24976 Federal Register / Vol. 76, No. 85 / Tuesday, May 3, 2011 / Proposed Rules 

ENVIRONMENTAL PROTECTION 

AGENCY 

40 CFR Parts 60 and 63 

[EPA–HQ–OAR–2009–0234; EPA–HQ–OAR– 

2011–0044, FRL–9286–1] 

RIN 2060–AP52 

National Emission Standards for 

Hazardous Air Pollutants From 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. 

ACTION: Proposed rule. 

SUMMARY: The United States (U.S.) 

Environmental Protection Agency (EPA 

or Agency) is proposing national 

emission standards for hazardous air 

pollutants (NESHAP) from coal- and oilfired electric utility steam generating 

units (EGUs) under Clean Air Act (CAA 

or the Act) section 112(d) and proposing 

revised new source performance 

standards (NSPS) for fossil fuel-fired 

EGUs under CAA section 111(b). The 

proposed NESHAP would protect air 

quality and promote public health by 

reducing emissions of the hazardous air 

pollutants (HAP) listed in CAA section 

112(b). In addition, these proposed 

amendments to the NSPS are in 

response to a voluntary remand of a 

final rule. We also are proposing several 

minor amendments, technical 

clarifications, and corrections to 

existing NSPS provisions for fossil fuelfired EGUs and large and small 

industrial-commercial-institutional 

steam generating units. 

DATES: Comments must be received on 

or before July 5, 2011. Under the 

Paperwork Reduction Act (PRA), 

comments on the information collection 

provisions are best assured of having 

full effect if the Office of Management 

and Budget (OMB) receives a copy of 

your comments on or before June 2, 

2011. 

Public Hearing: EPA will hold three 

public hearings on this proposal. The 

dates, times, and locations of the public 

hearings will be announced separately. 

Oral testimony will be limited to 

5 minutes per commenter. The EPA 

encourages commenters to provide 

written versions of their oral testimonies 

either electronically or in paper copy. 

Verbatim transcripts and written 

statements will be included in the 

rulemaking docket. If you would like to 

present oral testimony at one of the 

hearings, please notify Ms. Pamela 

Garrett, Sectors Policies and Programs 

Division (C504–03), U.S. EPA, Research 

Triangle Park, NC 27711, telephone 

number (919) 541–7966; e-mail: 

garrett.pamela@epa.gov. Persons 

wishing to provide testimony should 

notify Ms. Garrett at least 2 days in 

advance of each scheduled public 

hearing. For updates and additional 

information on the public hearings, 

please check EPA’s Web site for this 

rulemaking, http://www.epa.gov/ttn/ 

atw/utility/utilitypg.html. The public 

hearings will provide interested parties 

the opportunity to present data, views, 

or arguments concerning the proposed 

rule. EPA officials may ask clarifying 

questions during the oral presentations, 

but will not respond to the 

presentations or comments at that time. 

Written statements and supporting 

information submitted during the 

comment period will be considered 

with the same weight as any oral 

comments and supporting information 

presented at the public hearings. 

ADDRESSES: Submit your comments, 

identified by Docket ID. No. EPA–HQ– 

OAR–2011–0044 (NSPS action) or 

Docket ID No. EPA–HQ–OAR–2009– 

0234 (NESHAP action), by one of the 

following methods: 

• http://www.regulations.gov. Follow 

the instructions for submitting 

comments. 

• http://www.epa.gov/oar/ 

docket.html. Follow the instructions for 

submitting comments on the EPA Air 

and Radiation Docket Web site. 

• E-mail: Comments may be sent by 

electronic mail (e-mail) to a-and-rdocket@epa.gov, Attention EPA–HQ– 

OAR–2011–0044 (NSPS action) or EPA– 

HQ–OAR–2009–0234 (NESHAP action). 

• Fax: Fax your comments to: (202) 

566–9744, Docket ID No. EPA–HQ– 

OAR–2011–0044 (NSPS action) or 

Docket ID No. EPA–HQ–OAR–2009– 

0234 (NESHAP action). 

• Mail: Send your comments on the 

NESHAP action to: EPA Docket Center 

(EPA/DC), Environmental Protection 

Agency, Mailcode: 2822T, 1200 

Pennsylvania Ave., NW., Washington, 

DC 20460, Docket ID No. EPA–HQ– 

OAR–2009–0234. Send your comments 

on the NSPS action to: EPA Docket 

Center (EPA/DC), Environmental 

Protection Agency, Mailcode: 2822T, 

1200 Pennsylvania Ave., NW., 

Washington, DC 20460, Docket ID. EPA– 

HQ–OAR–2011–0044. Please include a 

total of two copies. In addition, please 

mail a copy of your comments on the 

information collection provisions to the 

Office of Information and Regulatory 

Affairs, OMB, Attn: Desk Officer for 

EPA, 725 17th St., NW., Washington, DC 

20503. 

• Hand Delivery or Courier: Deliver 

your comments to: EPA Docket Center, 

EPA West, Room 3334, 1301 

Constitution Ave., NW., Washington, 

DC 20460. Such deliveries are only 

accepted during the Docket’s normal 

hours of operation (8:30 a.m. to 4:30 

p.m., Monday through Friday, excluding 

legal holiday), and special arrangements 

should be made for deliveries of boxed 

information. 

Instructions: All submissions must 

include agency name and respective 

docket number or Regulatory 

Information Number (RIN) for this 

rulemaking. All comments will be 

posted without change and may be 

made available online at http:// 

www.regulations.gov, including any 

personal information provided, unless 

the comment includes information 

claimed to be confidential business 

information (CBI) or other information 

whose disclosure is restricted by statute. 

Do not submit information that you 

consider to be CBI or otherwise 

protected through http:// 

www.regulations.gov or e-mail. The 

http://www.regulations.gov Web site is 

an ‘‘anonymous access’’ system, which 

means EPA will not know your identity 

or contact information unless you 

provide it in the body of your comment. 

If you send an e-mail comment directly 

to EPA without going through http:// 

www.regulations.gov, your e-mail 

address will be automatically captured 

and included as part of the comment 

that is placed in the public docket and 

made available on the Internet. If you 

submit an electronic comment, EPA 

recommends that you include your 

name and other contact information in 

the body of your comment and with any 

disk or CD–ROM you submit. If EPA 

cannot read your comment due to 

technical difficulties and cannot contact 

you for clarification, EPA may not be 

able to consider your comment. 

Electronic files should avoid the use of 

special characters, any form of 

encryption, and be free of any defects or 

viruses. 

Docket: All documents in the docket 

are listed in the http:// 

www.regulations.gov index. Although 

listed in the index, some information is 

not publicly available (e.g., CBI or other 

information whose disclosure is 

restricted by statute). Certain other 

material, such as copyrighted material, 

will be publicly available only in hard 

copy form. Publicly available docket 

materials are available either 

electronically in http:// 

www.regulations.gov or in hard copy at 


jlentini on DSKJ8SOYB1PROD with PROPOSALS2
Federal Register / Vol. 76, No. 85 / Tuesday, May 3, 2011 / Proposed Rules 24977 

the EPA Docket Center, Room 3334, 

1301 Constitution Avenue, NW., 

Washington, DC. The Public Reading 

Room 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) 566–1742. 

FOR FURTHER INFORMATION CONTACT: For 

the NESHAP action: Mr. William 

Maxwell, Energy Strategies Group, 

Sector Policies and Programs Division, 

(D243–01), Office of Air Quality 

Planning and Standards, U.S. 

Environmental Protection Agency, 

Research Triangle Park, North Carolina 

27711; Telephone number: (919) 541– 

5430; Fax number (919) 541–5450; 

E-mail address: maxwell.bill@epa.gov. 

For the NSPS action: Mr. Christian 

Fellner, Energy Strategies Group, Sector 

Policies and Programs Division, (D243– 

01), Office of Air Quality Planning and 

Standards, U.S. Environmental 

Protection Agency, Research Triangle 

Park, North Carolina 27711; Telephone 

number: (919) 541–4003; Fax number 

(919) 541–5450; E-mail address: 

fellner.christian@epa.gov. 

SUPPLEMENTARY INFORMATION: The 

information presented in this preamble 

is organized as follows: 

I. General Information 

A. Executive Summary 

B. Does this action apply to me? 

C. What should I consider as I prepare my 

comments to EPA? 

D. Where can I get a copy of this 

document? 

E. When would a public hearing occur? 

II. Background Information on the NESHAP 

A. Statutory Background 

B. Regulatory and Litigation Background 

III. Appropriate and Necessary Finding 

A. Regulating EGUs Under CAA Section 

112 

B. The December 2000 Appropriate and 

Necessary Finding Was Reasonable 

C. EPA Must Regulate EGUs Under Section 

112 Because EGUs Were Properly Listed 

Under CAA Section 112(c)(1) and May 

Not Be Delisted Because They Do Not 

Meet the Delisting Criteria in CAA 

Section 112(c)(9) 

D. New Analyses Confirm That It Remains 

Appropriate and Necessary To Regulate 

U.S. EGU HAP Under Section 112 

IV. Summary of This Proposed NESHAP 

A. What source categories are affected by 

this proposed rule? 

B. What is the affected source? 

C. Does this proposed rule apply to me? 

D. Summary of Other Related D.C. Circuit 

Court Decisions 

E. EPA’s Response to the Vacatur of the 

2005 Action 

F. What is the relationship between this 

proposed rule and other combustion 

rules? 

G. What emission limitations and work 

practice standards must I meet? 

H. What are the startup, shutdown, and 

malfunction (SSM) requirements? 

I. What are the testing requirements? 

J. What are the continuous compliance 

requirements? 

K. What are the notification, 

recordkeeping, and reporting 

requirements? 

L. Submission of Emissions Test Results to 

EPA 

V. Rationale for This Proposed NESHAP 

A. How did EPA determine which 

subcategories and sources would be 

regulated under this proposed NESHAP? 

B. How did EPA select the format for this 

proposed rule? 

C. How did EPA determine the proposed 

emission limitations for existing EGUs? 

D. How did EPA determine the MACT 

floors for existing EGUs? 

E. How did EPA consider beyond-the-floor 

for existing EGUs? 

F. Should EPA consider different 

subcategories? 

G. How did EPA determine the proposed 

emission limitations for new EGUs? 

H. How did EPA determine the MACT 

floor for new EGUs? 

I. How did EPA consider beyond-the-floor 

for new EGUs? 

J. Consideration of Whether To Set 

Standards for HCl and Other Acid Gas 

HAP Under CAA Section 112(d)(4) 

K. How did we select the compliance 

requirements? 

L. What alternative compliance provisions 

are being proposed? 

M. How did EPA determine compliance 

times for this proposed rule? 

N. How did EPA determine the required 

records and reports for this proposed 

rule? 

O. How does this proposed rule affect 

permits? 

P. Alternative Standard for Consideration 

VI. Background Information on the Proposed 

NSPS 

A. What is the statutory authority for this 

proposed NSPS? 

B. Summary of State of New York, et al., 

v. EPA Remand 

C. EPA’s Response to the Remand 

D. EPA’s Response to the Utility Air 

Regulatory Group’s Petition for 

Reconsideration 

VII. Summary of the Significant Proposed 

NSPS Amendments 

A. What are the proposed amended 

emissions standards for EGUs? 

B. Would owners/operators of any EGUs be 

exempt from the proposed amendments? 

C. What other significant amendments are 

being proposed? 

VIII. Rationale for This Proposed NSPS 

A. How are periods of malfunction 

addressed? 

B. How did EPA determine the proposed 

emission limitations? 

C. Changes to the Affected Facility 

D. Additional Proposed Amendments 

E. Request for Comments on the Proposed 

NSPS Amendments 

IX. Summary of Cost, Environmental, Energy, 

and Economic Impacts of This Proposed 

NSPS 

X. Impacts of These Proposed Rules 

A. What are the air impacts? 

B. What are the energy impacts? 

C. What are the compliance costs? 

D. What are the economic impacts? 

E. What are the benefits of this proposed 

rule? 

XI. Public Participation and Request for 

Comment 

XII. 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 

I. General Information 

A. Executive Summary 

In December 2000, EPA appropriately 

concluded that it was appropriate and 

necessary to regulate hazardous air 

pollutants (HAP) from EGUs. Today, 

EPA confirms that finding and 

concludes that it remains appropriate 

and necessary to regulate these 

emissions from EGUs. Hazardous air 

pollutants from EGUs contribute to 

adverse health and environmental 

effects. EGUs are by far the largest U.S. 

anthropogenic sources of mercury (Hg) 

emissions into the air and emit a 

number of other HAP. Both the finding 

in 2000 and our conclusion that it 

remains appropriate and necessary to 

regulate HAP from EGUs are supported 

by the CAA and scientific and technical 

analyses. 

Mercury is a highly toxic pollutant 

that occurs naturally in the environment 

and is released into the atmosphere in 

significant quantities as the result of the 

burning of fossil fuels. Mercury in the 

environment is transformed into a more 

toxic form, methylmercury (MeHg), and 

because it is also a persistent pollutant, 

it accumulates in the food chain, 

especially the tissue of fish. When 

people consume these fish they 

consume MeHg, the consumption of 

which may cause neurotoxic effects. 

Children, and, in particular, developing 


jlentini on DSKJ8SOYB1PROD with PROPOSALS2
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1U.S. EPA. 1997. Mercury Study Report to 

Congress. EPA–452/R–97–003 December 1997. 

2Based on 2005 U.S. emissions of 105 tons, and 

global emissions of 2,100 tons from UNEP. Mercury 

emissions are discussed more fully in Section 

III.D.1 of this preamble. 

fetuses, are especially susceptible to 

MeHg effects because their developing 

bodies are more highly sensitive to its 

effects. In the December 2000 Finding, 

we estimated that about 7 percent of 

women of child-bearing age are exposed 

to MeHg at a level capable of causing 

adverse effects in the developing fetus, 

and that about 1 percent were exposed 

to 3 to 4 times that level. 65 FR 79827. 

Moreover, in the 1997 Mercury Study 

Report to Congress (the ‘‘Mercury 

Study’’),1 we concluded that exposures 

among specific subpopulations 

including anglers, Asian-Americans, 

and members of some Native American 

Tribes may be more than two-times 

greater than those experienced by the 

average U.S. population (U.S. EPA 1997 

Mercury Study Report to Congress, 

Volume IV, page 7–2). 

In addition to Hg, EGUs are 

significant emitters of HAP metals such 

as arsenic (As), nickel (Ni), cadmium 

(Cd), and chromium (Cr), which can 

cause cancer; HAP metals with 

potentially serious noncancer health 

effect such as lead (Pb) and selenium 

(Se); and other toxic air pollutants such 

as the acid gases hydrogen chloride 

(HCl) and hydrogen fluoride (HF). 

Adverse noncancer health effects 

associated with non-Hg EGU HAP 

include chronic health disorders (e.g., 

irritation of the lung, skin, and mucus 

membranes, effects on the central 

nervous system, and damage to the 

kidneys), and acute health disorders 

(e.g., lung irritation and congestion, 

alimentary effects such as nausea and 

vomiting, and effects on the kidney and 

central nervous system). Three of the 

key metal HAP emitted by EGUs (As, Cr, 

and Ni) have been classified as human 

carcinogens, while another (Cd) is 

classified as a probable human 

carcinogen. Current national emissions 

inventories indicate that EGUs are 

responsible for 62 percent of the 

national total emissions of As, 22 

percent of the national total emissions 

of Cr, and 28 percent of the national 

total emissions of Ni to the atmosphere. 

Notably, EGUs are also responsible for 

83 percent of the national total 

emissions of Se to the atmosphere. 

Congress recognized the threats posed 

by emissions of HAP and was 

dissatisfied with the pace of EPA’s 

progress in reducing them prior to 1990. 

As a result, it enacted significant 

changes to the CAA that required EPA 

to develop stringent standards for the 

control of these pollutants from both 

stationary and mobile sources. Congress 

included the requirements in the 1990 

CAA amendments regarding acid rain 

that would reduce emissions of certain 

criteria pollutants from EGUs and result 

in the installation of controls that might 

achieve HAP emission reduction cobenefits. For that reason, it added the 

requirement for EPA to make a finding 

before it could regulate EGUs under 

section 112. Specifically, Congress 

required in the air toxics provisions that 

EPA conduct a study of the public 

health hazards anticipated to remain 

from EGU HAP emissions after 

imposition of these other provisions and 

regulate EGUs under section 112 if the 

Agency found, after considering the 

results of the study, that such regulation 

was appropriate and necessary. 

Congress also required EPA to conduct 

a study of Hg emissions from EGUs and 

other sources and consider the health 

and environmental effects of the 

emissions and the availability and cost 

of control technologies. 

Responding to Congress, EPA 

published the required studies detailing 

the hazards posed by emissions of Hg 

and the risks posed by emissions of Hg 

and other HAP from fossil fuel-fired 

EGUs. Following the publication of the 

studies and after collecting additional 

relevant data, EPA concluded in 

December 2000 that the threats to public 

health and the environment from 

emissions of Hg and other HAP from 

EGUs made it both appropriate and 

necessary to adopt regulations under 

section 112 to reduce the emissions of 

Hg and other HAP from coal- and oilfired EGUs. As a result of its findings, 

EPA added these sources to the list of 

stationary sources subject to regulations 

governing the emissions of HAP. 

However, in a rulemaking effort 

completed in 2005, EPA reversed its 

findings and instead adopted 

regulations under other provisions of 

the CAA. The DC Circuit Court vacated 

the resulting regulations, noting that 

EPA had sidestepped important legal 

requirements in the CAA that govern the 

delisting of source categories. Those 

requirements provide that EPA can 

delist a source category only if it can 

demonstrate that no source within the 

listed category poses a lifetime cancer 

risk above one in one million to the 

individual most exposed and that 

emissions from no source in the 

category exceed the level that is 

adequate to protect public health with 

an ample margin of safety and that no 

adverse environmental effects will 

result from the emissions of any source. 

CAA 112(c)(9)(B). The DC Circuit 

Court’s action restored EPA’s December 

2000 determination that it was 

appropriate and necessary to regulate 

coal- and oil-fired EGUs under section 

112, and EGUs remain a listed source 

category. 

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 EGUs under 

section 112. Now, more than 10 years 

have passed since EPA’s determination 

that toxic emissions from coal- and oilfired EGUs pose a threat to public health 

and the environment. Although not 

required, EPA conducted additional, 

extensive technical analyses based on 

more recent data, and those analyses 

confirm that it remains appropriate and 

necessary to regulate HAPs from coaland oil-fired EGUs. Accordingly and 

without further delay, we are proposing 

a set of HAP emission standards for 

coal- and oil-fired EGUs that can be met 

with existing technology that has been 

available for a significant time. 

EPA acknowledges that although 

EGUs contribute significantly to the 

total amount of U.S. anthropogenic Hg 

emissions, other sources both here and 

abroad also contribute significantly to 

the global atmospheric burden and U.S. 

deposition of Hg. It is estimated that the 

U.S. contributes 5 percent to global 

anthropogenic Hg and 2 percent the 

total global Hg pool.2 However, as the 

U.S. Supreme Court has noted in 

decisions as recently as Massachusetts 

v. EPA, regarding the problem of climate 

change, it is not necessary to show that 

a problem will be entirely solved by the 

action being taken, nor that it is 

necessary to cure all ills before 

addressing those judged to be 

significant. 549 U.S. 497, 525 (2007). 

At the time it published the December 

2000 Finding, EPA identified certain 

technologies capable of significantly 

reducing Hg and other HAP emissions. 

Since then, additional technologies and 

improvements to those previously 

identified have become available. These 

technologies are also often effective at 

reducing significantly the emissions of 

other conventional pollutants such as 

SO2 and PM, thereby conferring even 

greater health co-benefits. As today’s 

notice discusses further, the reductions 

expected from the adopted final rule 

will produce substantially greater cobenefits to health and the environment 

than they will cost to affected 

companies. We further believe that 

these reductions can be achieved 

without significantly affecting the 

availability and cost of electricity to 


jlentini on DSKJ8SOYB1PROD with PROPOSALS2
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consumers. In those instances in which 

such concerns do arise, the Federal 

government will work with companies 

to ensure a reliable and reasonablypriced supply of electricity. Moreover, 

in its assessment of the impacts of 

today’s proposed rule on jobs and the 

economy, EPA finds that more jobs will 

be created in the air pollution control 

technology production field than may 

be lost as the result of compliance with 

these proposed rules. 

A number of EGUs operating today 

were built in the 1950s and 1960s, using 

now-obsolete and inefficient 

technologies. Today, new units are far 

more efficient in their production of 

electricity, their use of fuel, and the 

relative quantities of pollution emitted. 

To the extent that some of the oldest, 

least efficient, least controlled units are 

retired by companies who elect not to 

invest in controlling them, assessments 

included in the docket to today’s notice 

of proposed rulemaking indicate that 

there will be a sufficient supply of 

electricity from newer units. In fact, one 

consequence of today’s proposed rule, if 

adopted as a final rule, will 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. Thus, 

this proposed rule will require 

companies to make a decision—control 

HAP emissions from virtually 

uncontrolled sources or retire these 

sometimes 60 year old units and shift 

their emphasis to more efficient, cleaner 

modern methods of generation, 

including modern coal-fired generation. 

For the reasons summarized above 

and discussed in detail in this 

document, the standards being proposed 

today will be effective at significantly 

reducing emissions of Hg and an array 

of other toxic pollutants from coal- and 

oil-fired EGUs. In addition, as a result 

of the HAP reductions and co-benefits of 

these rules, many premature deaths 

from exposure to air pollution will be 

avoided by the application of controls 

that are well-known, broadly applied, 

and available. To the extent that isolated 

issues remain concerning the 

availability of electricity in some more 

remote parts of the country, we believe 

that EPA has the ability to work with 

companies making good faith efforts to 

comply with the standards so that 

consumers in those areas are not 

adversely affected. 

Consistent with the recently issued 

Executive Order (EO) 13563, ‘‘Improving 

Regulation and Regulatory Review,’’ we 

have estimated the cost and benefits of 

the proposed rule. The estimated net 

benefits of our proposed rule at a 3 

percent discount rate are $48 to 130 

billion or $42 to $120 billion at a 7 

percent discount rate. 

SUMMARY OF THE MONETIZED BENEFITS, SOCIAL COSTS, AND NET BENEFITS FOR THE PROPOSED RULE IN 2016 

[Millions of 2007$] a

3% Discount rate 7% Discount rate 

Total Monetized Benefits b ................................................................................................................... $59,000 to $140,000 $53,000 to $130,000. 

Hg-related Benefits c ............................................................................................................................ $4.1 to $5.9 ............. $0.45 to $0.89. 

CO2-related Benefits ........................................................................................................................... $570 ......................... $570. 

PM2.5-related Co-benefits d .................................................................................................................. $58,000 to $140,000 $53,000 to $120,000. 

Total Social Costs e ............................................................................................................................. $10,900 .................... $10,900. 

Net Benefits ......................................................................................................................................... $48,000 to $130,000 $42,000 to $130,000. 

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

Cardiovascular effects of Hg exposure. 

Other health effects of Hg exposure. 

Ecosystem effects. 

Commercial and non-freshwater fish consumption. 

aAll estimates are for 2016, and are rounded to two significant figures. The net present value of reduced CO2 emissions are calculated differently than other benefits. The same discount rate used to discount the value of damages from future emissions (SCC at 5, 3, 2.5 percent) is 

used to calculate net present value of SCC for internal consistency. This table shows monetized CO2 co-benefits at discount rates at 3 and 7 

percent that were calculated using the global average SCC estimate at a 3 percent discount rate because the interagency workgroup on this 

topic deemed this marginal value to be the central value. In section 6.6 of the RIA we also report the monetized CO2 co-benefits using discount 

rates of 5 percent (average), 2.5 percent (average), and 3 percent (95th percentile). bThe total monetized benefits reflect the human health benefits associated with reducing exposure to MeHg, PM2.5, and ozone. cBased on an analysis of health effects due to recreational freshwater fish consumption. 

dThe reduction in premature mortalities from account for over 90 percent of total monetized PM2.5 benefits. eSocial costs are estimated using the MultiMarket model, in order to estimate economic impacts of the proposal to industries outside the electric power sector. Details on the social cost estimates can be found in Chapter 9 and Appendix E of the RIA. 

For more information on how EPA is 

addressing EO 13563, see the executive 

order discussion, later in the preamble. 

B. Does this action apply to me? 

The regulated categories and entities 

potentially affected by the proposed 

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 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. 


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This table is not intended to be 

exhaustive, but rather provides a guide 

for readers regarding entities likely to be 

affected by this action. To determine 

whether your facility, company, 

business, organization, etc., would be 

regulated by this action, you should 

examine the applicability criteria in 40 

CFR 60.40, 60.40Da, or 60.40c or in 40 

CFR 63.9982. If you have any questions 

regarding the applicability of this action 

to a particular entity, consult either the 

air permitting authority for the entity or 

your EPA regional representative as 

listed in 40 CFR 60.4 or 40 CFR 63.13 

(General Provisions). 

C. What should I consider as I prepare 

my comments to EPA? 

Do not submit information containing 

CBI to EPA through http:// 

www.regulations.gov or e-mail. Send or 

deliver information identified as CBI 

only to the following address: Roberto 

Morales, OAQPS Document Control 

Officer (C404–02), Office of Air Quality 

Planning and Standards, U.S. 

Environmental Protection Agency, 

Research Triangle Park, North Carolina 

27711, Attention: Docket ID EPA–HQ– 

OAR–2011–0044 (NSPS action) or 

Docket ID EPA–HQ–OAR–2009–0234 

(NESHAP action). Clearly mark the part 

or all of the information that you claim 

to be CBI. For CBI information in a disk 

or CD–ROM that you mail to EPA, mark 

the outside of the disk or CD–ROM as 

CBI and then identify electronically 

within the disk or CD–ROM the specific 

information that is claimed as CBI. In 

addition to one complete version of the 

comment that includes information 

claimed as CBI, a copy of the comment 

that does not contain the information 

claimed as CBI must be submitted for 

inclusion in the public docket. 

Information so marked will not be 

disclosed except in accordance with 

procedures set forth in 40 CFR part 2. 

D. Where can I get a copy of this 

document? 

In addition to being available in the 

docket, an electronic copy of this 

proposed rule will also be available on 

the Worldwide Web (WWW) through 

the Technology Transfer Network 

(TTN). Following signature, a copy of 

the proposed rule 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. 

E. When would a public hearing occur? 

EPA will hold three public hearings 

on this proposal. The dates, times, and 

locations of the public hearings will be 

announced separately. If you would like 

to present oral testimony at one of the 

hearings, please notify Ms. Pamela 

Garrett, Sectors Policies and Programs 

Division (C504–03), U.S. EPA, Research 

Triangle Park, NC 27711, telephone 

number (919) 541–7966; e-mail: 

garrett.pamela@epa.gov. Persons 

wishing to provide testimony should 

notify Ms. Garrett at least 2 days in 

advance of the public hearings. For 

updates and additional information on 

the public hearings, please check EPA’s 

Web site for this rulemaking, http:// 

www.epa.gov/ttn/atw/utility/ 

utilitypg.html. 

II. Background Information on the 

NESHAP 

In 1990, Congress substantially 

rewrote provisions of the CAA 

addressing emissions of HAP from large 

and small stationary sources in the U.S. 

Collectively, these sources emit into the 

air millions of pounds of HAP each 

year, chemicals that are known to cause 

or are suspected of causing cancer, birth 

defects, reproduction problems, and 

other serious health effects. Many of the 

sources that emit air toxics are located 

in urban areas, which generally include 

predominantly low income, minority or 

otherwise vulnerable communities, 

where dense populations mean that 

large numbers of people may be 

exposed. 

Since 1990, EPA has promulgated 

regulations covering over 50 industrial 

sectors, requiring the use of available 

control technology and other practices 

to reduce emissions. These standards 

have reduced emissions of HAP from 

American industry by more than 60 

percent. HAP emissions from smaller 

sources such as dry cleaners and auto 

body shops have declined by 30 

percent, also due to CAA standards. 

Greater reductions are expected as 

greater numbers of smaller sources 

adopt pollution prevention, efficiency, 

or install control technologies to comply 

with EPA emission standards. 

Emissions from the mobile source sector 

have also been addressed. Controls for 

fuels and vehicles are expected to 

reduce selected HAP from vehicles by 

more than 75 percent by 2020. 

EGUs are the most significant source 

of HAP in the country that remains 

unaddressed by Congress’s air toxics 

program. EGUs emit multiple HAP of 

concern and are by far the largest 

remaining source of Hg, which is one of 

the more highly toxic chemicals on 

Congress’s list of HAP and which, once 

released, stays in the environment 

permanently. Coal- and oil-fired EGUs 

also emit HAP such as As, other metals 

and acid gases in amounts significantly 

higher than almost any other industrial 

sector. They are located in nearly every 

state, and emissions from their stacks 

affect people nearby as well as hundreds 

of miles away. 

Congress provided a specific path for 

EPA to regulate HAP emissions from 

EGUs. It gave explicit instructions about 

scientific studies EPA needed to 

develop and then consider in 

determining whether it was ‘‘appropriate 

and necessary’’ to regulate HAP 

emissions from EGUs. Congress 

anticipated that EPA would complete 

the studies by 1994. In 2000, EPA found 

that it was indeed ‘‘appropriate and 

necessary’’ to regulate HAP emissions 

from EGUs under section 112. In the 

decade that has passed since EPA made 

that finding, EGUs have continued to 

emit Hg and other HAP, and there are 

still no national limits on the amount of 

Hg and other HAP that EGUs can release 

into the air. And, although some plants 

have installed available and effective 

control technologies that reduce these 

emissions, there is no requirement for 

EGUs to control for Hg and other HAP. 

As our new analyses demonstrate, it 

remains both appropriate and necessary 

to set standards for coal- and oil-fired 

EGUs to protect public health and the 

environment from the adverse effects of 

HAP emissions from EGUs. The 

Agency’s appropriate and necessary 

finding was correct in 2000, and it 

remains correct today. EPA proposes to 

set standards for coal- and oil-fired 

EGUs that will reduce emissions of Hg, 

Ni and other metal HAP, acid gas HAP, 

and other harmful HAP. These 

standards are based on available control 

technologies and other practices already 

used by the better-controlled and loweremitting EGUs. They are achievable, we 

believe they can be implemented 

without disruption to the reliable 

provision of electricity, and will deliver 

health protection across the U.S. 

In this section, we provide an 

overview of the relevant statutory, 

regulatory, and litigation background. 

A. Statutory Background 

Congress enacted section 112 to 

address HAP emissions from stationary 

sources. Section 112 contains provisions 

specific to EGUs, which we will address 

in this preamble, but we begin with a 

summary of the overall structure and 

purpose of the section 112 program. 

Prior to the 1990 Amendments, the 

CAA required EPA to regulate HAP 

solely on the basis of risk to human 


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3A ‘‘stationary source’’ of HAP is any building, 

structure, facility or installation that emits or may 

emit any air pollutant. See CAA Section 112(a)(3). 

4Congress required EPA to publish a list of 

categories and subcategories of major sources and 

area sources by November 15, 1991. See CAA 

112(c)(1) & (c)(3). EPA published the initial list on 

July 16, 1992. See 57 FR 31576, July 16, 1992. EPA 

did not include EGUs on the initial section 112(c) 

list because Congress required EPA to conduct and 

consider the results of the study required by section 

112(n)(1)(A) before regulating these units. At the 

time of the initial listing, EPA had not completed 

the study required by section 112(n)(1)(A). 

5 ‘‘Electric utility steam generating unit’’ is defined 

as any ‘‘fossil fuel fired combustion unit of more 

than 25 megawatts that serves a generator that 

produces electricity for sale.’’ See CAA 112(a)(8). 

6US EPA. Study of Hazardous Air Pollutant 

Emissions from Electric Utility Steam Generating 

Units —Final Report to Congress. EPA–453/R–98– 

004a. February 1998. 

health. Legislative History of the CAA 

Amendments of 1990 (‘‘Legislative 

History’’), at 3174–75, 3346 (Comm. 

Print 1993). Congress was dissatisfied 

with the slow pace of exclusively riskbased regulation of HAP prior to 1990, 

however, and, as a result, substantially 

amended the CAA in 1990, setting forth 

a two-stage approach for regulating HAP 

emissions. Under the first stage, 

Congress directed EPA to issue 

technology-based emission standards for 

listed source categories. CAA sections 

112 (c)–(d). In the second stage, which 

occurs ‘‘within eight years’’ of the 

imposition of the technology-based 

standards, EPA must consider whether 

residual risks remain after imposition of 

the MACT standards that warrant more 

stringent standards to protect human 

health or to prevent an adverse 

environmental effect. CAA section 

112(f)(2)(A). 

In addition to adopting this twophased approach to standard-setting, 

Congress included a series of rigorous 

deadlines for EPA, including deadlines 

for listing categories and issuing 

emission standards for such categories. 

See, e.g., CAA section 112(e)(1). Thus, 

in substantially amending CAA section 

112 in 1990, Congress sought prompt 

and permanent reductions of HAP 

emissions from stationary sources—first 

through technology-based standards, 

and then further, as necessary, through 

risk-based standards designed to protect 

human health and the environment. 

The criteria for regulation differ in 

section 112 depending on whether the 

source is a major source or an area 

source. A ‘‘major source’’ is any 

stationary source 3 or group of stationary 

sources at a single location and under 

common control that emits or has the 

potential to emit 10 tons or more per 

year of any HAP or 25 tons or more per 

year of any combination of HAP. See 

CAA 112(a)(1). An ‘‘area source’’ is any 

stationary source of HAP that is not a 

‘‘major source.’’ See CAA 112(a)(2). For 

major sources, EPA must list a category 

under section 112(c)(1) if at least one 

stationary source in the category meets 

the definition of a major source.4 For 

area sources, EPA must list if: (1) EPA 

determines that the category of area 

sources presents a threat of adverse 

effects to human health or the 

environment that warrants regulation 

under CAA section 112; or (2) the 

category of area sources falls within the 

purview of CAA section 112(k)(3)(B) 

(the Urban Area Source Strategy). See 

CAA section 112(c)(3). 

Congress established a specific 

structure for determining whether to 

regulate EGUs under section 112.5

Specifically, Congress enacted CAA 

section 112(n)(1). 

In section 112(n)(1)(A), EPA is 

directed to conduct a study 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, and to 

report the results of such study to 

Congress by November 15, 1993 (Utility 

Study Report to Congress; 6 the ‘‘Utility 

Study’’). We discuss this study further 

below in conjunction with the other 

studies Congress required be conducted 

with respect to EGUs under section 

112(n)(1). The last sentence of section 

112(n)(1)(A) provides that EPA shall 

regulate EGUs under CAA section 112 

‘‘if the Administrator finds such 

regulation is appropriate and necessary, 

after considering the results of the 

[Utility Study] * * *’’ Thus, section 

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

Administrator decides whether to list 

EGUs for regulation under section 112. 

See New Jersey, 517 F.3d at 582 

(‘‘Section 112(n)(1) governs how the 

Administrator decides whether to list 

EGUs; it says nothing about delisting 

EGUs.’’). 

Once a source category is listed 

pursuant to section 112(c), the next step 

is for EPA to establish technology-based 

emission standards under section 

112(d). Under section 112(d), EPA must 

establish emission standards for major 

sources that ‘‘require the maximum 

degree of reduction in emissions of the 

HAP subject to this section’’ that EPA 

determines is achievable taking into 

account certain statutory factors. These 

are referred to as ‘‘maximum achievable 

control technology’’ or ‘‘MACT’’ 

standards. The MACT standards for 

existing sources must be at least as 

stringent as the average emissions 

limitation achieved by the best 

performing 12 percent of existing 

sources in the category (for which the 

Administrator has emissions 

information) or the best performing 5 

sources for source categories with less 

than 30 sources. See CAA section 

112(d)(3)(A) and (B). This level of 

minimum stringency is referred to as the 

MACT floor, and EPA cannot consider 

cost in setting the floor. For new 

sources, MACT standards must be at 

least as stringent as the control level 

achieved in practice by the best 

controlled similar source. See CAA 

section 112(d)(3). EPA also must 

consider more stringent ‘‘beyond-thefloor’’ control options. When 

considering beyond-the-floor options, 

EPA must consider not only the 

maximum degree of reduction in 

emissions of HAP, but must take into 

account costs, energy, and nonair 

quality health and environmental 

impacts when doing so. See Cement 

Kiln Recycling Coal. v. EPA, 255 F.3d 

855, 857–58 (D.C. Cir. 2001). 

CAA section 112(d)(4) authorizes EPA 

to set a health-based standard for a 

limited set of HAP for which a health 

threshold has been established, and that 

standard must provide for ‘‘an ample 

margin for safety.’’ 42 U.S.C. 7412(d)(4). 

As these standards are potentially 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, section 112(d)(5) 

authorizes EPA to issues standards or 

requirements that provide for the use of 

generally available control technologies 

(GACT) or management practices in lieu 

of promulgating standards pursuant to 

sections 112(d)(2) and (3). 

As noted above, Congress required 

that various reports concerning EGUs be 

completed. The first report, the Utility 

Study, required 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. This 

report was required by November 15, 

1993. The second report, due on 

November 15, 1994, directed EPA to 

‘‘conduct a study of mercury emissions 

from [EGUs], municipal waste 

combustion units, and other sources, 

including area sources.’’ See CAA 

section 112(n)(1)(B). In conducting the 

Mercury study Congress directed EPA to 

‘‘consider the rate and mass of 

emissions, the health and 

environmental effects of such emissions, 

technologies which are available to 

control such emissions, and the costs of 

such technologies.’’ Id. EPA completed 

both of these reports by 1998. 


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7National Research Council (NAS). 2000. 

Toxicological Effects of Methylmercury. Committee 

on the Toxicological Effects of Methylmercury, 

Board on Environmental Studies and Toxicology, 

National Research Council. Many of the peerreviewed articles cited in this section are 

publications originally cited in the NAS report. 

The last required report was to be 

completed by the National Institute of 

Environmental Health Sciences (NIEHS) 

and submitted to Congress by November 

15, 1993. CAA section 112(n)(1)(C) 

directed NIEHS to conduct ‘‘a study to 

determine the threshold level of Hg 

exposure below which adverse human 

health effects are not expected to occur.’’ 

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. NIEHS submitted this Report 

to Congress in August, 1995. 

In addition, Congress, in conference 

report language associated with EPA’s 

fiscal year 1999 appropriations, directed 

EPA to fund the National Academy of 

Sciences (NAS) to perform an 

independent evaluation of the available 

data related to the health impacts of 

MeHg (‘‘Toxicological Effects of 

Methylmercury,’’ hereinafter, NAS 

Study or MeHg Study).7 H.R. Conf. Rep. 

No. 105–769, at 281–282 (1998). 

Specifically, NAS was tasked with 

advising EPA as to the appropriate 

reference dose (RfD) for MeHg, which 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. 65 FR 79826. In that 

same conference report, Congress 

indicated that EPA should not make the 

appropriate and necessary regulatory 

determination for Hg emissions until 

EPA had reviewed the results of the 

NAS Study. See H.R. Conf. Rep. No. 

105–769, at 281–282 (1998). 

The NAS Study evaluated the same 

issues as those required to be 

considered under section 112(n)(1)(C). 

The NAS Study was completed 5 years 

after the NIEHS Study, and, thus, 

considered additional information not 

available to NIEHS. Because Congress 

required that the same issues be 

addressed in both the NAS and NIEHS 

Studies and the NAS Study was issued 

after the NIEHS study, we discuss, for 

purposes of this document, the content 

of the NAS Study, as opposed to the 

NIEHS Study. 

B. Regulatory and Litigation Background 

EPA conducted the studies required 

by section 112(n)(1) concerning utility 

HAP emissions. Prior to issuance of the 

Mercury Study, EPA engaged in two 

extensive external peer reviews of the 

document. Although EPA missed the 

statutory deadline for completing the 

studies, the Mercury Study and the 

Utility Study were complete by 1998. 

The NIEHS study was completed in 

1995, and the NAS Study was 

completed in 2000. 

In December 2000, after considering 

public input, the studies required by 

section 112(n)(1) and other relevant 

information, including Hg emissions 

data from EGUs, EPA determined that it 

was appropriate and necessary to 

regulate EGUs under CAA section 112. 

Based on that determination, the 

Agency listed such units for regulation 

under section 112(c). 

Pursuant to a settlement agreement, 

the deadline for issuing emission 

standards was March 15, 2005. 

However, instead of issuing emission 

standards pursuant to section 112(d), on 

March 15, 2005, EPA delisted EGUs, 

finding that it was neither appropriate 

nor necessary to regulate such units 

under section 112. That attempt to delist 

was subsequently invalidated by the DC 

Circuit Court. 

1. Studies Related to HAP Emissions 

From EGUs 

a. The Utility Study 

EPA issued the Utility Study in 

February 1998, over 4 years after the 

statutory deadline. The Utility Study 

included numerous analyses. EPA first 

collected HAP emissions test data from 

52 EGUs, including a range of coal-, 

oil-, and natural gas-fired units, and the 

test data along with facility specific 

information were used to estimate HAP 

emissions from all 684 utility facilities. 

EPA determined that 67 HAP were 

emitted from EGUs. In addition, the 

study evaluated HAP emissions based 

on two scenarios: (1) 1990 base year; 

and (2) 2010 projected emissions. The 

2010 scenario was selected to meet the 

section 112(n)(1)(A) mandate to evaluate 

hazards ‘‘after imposition of the 

requirements of the Act.’’ EPA also 

considered potential control strategies 

for the identified HAP consistent with 

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

EPA evaluated exposures, hazards, 

and risks due to HAP emissions from 

coal-, oil-, and natural gas-fired EGUs. 

EPA conducted a screening level 

assessment of all 67 HAP to prioritize 

the HAP for further analysis. A total of 

14 HAP were identified as priority HAP 

that would be further assessed. Twelve 

HAP (As, beryllium (Be), Cd, Cr, 

manganese (Mn), Ni, HCl, HF, acrolein, 

dioxins, formaldehyde, and 

radionuclides) were identified as a 

priority for further assessment based on 

inhalation exposure and risk. Six HAP 

(Hg, radionuclides, As, Cd, Pb, and 

dioxins) were considered a priority for 

multipathway assessment of exposure 

and risk. 

Based on the inhalation estimates for 

the priority HAP, EPA determined that 

As and Cr emissions from coal-fired 

EGUs and Ni emissions from oil-fired 

EGUs contributed most to the potential 

cancer related inhalation risks, but those 

risks were not high. The non-cancer risk 

assessment due to inhalation exposure 

indicated exposures were well below 

the reference levels. 

The Agency also conducted 

multipathway assessments for the six 

HAP identified above. Based on these 

analyses, EPA determined that Hg from 

coal-fired EGUs was the HAP of greatest 

potential concern. In addition, the 

screening multipathway assessments for 

dioxins and As suggested that these two 

HAP were of potential for multipathway 

risk. 

In addition to the 1990 analysis, EPA 

also estimated emissions and inhalation 

risks for the year 2010. HAP emissions 

from coal-fired utilities were predicted 

to increase by 10 to 30 percent by the 

year 2010. Predicted changes included 

the installation of scrubbers for a small 

number of facilities, the closing of a few 

facilities, and an increase in fuel 

consumption of other facilities. For oilfired plants, emissions and inhalation 

risks were estimated to decrease by 30 

to 50 percent by the year 2010, 

primarily due to projected reductions in 

use of oil for electricity generation. 

Multipathway risks for 2010 were not 

assessed. 

In estimating future emissions from 

EGUs, EPA primarily evaluated the 

effect of implementation of the Acid 

Rain Program (ARP) on HAP emissions 

from EGUs. The 2010 scenario also 

included estimated changes in 

emissions resulting from projected 

trends in fuel choices and power 

demands. 

Table 2 of this preamble presents 

estimated emissions for a subset of 

priority HAP for 1990 and 2010. 


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TABLE 2—NATIONWIDE EMISSIONS FOR SIX PRIORITY HAP, TPY

HAP 

Coal Oil Natural gas 

1990 2010 1990 2010 1990 2010 

Arsenic ............................................. 61 71 5 3 0 .15 0 .25 

Chromium ......................................... 73 87 4 .7 2 .4 .......................... ..........................

Mercury ............................................ 46 60 0 .25 0 .13 0 .0015 0 .024 

Nickel ............................................... 58 69 390 200 2 .2 3 .5 

Hydrogen chloride ............................ 143,000 155,000 2,900 1,500 NM NM 

Hydrogen fluoride ............................. 20,000 26,000 140 73 NM NM 

Numerous potential alternative 

control strategies for reducing HAP 

emissions from EGUs were identified. 

These included pre-combustion controls 

(e.g., fuel switching, coal cleaning), post 

combustion controls (e.g., PM controls, 

SO2 controls), and improving efficiency 

in supply or demand. For example, coal 

cleaning tends to remove at least some 

of all the trace metals. EPA also 

concluded that PM controls tend to 

effectively remove the trace metals 

(excluding Hg). The Utility Study also 

found that flue gas desulfurization 

(FGD) units were less effective at 

removing trace metals and exhibited 

more variability in removal of those 

metals than PM control, but FGD were 

more effective at reducing acid gas HAP. 

b. The Mercury Study 

EPA issued the Mercury Study in 

December 1997, 3 years after the 

statutory deadline. The Mercury Study 

assessed the magnitude of U.S. Hg 

emissions by source, the health and 

environmental implications of those 

emissions, and the availability and cost 

of control technologies. 

According to the Mercury Study, Hg 

cycles in the environment as a result of 

natural and human (anthropogenic) 

activities. Most of the Hg in the 

atmosphere is elemental Hg vapor, 

which circulates in the atmosphere for 

up to a year, and, hence, can be widely 

dispersed and transported thousands of 

miles from likely sources of emission. 

The Mercury Study also found that most 

of the Hg in water, soil, sediments, or 

plants and animals is in the form of 

inorganic Hg salts and organic forms of 

Hg (e.g., MeHg). The inorganic form of 

Hg, when either bound to airborne 

particles or in a gaseous form, is readily 

removed from the atmosphere by 

precipitation and is also dry deposited. 

Wet deposition is the primary 

mechanism for transporting Hg from the 

atmosphere to surface waters and land. 

Even after it deposits, Hg commonly is 

emitted back to the atmosphere either as 

a gas or associated with particles, to be 

re-deposited elsewhere. 

The Mercury Study estimated that in 

1994–1995, anthropogenic U.S. Hg 

emissions were about 158 tons annually. 

Roughly 87 percent of those emissions 

were from combustion sources, 

including waste and fossil fuel 

combustion. According to the Mercury 

Study, current anthropogenic emissions 

were only one part of the Hg cycle. The 

Mercury Study noted that current 

releases from human activities were 

adding to the Hg reservoirs that already 

exist in land, water, and air, both 

naturally and as a result of prior human 

activities. The Mercury Study 

concluded that the flux of Hg from the 

atmosphere to land or water at any one 

location is comprised of contributions 

from the natural global cycle, including 

re-emissions from the oceans, 

international sources, regional sources, 

and local sources. 

The Mercury Study further described 

a computer simulation of long-range 

transport of Hg, which suggested that 

about one-third (approximately 52 tons) 

of U.S. anthropogenic emissions are 

deposited, through wet and dry 

deposition, within the lower 48 states. 

The remaining two-thirds 

(approximately 107 tons) was estimated 

to be transported outside of U.S. borders 

where it would diffuse into the global 

reservoir. The computer simulation 

further suggested that another 35 tons of 

Hg from the global reservoir outside the 

U.S. was deposited annually in the U.S. 

for a total deposition in the U.S. of 

roughly 87 tons per year (tpy). 

The Mercury Study also found that 

fish consumption dominates the 

pathway for human and wildlife 

exposure to MeHg and that there was a 

plausible link between anthropogenic 

releases of Hg from industrial and 

combustion sources in the U.S. and 

MeHg in fish. In the Mercury Study, 

EPA explained that, given the current 

scientific understanding of the 

environmental fate and transport of this 

element, it was not possible to quantify 

how much of the MeHg in fish 

consumed by the U.S. population 

results from U.S. anthropogenic 

emissions, as compared to other sources 

of Hg (such as natural sources and reemissions from the global pool). 

The Mercury Study noted that those 

who regularly and frequently consume 

large amounts of fish—either marine 

species that typically have much higher 

levels of MeHg than other species, or 

freshwater fish that have been affected 

by Hg pollution—are more highly 

exposed. Because the developing fetus 

may be the most sensitive to the effects 

from MeHg, women of child-bearing age 

were the population of greatest interest. 

EPA concluded in the Mercury Study 

that approximately 7 percent of women 

of child-bearing age (i.e., between the 

ages of 15 and 44) were exposed to 

MeHg at levels exceeding the RfD. 

Finally, the Mercury Study concluded 

that piscivorous (fish-eating) birds and 

mammals were more highly exposed to 

Hg than any other known component of 

aquatic ecosystems, and that adverse 

effects of Hg on fish, birds and 

mammals include death, reduced 

reproductive success, impaired growth 

and development, and behavioral 

abnormalities. The Mercury Study also 

evaluated Hg emissions control 

technologies and the costs of such 

technologies. 

c. The NAS Methylmercury Study 

In the appropriations report for EPA’s 

fiscal 1999 funding, Congress directed 

EPA to fund the NAS to perform an 

independent study on the toxicological 

effects of MeHg and to prepare 

recommendations on the establishment 

of a scientifically appropriate MeHg 

exposure RfD. In response, EPA 

contracted with NAS, which conducted 

an 18-month study of the available data 

on the health effects of MeHg and 

reported its findings to EPA in July 

2000. 

The EPA included four charges to 

NAS: (1) Evaluate the body of evidence 

that led to EPA’s current RfD for MeHg, 

and on the basis of available human 

epidemiological and animal toxicity 

data, determine whether the critical 

study, end point of toxicity, and 

uncertainty factors used by EPA in the 

derivation of the RfD for MeHg are 

scientifically appropriate, including 


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consideration of sensitive populations; 

(2) evaluate any new data not 

considered in the Mercury Study that 

could affect the adequacy of EPA’s 

MeHg RfD for protecting human health; 

(3) consider exposures in the 

environment relevant to evaluation of 

likely human exposures (especially to 

sensitive subpopulations and especially 

from consumption of fish that contain 

MeHg), and include in the evaluation a 

focus on those elements of exposure 

relevant to the establishment of an 

appropriate RfD; and (4) identify data 

gaps and make recommendations for 

future research. 

The NAS held both public and closed 

sessions wherein they evaluated data 

and presentations from government 

agencies, trade organizations, public 

interest groups, and concerned citizens. 

The NAS also evaluated new findings 

that had emerged since the development 

of EPA’s 1995 RfD and met with the 

investigators of major ongoing 

epidemiological studies. 

The NAS Study concluded that the 

value of EPA’s 1995 RfD for MeHg, 0.1 

micrograms per kilogram (μg/kg) per 

day, was a scientifically appropriate 

level for the protection of public health. 

The NAS Study further concluded that 

data from both human and animal 

studies indicated that the developing 

nervous system was a sensitive target 

organ for low-dose MeHg exposure. The 

NAS Study indicated that there was 

evidence that exposure to MeHg in 

humans and animals can have adverse 

effects on both the developing and adult 

cardiovascular system. Some of the 

studies observed adverse cardiovascular 

effects at or below MeHg exposure 

levels associated with 

neurodevelopmental effects. The weight 

of evidence for carcinogenicity of MeHg 

was inconclusive. There was also 

evidence from animal studies that the 

immune and reproductive systems are 

sensitive targets for MeHg toxicity. 

According to the NAS Study, the 

estimates of MeHg exposures in the U.S. 

population indicated that the risk of 

adverse effects from then-current MeHg 

exposures in the majority of the 

population was low. However, the NAS 

Study concluded that individuals with 

high MeHg exposures from frequent fish 

consumption might have little or no 

margin of safety (i.e., exposures of highend consumers are close to those with 

observable adverse effects). The NAS 

Study also noted that the population at 

highest risk was the children of women 

who consumed large amounts of fish 

and seafood during pregnancy. The NAS 

Study further concluded that the impact 

on that population was likely to be 

sufficient to result in an increase in the 

number of children who struggle to keep 

up in school and might require remedial 

classes or special education. 

2. EPA’s December 2000 Appropriate 

and Necessary Finding 

On December 20, 2000, 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 section 112 and added such 

units to the list of source categories 

subject to regulation under section 

112(d). In making that finding, 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 

EPA obtained pursuant to an 

information collection request (ICR) 

under the authority of section 114 of the 

CAA. 65 FR 79826–27. EPA collected 

data on the Hg content of coal from all 

coal-fired EGUs for the calendar year 

1999 and Hg emissions stack test data 

for certain coal-fired EGUs. 65 FR 

79826. EPA also solicited data from the 

public through a February 29, 2000, 

notice (65 FR 10783). The public had an 

opportunity to provide their views on 

what the section 112(n)(1)(A) 

appropriate and necessary regulatory 

finding should be at a public meeting in 

Chicago, Illinois, on June 13, 2000 (65 

FR 18,992). 65 FR 79826. 

In the December 2000 notice, EPA 

explained that it evaluated EGUs based 

on the type of fossil fuel combusted (i.e., 

coal, oil, and natural gas). The 

December 2000 Finding focused 

primarily on Hg emissions from coalfired EGUs. Mercury was determined to 

be the HAP of greatest concern in the 

Utility Study. In evaluating Hg 

emissions from coal-fired EGUs, EPA 

stated that the quality of the Hg data 

available in 2000 was considerably 

better than the data available for the 

Utility Study because of the results of 

the 1999 ICR. The new data also 

corroborated the Hg emissions estimates 

in the study. 65 FR 79828. In the 

finding, EPA explained that Hg is highly 

toxic and persistent and that it 

bioaccumulates in the food chain; that 

Hg air emissions from all sources, 

including EGUs, deposit on the land 

where the Hg may transform into MeHg, 

which is the primary type of Hg that 

accumulates in fish tissue; and that 

eating Hg contaminated fish was the 

primary route of exposure for humans. 

65 FR 79827. The potential hazard of 

most concern was determined to be 

consumption by subsistence fish-eating 

populations and women of childbearing 

age because of the adverse effects that 

Hg poses to the developing fetus. 65 FR 

79827. Finally, EPA noted that 

approximately 7 percent of women of 

child bearing age were exposed to levels 

of MeHg that exceeded the RfD. 65 FR 

79827. 

EPA further estimated that about 60 

percent of the total Hg deposited in the 

U.S. came from anthropogenic air 

emissions originating in the U.S. and 

that EGUs contributed approximately 30 

percent of those anthropogenic air 

emissions. 65 FR 79827. Based on the 

record before the Agency at the time, 

EPA determined that there was a 

plausible link between Hg emissions 

from EGUs and MeHg in fish and that 

Hg emissions from EGUs were a threat 

to public health and the environment. 

65 FR 79827. 

In discussing the non-Hg HAP from 

coal- and oil-fired EGUs, EPA stated that 

HAP metals such as As, Cr, Ni, and Cd 

are of potential concern for carcinogenic 

effects. 65 FR 79827. EPA acknowledged 

that the risk assessments conducted for 

these HAP indicated that cancer risks 

were not high, but the Agency could not 

conclude the potential concern for 

public health was eliminated for those 

metals. 65 FR 79827. EPA further stated 

that dioxins, HCl, and HF were of 

potential concern and could be 

evaluated further during the regulatory 

development process. 65 FR 79827. EPA 

also concluded that the remaining HAP 

evaluated in the Utility Study did not 

appear to be a public health concern, 

but the Agency noted that there were 

limited data and uncertainties 

associated with this conclusion, and we 

stated that future data collection efforts 

could identify additional HAP of 

potential concern. 65 FR 79827. 

EPA also explained that, consistent 

with Congress’s direction in section 

112(n)(1)(A), we considered the 

alternative control strategies available to 

control the HAP emissions that may 

warrant control. We noted that currently 

available controls for criteria pollutants 

would also be effective at controlling 

the HAP emissions from EGUs. 65 FR 

79828. 

EPA then made nine specific 

conclusions based on the information in 

the record, some of which are 

summarized above. 65 FR 79829–30. 

Based on those conclusions, EPA found 

that it was ‘‘appropriate’’ to regulate 

HAP emissions from coal- and oil-fired 

EGUs because EGUs ‘‘are the largest 

domestic source of Hg emissions, and 

Hg in the environment presents 

significant hazards to public health and 

the environment.’’ 65 FR 79830. EPA 

noted that the NAS Study confirmed 

EPA’s own research concluding that 

‘‘mercury in the environment presents a 

significant hazard to public health.’’ 65 


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8On May 18, 2005, EPA issued the Clean Air 

Mercury Rule (CAMR). 70 FR 28606. That rule 

established standards of performance for emissions 

of mercury from new and existing coal-fired EGUs 

pursuant to CAA section 111. 

FR 79830. EPA explained that it was 

appropriate to regulate HAP emissions 

from coal- and oil-fired units because it 

had identified certain control options 

that, it anticipated, would effectively 

reduce HAP from such units. 65 FR 

79830. In discussing its findings, EPA 

also noted that uncertainties remained 

concerning the extent of the public 

health impact from HAP emissions from 

oil-fired units. 65 FR 79830. 

Once EPA determined that it was 

‘‘appropriate’’ to regulate coal- and oilfired EGUs under CAA section 112, EPA 

next concluded that it was also 

‘‘necessary’’ to regulate HAP emissions 

from such units 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 such emissions identified 

in the Utility RTC and confirmed by the 

NAS Study, and which section 112 is 

intended to address.’’ 65 FR 79830. 

For natural gas-fired EGUs, EPA 

found that regulation of HAP emissions 

‘‘is not appropriate or necessary because 

the impacts due to HAP emissions from 

such units are negligible based on the 

results of the study documented in the 

utility RTC.’’ 65 FR 79831. 

In light of the positive appropriate 

and necessary determination, EPA in 

December 2000 listed coal- and oil-fired 

EGUs on the section 112(c) source 

category list. 65 FR 79831. 

3. The 2005 Action 

On March 29, 2005, EPA issued the 

Section 112(n) Revision Rule (‘‘2005 

Action’’) that has since been vacated by 

the DC Circuit Court. In that rule, EPA 

reversed the December 2000 Finding 

and concluded that it was neither 

appropriate nor necessary to regulate 

coal- and oil-fired EGUs under section 

112 and delisted such units from the 

section 112(c) source category list. 70 

FR 15994. EPA took the position that 

the December 2000 Finding lacked 

foundation and that new information 

confirmed that it was not appropriate or 

necessary to regulate coal- and oil-fired 

EGUs under CAA section 112. 

In the final rule, EPA provided a 

detailed interpretation of section 

112(n)(1)(A), including the terms 

‘‘appropriate’’ and ‘‘necessary,’’ as those 

terms relate to the regulation of EGUs 

under section 112. In interpreting the 

statute, EPA recognized that section 

112(n)(1)(A) provided no explicit 

guidance for determining whether 

regulation of EGUs is appropriate and 

necessary. As such, EPA concluded that 

Congress’ direction on the Utility Study 

provided the only guidance about the 

substance of the appropriate and 

necessary finding. Accordingly, EPA 

extrapolated from Congress’ description 

of the Utility Study when interpreting 

the terms appropriate and necessary. 

Among other things, the Agency 

interpreted the focus on public health in 

the Utility Study as precluding EPA 

from considering environmental 

impacts. 70 FR 15998. EPA also looked 

at Congress’ focus on EGU emissions in 

the Study and took the position that 

EPA could only consider hazards to 

public health that could be traced 

directly to HAP emissions from EGUs in 

assessing whether it was appropriate to 

regulate. EPA declined to consider the 

potential adverse public health impacts 

that may occur as the result of the 

combination of EGU HAP emissions and 

HAP emissions from other sources. 70 

FR 15998. 

In making the determination as to 

whether it was appropriate to regulate, 

EPA analyzed whether the level of HAP 

emissions from EGUs remaining after 

imposition of the requirements of the 

CAA would result in a hazard to public 

health. EPA concluded that if the HAP 

emissions remaining after imposition of 

the requirements of the CAA do not 

pose a hazard to public health, then 

regulation under section 112 is not 

appropriate. EPA also maintained that 

even if it identified a hazard to public 

health, regulation may still not be 

‘‘appropriate’’ based on other relevant 

factors, such as the cost effectiveness of 

regulation under section 112. 70 FR 

15600. 

In the 2005 Action, EPA interpreted 

the term ‘‘necessary’’ to mean ‘‘that it is 

necessary to regulate EGUs under 

section 112 only if there are no other 

authorities available under the CAA that 

would, if implemented, effectively 

address the remaining HAP emissions 

from EGUs.’’ 70 FR 16001. 

Applying these interpretations, the 

Agency stated that it was neither 

appropriate nor necessary to regulate 

HAP emissions from EGUs. The Agency 

took the position that the December 

2000 appropriate finding lacked 

foundation because the finding was 

overbroad to the extent that it relied on 

environmental effects. 70 FR 16002. The 

EPA next stated that the appropriate 

determination in the December 2000 

Finding lacked foundation because EPA 

did not fully consider the Hg reductions 

that would result after imposition of the 

requirements of the CAA and that new 

information showed that the level of Hg 

emissions from EGUs remaining after 

imposition of the requirements of the 

CAA do not pose a hazard to public 

health. 70 FR 16003–4. Specifically, 

EPA pointed to the promulgation of the 

Clean Air Interstate Rule (CAIR), issued 

pursuant to CAA section 110(a)(2)(D), 

and the Clean Air Mercury Rule 

(CAMR),8 issued pursuant to section 

111, and, based on modeling, 

determined that CAIR, and 

independently CAMR, could be 

expected to reduce Hg emissions to 

levels that would not cause a hazard to 

public health. Therefore, EPA 

concluded that it was not appropriate to 

regulate EGUs under section 112. We 

note that CAMR was vacated by the D.C. 

Circuit Court in New Jersey v. EPA, and 

that CAIR was remanded to the Agency 

in North Carolina v. EPA, 531 F.3d 896, 

modified on reh’g, 550 F.3d 1176 (DC 

Cir. 2008). 

As to the necessary finding, EPA took 

the position that the December 2000 

Finding was in error because EPA did 

not, at the time, examine whether there 

were any CAA provisions other than 

section 112 that, if implemented, would 

address any identified hazards to public 

health from HAP emissions from EGUs. 

70 FR 16004. Specifically, EPA stated 

that the error existed because EPA did 

not consider CAA sections 110(a)(2)(D) 

and 111 and that, considering actions 

under these sections, hazard to public 

health from EGUs would be reduced. 70 

FR 16005. 

EPA also determined that it was not 

appropriate and necessary to regulate 

coal-fired EGUs on the basis of non-Hg 

HAP emission or oil-fired EGUs on the 

basis of Ni and non-Ni HAP. 70 FR 

16007. 

4. Litigation History 

Shortly after issuance of the December 

2000 Finding, an industry group 

challenged that finding in the DC 

Circuit Court. UARG v. EPA, 2001 WL 

936363, No. 01–1074 (DC Cir. July 26, 

2001). The DC Circuit Court dismissed 

the lawsuit holding that it did not have 

jurisdiction because 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.’’ 

(emphasis added) 

Environmental groups, States, and 

tribes challenged the 2005 Action and 

CAMR. Among other things, the 

environmental and state petitioners 

argued that EPA could not remove EGUs 


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9 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 section 111(d) for any HAP 

emitted from a particular source category, if the 

source category is regulated under section 112. 

10American 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. 

from the section 112(c) source category 

list without following the requirements 

of section 112(c)(9). 

On February 8, 2008, the DC Circuit 

Court vacated both the 2005 Action and 

CAMR. The DC Circuit Court held that 

EPA failed to comply with the 

requirements of section 112(c)(9) for 

delisting source categories. Specifically, 

the DC Circuit Court held that section 

112(c)(9) applies to the removal of ‘‘any 

source category’’ from the section 112(c) 

list, including EGUs. The DC Circuit 

Court rejected the argument that EPA 

has the inherent authority to correct its 

mistakes, finding that, by enacting 

section 112(c)(9), Congress limited 

EPA’s discretion to reverse itself and 

remove source categories from the 

section 112(c) list. The DC Circuit Court 

found that EPA’s contrary position 

would ‘‘nullify § 112(c)(9) altogether.’’ 

New Jersey, 517 F.3d at 583. The DC 

Circuit Court did not reach the merits of 

petitioners’ arguments on CAMR, but 

vacated CAMR for existing sources 

because coal-fired EGUs were listed 

sources under section 112. The DC 

Circuit Court reasoned that even under 

EPA’s own interpretation of the CAA, 

regulation of existing sources’ Hg 

emissions under section 111 was 

prohibited if those sources were a listed 

source category under section 112.9 The 

DC Circuit Court vacated and remanded 

CAMR for new sources because it 

concluded that the assumptions EPA 

made when issuing CAMR for new 

sources were no longer accurate (i.e., 

that there would be no section 112 

regulation of EGUs and that the section 

111 standards would be accompanied 

by standards for existing sources). Id. at 

583–84. Thus, CAMR and the 2005 

appropriate and necessary finding 

became null and void. 

On December 18, 2008, several 

environmental and public health 

organizations (‘‘Plaintiffs’’) 10 filed a 

complaint in the DC District Court (Civ. 

No. 1:08-cv-02198 (RMC)) alleging that 

the Agency had failed to perform a 

nondiscretionary duty under CAA 

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

promulgate final section 112(d) 

standards for HAP from coal- and oilfired EGUs by the statutorily mandated 

deadline, December 20, 2002, 2 years 

after such sources were listed under 

section 112(c). EPA settled that 

litigation. The consent decree resolving 

the case requires EPA to sign a notice of 

proposed rulemaking setting forth EPA’s 

proposed section 112(d) emission 

standards for coal- and oil-fired EGUs 

by March 16, 2011, and a notice of final 

rulemaking by November 16, 2011. 

III. Appropriate and Necessary Finding 

As required by the CAA, we 

determined in December 2000, and 

confirm that finding here, that it is 

appropriate to regulate emissions of Hg 

and other HAP from EGUs because 

manmade emissions of those pollutants 

pose hazards to public health and the 

environment, and EGUs are the largest 

or among the largest contributors of 

many of those HAP. It is necessary to do 

so for a variety of reasons, including 

that hazards to public health and the 

environment from EGUs remain after 

imposition of the requirements of the 

CAA. 

In this section, we address the 

Agency’s determination that it is 

appropriate and necessary to regulate 

coal- and oil-fired EGUs under CAA 

section 112. We first provide our 

interpretation of the critical terms in 

CAA section 112(n)(1). As shown below, 

these interpretations are wholly 

consistent with the CAA and the 

December 2000 Finding. We then 

demonstrate that the December 2000 

Finding was valid at the time it was 

made based on the information available 

to the Agency at that time. Finally, we 

explain that, although not required, we 

recently conducted additional technical 

analyses given that several years have 

passed since the December 2000 

Finding was issued. Those analyses 

include both a quantitative and 

qualitative assessment of the hazards to 

public health and a qualitative analysis 

of hazards to the environment 

associated with Hg and non-Hg HAP 

from EGUs. The analyses confirm that it 

remains appropriate and necessary 

today to regulate EGUs under CAA 

section 112. We also explain why these 

analyses and the other information 

currently before the Agency confirm 

that regulation of EGUs under section 

112 is appropriate and necessary. 

Accordingly, such units are properly 

listed pursuant to section 112(c). 

A. Regulating EGUs Under CAA Section 

112 

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

Agency to regulate EGUs under section 

112 ‘‘if the Administrator finds such 

regulation is appropriate and necessary 

after considering the results of the 

[Utility Study].’’ (emphasis added). 

Congress did not define the phrase 

‘‘appropriate and necessary’’ in section 

112(n)(1)(A). Rather, Congress expressly 

delegated to the Agency the authority to 

interpret and apply those terms. See 

Chevron U.S.A. Inc. v. Natural 

Resources Defense Council, Inc., 467 

U.S. 837, 843–44 (1984) (the Agency’s 

interpretation of statutory terms is 

entitled to considerable deference as 

long as it is a reasonable reading of the 

statute). 

Courts have interpreted the terms 

‘‘appropriate’’ and ‘‘necessary’’ in other 

provisions of the CAA and other 

statutes, and concluded that those terms 

convey upon the Agency a wide degree 

of discretion. See, e.g., National 

Association of Clean Air Act Agencies v. 

EPA, 489 F.3d 1221, 1229 (DC Cir. 2007) 

(finding ‘‘both explicit and 

extraordinarily broad’’ the 

Administrator’s authority under CAA 

section 231(a)(3) to ‘‘issue regulations 

with such modifications as he deems 

appropriate.’’) (emphasis in original); 

see also Cellular Telecommunications & 

Internet Association, et al. v. FCC, 330 

F.3d 502, 510 (DC Cir. 2003), (finding 

that ‘‘[c]ourts have frequently 

interpreted the word ‘necessary’ to 

mean less than absolutely essential, and 

have explicitly found that a measure 

may be ‘necessary’ even though 

acceptable alternatives have not been 

exhausted.’’ (quoting Natural Res. Def. 

Council v. Thomas, 838 F.2d 1224, 1236 

(DC Cir. 1998) (internal quotation marks 

omitted)). 

We evaluate the terms ‘‘appropriate’’ 

and ‘‘necessary’’ within the statutory 

context in which they appear to 

determine the meaning of the words. 

See Cellular Telecommunications, 330 

F.3d at 510 (finding that ‘‘it is crucial to 

understand the context in which the 

word [necessary] is used in order to 

comprehend its meaning.’’) (citations 

omitted). In this case, we look for 

guidance in section 112 generally, and 

focus specifically on section 112(n)(1), 

which addresses EGUs. 

1. Statutory Framework for Evaluating 

EGUs 

As explained above, Congress, 

concerned by the slow pace of EPA’s 

regulation of HAP, ‘‘altered section 112 

by eliminating much of EPA’s discretion 

in the process.’’ New Jersey, 517 F.3d at 

578 (citations omitted). We describe 

above the two-phased approach to 

standard setting. Also, relevant, 

however, is that Congress set very strict 

deadlines for listing source categories 

and issuing emission standards for such 


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11As explained above, the NAS Study studied the 

same issues Congress wanted addressed pursuant to 

section 112(n)(1)(C) and, because it was conducted 

five years after the NIEHS study, it was a more 

comprehensive study accounting for new 

information not available to NIEHS. Congress 

directed both studies and wanted EPA to consider 

the NAS Study before issuing the appropriate and 

necessary finding so we are reasonably focusing our 

discussion on the content of the later study. 

categories. See e.g., Section 112(c)(6), 

112(e)(1); New Jersey, 517 F.3d at 578 

(noting that ‘‘EPA was required to list 

and to regulate, on a prioritized 

schedule’’ all categories and 

subcategories of major and area 

sources). Thus, in substantially 

amending section 112 of the CAA in 

1990, Congress sought prompt and 

permanent reductions of HAP emissions 

from stationary sources—first through 

technology-based standards, and then 

further, as necessary, through risk-based 

standards designed to protect human 

health and the environment. 

Congress’ focus on protecting public 

health and the environment from EGU 

HAP emissions is reflected in section 

112(n)(1), titled ‘‘[e]lectric utility steam 

generating units.’’ That section directs 

EPA to evaluate HAP emissions from 

EGUs. In addition to directing EPA to 

regulate EGUs under section 112 if it 

determines that it is appropriate and 

necessary to do so, section 112(n)(1) 

requires the completion of three studies 

related to HAP emissions from EGUs. 

Those studies include: (1) The Utility 

Study pursuant to section (n)(1)(A); (2) 

the Mercury Study pursuant to section 

(n)(1)(B); and (3) the NIEHS Study (NAS 

Study) pursuant to section 

112(n)(1)(C).11

These studies are described above, in 

detail. In summary, for the Utility 

Study, Congress required EPA to 

evaluate the hazards to public health 

that are reasonably anticipated to occur 

as the result of EGU emissions following 

imposition of the requirements of the 

CAA. Congress also directed EPA to 

identify alternative control strategies for 

those HAP that may warrant regulation 

under section 112. 

The Mercury Study required by 

section 112(n)(1)(B) is both broader and 

narrower in scope, as compared to the 

Utility Study. For example, the Mercury 

Study is narrower in scope, in that it 

focuses solely on the impacts from Hg 

emissions, as opposed to all HAP. The 

Mercury Study is broader in scope, 

however, in two important respects. 

First, Congress required EPA to consider 

environmental effects in addition to 

health effects. Second, Congress 

required the Agency to consider the 

cumulative effects of Hg from all 

sources, including EGUs. In considering 

the cumulative effects of Hg, the Agency 

was not required to apportion the cause 

of any adverse effects among the various 

sources of Hg. Both the Utility and 

Mercury Studies considered the control 

technologies available to control Hg 

emissions, but only the Mercury Study 

called for the evaluation of the costs of 

such controls. Section 112(n)(1)(B). 

EPA believes that Congress directed 

the Agency to conduct the Utility Study 

so that the Agency would understand 

the hazards to public health posed by 

HAP emissions from EGUs alone, and 

consider whether any hazards that were 

identified would be addressed through 

imposition of the requirements of the 

CAA applicable to EGUs at that time. 

Congress provided EPA an additional 

year to examine the impacts of EGU 

emissions of Hg on health and the 

environment in combination with other 

sources of Hg emissions. 

The NAS Study required by section 

112(n)(1)(C), which was due at the same 

time as the Utility Study, was to focus 

on Hg only and the adverse human 

health effects associated with Hg. The 

statute directed the determination of the 

threshold level of Hg below which 

adverse effects to human health are not 

expected to occur. The statute further 

directed the determination of the 

threshold for Hg concentrations in the 

tissue of fish which may be consumed, 

including by sensitive populations, 

without adverse effects to public health. 

Here, unlike the Utility Study and the 

Mercury Study, the statute specifically 

requires an evaluation of the adverse 

human health effects of Hg on sensitive 

populations. 

The remaining critical element of 

section 112(n)(1) is the direction to EPA 

to determine whether it is appropriate 

and necessary to regulate EGUs under 

section 112, considering the results of 

the Utility Study. Although the Utility 

Study is a condition precedent to 

making the appropriate and necessary 

determination, nothing in section 

112(n)(1)(A) precludes the Agency from 

considering other information in making 

that determination. 

Taken together, we believe these 

provisions provide a framework for the 

Agency’s determination of whether to 

regulate HAP emissions from EGUs 

under section 112. Through these 

provisions, Congress sought a prompt 

review and evaluation of the hazards to 

public health and the environment 

associated with Utility HAP emissions. 

This prompt consideration of health and 

environmental impacts is consistent 

with the strict deadlines Congress 

imposed in section 112 on all other 

source categories. See infra. 

Section 112(n)(1)(B) is direct evidence 

that Congress was concerned with 

environmental effects and cumulative 

impacts of HAP emissions from EGUs 

and other sources, particularly with 

regard to the bio-accumulative HAP Hg. 

Section 112(n)(1)(C) provides further 

evidence that Congress was concerned 

with limiting HAP emissions from EGUs 

to a level that protects sensitive 

populations. We believe the scope of the 

Utility Study was limited to HAP 

emissions from EGUs and hazards to 

public health, not because Congress was 

unconcerned with adverse 

environmental effects or the cumulative 

impact of HAP emissions, but because 

the Utility Study, as required, was a 

significant undertaking in itself and 

Congress wanted the Agency to 

complete the study within 3 years. 

Thus, section 112(n)(1) reveals, among 

other things, Congress’ concern for the 

health and environmental effects of 

HAP emissions from EGUs, both alone 

and in conjunction with other sources, 

the impact of Hg emissions from EGUs, 

and the availability of controls to 

address HAP emissions from EGUs. 

Finally, significantly, nowhere in 

section 112(n)(1) does Congress require 

the consideration of costs in assessing 

health and environmental impacts. The 

only reference to costs is in section 

112(n)(1)(B) and that reference required 

the Agency to consider the costs of 

emission reduction controls for Hg. 

2. Interpretation of Key Terms 

Section 112(n)(1)(A) itself provides no 

clear standard to govern EPA’s analysis 

and determination of whether it is 

‘‘appropriate and necessary’’ to regulate 

utilities under section 112. The statute 

simply requires EPA to regulate EGUs 

under section 112 if it determines that 

such regulation is appropriate and 

necessary, after considering the results 

of the Utility Study. As noted above, 

courts have interpreted the terms 

appropriate and necessary as conveying 

considerable discretion to the Agency in 

determining what is appropriate and 

necessary in a given context. 

As explained more fully below, in this 

context, we interpret the statute to 

require the Agency to find it 

appropriate to regulate EGUs under 

CAA section 112 if the Agency 

determines that the emissions of one or 

more HAP emitted from EGUs pose an 

identified or potential hazard to public 

health or the environment at the time 

the finding is made. If the Agency finds 

that it is appropriate to regulate, it must 

find it necessary to regulate EGUs under 

section 112 if the identified or potential 

hazards to public health or the 

environment will not be adequately 

addressed by the imposition of the 

requirements of the CAA. Moreover, it 


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may be necessary to regulate utilities 

under section 112 for a number of other 

reasons, including, for example, that 

section 112 standards will assure 

permanent reductions in EGU HAP 

emissions, which cannot be assured 

based on other requirements of the 

CAA. 

The following subsections describe in 

detail our interpretation of the key 

statutory terms. We also explain below 

how the interpretations set forth in this 

notice are wholly consistent with the 

December 2000 Finding. Further, to 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. See 

National Cable & Telecommunications 

Ass’n, et al. v. Brand X Internet 

Services, et al., 545 U.S. 967, 981 (2005) 

(Discussing the deference provided to 

an Agency when 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); see also 

Department of Treasury v. FLRA, 494 

U.S. 922, 933 (1990) (Finding that EPA’s 

judgment should only be overturned if 

it is deemed unreasonable, not merely 

because other, reasonable alternatives 

exist). 

a. ‘‘Appropriate’’ To Regulate EGUs 

We interpret section 112(n)(1)(A) to 

require the Agency to find regulation of 

EGUs under section 112 appropriate if 

we determine that HAP emissions from 

EGUs pose a hazard to public health or 

the environment at the time the finding 

is made. The hazard to public health or 

the environment may be the result of 

HAP emissions from EGUs alone or the 

result of HAP emissions from EGUs in 

conjunction with HAP emissions from 

other sources. In addition, EPA must 

find that it is appropriate to regulate 

EGUs if it determines that any single 

HAP emitted by utilities poses a hazard 

to public health or the environment. We 

further interpret the term ‘‘appropriate’’ 

to not allow for the consideration of 

costs in assessing whether HAP 

emissions from EGUs pose a hazard to 

public health or the environment. 

Finally, we may conclude that it is 

appropriate, in part, to regulate EGUs if 

we determine that there are controls 

available to address HAP emissions 

from EGUs. 

i. Basis for Interpretation 

As stated above, the appropriate 

finding may be based on hazards to 

public health or the environment. 

Although we believe that Congress’ 

primary concern, as expressed in 

section 112(n)(1)(A) and 112(n)(1)(C), 

related to hazards to public health, the 

inclusion of environmental effects in 

section 112(n)(1)(B) indicates Congress’ 

interest in protecting the environment 

from HAP emissions from EGUs as well. 

Moreover, the term ‘‘appropriate’’ is 

extremely broad and nothing in the 

statute suggests that the Agency should 

ignore adverse environmental effects in 

determining whether to regulate EGUs 

under section 112. Further, had 

Congress intended to prohibit EPA from 

considering adverse environmental 

effects in the ‘‘appropriate’’ finding, it 

would have stated so expressly. Absent 

clear direction to the contrary, and 

considering the purpose of the CAA (see 

e.g., CAA section 101, 112(c)(9)(B)(ii)), it 

is reasonable to consider environmental 

effects in evaluating the hazards posed 

by HAP emitted from EGUs when 

assessing whether regulation of EGUs 

under section 112 is appropriate. 

Accordingly, we interpret the statute to 

authorize the Agency to base the 

appropriate finding on either hazards to 

public health or the environment. 

We also maintain that the Agency 

should base its ‘‘appropriate’’ evaluation 

on the hazards to public health or the 

environment that exist at the time the 

determination is made, not after 

considering the imposition of the other 

requirements of the CAA. The Agency 

evaluates whether imposition of the 

requirements of the CAA will 

adequately address any identified 

hazards only in the context of the 

necessary finding. Thus, in assessing 

whether regulation of EGUs is 

appropriate under section 112, we 

evaluate the current hazards posed by 

such units, as opposed to projecting 

what such hazards may look like after 

imposition of the requirements of the 

CAA. 

We further interpret the CAA as 

allowing the Agency to base the 

appropriate finding on hazards to public 

health or the environment that result 

from HAP emissions from EGUs alone 

or hazards to public health and the 

environment that result from HAP 

emissions from EGUs in conjunction 

with HAP emissions from other sources. 

Section 112(n)(1) does not focus 

exclusively on EGU-only HAP 

emissions. 

As explained above, section 

112(n)(1)(B) and (C) require either 

expressly or implicitly the consideration 

of Hg emissions from all sources, not 

just EGUs. Section 112(n)(1)(B) is of 

note because that provision does not 

require the Agency to determine the 

hazard posed by Hg from EGUs alone. 

Rather, Congress required EPA to 

evaluate the health and environmental 

effects of Hg emissions from ‘‘electric 

utility steam generating units, 

municipal waste combustion units, and 

other sources, including area sources.’’ 

Section 112(n)(1)(C) is also relevant 

because it requires a human healthbased assessment of the hazards posed 

by Hg without regard to the origin of the 

Hg. Congress could have directed an 

evaluation of the human health risk 

attributable to EGUs alone, but it did 

not. Congress also did not require such 

an assessment be conducted in the NAS 

Study. 

In addition, Congress directed the 

Agency in section 112(n)(1)(A) to 

regulate EGUs under section 112 if the 

results of the Utility Study caused the 

Agency to conclude that regulation was 

appropriate and necessary. Section 

112(n)(1)(A) is not written in a manner 

to preclude consideration of other 

information when determining whether 

it is appropriate and necessary to 

regulate EGUs under section 112, and 

that includes consideration of all 

hazards, both health and environmental, 

posed by HAP emitted by EGUs. See 

United States v. United Technologies 

Corp., 985 F.2d 1148, 1158 (2d Cir. 

1993) (‘‘based upon’’ does not mean 

‘‘solely’’). 

Finally, focusing on HAP emissions 

from EGUs alone when making the 

appropriate finding ignores 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 that 

harm. For this reason, we believe we 

may consider the hazards to public 

health and the environment posed by 

HAP emissions from EGUs alone or in 

conjunction with HAP emissions from 

other sources. 

Furthermore, the appropriate finding 

may be based on a finding that any 

single HAP emitted from EGUs poses a 

hazard to public health or the 

environment. Nothing in 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 

section 112. Interpreting the statute in 

this manner would preclude the Agency 

from addressing under section 112 

identified or potential hazards to public 

health or the environment associated 

with HAP emissions from EGUs unless 


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12As explained below, EPA reasonably 

concluded in December 2000 that it was 

appropriate and necessary to regulate EGUs under 

section 112 based on the record before the Agency 

at that time. 

we found a hazard existed with respect 

to each and every HAP emitted. 

Indeed, Congress’ focus in section 

112(n)(1)(B) and (C) on Hg indicates 

Congress’ awareness that Hg was a 

problem and supports the position that 

EPA could find it appropriate to 

regulate EGUs based on the adverse 

health and environmental effects of a 

single HAP. Furthermore, the statute 

does not directly or expressly authorize 

the Agency to regulate only those HAP 

for which a hazard finding has been 

made. In fact, the statute requires the 

Agency to regulate EGUs under section 

112 if the Agency finds regulation under 

section 112 is appropriate and 

necessary, and regulation under section 

112 for major sources requires MACT 

standards for all HAP emitted from the 

source category. See, e.g., National Lime 

Ass’n v. EPA, 233 F.3d 625, 633 (DC Cir. 

2000). For these reasons, we conclude 

we must find it appropriate to regulate 

EGUs under section 112 if we determine 

that the emissions of any single HAP 

from such units pose a hazard to public 

health or the environment. 

We also maintain that the better 

reading of the term ‘‘appropriate’’ is that 

it does not allow for the consideration 

of costs in assessing whether hazards to 

public health or the environment are 

reasonably anticipated to occur based 

on EGU emissions. Had Congress 

intended to require the Agency to 

consider costs in assessing hazards to 

public health or the environment 

associated with EGU HAP emissions, it 

would have so stated. 

This interpretation is consistent with 

the overall structure of the CAA. 

Congress did not authorize the 

consideration of costs in listing any 

source categories for regulation under 

section 112. In addition, Congress did 

not permit the consideration of costs in 

evaluating whether a source category 

could be delisted pursuant to the 

provisions of section 112(c)(9). 

Under section 112(n)(1)(A), EPA is 

evaluating whether to regulate HAP 

emissions from EGUs at all. It is 

reasonable to conclude that costs may 

not be considered in determining 

whether to regulate EGUs under section 

112 when hazards to public health and 

the environment are at issue. 

Finally, consistent with sections 

112(n)(1)(A) and 112(n)(1)(B), we 

conclude that we may base the 

appropriate finding on the availability 

of controls to address HAP emissions 

from EGUs. 

ii. The December 2000 Finding 

The Agency’s interpretation of the 

term ‘‘appropriate,’’ as set forth above, is 

wholly consistent with the Agency’s 

appropriate finding in December 2000. 

As noted above, in 2000, we concluded 

that it was appropriate to regulate EGUs 

under section 112 because Hg in the 

environment posed a hazard to public 

health and the environment. The 

Agency also concluded it was 

appropriate because of uncertainties 

associated with the hazards posed by 

other HAP emitted from EGUs. 65 FR 

79827. Finally, the EPA concluded that 

it was appropriate because of the 

availability of controls to reduce HAP 

emissions from EGUs. In making the 

finding as it related to Hg, the Agency 

considered the hazards posed by Hg in 

the environment and the contribution of 

EGUs to that hazard. In addition, EPA 

did not consider costs when making the 

appropriate determination. Further, the 

appropriate finding evaluated the 

hazards at the time, as opposed to the 

hazards remaining after imposition of 

the requirements of the CAA. EPA 

evaluated whether the other 

requirements of the CAA would 

adequately address the hazards in the 

necessary prong only.12

iii. The 2005 Action 

As noted above, in 2005, EPA revised 

its December 2000 Finding and stated 

that the appropriate finding: (1) Could 

not be based on adverse environmental 

effects; (2) must be made considering 

only HAP emissions from EGUs; (3) 

must be made after consideration of the 

imposition of the requirements of the 

CAA; and (4) must consider other 

factors (e.g., costs) even if we determine 

that HAP emissions from EGUs pose a 

hazard to public health. This proposal 

differs from the 2005 Action, and we 

address each of these differences below. 

First, we change the position taken in 

2005 that the appropriate finding could 

not be based on environmental effects 

alone. In 2005, we did not properly 

consider all of the provisions of section 

112(n)(1). The Agency should not 

interpret the CAA to limit the Agency’s 

discretion to protect the environment 

absent clear direction to that effect. In 

essence, the Agency’s interpretation in 

2005 would have required the Agency to 

ignore a catastrophic environmental 

harm (e.g., the extinction of a species) 

if the Agency could not also identify a 

hazard to public health. EPA took this 

position regarding environmental effects 

in 2005 even though in that same rule 

it correctly interpreted section 

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

consider information beyond the Utility 

Study in making the appropriate and 

necessary determination. 70 FR 15,997– 

99. The 2005 interpretation that EPA 

cannot consider environmental effects 

in evaluating whether it is appropriate 

to regulate EGUs under section 112 was 

neither reasonable nor consistent with 

the goals of the CAA, and, therefore, we 

are rejecting that interpretation and 

returning to the approach taken in 2000 

that allowed consideration of 

environmental effects. 

Second, for all of the reasons stated 

above, we are revisiting the 2005 

interpretation that required the Agency 

to consider HAP emissions from EGUs 

without considering the cumulative 

impacts of all sources of HAP emissions. 

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

prohibits consideration of HAP 

emissions from EGUs in conjunction 

with HAP emissions from other sources 

of HAP. We believe it is more 

reasonable to interpret the statute to 

authorize the Agency to consider the 

cumulative effects of HAP that are 

emitted from EGUs and other sources. 

This interpretation allows the Agency to 

evaluate more fully whether HAP 

emissions from EGUs pose a hazard to 

public health or the environment 

consistent with the manner in which the 

public and the environment are exposed 

to HAP emissions. 

Third, we are revising the 2005 

interpretation that required the Agency 

to evaluate the hazards to public health 

after imposition of the requirements of 

the CAA. We conclude today that in 

2005 the Agency improperly conflated 

the appropriate finding and the 

necessary finding by requiring 

consideration of the ameliorative effects 

of other CAA requirements in both 

prongs of the appropriate and necessary 

finding. We believe the Agency must 

find it appropriate to regulate EGUs 

under section 112 if we determine that 

HAP emitted by EGUs pose a hazard to 

public health or the environment at the 

time the finding is made. The issue of 

how and whether those hazards are 

reduced after imposition of the 

requirements of the CAA is an issue for 

the necessary prong of the finding. 

Finally, we are rejecting the 2005 

interpretation that authorizes the 

Agency to consider other factors (e.g., 

cost), even if the Agency determines 

that HAP emitted by EGUs pose a 

hazard to public health (or the 

environment). We reject the 

consideration of costs for all the reasons 

set forth above. Furthermore, the better 

reading of section 112(n)(1)(A) is that 

the Agency should find it appropriate to 

regulate EGUs under section 112 if a 

hazard to public health or the 

environment is identified. We think it 


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unreasonable to decline to make the 

appropriate finding based on any factor, 

cost or otherwise, if we determine that 

EGUs pose a hazard to public health or 

the environment. 

b. ‘‘Necessary’’ To Regulate EGUs 

Once the Agency has determined that 

it is appropriate to regulate EGUs under 

section 112, the Agency must then 

determine whether it is necessary to 

regulate EGUs under section 112. As 

stated above, we have considerable 

discretion to determine whether 

regulation of EGUs under section 112 is 

necessary. The DC Circuit Court 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.’’ Cellular Telecommunication, 330 

F.3d at 510. 

If the Agency concludes that it is 

appropriate to regulate EGUs, we 

believe it is necessary to regulate HAP 

emissions from EGUs if we determine 

that the imposition of the requirements 

of the CAA will not sufficiently address 

the identified hazards to public health 

or the environment posed by HAP that 

are emitted from EGUs. We maintain 

that we must find it necessary based on 

such a finding even if regulation under 

section 112 will not fully resolve the 

identified hazard to public health or the 

environment. 

We may also determine it is necessary 

to regulate under section 112 if we are 

uncertain whether the imposition of the 

other requirements of the CAA will 

sufficiently address the identified 

hazards. We may find it necessary to 

regulate EGUs under section 112 even if 

we were to conclude, based on 

reasonable estimations of emissions 

reductions, that the imposition of the 

other requirements of the CAA would, 

or might, significantly reduce the 

identified hazard, because the only way 

to guarantee that such reductions will 

occur at all EGUs and be maintained is 

through a section 112(d) standard that 

directly regulates HAP emissions from 

utilities. Finally, we may also find it 

necessary to regulate EGUs under 

section 112 to further the policy goal of 

supporting international efforts to 

reduce HAP emissions, including Hg. 

i. Necessary After Imposition of the 

Requirements of the CAA 

In the Utility Study, Congress directed 

the Agency to evaluate the hazards to 

public health posed by HAP emissions 

from EGUs remaining after imposition 

of the requirements of the CAA, and it 

gave EPA 3 years to complete that 

Study. We interpret the necessary 

requirement first in the context of the 

phrase ‘‘after imposition of the 

requirements of [the CAA].’’ Section 

112(n)(1)(A). 

Congress did not define the phrase 

‘‘after imposition of the requirements of 

the Act.’’ The plain meaning of the term 

‘‘requirement’’ is something that is 

necessary, or obligatory. See, e.g., 

Random House Webster’s Unabridged 

Dictionary, Deluxe Edition, 2001. Given 

that Congress intended the Utility Study 

to be completed by 1993, it is reasonable 

to interpret the phrase ‘‘after imposition 

of the requirements of the Act’’, as 

requiring the Agency to consider only 

those requirements that Congress 

directly imposed on EGUs through the 

CAA as amended in 1990 and for which 

EPA could reasonably predict HAP 

emission reductions at the time of the 

Utility Study. The most substantial 

requirement in this regard was the 

newly enacted ARP. 

The purpose of the ARP was to reduce 

the adverse effects of acid deposition 

(more commonly known as ‘‘acid rain’’), 

by limiting the allowable emissions of 

SO2 and NOX primarily from EGUs. In 

enacting the Acid Rain provisions of the 

Act, Congress explained that the 

problem of acid deposition was one of 

‘‘national and international 

significance,’’ that technologies to 

reduce the precursors to acid deposition 

were ‘‘economically feasible,’’ and that 

‘‘control measures to reduce precursor 

emissions from steam-electric 

generating units should be initiated 

without delay.’’ CAA section 401(a). The 

ARP also includes a series of very 

specific emission reduction 

requirements. For example, the goals of 

the program include a reduction of 

annual SO2 emissions by 10 million 

tons below 1980 levels and a reduction 

of NOX emissions by two million tons 

from 1980 levels. 

Moreover, the ARP achieved the 

required reductions by allocating 

allowances to emit SO2 at reduced 

levels to each affected EGU. Sources 

were prohibited from emitting more SO2

than the number of allowances held. To 

comply with these requirements, source 

owners or operators could elect to 

install controls, such as scrubbers, 

switch to lower sulfur fuels at their 

facilities, or purchase allowances from 

other EGUs that had reduced their 

emissions beyond what they were 

required by the ARP to achieve. It was 

known at the time of enactment of the 

1990 Amendments that the controls 

used to reduce emissions of SO2, 

primarily scrubbers, had the co-benefit 

of controlling HAP emissions, including 

Hg emissions. The ARP also included 

requirements for limiting NOX

emissions from EGUs. Considering the 

Acid Rain requirements under section 

112(n)(1) is reasonable because the Act 

contained very specific emission 

reduction requirements for EGUs, and a 

tight compliance time-frame. In fact, all 

of the regulations implementing the SO2

allowance trading portion of the ARP 

were completed by the mid-1990’s. 

The other significant requirement that 

Congress imposed in the 1990 

Amendments was to revise the NSPS for 

NOX emissions from EGUs by 1994. 

CAA 407(c). However, unlike the SO2

allowance requirements of the ARP, 

Congress did not specify the amount of 

required reductions, but instead 

directed EPA to consider the 

improvements in methods for reducing 

NOX when establishing standards for 

new sources. Thus, in the 1990 

Amendments, Congress sought NOX

reductions from EGUs both through the 

ARP and a revision of the NSPS 

applicable to new sources. The Agency 

issued these NSPS in 1997. 

There are other requirements of Title 

I of the Act that could affect EGUs, and 

they include the National Ambient Air 

Quality Standards (NAAQS). Congress 

did not impose these provisions directly 

on EGUs, however. Instead, EPA is 

responsible for developing the NAAQS, 

and states are primarily responsible for 

assuring attainment and maintenance of 

the NAAQS. For example, EPA stated in 

the Utility Study that implementation of 

the 1997 NAAQS for ozone and PM may 

lead to reductions in Hg emissions, but 

those potential reductions could not be 

sufficiently quantified because states 

have the ultimate responsibility for 

implementing the NAAQS. See Utility 

Study, pages ES–25, 1–3, 2–32, 3–14, 

and 6–15. States use a broad 

combination of measures (mobile and 

stationary) to obtain the reductions 

needed to meet the NAAQS. These 

decisions are unique to each state, as 

each state must identify and assess the 

sources contributing to nonattainment 

and determine how best to meet the 

NAAQS. EPA cannot predict with any 

certainty precisely how states will 

ensure that the reductions needed to 

meet the NAAQS will be realized. 

Moreover, there are additional 

uncertainties even were a state to 

impose requirements on EGUs through 

a State Implementation Plan (SIP), 

because each EGU may choose to meet 

the required reductions in a different 

manner, which could result in more or 

less HAP emission reductions. 

Accordingly, we do not believe it would 

have been appropriate to include such 

potential emissions reductions in 

determining whether it is necessary to 


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13 In our analysis, we included state requirements 

and citizen and state settlements associated with 

criteria pollutants because those requirements may 

have a basis under the CAA. We did not, however, 

conduct an analysis to determine whether that was 

the case in each instance. As such, we believe there 

may be instances where we should not have 

considered certain state rules or state and citizen 

suit settlements in our analysis, because those 

requirements are based solely in state law and are 

not required by Federal law. 

14Although, as explained below, our technical 

analysis examined impacts projected out to 2016, 

this is a very conservative approach. Given that two 

decades have passed since the enactment of the 

1990 CAA Amendments, we believe we can find it 

appropriate and necessary to regulate EGUs under 

section 112, if we determine EGU HAP emissions 

pose a hazard to public health and the environment 

today without considering future HAP emission 

reductions. Congress could not have contemplated 

in 1990 that EPA would have failed in 2011 to have 

regulated HAP emissions from EGUs where hazards 

to public health and the environment remain. 

15Federal Implementation Plans To Reduce 

Interstate Transport of Fine Particulate Matter and 

Ozone. Proposed Rule. August 2, 2010. 75 FR 

45,210. 

regulate HAP emissions from EGUs 

under section 112. 

Further, it is reasonable to interpret 

the phrase ‘‘after imposition of the 

requirements of the Act’’, as only 

requiring consideration of those 

requirements that Congress directly 

imposed on EGUs through the CAA as 

amended in 1990 and for which EPA 

could reasonably predict emission 

reductions at the time of the Utility 

Study. To interpret the phrase otherwise 

would require the Agency to look ahead 

two to three decades to forecast what 

possible requirements might be 

developed and applied to EGUs under 

some requirement of the CAA at some 

point in the future. 

Indeed, such an interpretation would 

be inconsistent with the structure and 

purpose of section 112. As noted above, 

Congress gave EPA until 1993 to issue 

the Utility Study and expected the 

appropriate and necessary finding 

would follow shortly thereafter. 

Congress also required EPA to address 

HAP emissions rapidly from all source 

categories. See CAA 112(e), supra. It is 

reasonable to presume that Congress 

intended EPA to evaluate the need for 

EGU HAP controls in light of the 

requirements imposed upon the 

industry via the new 1990 requirements. 

Obviously the central requirement that 

was new and applied to EGUs was the 

ARP which would be implemented 

rapidly following passage of the 1990 

amendments to the Act. 

Although the above represents a 

reasonable interpretation of what 

Congress contemplated the Utility Study 

would examine with regard to 

‘‘imposition of the requirements of the 

Act,’’ we recognize that we have 

discretion to look beyond the Utility 

Study in determining whether it is 

necessary to regulate EGUs under 

section 112. Given that several years 

have passed since the December 2000 

Finding, we conducted additional 

analysis. Although not required, we 

conducted this analysis to demonstrate 

that even considering a broad array of 

diverse requirements, it remains 

appropriate and necessary to regulate 

EGUs under section 112. 

Specifically, we examined a host of 

requirements, which in our view, far 

surpass anything Congress could have 

contemplated in 1990 we would 

consider as part of our ‘‘necessary’’ 

determination. For example, our 

analysis includes certain state rules 

regulating criteria pollutants, Federal 

consent decrees, and settlement 

agreements for criteria pollutants 

resolving state-initiated and citizeninitiated enforcement actions.13 We did 

not include in our analysis any stateonly HAP requirements or voluntary 

actions to reduce HAP emissions, as 

those are not requirements of the CAA, 

and are not required by Federal law to 

remain applicable.14

ii. Necessary Interpretation 

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. 

Furthermore, we believe it is 

necessary to regulate if we have 

identified a hazard to public health or 

the environment that will not be 

addressed by imposition of the 

requirements of the CAA even if 

regulation of EGUs under section 112 

will not fully resolve the identified 

hazard. We conclude that this is 

particularly true for bio-accumulative 

HAP such as Hg because EPA can only 

address such emissions from domestic 

sources and mitigation of identified 

risks associated with such HAP is a 

reasonable goal. See section 112(c)(6). 

EPA cannot decline to find it 

‘‘necessary’’ to regulate EGUs under 

section 112 when it has identified a 

hazard to public health or the 

environment, simply because that 

regulation will not wholly resolve the 

identified hazards. The statute does not 

require the Agency to conclude that 

identified hazards will be fully resolved 

before it may find regulation under 

section 112 necessary. See 

Massachusetts v. EPA, 549 U.S. 497, 525 

(2007). 

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 final or 

are still subject to judicial review (i.e., 

the Transport Rule 15). If such rules are 

either not finalized or upheld by the 

Courts, the level of risk would 

potentially increase. 

We also may find it necessary to 

regulate EGUs under section 112 even if 

we conclude, based on reasonable 

estimations of emissions reductions, 

that the imposition of the other 

requirements of the CAA will 

significantly reduce the identified 

hazard. We maintain this is reasonable 

because the only way to guarantee that 

the necessary reductions in HAP 

emissions will occur at all EGUs and be 

maintained is through a section 112(d) 

standard that directly regulates HAP 

emissions from EGUs. This is true 

because sources could discontinue use 

of controls for criteria pollutants that 

achieve HAP reductions as a co-benefit 

if new control technologies or practices 

are identified that reduce the relevant 

criteria pollutants but do not also 

reduce HAP. For example, scrubbers are 

often used to reduce SO2 emissions and 

those scrubbers also reduce emissions of 

several HAP. However, if an EGU with 

a scrubber started complying with its 

SO2 standard by switching to low sulfur 

coal or purchasing allowances, the HAP 


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16 In the rule reconsidering the 2005 Action, we 

further clarified that in evaluating the effectiveness 

of other CAA authorities we considered whether 

those other authorities could be implemented in a 

cost-effective and administratively effective 

manner. 71 FR 33,391. We need not address this in 

detail because we conclude that the threshold 

conclusion that the Agency must look for 

alternative CAA authorities that could be used to 

regulate HAP emissions from EGUs before finding 

it necessary is invalid. 

17 In theory, an NSPS is legally permissible for 

new stationary sources of HAP. 

emission reduction co-benefits 

associated with the scrubber would no 

longer be realized. In addition, at the 

time Congress passed the 1990 CAA 

amendments, there were many older 

EGUs that had few or no controls in 

place. Over 20 years later, there remain 

a significant number of older EGUs that 

are only minimally controlled. The 

Agency may find it necessary to regulate 

EGUs under section 112 to ensure that 

these minimally controlled EGUs and 

those units that switch to other criteria 

pollutant compliance options, thereby 

no longer achieving the same HAP 

reductions, are subject to HAP 

regulation, such that the estimated 

reductions in the identified hazards are 

realized. 

iii. December 2000 Finding 

Our interpretation of the necessary 

finding is reasonable and consistent 

with the December 2000 Finding. In that 

finding, EPA determined that the 

imposition of the requirements of the 

CAA would not address the serious 

public health and environmental 

hazards resulting from EGU HAP 

emissions. We also stated that section 

112 is the authority to address hazards 

from HAP emissions. Because we 

determined that the imposition of the 

requirements of the CAA would not 

address the identified hazards, we 

correctly concluded it was necessary to 

regulate under section 112. Although 

the Agency did not expressly interpret 

the term necessary in the December 

2000 Finding, under the interpretation 

set forth above, the Agency must find it 

necessary if we conclude that the 

imposition of the other requirements of 

the CAA will not address the identified 

hazards. Because EPA reached that 

conclusion, the Agency correctly 

determined that it was necessary to 

regulate EGU HAP emissions and did 

not need to base the 2000 necessary 

finding on any of the other bases set 

forth above. 

iv. The 2005 Action 

We stated in 2005 that ‘‘it is necessary 

to regulate EGUs under section 112 only 

if there are no other authorities under 

the CAA that, if implemented, would 

effectively address the remaining HAP 

emissions from EGUs.’’ 70 FR 16,001.16

In essence, we stated in 2005 that 

section 112(n)(1)(A) requires the Agency 

to scour the CAA to determine whether 

there is a direct or indirect manner in 

which EPA could regulate HAP 

emissions from EGUs, notwithstanding 

the fact that Congress expressly 

provided section 112 for the purpose of 

regulating HAP emissions from 

stationary sources. This interpretation is 

not reasonable. 

Congress enacted section 112 for the 

express purpose of regulating HAP 

emissions. It is not reasonable to 

interpret section 112(n)(1)(A) to require 

the Agency to find another provision of 

the CAA to address identified hazards to 

public health or the environment. This 

is particularly the case where the 

Agency would not have certainty that 

such alternative legal theory would 

withstand judicial scrutiny because 

section 112 is the authority expressly 

provided to regulate HAP emissions and 

no other provision provides express 

authority to regulate HAP emissions 

from existing stationary sources.17

Although anyone can challenge the 

substance of a section 112 standard, no 

one can challenge that regulation of 

HAP emissions under section 112 is 

proper for validly listed source 

categories. 

Furthermore, section 112(n)(1)(A) 

states explicitly that the Agency shall 

regulate EGUs ‘‘under this section’’ if the 

Agency determines it is ‘‘appropriate 

and necessary after considering the 

results of the (Utility Study).’’ We 

reiterate that the only precondition to 

regulating EGUs is consideration of the 

results of the Utility Study. We believe 

it is unreasonable to argue that Congress 

directed the Agency as part of the 

Utility Study to scour the CAA for 

alternative legal authorities for 

regulating HAP emissions, either 

directly or indirectly. Indeed, the 

Agency did not interpret the 

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

conduct the study in that manner, as 

evidenced by the Utility Study itself. 

Absent that interpretation, we think it is 

unreasonable to conclude that the 

Agency must undertake such an effort to 

make the necessary finding because 

Congress authorized the Agency to base 

the ‘‘appropriate and necessary’’ finding 

on the Utility Study alone. 

For all the reasons above, we believe 

it is appropriate to regulate EGUs under 

section 112 if the Agency determines 

that HAP emissions from such units 

pose a hazard to public health or the 

environment at the time of the finding, 

and it is necessary to regulate EGUs 

under section 112 if the imposition of 

the other requirements of the CAA will 

not adequately address the identified 

hazards to public health or the 

environment, or there are other 

compelling reasons making it necessary 

to regulate HAP emissions from EGUs 

under section 112. 

c. Hazards to Public Health or the 

Environment 

Section 112(n)(1)(A) neither defines 

the phrase ‘‘hazards to public health,’’ 

nor sets forth parameters for EPA to use 

in determining whether HAP emissions 

from EGUs pose a hazard to public 

health. The phrase is also not defined 

elsewhere in the CAA. EPA, therefore, 

has broad discretion, using its technical 

and scientific expertise, to determine 

whether HAP emissions from EGUs 

pose a hazard to public health. 

In evaluating hazards to the 

environment, however, Congress did 

provide some direction. Specifically, it 

defined the term ‘‘adverse 

environmental effects’’ in section 

112(a)(7), and as explained further 

below, we evaluate hazards to the 

environment consistent with that 

definition. 

Because Congress did not define 

‘‘hazard to public health’’ the Agency 

must use its scientific and technical 

expertise to determine what constitutes 

a hazard to public health in the context 

of EGU HAP emissions. The Agency 

considers various factors in evaluating 

hazards to public health, including, but 

not limited to, the nature and severity 

of the health effects associated with 

exposure to HAP emissions; the degree 

of confidence in our knowledge of those 

health effects; the size and 

characteristics of the populations 

affected by exposures to HAP emissions; 

the magnitude and breadth of the 

exposures and risks posed by HAP 

emissions from a particular source 

category, including how those 

exposures contribute to risk in 

populations with additional exposures 

to HAP from other sources; and the 

proportion of the population exposed 

above benchmark levels of concern (e.g., 

cancer risks greater than 1 in a million 

or non-cancer effects with a hazard 

quotient (HQ) greater than 1). See 

Section III(D) below for a discussion of 

the Agency’s technical conclusions as to 

whether a hazard to public health or the 

environment exists based on the facts at 

issue here. 

Although Congress provided no 

definition of hazard to public health, 

section 112(c)(9)(B) is instructive. In 

that section, Congress set forth a test for 

removing source categories from the 

section 112(c) source category list. That 


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18As explained above, we discuss the NAS Study 

here because it addressed the same issues as the 

NIEHS study, and it is the more recent study. 

test is relevant because it reflects 

Congress’ view as to the level of health 

effects associated with HAP emissions 

that Congress thought warranted 

continued regulation under section 112. 

The Agency finds section 112(c)(9)(B)(i) 

particularly instructive because it 

provides a numerical threshold for HAP 

that may cause cancer. Specifically, that 

provision provides that EPA may delete 

a source category from the section 

112(c) list if no source in the category 

emits such HAP 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 such HAP emissions. 

Thus, the Agency reads section 

112(c)(9)(B)(i) to reflect Congress’ view 

of the acceptable hazard to public health 

for HAP that may cause cancer. 

Congress defined the phrase ‘‘adverse 

environmental effect’’ in section 

112(a)(7) to mean ‘‘any significant and 

widespread adverse effect, which may 

reasonably be anticipated, to wildlife, 

aquatic life, or other natural resources, 

including adverse impacts on 

populations of endangered or threatened 

species or significant degradation of 

environmental quality over broad areas.’’ 

Section 112(n)(1)(B) required EPA to 

examine the environmental effects of Hg 

emissions. Because Congress defined 

the term ‘‘adverse environmental effect’’ 

in section 112(a)(7), we believe that 

such definition should guide our 

assessment of whether hazards to the 

environment posed by Utility HAP 

emissions exist. As with hazards to 

public health, however, the Agency 

must use its discretion to determine 

whether the adverse environmental 

effects identified warrant a finding that 

it is appropriate to regulate HAP 

emissions from EGUs based on those 

effects. In evaluating the environmental 

effects, we have stated that we may 

consider various aspects of pollutant 

exposure, including: ‘‘[t]oxicity effects 

from acute and chronic exposures’’ 

expected from the source category (as 

measured or modeled); ‘‘persistence in 

the environment;’’ ‘‘local and long-range 

transport;’’ and ‘‘tendency for biomagnification with toxic effects 

manifest at higher trophic levels.’’ 67 FR 

44,718 (July 3, 2002). 

In interpreting the term itself, we 

believe the broad language in section 

112(a)(7) referring to ‘‘any’’ enumerated 

effect ‘‘which may be reasonably 

anticipated’’ evinces Congressional 

intent to not restrict the scope of that 

term to only certain specific impacts. 62 

FR 36440 (July 7, 1997); 63 FR 14094 

(March 24, 1998). Further, the section 

112(a)(7) reference to ‘‘any’’ enumerated 

effect in the singular clearly 

contemplates impacts of limited 

geographic scope, suggesting that the 

‘‘widespread’’ criterion does not present 

a particularly difficult threshold to 

cross. Id. This is further supported by 

the fact that section 112(a)(7) provides 

as an example of adverse environmental 

effects, adverse impacts on populations 

of endangered or threatened species, 

which as reflective of their imperiled 

status are especially likely to exist in 

limited geographic areas. EPA believes 

that the ‘‘widespread’’ criterion would 

not exclude impacts that might occur in 

only one region of the country. Id. 

d. Regulating EGUs ‘‘Under This 

Section’’ 

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., section 

112(b)). The last sentence requires the 

Agency to regulate under this section 

(i.e., 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., section 112(n)(1)(A)). The 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 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. 

Furthermore, the DC 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 section 112. New Jersey, 

517 F.3d at 583. Indeed, the DC 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, EPA is required to establish 

emission standards for EGUs consistent 

with the requirements set forth in 

section 112(d), as described above. 

EPA requests comment on section 

III.A. 

B. The December 2000 Appropriate and 

Necessary Finding was Reasonable 

EPA reasonably determined in 

December 2000 that it was appropriate 

and necessary to regulate HAP 

emissions from EGUs under CAA 

section 112. In making that finding, EPA 

considered all of the information that 

Congress had identified as most salient, 

including the Utility Study, the Mercury 

Study, and the information in the NAS 

Study.18 EPA even conducted an ICR 

soliciting emissions information on Hg, 

which was the HAP of most concern to 

Congress, as evidenced by section 

112(n)(1). EPA collaborated further with 

a number of other entities and Federal 

Agencies, including the U.S. 

Department of Energy (DOE). EPA 

carefully evaluated all of this 

information, much of which had been 

the subject of extensive peer review, and 

reasonably determined, on the record 

before the Agency at the time, that it 

was appropriate and necessary to 

regulate EGUs under section 112. 

1. EPA Appropriately Based the Finding 

on the Information Required by Section 

112(n)(1) and Reasonably Made the 

Finding Once It Had Completed the 

Required Studies 

In making the appropriate and 

necessary finding in 2000, EPA 

considered all of the relevant 

information in the three Studies 

required by section 112(n)(1) and the 

NAS Study. 65 FR 79826–27. The 

Utility, Mercury, and NAS Studies 

together consisted of thousands of pages 

of information and technical analyses. 

All of these studies were peer reviewed 

prior to issuance. In fact, the Mercury 

Study was reviewed by over 65 


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19Mercury Study Report to Congress, Vol. I, Pg. 

6, December 1997. 

20This direction is consistent with section 

112(n)(1). As noted above, the Utility Study was the 

only condition precedent to making the appropriate 

and necessary finding. The NIEHS study called for 

by 112(n)(1)(C) was to have been completed at the 

same time as the Utility Study. As such, Congress 

had originally contemplated that both the Utility 

and NIEHS studies would be available at the time 

the Agency made the appropriate and necessary 

finding. The NAS study considered the same 

information required in the NIEHS study so the 

Congressional direction in the fiscal year 1999 

appropriation is consistent with the original 

drafting of section 112(n)(1). 

21http://yosemite.epa.gov/sab/SABPRODUCT.

nsf/FF2962529C7B158A852571AE00648B72/$File/

ehc9801.pdf. 

22The central conclusions underlying the 2000 

finding are described in detail in the 2000 notice, 

at 65 FR 79829–30. 

independent scientists.19 The NAS 

Study contains a thorough technical 

discussion summarizing the state of the 

science at the time regarding the human 

health effects of MeHg. 

In addition to conducting the studies 

that Congress required, EPA collected 

relevant information on Hg emissions 

and available control technologies. 

Specifically, pursuant to a CAA section 

114 ICR, EPA collected data on the Hg 

content in coal from all coal-fired EGUs 

for calendar year 1999. Through the 

1999 ICR, EPA also obtained stack test 

data for certain coal-fired EGUs to verify 

Hg emissions estimates for the EGU 

source category. 65 FR 79826. EPA 

further solicited data from the public 

through a February 29, 2000, notice (65 

FR 10,783), and provided the public an 

opportunity to provide its views on 

what the regulatory finding should be at 

a public meeting. 65 FR 79826 (citing 65 

FR 18992). Finally, EPA undertook an 

evaluation of the Hg control 

performance of various emission control 

technologies that were either currently 

in use on EGUs or that could be applied 

to such units for Hg control. EPA 

conducted this evaluation with other 

parties, including the DOE. 65 FR 

79826. EPA also evaluated other 

emission control approaches that would 

reduce EGU HAP emissions. Id. at 

79827–29. 

Although Congress did not provide a 

deadline by which EPA must issue the 

appropriate and necessary finding, the 

deadlines Congress provided for 

completion of the required studies 

signal that Congress wanted EPA to 

make the appropriate and necessary 

finding shortly after completion of the 

studies. Congress required that the 

Utility Study and NIEHS Study be 

submitted by November 15, 1993, and 

the Mercury Study by November 15, 

1994. We reasonably conclude based on 

the timing of the studies that Congress 

wanted the Agency to evaluate the 

hazards to public health and the 

environment associated with HAP 

emissions from EGUs as quickly as 

possible and take steps to regulate such 

units under section 112 if hazards were 

identified. 

Congress later provided a direct signal 

as to the timing of the appropriate and 

necessary finding in the committee 

report associated with EPA’s fiscal year 

1999 appropriations bill, which directed 

the Agency to fund the NAS Study. In 

that report, Congress indicated that it 

did not want the Agency to make the 

appropriate and necessary finding for 

Hg until the NAS study was completed. 

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

282 (1998).20

After considering all of the 

information that Congress considered 

most relevant, including the NAS Study 

that was issued in June 2000, EPA 

determined that it was appropriate and 

necessary to regulate EGUs under 

section 112 and listed such units for 

regulation on December 20, 2000. As 

explained below, the Agency acted 

reasonably in issuing the finding at that 

time because of the identified and 

potential hazards to public health and 

the environment associated with HAP 

emissions from utilities, which the 

Agency concluded would not be 

addressed through imposition of the 

requirements of the CAA. It would not 

have been reasonable to delay the 

finding to collect additional information 

given the considerable delay in 

completion of the required studies and 

the hazards to public health and the 

environment identified as of December 

2000. 

2. EPA Reasonably Concluded in 

December 2000 That It Was Appropriate 

To Regulate EGUs Under Section 112 

The December 2000 Finding that it 

was appropriate to regulate EGUs under 

section 112 focused largely on hazards 

to public health and the environment 

associated with Hg emissions. EPA 

reasonably focused on this pollutant 

given that Hg is a persistent, 

bioaccumulative pollutant that causes 

serious neurotoxic effects. Indeed, 

Congress specifically identified this 

pollutant as one of concern and required 

two separate studies to be conducted 

regarding Hg emissions. See Section 

112(n)(1)(B) and (C). The information 

before the Agency in 2000 concerning 

Hg was both well-documented and 

scientifically supported. Based on all of 

the information before it, the Agency 

concluded that Hg emissions from EGUs 

posed a hazard to public health. It was 

also reasonable for the Agency to find 

regulation of EGUs appropriate given 

the uncertainties regarding the extent of 

public health impacts posed by non-Hg 

HAP. Finally, it was reasonable to base 

the appropriate finding on the 

availability of controls for HAP 

emissions from EGUs. 

a. The Agency Reasonably Concluded It 

Was Appropriate To Regulate EGUs 

Based on Hg Emissions 

By 2000, the Agency had amassed ‘‘a 

truly vast amount of data’’ on Hg. See 

October 10, 1997, letter (page 2) 

submitting Science Advisory Board 

(SAB) peer review recommendations on 

draft Mercury Study.21 Those data 

confirmed the hazards to public health 

and the environment associated with 

Hg. The data also helped EPA identify 

the populations of most concern with 

regard to MeHg exposure. See CAA 

112(n)(1)(C). Finally, the data showed 

that EGUs were the largest unregulated 

source of Hg emissions in the U.S., and 

that EGUs were projected to increase 

their Hg emissions to approximately 60 

tons in 2010. 

We discuss below the central pieces 

of data and information concerning Hg 

that formed the basis of our conclusion 

that Hg posed a threat to public health 

and the environment.22 These 

conclusions were largely drawn from 

the Mercury Study, which, as noted 

above, was reviewed by over 65 peer 

reviewers. Upon reviewing the draft 

report, the SAB noted that the ‘‘major 

findings of the draft report are well 

supported by the scientific evidence.’’ In 

direct response to the SAB review, the 

Agency conducted additional, 

comprehensive analyses addressing 

SAB’s recommendations. Thus, in 2000, 

the Agency had before it a 

comprehensive record concerning Hg 

emissions, including the best available 

science on Hg at the time. 

i. Key Facts: Impacts of Hg on Health 

and the Environment 

EPA first concluded that Hg from 

EGUs was the HAP of greatest concern. 

Id. at 79827. The Agency explained that 

‘‘mercury is highly toxic, persistent, and 

bioaccumulates in food chains;’’ that Hg 

deposited on land and water can then be 

metabolized by microorganisms into 

MeHg; that MeHg is ‘‘a highly toxic, 

more bioavailable, form that 

biomagnifies in the aquatic food chain 

(e.g., fish);’’ and that nearly all of the Hg 

in fish is MeHg. 65 FR 79827. The 

Agency further noted that fish 

consumption is the primary route of 

exposure for humans and wildlife, and, 

by July 2000, 40 states and America 

Samoa had issued fish advisories for Hg, 


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23EPA estimated that U.S. anthropogenic air 

emissions of mercury accounted for 60 percent of 

total deposition in the U.S. and U.S. EGUs 

accounted for 30 percent of that deposited mercury. 

Thirty percent of the 60 percent contribution is 

equal to approximately 18 percent of the total 

deposition. See Utility Study, page 7–28. 

24The NESHAP for Portland cement did not 

include a standard for Hg when initially 

promulgated. In National Lime Ass’n v. EPA, the DC 

Circuit Court held that section 112(d) contains a 

clear statutory directive to regulate all HAP emitted 

from a listed source category. 233 F.3d 624, 634 (DC 

Cir. 2000). EPA recently issued final section 112 

standards for Portland cement manufacturers, 

including a standard for Hg emissions from such 

sources. 

with 13 of those states issuing 

advisories for all the water bodies in 

their state. 65 FR 79827. Finally, the 

Agency explained that neurotoxicity is 

the health effect of greatest concern with 

MeHg exposure, and that exposures to 

MeHg can have serious toxicological 

effects on wildlife as well as humans. 

EPA recognized that increased Hg 

deposition would lead to increased 

levels of MeHg in fish and such 

‘‘increased levels in fish [would] * * * 

lead to toxicity in fish-eating birds and 

mammals, including humans.’’ 65 FR 

79830. EPA agreed with the NAS that 

‘‘the long term goal needs to be the 

reduction in the concentrations of 

methylmercury in fish’’ and concluded 

that reducing Hg emissions from EGUs 

was ‘‘an important step toward 

achieving that goal.’’ 65 FR 79830. 

The Agency then identified the most 

affected populations. Specifically, the 

Agency concluded that women of 

childbearing age are the population of 

greatest concern because the developing 

fetus is the most sensitive to the effects 

of MeHg. 65 FR 79827. EPA estimated 

that at that time, 7 percent of women of 

childbearing age (or about 4,000,000 

women) in the continental U.S. were 

exposed to MeHg at levels that exceeded 

the RfD and that about 1 percent of 

women of childbearing age (or about 

580,000 women) had MeHg exposures 3 

to 4 times the RfD. 65 FR 79827. 

The NAS Study affirmed EPA’s 

assessment of the toxicity of MeHg and 

that the RfD EPA had developed for 

MeHg was valid. 65 FR 79827. The 

Agency acknowledged that there was 

uncertainty with risk at exposure above 

the RfD, but indicated that risk 

increased with increased exposure. 65 

FR 79827. In addition to focusing on 

women of childbearing age and 

developing fetuses, EPA stated a 

particular concern for subsistence fisheating populations due to their regular 

and frequent consumption of relatively 

large quantities of fish. 65 FR 79830. 

As for environmental effects, the 

Agency observed adverse effects to 

avian species and wildlife in laboratory 

studies at levels corresponding to fish 

tissue MeHg concentrations that are 

exceeded by a significant percentage of 

fish sampled in lake surveys. 65 FR 

79830. The Agency explained that 

wildlife consume fish from a more 

localized geographic area than humans, 

which can result in elevated levels of Hg 

in certain fish eating species. Those 

species include, for example, the 

kingfisher and some endangered 

species, such as the Florida panther. 65 

FR 79830. 

In summary, in the December 2000 

Finding, EPA identified Hg in the 

environment as a hazard to public 

health and the environment, determined 

that a significant segment of the most 

sensitive members of the population 

were exposed to MeHg at levels 

exceeding the RfD, and confirmed that 

the RfD was valid. 

ii. EGU Emissions of Hg 

In the 2000 finding, the Agency 

estimated that about 60 percent of the 

total Hg deposited in the U.S. came from 

U.S. anthropogenic air emission 

sources. 65 FR 79827. The Agency 

stated that the remainder of the Hg 

deposited in the U.S. was from natural 

emission sources, reemissions of 

historic global anthropogenic Hg 

releases, and non-domestic 

anthropogenic sources of Hg. 65 FR 

79827. EPA identified coal combustion 

and waste incineration as the source 

categories likely to bear the greatest 

responsibility for direct anthropogenic 

Hg deposition in the continental U.S. 65 

FR 79827. EPA further explained that 

EGUs are the largest unregulated 

domestic source of Hg emissions, 

accounting for approximately 30 percent 

of the current anthropogenic air 

emissions from domestic sources. 65 FR 

79827. These numbers, taken together, 

reveal that EGUs accounted for 

approximately 18 percent of the total Hg 

deposition in the U.S on an annual 

basis, considering all U.S. 

anthropogenic sources, natural emission 

sources, reemissions of historic global 

anthropogenic Hg releases, and nondomestic anthropogenic sources of Hg.23

In 2000, the Agency also found a 

plausible link between domestic 

anthropogenic Hg emissions and MeHg 

in fish. 65 FR 79829. The Agency 

explained that although that link could 

not be estimated quantitatively at the 

time, the facts before the Agency were 

sufficient for it to conclude that EGU Hg 

emissions posed a hazard to public 

health. Id. at 79830. Those facts 

included, for example, the link between 

coal consumption and Hg emissions, 

EGUs being the largest domestic source 

of Hg, and certain segments of the 

population being at risk for adverse 

health effects due to consumption of 

contaminated fish. Id. 

iii. EPA’s Conclusions Regarding Hg 

Based on the foregoing and all of the 

information set forth in the December 

20, 2000, notice, the Agency found that 

Hg emissions from EGUs posed a hazard 

to public health and the environment. In 

making this finding, the Agency focused 

on the significant adverse health effects 

associated with MeHg and the persons 

most adversely impacted by Hg. The 

populations most affected were women 

of childbearing years and their 

developing fetuses and subsistence 

fishers. The Agency viewed the adverse 

health effects and environmental effects 

described above in conjunction with the 

then current Hg emissions information 

provided by EGUs in response to the 

1999 ICR. Based on that information, 

EPA concluded that EGUs accounted for 

approximately 30 percent of the U.S. 

anthropogenic emissions of Hg, which 

translated into about 18 percent of the 

total Hg deposition in the U.S. at that 

time. EPA also knew that Hg from EGUs 

comprised an undetermined amount of 

the reemissions of Hg. See Mercury 

Study, Volume 3, page 2–3. 

At the time of the December 2000 

Finding, the Agency had issued section 

112 or 129 standards for several of the 

other source categories that were 

significant Hg emitters, and the Agency 

was required by the CAA to establish 

section 112 or 129 standards for the 

other significant Hg emitters. See 

Standards for Large Municipal Waste 

Combustors, 40 CFR part 60, subpart Ea 

(NSPS), 56 FR 5507 (February 11, 1991), 

as amended, and 40 CFR part 60, 

subpart Eb (Emissions Guidelines), 60 

FR 65419 (December 19, 1995), as 

amended; Standards for Medical Waste 

Incinerators, 40 CFR part 60, subpart Ec 

(NSPS), 62 FR 48382 (September 15, 

1997), as amended, and 40 CFR part 60, 

subpart Ce (Emission Guidelines), 62 FR 

48379 (September 15, 1997); Standards 

for Hazardous Waste Combustors, 40 

CFR part 63, subpart EEE, 64 FR 53038 

(September 30, 1999); Standards for 

Small Municipal Waste Combustors, 40 

CFR part 60, subpart AAAA (NSPS), 65 

FR 76355 (December 6, 2000), and 40 

CFR part 60, subpart BBBB (Emissions 

Guidelines), 65 FR 76384 (December 6, 

2000); and standard for Portland cement 

manufacturers (40 CFR part 63, subpart 

LLL, 64 FR 31925 (June 14, 1999)).24

Most of these categories emitted far less 

Hg than EGUs at the time of the finding. 

Thus, at the time EPA made the 

December 2000 Finding, the record 


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25Consistent with section 112(n)(1), none of the 

studies addressed the amount of MeHg in fish 

attributable solely to EGUs. Instead, in the Utility 

and Mercury Studies, EPA discussed the significant 

contribution EGUs made to Hg deposition and that 

Hg deposition was problematic from a health and 

environmental standpoint. EPA submitted both the 

Utility Study and the Mercury Study to Congress by 

1998. Aware of these studies, Congress, when 

directing the additional NAS Study, still did not 

require EPA to determine the amount of MeHg in 

fish due solely to EGUs. In light of this fact and the 

broad discretion Congress gave EPA to determine 

whether it was appropriate or necessary to regulate 

EGUs under section 112, EPA acted reasonably in 

2000 by not delaying its finding several years to 

conduct an analysis of the portion of MeHg in fish 

due solely to EGUs. 

reflected that Hg posed hazards to 

public health and the environment, that 

EGUs were the single largest 

unregulated domestic source of Hg 

emissions, and that HAP emissions from 

EGUs would remain unregulated absent 

listing under section 112. EPA 

reasonably found at the time that 

reducing Hg emissions from EGUs 

would further the goal of mitigating the 

hazards to public health and the 

environment posed by Hg. 

EPA also reasonably predicted that 

incremental reductions in Hg emissions, 

including from EGUs, would lead to 

incremental reductions in the MeHg 

concentration in fish tissue, and that 

such reductions would, in turn, reduce 

the risk to public health and the 

environment. 65 FR 79830. The Mercury 

Study recognized that Hg is a metal that 

remains in the environment 

permanently and can circulate 

continuously through various 

environmental media. Although EPA 

was aware that reductions of Hg from 

anthropogenic sources may not lead to 

immediate reductions in fish tissue 

levels, such reductions would 

nonetheless serve the long-term goal of 

reducing the mobilization of Hg to the 

atmosphere and thus reduce MeHg 

concentrations in fish. 

EPA, therefore, reasonably 

determined based on the facts that 

existed at the time that regulation of 

EGUs was appropriate in order to 

reduce the hazards to public health and 

the environment associated with the Hg 

emissions from EGUs. EPA expressly 

acknowledged that there were 

uncertainties concerning the extent of 

the risk due to Hg emissions from EGUs, 

because the Agency had not quantified 

the amount of MeHg in fish that was 

directly attributable to EGUs compared 

to other sources of MeHg. 65 FR 79827. 

That EPA did not quantify in 2000 the 

amount of MeHg in fish due to EGUs 

did not preclude EPA from making an 

‘‘appropriate’’ finding. Nowhere in 

section 112(n)(1) or in its direction 

concerning the NAS Study did Congress 

require EPA to quantify the amount of 

MeHg in fish tissue that was directly 

attributable to EGUs.25 Moreover, EPA 

did not have sufficient confidence in its 

modeling tools at the time to draw 

conclusions about the contribution of 

specific source types to fish MeHg 

concentrations in specific geographic 

areas or nationally. These uncertainties 

are well described in the Utility, 

Mercury, and NAS Studies. 

In any event, in light of the breadth 

of the scientific evidence before the 

Agency and the conclusions the Agency 

reached, it would not have been 

reasonable to delay the finding to 

develop an analytical tool to apportion 

the Hg in fish. The Hg problem at the 

time was well documented, and the fact 

that EGUs represented such a significant 

portion of the Hg deposition in the U.S. 

was ample evidence that it was 

appropriate to regulate emissions from 

EGUs—the single largest unregulated 

domestic source of Hg emissions. 65 FR 

79827. 

Finally, the Agency had already 

delayed in completing the section 

112(n)(1) studies. Additional delay 

would have been unreasonable because 

of the persistence of Hg in the 

environment and its tendency to 

bioaccumulate up the food chain, both 

aspects of Hg in the environment that 

make it critical to limit additional 

releases to the environment as quickly 

as possible. In addition, delay would 

have been unreasonable because EPA 

estimated at that time that about 7 

percent of women of child-bearing age, 

one of the most at-risk populations, was 

exposed to Hg at levels exceeding the 

RfD, and EPA knew that as the level of 

exposure above the RfD increased, the 

level of risk and the extent and severity 

of adverse effects increased. Thus, EPA 

reasonably made the appropriate and 

necessary determination in 2000 to 

ensure that the largest unregulated 

domestic source of Hg would be 

required to install controls, thereby 

achieving an incremental reduction in 

the risk associated with a persistent, 

bioaccumulative HAP. 

b. The Appropriate Finding for Non-Hg 

HAP Was Reasonable 

The December 2000 Finding was also 

reasonable as it pertained to the non-Hg 

HAP emitted from EGUs. The Agency 

found it was appropriate to regulate 

EGUs based on the potential human 

health concerns from non-Hg HAP, 

particularly Ni from oil-fired EGUs, and 

the uncertainties regarding the public 

health impact of emissions of such HAP. 

65 FR 79830. Based on the information 

in the Utility Study, EPA could not 

conclude based on the available 

information that the non-Hg HAP posed 

no hazards to public health. 

Specifically, the Agency noted that 

several non-Hg HAP metals, including 

As, Cr, Ni, and Cd, were of potential 

concern for carcinogenic effects. 65 FR 

79827. EPA acknowledged that the risks 

did not appear high, but it stated that 

the risks were not sufficiently low to 

disregard the metals as a potential 

concern for public health. 65 FR 79827; 

see Utility Study, Table 5–4, page 5–9 

(finding cancer risks from oil-fired EGUs 

alone for Ni exceeded 1 in a million). 

The Agency also indicated that dioxins, 

HCl, and HF were of potential concern 

and might be evaluated further. 65 FR 

79827. 

EPA did not view the risks associated 

with non-Hg HAP in a vacuum. Rather, 

EPA considered the threat to public 

health, including uncertainties, 

associated with both Hg and non-Hg 

HAP emissions from EGUs in 

determining whether it was appropriate 

to regulate such units under section 112. 

Finally, even looking solely at non-Hg 

HAP, EPA’s conclusions support 

regulation of EGUs under section 112. 

Although Congress provided no metric 

for the hazard to public health 

determination, section 112(c)(9) is 

instructive. Specifically, in that section, 

Congress set forth a test for removing 

source categories from the section 112(c) 

source category list. That test is relevant 

because it reflects Congress’ view as to 

the level of health effects associated 

with HAP emissions that Congress 

thought warranted regulation under 

section 112. If a source category failed 

to meet that test, it would remain 

subject to the requirements of CAA 

section 112. Thus, CAA section 

112(c)(9) can be read to reflect Congress’ 

view of what adverse public health 

effects from HAP emissions are 

acceptable and thus do not warrant 

regulation under CAA section 112. 

For carcinogens, which are at issue 

here, section 112(c)(9)(B)(i) provides 

that EPA may delete a source category 

from the section 112(c) list if no source 

in the category (or group of sources in 

the case of area sources) emits such 

HAP in quantities that 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). Thus, section 

112(c)(9)(B)(i) prohibits the Agency 

from delisting a major source category 

from the section 112(c) list if any single 

source within that category emits cancer 

causing HAP at levels that may cause a 


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lifetime cancer risk greater than one in 

one million to the most exposed 

individual. The Utility Study 

demonstrated that there were EGUs 

whose emissions resulted in a cancer 

risk greater than one in one million. 

Accordingly, it was reasonable to 

conclude at the time that non-Hg HAP 

emissions were of sufficient concern 

from a health perspective to warrant 

regulation. 

3. EPA Reasonably Based the 

Appropriate Determination in Part on 

the Availability of Controls for HAP 

Emissions From EGUs 

In addition to determining that it was 

appropriate to regulate because of the 

known and potential hazards to public 

health and the environment, EPA also 

concluded that it was appropriate to 

regulate HAP emissions from EGUs 

because EPA had identified a number of 

control options that would effectively 

reduce HAP emissions from EGUs. 65 

FR 79828–30. EPA discussed the 

various controls available to reduce 

HAP emissions from EGUs in the 

December 2000 Finding. The approach 

of section 112, as amended in 1990, is 

based on the premise that, to the extent 

there are controls available to reduce 

HAP emissions, sources should be 

required to use them. Thus, it was 

reasonable to base the appropriate 

finding in part on the conclusion that 

controls currently available were 

expected to reduce HAP emissions from 

EGUs. 

4. EPA Reasonably Concluded It Was 

Necessary To Regulate EGUs 

In 2000, EPA found it was necessary 

to regulate HAP emissions from EGUs 

under section 112 because the 

imposition of the other requirements of 

the CAA would not address the serious 

public health and environmental 

hazards arising from such emissions. 65 

FR 79830. EPA also noted that Congress 

enacted section 112 specifically to 

address HAP emissions from stationary 

sources, and it was thus reasonable to 

regulate HAP emissions from EGUs 

under that section given the hazards to 

public health and the environment 

posed by such emissions. Id. 

In Table 1 of the December 20, 2000 

notice, EPA set forth its projections of 

HAP emissions for 2010. In assessing 

those projections in 2000, EPA 

considered the data that it had obtained 

as the result of the 1999 ICR. 65 FR 

79828. It also considered projected 

changes in the population of units, fuel 

consumption, and control device 

configuration. Id. EPA considered 

control device configurations in making 

the 2010 projections, in an effort to 

account for the reductions attributable 

to the imposition of other requirements 

of the CAA. 

Specifically, in estimating the 

projected 2010 HAP emissions from 

EGUs, EPA accounted for the HAP 

reductions that would occur as the 

result of the controls required to comply 

with the ARP. Congress added the ARP 

in CAA Title IV, as part of the 1990 

amendments, and that program is 

primarily directed at EGUs. EPA, 

therefore, considered the HAP 

reductions projected to occur as the 

result of control configurations needed 

to meet the Acid Rain requirements of 

the CAA. See, e.g., Utility Study, ES–2. 

As shown in Table 1 of the December 

20, 2000 notice, EPA estimated that the 

level of all HAP emitted by coal-fired 

EGUs would increase by 2010. 65 FR 

79828 (Table 1). For Hg, EPA estimated 

that EGUs emitted 46 tons of Hg in 1990 

and 43 tons of Hg in 1999, and it 

projected that EGUs would emit 

approximately 60 tons of Hg in 2010. 65 

FR 79827–828. EPA also estimated an 

overall increase in non-Hg HAP 

emissions from coal-fired EGUs. Given 

these estimates and projections, which 

were based on the best information 

available at the time, EPA reasonably 

concluded that the identified and 

potential hazards associated with HAP 

from coal-fired EGUs would not be 

addressed through imposition of the 

other requirements of the CAA. 

For oil-fired EGUs, EPA projected a 

decline in overall HAP emissions. The 

decline was primarily due to projected 

retirements and fuel switching from oil 

to natural gas. EPA could not conclude 

based on the information available at 

the time that the facilities posing the 

cancer risks, due primarily to Ni 

emissions, would retire or change fuels. 

As a result of these uncertainties and 

the uncertainties as to the extent of the 

public health impact from oil-fired 

units, EPA found that it was necessary 

to regulate such units under section 112. 

5. The 2005 Action: EPA Erred in the 

2005 Action by Concluding That the 

December 2000 Finding Lacked 

Foundation 

In 2005, the Agency asserted that the 

December 2000 Finding lacked 

foundation for two reasons. First, the 

Agency stated that the 2000 appropriate 

finding was overbroad to the extent it 

relied on adverse environmental effects. 

Second, the Agency stated that the 2000 

appropriate finding lacked foundation 

because EPA did not fully consider the 

Hg emissions remaining after imposition 

of the requirements of the CAA. For the 

reasons provided below, we reject these 

assertions as unfounded. As 

demonstrated above, EPA’s 2000 

appropriate and necessary finding was 

sound and fully supported by the record 

before the Agency in 2000. 

a. Consideration of Environmental 

Effects in the Appropriate Finding 

EPA reasonably examined the adverse 

environmental impacts associated with 

Hg in making the December 2000 

Finding. In 2005, EPA changed its 

interpretation of the broad term 

‘‘appropriate’’ to restrict the 

consideration of environmental effects 

only to situations where the Agency had 

determined that a hazard to public 

health exists as a result of EGU HAP 

emissions. As such, EPA stated in 2005 

that the December 2000 Finding lacked 

foundation to the extent it was based on 

environmental effects. 

As explained above in Section III.A, 

EPA’s 2005 change in how it interpreted 

the term ‘‘appropriate’’ lacks merit. 

Congress gave EPA broad discretion to 

determine whether it was appropriate to 

regulate EGUs under section 112. On the 

one hand, EPA recognized that broad 

discretion in 2005, but on the other 

hand, it sought to limit that discretion 

by only allowing environmental impacts 

to be considered if a hazard to public 

health was found. The 2005 

interpretation was based on the flawed 

notion that the Agency should only 

consider health effects because the 

Utility Study only required 

consideration of hazards to public 

health. But, as noted above, Congress 

specifically directed EPA in section 

112(n)(1)(B) to consider the 

environmental effects associated with 

Hg emissions from EGUs. It was entirely 

reasonable, therefore, for EPA to 

consider such effects in making its 

appropriate finding in 2000. 

Furthermore, even under the Agency’s 

flawed 2005 interpretation, which 

allowed consideration of environmental 

effects only where a hazard to public 

health exists, EPA properly considered 

environmental effects in 2000 because 

we, in fact, found a hazard to public 

health based on the record at that time. 

b. Scope of ‘‘Appropriate’’ Finding 

EPA interprets the ‘‘appropriate’’ 

finding to require an evaluation of the 

hazards to public health and the 

environment at the time of the finding. 

This interpretation is consistent with 

the approach taken in 2000. By contrast, 

in the 2005 ‘‘appropriate’’ analysis, EPA 

considered the hazards to public health 

that were reasonably anticipated to 

occur ‘‘after imposition of the 

requirements of the Act.’’ In short, EPA 

infused the ‘‘after imposition of the 

requirements of the Act’’ inquiry into 


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both the appropriate and necessary 

prongs. 

As explained in Section III.A, this 

interpretation improperly conflates the 

‘‘appropriate’’ and ‘‘necessary’’ analysis. 

Accordingly, any assertion that EPA’s 

2000 appropriate finding is flawed 

because the Agency failed to consider 

the other requirements of the CAA 

should be rejected. 

Even considering the Agency’s flawed 

2005 interpretation of the term 

‘‘appropriate,’’ there is nothing in the 

record to suggest that the Agency erred 

in 2000 with regard to assessing Hg 

emissions. As explained above, in 2000, 

EPA reasonably considered those 

requirements of the CAA that directly 

pertained to EGUs (i.e., the ARP in Title 

IV of the Act). 

In addition, in 2000, EPA recognized 

that EGUs may be subject to 

requirements pursuant to SIP developed 

in response to NAAQS. In fact, EPA had 

projected a potential 11 tpy reduction in 

EGU Hg emissions as the result of the 

ozone and PM NAAQS. Utility Study, p. 

1–3. EPA explained in the Utility Study, 

however, why it did not account for 

such reductions in its 2010 emission 

projections. 

First, EPA explained that some of the 

Hg reductions associated with the PM 

and ozone NAAQS would be realized 

through the implementation of the ARP, 

and, thus, had already been accounted 

for in its 2010 projections. See Utility 

Study, page 1–3. Thus, to consider the 

projected reductions from the NAAQS 

would have potentially led to double 

counting of the estimated HAP 

reductions. Second, the states, not EPA, 

are primarily responsible for 

implementation of the NAAQS. EPA 

could not have reasonably assumed that 

the estimated Hg reductions from EGUs 

would occur because it could not 

forecast the prospective regulatory 

actions of the states and the impact that 

those actions would have on HAP 

emissions. In short, there was no 

guarantee that states would regulate 

EGUs to achieve the reductions 

necessary to meet the NAAQS in such 

a way that would achieve Hg 

reductions, and EPA reasonably did not 

consider such possible reductions in its 

2000 analysis. 

Furthermore, at the time of the Utility 

Study, no areas had been designated as 

nonattainment with the 1997 revised 

PM NAAQS. See Utility Study, page 2– 

32. Even had all areas been designated 

at the time of the Utility Study, we still 

would not have known how the states 

would have elected to obtain the 

required reductions to meet the 

NAAQS. We also would not have had 

information as to how the sources 

would actually implement the 

requirements in any SIP, and as noted 

above, the degree of HAP co-benefit 

reductions varies depending on the 

control approach used. Even had we 

considered the potential 11 tpy of Hg 

reductions estimated to occur as a result 

of implementing the 1997 NAAQS, the 

projected level of Hg emissions from 

EGUs in 2010 would have been 49 tpy 

(60 ¥ 11 = 49), which is still 6 tpy 

greater than the 43 tpy that the Agency 

concluded in 2000 caused a hazard to 

public health and the environment. 

Thus, even if the NAAQS had been 

included in the 2010 projections, the 

Agency would still have found that the 

identified hazards would not be 

resolved through imposition of the 

requirements of the CAA and would 

have concluded it was necessary to 

regulate EGUs under section 112. 

EPA also asserted in 2005 that it 

failed to account for Hg reductions 

associated with the 1997 Utility NSPS 

in assessing whether it was appropriate 

to regulate in 2000. In the Utility Study, 

EPA noted that EGUs would be 

implementing the same controls for 

NOX and SO2 to meet the requirements 

of both Title I and Title IV. EPA 

accounted for the ARP in its 2010 

projections. In addition, in the Utility 

Study, EPA determined that HAP 

emissions from EGUs would increase in 

2010 based on estimated increases in 

coal use, which was primarily projected 

to occur at new units. Utility Study, 

pages 2–26 to 2–31. Because EPA was 

unable to determine the size and 

location of the new units at the time of 

the Utility Study, the Agency reasonably 

allocated the increased fuel 

consumption to existing units 

(excluding the coal-fired units that were 

projected to retire between 1990 and 

2010). All or a substantial majority of 

existing units already had some type of 

PM control and many units had 

scrubbers. To the extent this approach 

of assigning increased fuel consumption 

to existing controlled units led to an 

overestimation of remaining HAP 

emissions, we do not believe the 

overestimation was significant. EPA’s 

approach to projecting emissions in 

2010 was entirely reasonable given the 

data and information available to the 

Agency at the time. See Utility Study, 

page 6–15. 

Finally, EPA asserted in 2005 that it 

failed to account for the Hg reductions 

associated with the NOX SIP call. Like 

the NAAQS, states are primarily 

responsible for developing regulations 

to meet the NOX SIP call. EPA could not 

have reasonably assumed that the 

estimated Hg reductions from EGUs 

would occur because it could not 

forecast the prospective regulatory 

actions of the states. In addition, in 

2005, EPA neither identified the 

reductions that would occur as the 

result of the NOX SIP call, nor explained 

how those reductions would have 

changed EPA’s 2000 appropriate 

finding. 

EPA solicits comment on section III.B. 

C. EPA Must Regulate EGUs Under 

Section 112 Because EGUs Were 

Properly Listed Under CAA Section 

112(c)(1) and may not be Delisted 

Because They do not Meet the Delisting 

Criteria in CAA Section 112(c)(9) 

As shown above, in 2000, EPA 

reasonably determined, based on the 

record before it at the time, that it was 

appropriate and necessary to regulate 

EGUs under CAA section 112. Once that 

finding was made, EPA properly listed 

EGUs pursuant to section 112(c), and 

EGUs remain a listed source category. 

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

As the DC Circuit Court held in New 

Jersey, EPA cannot ignore the delisting 

criteria in section 112(c)(9). CAA 

section 112(c)(9)(B) authorizes the 

Agency to delist any source category if 

the Agency determines that: (1) For HAP 

that may cause cancer in humans, no 

source in the category emits such HAP 

in quantities that ‘‘may cause a lifetime 

risk of cancer greater than one in one 

million’’ to the most exposed individual; 

section 112(c)(9)(B)(i); and (2) for HAP 

that may result human health effects 

other than cancer or adverse 

environmental effects, ‘‘emissions from 

no source in the category or subcategory 

concerned*** exceeds 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.’’ Section 112(c)(9)(B)(ii). 

Here, we have a validly listed source 

category. EPA could not have met the 

delisting criteria in 2000 or 2005, and it 

still cannot meet those criteria today. 

The information in the Utility Study 

shows that HAP emissions from a 

number of EGUs caused a lifetime 

cancer risk greater than one in one 

million. Nothing in the 2005 record 

suggested anything to the contrary, and 

as such, the Agency did not delist EGUs 

in 2005 pursuant to section 112(c)(9). 

Finally, EPA has conducted 16 case 

studies based on the data collected in 

support of this proposed rule and 

determined that 4 of those facilities 

evaluated (25 percent) presented a 

lifetime cancer risk greater than 1 in 1 

million. Thus, based on current data 

and analysis, EGUs fail the first 

requirement for delisting set forth in 

section 112(c)(9)(B)(i). Because EGUs do 


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26Strum, M., Houyoux, M., U.S. Environmental 

Protection Agency. Emissions Overview: Hazardous 

Air Pollutants in Support of the Proposed Toxics 

Rule. Memorandum to Docket EPA–HQ–OAR– 

2009–0234. March 15, 2011. 

27 Ibid. Tables 3 and 4. 

28Strum, M., Thurman, J., and Morris, M., U.S. 

Environmental Protection Agency. Non-Hg Case 

Study Chronic Inhalation Risk Assessment for the 

Utility MACT ‘‘Appropriate and Necessary’’ 

Analysis. Memorandum to Docket EPA–HQ–OAR– 

2009–0234. March 1, 2011. 

29Strum, M., Houyoux, H., op. cit., Tables 3 

and 4. 

not meet the first delisting requirement, 

the Agency need not determine whether 

the second delisting requirement is 

satisfied; however, the Agency believes 

that EGUs would similarly fail the 

second delisting requirement for the 

reasons described below in section III.D. 

D. New Analyses Confirm That it 

Remains Appropriate and Necessary to 

Regulate U.S. EGU HAP Under Section 

112 

As explained above, the December 

2000 appropriate and necessary 

determination is wholly supported by 

the record that was before the Agency at 

the time it made its decision. Although 

not required, we conducted additional 

technical analyses because several years 

have passed since the December 2000 

Finding. These extensive analyses 

confirm that it remains appropriate and 

necessary today to regulate EGUs under 

section 112. We discuss below the new 

analyses that we conducted. We also 

explain why these analyses and the 

other information currently before the 

Agency confirm that regulation of EGUs 

under section 112 is appropriate and 

necessary. We solicit comment on the 

new analyses. 

Utilities are by far the largest 

remaining source of Hg in the U.S.26 In 

addition, EGUs are the largest source of 

HCl, HF, and Se emissions, and a major 

source of metallic HAP emissions 

including As, Cr, Ni, and others.27 The 

discrepancy is even greater now that 

almost all other major source categories 

have been required to control Hg and 

other HAP under section 112. 

These significant HAP emissions pose 

a known or potential hazard to public 

health and the environment and, thus, 

it remains appropriate to regulate EGUs 

under section 112. 

In this section, we describe briefly the 

health and environmental effects 

associated with the HAP emitted by 

EGUs and summarize the new analyses 

that the Agency conducted to assess the 

hazards to public health and the 

environment associated with EGU 

emissions, including the hazards 

remaining after imposition of the 

requirements of the CAA. We then 

discuss our conclusion that it remains 

appropriate and necessary to regulate 

EGUs under section 112. 

Specifically, we conclude today that it 

remains appropriate to regulate EGUs 

under section 112 because Hg is a 

persistent, bioaccumulative pollutant, 

and emissions of Hg from EGUs 

continue to pose a hazard to public 

health and to the environment. Because 

of the persistent nature of Hg in the 

environment, Hg emitted today can lead 

to re-emissions of Hg in the future, and 

as a result continue to contribute to Hg 

deposition and associated health and 

environmental hazards in the future. 

In addition, we conclude today that it 

is appropriate to regulate non-Hg HAP 

because emissions of these HAP from 

some EGUs pose a cancer risk greater 

than one in one million to the most 

exposed individual.28 EGUs remain the 

largest contributors of several HAP (e.g., 

HF, Se, HCl), and are among the largest 

contributor for other HAP (e.g., As, Cr, 

Ni, hydrogen cyanide (HCN)).29 EPA 

recognizes that there are additional 

health and environmental effects for 

which we have insufficient information 

to quantify risks, or which have a higher 

degree of uncertainty regarding the 

weight of evidence for causality. While 

not quantified in our analysis, the 

potential for additional hazards to 

public health and the environment 

beyond what we have analyzed provides 

additional support for regulation under 

section 112 that will assure reductions 

of all HAP and the risks, quantified or 

unquantified, that they pose. 

Finally, we find that it remains 

appropriate to regulate EGUs under 

section 112 because we have identified 

a number of currently available control 

technologies that will adequately 

address HAP emissions from EGUs. 

Several of these findings provide an 

independent basis for our determination 

consistent with our interpretation of the 

appropriate finding set forth above, and 

the combined weight of these findings 

provides a strong overall basis for our 

determination that it is and remains 

appropriate to regulate EGUs under 

CAA section 112. 

We conclude that it remains necessary 

to regulate HAP emissions from EGUs 

because the imposition of the 

requirements of the CAA will not 

sufficiently address the hazards to 

public health and the environment 

posed by Hg emissions or the cancer 

risk and potential hazards to the 

environment posed by non-Hg HAP 

emissions from EGUs. Although the 

identified hazards will not be fully 

addressed through regulation under 

section 112, there will be a significant 

reduction in domestic Hg and non-Hg 

HAP emissions as the result of a section 

112 regulation. EGUs remain the largest 

source of HCl and HF emissions in the 

U.S., and it is essential that those 

emissions be reduced to the maximum 

extent achievable, as Congress 

envisioned pursuant to section 112. 

Furthermore, it is necessary to regulate 

EGUs under section 112 because 

standards under that section assure that 

reductions in HAP emissions from EGUs 

will be permanently realized, thereby 

assuring that recent decreases in HAP 

emissions from U.S. EGUs will not be 

reversed in the future. Each of these 

conclusions independently supports our 

determination that it remains necessary 

to regulate EGUs under section 112. 

Below we present an overview of 

EPA’s current view of the scientific and 

technical information relevant to 

evaluating U.S. EGU Hg emissions and 

the public health hazards associated 

with such emissions. We provide 

general background information on the 

health hazards and environmental 

impacts of Hg and its transformation 

product MeHg; the emissions of those 

pollutants; the U.S. EGU contribution to 

these emissions; the predominant 

exposure pathway by which humans are 

affected by MeHg, which is by ingestion 

of fish containing MeHg; EPA’s 

methodology for determining the 

impacts of U.S. EGU Hg emissions on 

potential exposures to MeHg in fish; the 

estimated potential risks associated with 

recent and future anticipated emissions 

of Hg from U.S. EGUs; and a qualitative 

analysis of the environmental hazards 

associated with Hg deposition. In 

addition to these analyses of hazards to 

public health and the environment 

associated with emissions of Hg from 

U.S. EGUs, this section also includes 

analyses of the hazards to public health 

and the environment from U.S. EGU 

emissions of non-Hg HAP. We then 

explain why the hazards to public 

health and the environment from Hg 

and non-Hg HAP emissions are 

reasonably anticipated to remain from 

U.S. EGUs after imposition of the 

requirements of the CAA. Finally, we 

discuss our evaluation of the new data 

and our finding that it remains 

appropriate and necessary to regulate 

EGUs under section 112. 

1. Background Information on Hg 

Emissions, Deposition, and Effects on 

Human Health and the Environment 

a. Overview of Hg and Associated 

Health and Environmental Hazards 

Mercury is a persistent, 

bioaccumulative toxic metal that is 

emitted from EGUs in three forms: 


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30MeHg exposure is measured as milligrams of 

MeHg per kilogram of bodyweight per day, thus 

normalizing for the size of fish meals and the 

differences in bodyweight among exposed 

individuals. 

31Marsh DO, Clarkson TW, Cox C, Myers GJ, 

Amin-Zaki L, Al-Tikriti S 1987. Fetal 

methylmercury poisoning. Relationship between 

concentration in single strands of maternal hair and 

child effects. Arch Neurol 44(10):1017–1022. 

32 Davidson, P.W., G. Myers, C.C. Cox, C.F. 

Shamlaye, D.O.Marsh, M.A.Tanner, M. Berlin, J. 

Sloane-Reeves, E. Chernichiari,, O. Choisy, A. Choi 

and T.W. Clarkson. 1995. Longitudinal 

neurodevelopment study of Seychellois children 

following in utero exposure to methylemrcury from 

maternal fish ingestion: outcomes at 19 and 29 

months. NeuroToxicology 16:677–688. 

33 Grandjean, P., Weihe, P., White, R.F., Debes, F., 

Araki, S., Murata, K., S<rensen, N., Dahl, D., 

Yokoyama, K., J<rgensen, P.J., 1997. Cognitive 

deficit in 7-year-old children with prenatal 

exposure to methylmercury. Neurotoxicol. Teratol. 

19, 417–428. 

34 Kjellstrom T, Kennedy P, Wallis S, Stewart A, 

Friberg L, Lind B, et al. (1989). Physical and mental 

development of children with prenatal exposure to 

mercury from fish. Stage 2: Interviews and 

psychological tests at age 6. Solna, Sweden: 

National Swedish Environmental Protection Board. 

Report No.: Report 3642. 

35EPA, 2001. 36NAS, 2000. 

Gaseous elemental Hg (Hg0), oxidized 

Hg compounds (Hg+2), and particlebound Hg (HgP). Elemental Hg does not 

quickly deposit or chemically react in 

the atmosphere, resulting in residence 

times that are long enough to contribute 

to global scale deposition. Oxidized Hg 

and HgP deposit quickly from the 

atmosphere impacting local and 

regional areas in proximity to sources. 

Methylmercury is formed by microbial 

action in the top layers of sediment and 

soils, after Hg has precipitated from the 

air and deposited into waterbodies or 

land. Once formed, MeHg is taken up by 

aquatic organisms and bioaccumulates 

up the aquatic food web. Larger 

predatory fish may have MeHg 

concentrations many times, typically on 

the order of one million times, that of 

the concentrations in the freshwater 

body in which they live. Although Hg 

is toxic to humans when it is inhaled or 

ingested, we focus in this rulemaking on 

exposure to MeHg through ingestion of 

fish, as it is the primary route for human 

exposures in the U.S., and potential 

health risks do not likely result from Hg 

inhalation exposures associated with Hg 

emissions from utilities. 

In 2000, the National Research 

Council (NRC) of the NAS issued the 

NAS Study, which provides a thorough 

review of the effects of MeHg on human 

health. There are numerous studies that 

have been published more recently that 

report effects on neurologic and other 

endpoints. 

i. Reference and Benchmark Doses 

As discussed earlier in Sections II.A.1 

and III.B.3.a.i of this preamble, EPA has 

set and evaluated the RfD for Hg several 

times, and has received input from the 

NRC on the appropriateness of the RfD. 

In 1995, EPA set a health-based 

ingestion rate for chronic oral exposure 

to MeHg termed an oral RfD, at 0.0001 

milligrams per kilogram per day (mg/kgday).30 The RfD was based on effects 

reported for children exposed in utero 

during the Iraqi Hg poisoning episode, 

in which children were exposed to high 

levels of Hg when their mothers 

consumed contaminated grain.31

Subsequent research from large 

epidemiological studies in the 

Seychelles,32 Faroe Islands,33 and New 

Zealand 34 added substantially to the 

body of knowledge on neurological 

effects from MeHg exposure. In 2001 

EPA established a revised RfD based on 

the advice of the NAS and an 

independent review panel convened as 

part of the Integrated Risk Information 

System (IRIS) process. In their analysis, 

the NAS examined in detail the 

epidemiological data from the 

Seychelles, the Faroe Islands, and New 

Zealand, as well as other toxicological 

data on MeHg. The NAS recommended 

that neurobehavioral deficits as 

measured in several different tests 

among these studies be used as the basis 

for the RfD. 

The NAS proposed that the Faroe 

Islands cohort was the most appropriate 

study for defining an RfD, and 

specifically selected children’s 

performance on the Boston Naming Test 

(a neurobehavioral test) as the key 

endpoint. Results from all three studies 

were considered in defining the RfD, as 

published in the ‘‘2001 Water Quality 

for the Protection of Human Health: 

Methylmercury,’’ and in the IRIS 

summary for MeHg: ‘‘Rather than choose 

a single measure for the RfD critical 

endpoint, EPA based this RfD for this 

assessment on several scores from the 

Faroes’ measures, with supporting 

analyses from the New Zealand study, 

and the integrative analysis of all three 

studies.’’ 35

EPA defined the updated RfD of 

0.0001 mg/kg-day in 2001. Although 

derived from a more complete data set 

and with a somewhat different 

methodology, the current RfD is 

numerically the same as the previous 

(1995) RfD (0.0001 mg/kg-day, or 0.1 μg/ 

kg-day). 

This RfD, consistent with the standard 

definition, is an estimate (with 

uncertainty spanning perhaps an order 

of magnitude) of a daily exposure to the 

human population (including sensitive 

subgroups) that is likely to be without 

an appreciable risk of deleterious effects 

during a lifetime (EPA, 2002). In general 

EPA believes that exposures at or below 

the RfD are unlikely to be associated 

with appreciable risk of deleterious 

effects. However, no RfD defines an 

exposure level corresponding to zero 

risk; moreover the RfD does not 

represent a bright line, above which 

individuals are at risk of adverse effects. 

EPA’s interpretation for this assessment 

is that any exposures to MeHg above the 

RfD are of concern given the nature of 

the data available for Hg that is not 

necessarily available for many other 

chemicals. The scientific basis for the 

Hg RfD includes extensive human data 

and extensive data on sensitive 

subpopulations, including pregnant 

mothers; therefore, the RfD does not 

include extrapolations from animals to 

humans, and from the general 

population to sensitive subpopulations. 

In addition, there was no evidence of a 

threshold for MeHg-related 

neurotoxicity within the range of 

exposures in the Faroe Islands study 

which served as the primary basis for 

the RfD. This additional confidence in 

the basis for the RfD suggests that all 

exposures above the RfD can be 

interpreted with more confidence as 

causing a potential hazard to public 

health. Studies published since the 

current MeHg RfD was released include 

new analyses of children’s 

neuropsychological effects from the 

existing Seychelles and Faroe Islands 

cohorts, including formation of a new 

cohort in the Faroe Islands study. There 

are also a number of new studies that 

were conducted in population-based 

cohorts in the U.S and other countries. 

A comprehensive assessment of the new 

literature has not been completed by 

EPA. However, 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 Faroes. 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. 

ii. Neurologic Effects 

In its review of the literature, the NAS 

found neurodevelopmental effects to be 

the most sensitive and best documented 

endpoints and appropriate for 

establishing an RfD;36 in particular NAS 


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37NAS, 2000. 

38Amorim, M.I., Mergler, D., Bahia, M.O., 

Dubeau, H., Miranda, D., Lebel, J., Burbano, R.R., 

Lucotte, M., 2000. Cytogenetic damage related to 

low levels of methyl mercury contamination in the 

Brazilian Amazon. An. Acad. Bras. Cienc. 72, 487– 

507. 

39Agency for Toxic Substances and Disease 

Registry (ATSDR). 1999. Toxicological profile for 

Mercury. Atlanta, GA: U.S. Department of Health 

and Human Services, Public Health Service. http:// 

www.atsdr.cdc.gov/toxprofiles/tp.asp?id=115&

tid=24. 

40National Academy of Sciences. Toxicologic 

effects of methylmercury. Washington, DC: National 

Research Council, 2000. Available online at http:// 

www.nap.edu/openbook.php?isbn=0309071402. 

41 IARC, 1994. 

42EPA, 2002. 

43NAS, 2000. 

44Lindberg, S., Bullock, R., Ebinghaus, R., 

Engstrom, D., Feng, X., Fitzgerald, W., et al. (2007). 

A Synthesis of Progress and Uncertainties in 

Attributing the Sources of Mercury in Deposition. 

Ambio, 36(1), 19–33. 

45Lohman, K., Seigneur, C., Gustin, M., & 

Lindberg, S. (2008). Sensitivity of the global 

atmospheric cycle of mercury to emissions. Applied 

Geochemistry, 23(3), 454–466. 

46Seigneur, C., Vijayaraghavan, K., Lohman, K., 

Karamchandani, P., & Scott, C. (2004). Global 

Source Attribution for Mercury Speciation in the 

United States. Environmental Science and 

Technology(38), 555–569. 

47Mason, R., Pirrone, N., & Mason, R. P. (2009). 

Mercury emissions from natural processes and their 

importance in the global mercury cycle. In Mercury 

Fate and Transport in the Global Atmosphere (pp. 

173–191): Springer U.S. 

48Selin, N. E., Jacob, D. J., Park, R. J., Yantosca, 

R. M., Strode, S., Jaegle ́, L., et al. (2007). Chemical 

cycling and deposition of atmospheric mercury: 

Global constraints from observations. J. Geophys. 

Res, 112, 1071–1077. 

supported the use of results from 

neurobehavioral or neuropsychological 

tests. The NAS report 37 noted that 

studies in animals reported sensory 

effects as well as effects on brain 

development and memory functions and 

support the conclusions based on 

epidemiology studies. The NAS noted 

that their recommended endpoints for 

an RfD are associated with the ability of 

children to learn and to succeed in 

school. They concluded the following: 

‘‘The population at highest risk is the 

children of women who consumed large 

amounts of fish and seafood during 

pregnancy. The committee concludes 

that the risk to that population is likely 

to be sufficient to result in an increase 

in the number of children who have to 

struggle to keep up in school.’’ 

iii. Cardiovascular Impacts 

The NAS summarized data on 

cardiovascular effects available up to 

2000 (IRIS 2001). Based on these and 

other studies, the NRC (2000) 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 NRC also 

stated that ‘‘additional studies are 

needed to better characterize the effect 

of methylmercury exposure on blood 

pressure and cardiovascular function at 

various stages of life.’’ 

Additional cardiovascular studies 

have been published since 2000. EPA 

did not to develop a quantitative doseresponse assessment for cardiovascular 

effects associated with MeHg exposures, 

as there is no consensus among 

scientists on the dose-response 

functions for these effects. In addition, 

there is inconsistency among available 

studies as to the association between 

MeHg exposure and various 

cardiovascular system effects. The 

pharmacokinetics of some of the 

exposure measures (such as toenail Hg 

levels) are not well understood. The 

studies have not yet received the review 

and scrutiny of the more wellestablished neurotoxicity data base. 

iv. Genotoxic Effects 

The Mercury Study noted that MeHg 

is not a potent mutagen but is capable 

of causing chromosomal damage in a 

number of experimental systems. The 

NAS concluded that evidence that 

human exposure to MeHg caused 

genetic damage is inconclusive; they 

note that some 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 38 reported a direct 

relationship between MeHg 

concentration in hair and DNA damage 

in lymphocytes; as well as effects on 

chromosomes. Long-term MeHg 

exposures in this population were 

believed to occur through consumption 

of fish, suggesting that genotoxic effects 

(largely chromosomal aberrations) may 

result from dietary, chronic MeHg 

exposures similar to and above those 

seen in the Faroes and Seychelles 

populations. 

v. Immunotoxic Effects 

Although exposure to some forms of 

Hg can result in a decrease in immune 

activity or an autoimmune response,39

evidence for immunotoxic effects of 

MeHg is limited.40

vi. Other 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) 41 and in IRIS.42 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 43). 

There is also some evidence of 

reproductive and renal toxicity in 

humans from MeHg exposure. However, 

overall, human data regarding 

reproductive, renal, and hematological 

toxicity from MeHg are very limited and 

are based on either studies of the two 

high-dose poisoning episodes in Iraq 

and Japan or animal data, rather than 

epidemiological studies of chronic 

exposures at the levels of interest in this 

analysis. 

b. Mercury Emissions 

Mercury is an element. There is a 

fixed amount of it in the world. As long 

as it is bound up, for example in coal, 

it cannot affect people or the 

environment. Once it is released, for 

example via the combustion process, it 

enters the environment and becomes 

available for chemical conversion. Once 

emitted, Hg remains in the environment, 

and can bioaccumulate in organisms or 

be remitted through natural processes. 

Mercury is emitted through natural and 

anthropogenic processes; in addition, 

previously deposited Hg from either 

process may be re-emitted. Mercury 

deposition in the U.S. is not directly 

proportional to total Hg emissions, due 

to the differing rates at which the three 

species of Hg (Hg0, Hg+2, Hgp) deposit. 

In general, the greater the fraction of 

total Hg accounted for by Hg+2 and HgP, 

the higher the correlation between total 

Hg emissions and total Hg deposition in 

the U.S. In the following discussion, we 

will be describing emissions of Hg, 

while we discuss deposition later in this 

section. 

The categories for anthropogenic Hg 

emissions include the combustion of 

fossil-fuels, cement production, waste 

incineration, metals production, and 

other industrial processes. 

Anthropogenic Hg emissions consist of 

Hg0, Hg+2, and HgP. 

Mercury re-emissions include 

previously deposited Hg originating 

from both natural and anthropogenic 

sources. At this time, it is not possible 

to determine the original source of 

previously deposited Hg, whether its 

source is natural emissions or reemissions from previously deposited 

anthropogenic Hg.44 45 46 It is believed 

that half of re-emitted Hg originates 

from anthropogenic sources.47 48

Current estimates of total global Hg 

emissions based on a 2005 inventory 


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49Lindberg, S., Bullock, R., Ebinghaus, R., 

Engstrom, D., Feng, X., Fitzgerald, W., et al. (2007). 

A Synthesis of Progress and Uncertainties in 

Attributing the Sources of Mercury in Deposition. 

Ambio, 36(1), 19–33. 

50Pirrone, N., Cinnirella, S., Feng, X., Finkelman, 

R. B., Friedli, H. R., Leaner, J., et al. (2010). Global 

mercury emissions to the atmosphere from 

anthropogenic and natural sources. Atmospheric 

Chemistry and Physics Discussions, 10(2), 4719– 

4752. 

51UNEP (United Nations Environment 

Programme), Chemicals Branch, 2008. The Global 

Atmospheric Mercury Assessment: Sources, 

Emissions and Transport, UNEP Chemicals, 

Geneva. 

52Study on Mercury Sources and Emissions and 

Analysis of the Cost and Effectiveness of Control 

Measures ‘‘UNEP Paragraph 29 study’’, UNEP 

(DTIE)/Hg/INC.2/4. November, 2010. 53Pirrone, N., Cinnirella, S., Feng, X., Finkelman, 

R. B., Friedli, H. R., Leaner, J., et al. (2010). Global 

mercury emissions to the atmosphere from 

anthropogenic and natural sources. Atmospheric 

Chemistry and Physics Discussions, 10(2), 4719– 

4752. 

54Study on Mercury Sources and Emissions and 

Analysis of the Cost and Effectiveness of Control 

Measures ‘‘UNEP Paragraph 29 study’’, UNEP 

(DTIE)/Hg/INC.2/4. November, 2010. 55The estimate of 5 percent is based upon 105 

tons in 2005 divided by 2,100 tons from UNEP. 

56The 46 ton estimate is based on the Utility 

Study. Since that time, EPA has updated its 

estimate of U.S. EGU Hg emissions in 1990. The 

updated estimate is 59 tons. 

57Since the December 2000 Finding, the NEI 

process has led to an updated emissions estimate 

of 49 tons. 

58As explained further in the emissions modeling 

TSD, this projection does not include reductions 

from a number of state-only Hg regulations and 

voluntary Hg reductions programs that are not 

Federally enforceable, and are not relevant to our 

assessment of whether it is appropriate and 

necessary to regulate U.S. EGU sources under 

section 112. 

59Schroeder, W. H. and J. Munthe (1998). 

‘‘Atmospheric mercury—An overview.’’ 

Atmospheric Environment 32(5): 809–822. 

60Schroeder, W. H. and J. Munthe (1998). 

‘‘Atmospheric mercury—An overview.’’ 

Atmospheric Environment 32(5): 809–822. 

range from 7,300 to 8,300 tpy.49 50 The 

United Nations Environment 

Programme (UNEP) estimates of 2005 

global Hg emissions are somewhat 

lower, at 5,600 metric tpy.51 Global 

anthropogenic Hg emissions, excluding 

biomass burning, have been estimated 

by many researchers. UNEP’s 2005 

estimate is approximately 2,100 tpy 

(with a range of 1,300 tpy to 3,300 

tpy) 52 and Pirrone, et al.’s 2005 estimate 

is approximately 2,600 tpy. Global 

fossil-fuel fired EGUs total 

approximately 500 to 900 tpy, a large 

fraction (25 to 35 percent) of the total 

global anthropogenic emissions.53 54 The 

U.S. contribution to global 

anthropogenic emissions has declined 

from 10 percent in 1990 to 5 percent in 

2005, due to reductions in U.S. 

emissions and increases in emissions 

from other countries.55

Although total U.S. anthropogenic Hg 

has decreased, the EGU sector remains 

the largest contributor to the total. In 

1990, U.S. EGU Hg emissions for coalfired units above 25 MW were 46 tons 

out of total U.S. Hg emissions of 264 

tons.56 By 1999 U.S. EGU Hg emissions 

for coal-fired units above 25 MW were 

43 out of 115 tons.57 In 2005, estimated 

emissions for coal- and oil-fired units 

above 25 MW were 53 tons out of a total 

of 105 tons. However, the 2005 estimate 

is based on control configurations as of 

2002; therefore, it does not reflect 

reductions due to control installations 

that took place between 2002 and 2005. 

A current estimate of Hg emissions for 

both coal- and oil-fired units above 25 

MW, using data from the EPA’s 2010 

ICR database, which used testing data 

for over 300 units, is 29 tons of Hg. We 

believe our estimate of the current level 

of Hg emissions based on the 2010 ICR 

database may underestimate total EGU 

Hg emissions due to the fact that 

emission factors used to develop the 

estimates may not accurately account 

for larger emissions from units with 

more poorly performing emission 

controls. EPA tested only 50 randomly 

selected units that were not selected for 

testing as best performing units (the 

bottom 85 percent of units), and we 

used that small sample to attempt to 

characterize the lower performing units. 

Because the 50 units were randomly 

selected, we do not believe we have 

sufficiently characterized the units that 

have poorly performing controls. In 

addition, the 2010 estimate also reflects 

the installation of Hg controls to comply 

with state Hg-specific rules, voluntary 

reductions from EGUs, and the cobenefits of Hg reductions associated 

with control devices installed for the 

reduction of SO2 and PM as a result of 

state and Federal actions, such as New 

Source Review (NSR) enforcement 

actions and implementation of CAIR. 

Table 3 shows U.S. EGU Hg emissions 

along with emissions from other major 

non-EGU Hg sources. Table 3 also 

shows EPA’s projection that U.S. EGU 

emissions will continue to comprise a 

dominant portion of the total U.S. 

anthropogenic inventory in 2016. In 

2016, U.S. EGU Hg emission for the 

subset of coal-fired units above 25 MW 

is projected to be 29 tons out of a total 

of 64 tons.58

TABLE 3—ANTHROPOGENIC HG EMISSIONS AND PROJECTIONS IN THE U.S.* 

Category 2005 Mercury 

(tons) 

2016 Mercury 

(tons) 

Electric Generating Units ......................................................................................................................................... 53 29 

Portland Cement Manufacturing .............................................................................................................................. 7.5 1.1 

Stainless and Nonstainless Steel Manufacturing: Electric Arc Furnaces ............................................................... 7.0 4.6 

Industrial, Commercial, Institutional Boilers & Process Heaters ............................................................................. 6.4 4.6 

Chemical Manufacturing .......................................................................................................................................... 3.3 3.3 

Hazardous Waste Incineration ................................................................................................................................ 3.2 2.1 

Mercury Cell Chlor-Alkali Plants .............................................................................................................................. 3.1 0.3 

Gold Mining .............................................................................................................................................................. 2.5 0.7 

Municipal Waste Combustors .................................................................................................................................. 2.3 2.3 

Sum of other source categories (each of which emits less than 2 tons) ............................................................... 17 16 

Total .................................................................................................................................................................. 105 64 

* Emissions estimates are presented at a maximum of two significant figures. 

c. Atmospheric Processing and 

Deposition of Hg 

Mercury is known to exist in the 

atmosphere in three forms: Hg0, Hg+2, 

and HgP. The dominant form of Hg in 

the atmosphere is Hg0.59 Elemental Hg 

dominates total Hg composition in the 

atmosphere (greater than 95 percent) 

and has a much greater residence time 

than Hg+2 or HgP. Elemental Hg has a 

long atmospheric residence time due to 

its near insolubility in water and high 

vapor pressure which minimize removal 

through wet and dry deposition 

processes.60 Oxidized Hg (which is 


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Marsik, F. J., G. J. Keeler, et al. (2007). ‘‘The drydeposition of speciated mercury to the Florida 

Everglades: Measurements and modeling.’’ 

Atmospheric Environment 41(1): 136–149. 

61U.S. Environmental Protection Agency (U.S. 

EPA). 1991. Integrated Risk Information System File 

of Acetaldehyde. Research and Development, 

National Center for Environmental Assessment, 

Washington, DC. This material is available 

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

0290.htm. 

62U.S. Department of Health and Human Services 

National Toxicology Program 11th Report on 

Carcinogens available at: http://ntp.niehs.nih.gov/ 

go/16183. 

63 International Agency for Research on Cancer 

(IARC). 1999. Re-evaluation of some organic 

chemicals, hydrazine, and hydrogen peroxide. IARC 

Monographs on the Evaluation of Carcinogenic Risk 

of Chemical to Humans, Vol 71. Lyon, France. 

64U.S. Environmental Protection Agency (U.S. 

EPA). 1991. Integrated Risk Information System File 

of Acetaldehyde. Research and Development, 

National Center for Environmental Assessment, 

Washington, DC. This material is available 

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

0290.htm. 

65Agency for Toxic Substances and Disease 

Registry (ATSDR). Medical Management Guidelines 

for Arsenic. Atlanta, GA: U.S. Department of Health 

and Human Services. Available on the Internet at 

http://www.atsdr.cdc.gov/mhmi/ 

mmg168.html#bookmark02. 

66U.S. Environmental Protection Agency (U.S. 

EPA). 1998. Integrated Risk Information System File 

for Arsenic. Research and Development, National 

Center for Environmental Assessment, Washington, 

DC. This material is available electronically at: 

http://www.epa.gov/iris/subst/0278.htm. 

67U.S. Environmental Protection Agency (U.S. 

EPA). 2000. Integrated Risk Information System File 

for Benzene. Research and Development, National 

Center for Environmental Assessment, Washington, 

DC. This material is available electronically at: 

http://www.epa.gov/iris/subst/0276.htm. 

68 International Agency for Research on Cancer, 

IARC monographs on the evaluation of carcinogenic 

risk of chemicals to humans, Volume 29, Some 

industrial chemicals and dyestuffs, International 

Agency for Research on Cancer, World Health 

Organization, Lyon, France, p. 345–389, 1982. 

69 Irons, R.D.; Stillman, W.S.; Colagiovanni, D.B.; 

Henry, V.A. (1992) Synergistic action of the 

benzene metabolite hydroquinone on myelopoietic 

stimulating activity of granulocyte/macrophage 

colony-stimulating factor in vitro, Proc. Natl. Acad. 

Sci. 89:3691–3695. 

70 International Agency for Research on Cancer 

(IARC). 1987. Monographs on the evaluation of 

carcinogenic risk of chemicals to humans, Volume 

29, Supplement 7, Some industrial chemicals and 

dyestuffs, World Health Organization, Lyon, France. 

71U.S. Department of Health and Human Services 

National Toxicology Program 11th Report on 

Carcinogens available at: http://ntp.niehs.nih.gov/ 

go/16183. 

72Aksoy, M. (1989). Hematotoxicity and 

carcinogenicity of benzene. Environ. Health 

Perspect. 82: 193–197. 

Continued 

soluble) and HgP are more readily 

scavenged by precipitation and have 

higher dry deposition velocities than 

Hg0 resulting in much shorter residence 

times. Although natural sources such as 

land, ocean and volcanic Hg are emitted 

as elemental, most anthropogenic 

sources are emitted in all three forms. 

EGU Hg ranges from 20 to 40 percent 

Hg+2 and from 2 to 5 percent Hgp. This 

results in greater deposition of Hg+2 and 

HgP within the U.S. due to U.S. EGU 

emissions of these two Hg species, 

relative to emissions of Hg0. As a result, 

control of emissions of Hg+2 and HgP are 

more relevant for decreasing U.S. EGUattributable exposures to MeHg for 

recreational and subsistence-level fish 

consumers than control of emissions of 

Hg0. Control of emissions of Hg0 will 

still have value in reducing overall 

global levels of Hg deposition, and will, 

all else equal, eventually result in lower 

global fish MeHg concentrations which 

can benefit both U.S. and global 

populations. 

2. Background Information on Non-Hg 

HAP Emissions and Effects on Human 

Health and the Environment 

a. Overview of Non-Hg HAP and 

Associated Health and Environmental 

Hazards 

Emissions data collected through the 

2010 ICR during development of this 

proposed rule show that HCl emissions 

represent the predominant HAP emitted 

by U.S. EGUs. Coal- and oil-fired EGUs 

emit lesser amounts of HF, chlorine 

(Cl2), metals (As, Cd, Cr, Hg, Mn, Ni, 

and Pb), and organic HAP emissions. 

Although numerous organic HAP may 

be emitted from coal- and oil-fired 

EGUs, only a few account for essentially 

all the mass of organic HAP emissions. 

These organic HAP are formaldehyde, 

benzene, and acetaldehyde. 

Exposure to high levels of the various 

non-Hg HAP emitted by EGUs is 

associated with a variety of adverse 

health effects. These adverse health 

effects include chronic (long-term) 

health disorders (e.g., effects on the 

central nervous system, damage to the 

kidneys, and irritation of the lung, skin, 

and mucus membranes); and acute 

health disorders (e.g., effects on the 

kidney and central nervous system, 

alimentary effects such as nausea and 

vomiting, and lung irritation and 

congestion). EPA has classified three of 

the HAP emitted by EGUs as human 

carcinogens and five as probable human 

carcinogens. The following sections 

briefly discuss the main health effects 

information we have regarding the key 

HAP emitted by EGUs in alphabetical 

order by HAP name. 

i. Acetaldehyde 

Acetaldehyde is classified in EPA’s 

IRIS database as a probable human 

carcinogen, based on nasal tumors in 

rats, and is considered toxic by the 

inhalation, oral, and intravenous 

routes.61 Acetaldehyde is reasonably 

anticipated to be a human carcinogen by 

the U.S. Department of Health and 

Human Services (DHHS) in the 11th 

Report on Carcinogens and is classified 

as possibly carcinogenic to humans 

(Group 2B) by the IARC.62 63 The 

primary noncancer effects of exposure 

to acetaldehyde vapors include 

irritation of the eyes, skin, and 

respiratory tract.64

ii. Arsenic 

Arsenic, a naturally occurring 

element, is found throughout the 

environment and is considered toxic 

through the oral, inhalation and dermal 

routes. Acute (short-term) high-level 

inhalation exposure to As dust or fumes 

has resulted in gastrointestinal effects 

(nausea, diarrhea, abdominal pain, and 

gastrointestinal hemorrhage); central 

and peripheral nervous system 

disorders have occurred in workers 

acutely exposed to inorganic As. 

Chronic (long-term) inhalation exposure 

to inorganic As in humans is associated 

with irritation of the skin and mucous 

membranes. Chronic inhalation can also 

lead to conjunctivitis, irritation of the 

throat and respiratory tract and 

perforation of the nasal septum.65

Chronic oral exposure has resulted in 

gastrointestinal effects, anemia, 

peripheral neuropathy, skin lesions, 

hyperpigmentation, and liver or kidney 

damage in humans. Inorganic As 

exposure in humans, by the inhalation 

route, has been shown to be strongly 

associated with lung cancer, while 

ingestion of inorganic As in humans has 

been linked to a form of skin cancer and 

also to bladder, liver, and lung cancer. 

EPA has classified inorganic As as a 

Group A, human carcinogen.66

iii. Benzene 

The EPA’s IRIS database lists benzene 

as a known human carcinogen (causing 

leukemia) by all routes of exposure, and 

concludes that exposure is associated 

with additional health effects, including 

genetic changes in both humans and 

animals and increased proliferation of 

bone marrow cells in mice.67 68 69 EPA 

states in its IRIS database that data 

indicate a causal relationship between 

benzene exposure and acute 

lymphocytic leukemia and suggest a 

relationship between benzene exposure 

and chronic non-lymphocytic leukemia 

and chronic lymphocytic leukemia. The 

IARC has determined that benzene is a 

human carcinogen and the DHHS has 

characterized benzene as a known 

human carcinogen.70 71

A number of adverse noncancer 

health effects including blood disorders, 

such as preleukemia and aplastic 

anemia, have also been associated with 

long-term exposure to benzene.72 73


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Occupational medicine. State of the Art Reviews. 3: 

541–554. 

74Agency for Toxic Substances and Disease 

Registry (ATSDR). 2008. Public Health Statement 

for Cadmium. CAS# 1306–19–0. Atlanta, GA: U.S. 

Department of Health and Human Services, Public 

Health Service. Available on the Internet at 

http://www.atsdr.cdc.gov/PHS/PHS.asp?id=46&

tid=15. 

75Agency for Toxic Substances and Disease 

Registry (ATSDR). Medical Management Guidelines 

for Chlorine. Atlanta, GA: U.S. Department of 

Health and Human Services. http:// 

www.atsdr.cdc.gov/mmg/mmg.asp?id=198&tid=36. 

76U.S. EPA. 1987. Assessment of Health Risks to 

Garment Workers and Certain Home Residents from 

Exposure to Formaldehyde, Office of Pesticides and 

Toxic Substances, April 1987. 

77 International Agency for Research on Cancer 

(2006) Formaldehyde, 2–Butoxyethanol and 1-tertButoxypropan-2-ol. Monographs Volume 88. World 

Health Organization, Lyon, France. 

78Agency for Toxic Substances and Disease 

Registry (ATSDR). 1999. Toxicological profile for 

Formaldehyde. Atlanta, GA: U.S. Department of 

Health and Human Services, Public Health Service. 

http://www.atsdr.cdc.gov/toxprofiles/tp111.html 

79WHO (2002) Concise International Chemical 

Assessment Document 40: Formaldehyde. 

Published under the joint sponsorship of the United 

Nations Environment Programme, the International 

Labour Organization, and the World Health 

Organization, and produced within the framework 

of the Inter-Organization Programme for the Sound 

Management of Chemicals. Geneva. 

80Agency for Toxic Substances and Disease 

Registry (ATSDR). Medical Management Guidelines 

for Hydrogen Chloride. Atlanta, GA: U.S. 

Department of Health and Human Services. 

Available online at http://www.atsdr.cdc.gov/mmg/ 

mmg.asp?id=758&tid=147#bookmark02. 

81U.S. Environmental Protection Agency (U.S. 

EPA). 1995. Integrated Risk Information System File 

of Hydrogen Chloride. Research and Development, 

National Center for Environmental Assessment, 

Washington, DC. This material is available 

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

0396.htm. 

iv. Cadmium 

Breathing air with lower levels of Cd 

over long periods of time (for years) 

results in a build-up of Cd in the 

kidney, and if sufficiently high, may 

result in kidney disease. Lung cancer 

has been found in some studies of 

workers exposed to Cd in the air and 

studies of rats that inhaled Cd. DHHS 

has determined that Cd and Cd 

compounds are known human 

carcinogens. IARC has determined that 

Cd is carcinogenic to humans. EPA has 

determined that Cd is a probable human 

carcinogen.74

v. Chlorine 

The acute (short term) toxic effects of 

Cl2 are primarily due to its corrosive 

properties. Chlorine is a strong oxidant 

that upon contact with water moist 

tissue (e.g., eyes, skin, and upper 

respiratory tract) can produce major 

tissue damage.75 Chronic inhalation 

exposure to low concentrations of Cl2 (1 

to 10 parts per million, ppm) may cause 

eye and nasal irritation, sore throat, and 

coughing. Chronic exposure to Cl2, 

usually in the workplace, has been 

reported to cause corrosion of the teeth. 

Inhalation of higher concentrations of 

Cl2 gas (greater than 15 ppm) can 

rapidly lead to respiratory distress with 

airway constriction and accumulation of 

fluid in the lungs (pulmonary edema). 

Exposed individuals may have 

immediate onset of rapid breathing, blue 

discoloration of the skin, wheezing, 

rales or hemoptysis (coughing up blood 

or blood-stain sputum). Intoxication 

with high concentrations of Cl2 may 

induce lung collapse. Exposure to Cl2

can lead to reactive airways dysfunction 

syndrome (RADS), a chemical irritantinduced type of asthma. Dermal 

exposure to Cl2 may cause irritation, 

burns, inflammation and blisters. EPA 

has not classified Cl2 with respect to 

carcinogenicity. 

vi. Chromium 

Chromium may be emitted in two 

forms, trivalent Cr (Cr+3) or hexavalent 

Cr (Cr+6). The respiratory tract is the 

major target organ for Cr+6 toxicity, for 

acute and chronic inhalation exposures. 

Shortness of breath, coughing, and 

wheezing have been reported from acute 

exposure to Cr+6, while perforations and 

ulcerations of the septum, bronchitis, 

decreased pulmonary function, 

pneumonia, and other respiratory effects 

have been noted from chronic 

exposures. Limited human studies 

suggest that Cr+6 inhalation exposure 

may be associated with complications 

during pregnancy and childbirth, but 

there are no supporting data from 

animal studies reporting reproductive 

effects from inhalation exposure to Cr+6. 

Human and animal studies have clearly 

established the carcinogenic potential of 

Cr+6 by the inhalation route, resulting in 

an increased risk of lung cancer. EPA 

has classified Cr+6 as a Group A, human 

carcinogen. Trivalent Cr is less toxic 

than Cr+6. The respiratory tract is also 

the major target organ for Cr+3 toxicity, 

similar to Cr+6. EPA has not classified 

Cr+3 with respect to carcinogenicity. 

vii. Formaldehyde 

Since 1987, EPA has classified 

formaldehyde as a probable human 

carcinogen based on evidence in 

humans and in rats, mice, hamsters, and 

monkeys.76 EPA is currently reviewing 

recently published epidemiological 

data. After reviewing the currently 

available epidemiological evidence, the 

IARC (2006) characterized the human 

evidence for formaldehyde 

carcinogenicity as ‘‘sufficient,’’ based 

upon the data on nasopharyngeal 

cancers; the epidemiologic evidence on 

leukemia was characterized as 

‘‘strong.’’ 77 EPA is reviewing the recent 

work cited above from the National 

Cancer Institute (NCI) and National 

Institute for Occupational Safety and 

Health (NIOSH), as well as the analysis 

by the CIIT Centers for Health Research 

and other studies, as part of a 

reassessment of the human hazard and 

dose-response associated with 

formaldehyde. 

Formaldehyde exposure also causes a 

range of noncancer health effects, 

including irritation of the eyes (burning 

and watering of the eyes), nose and 

throat. Effects from repeated exposure in 

humans include respiratory tract 

irritation, chronic bronchitis and nasal 

epithelial lesions such as metaplasia 

and loss of cilia. Animal studies suggest 

that formaldehyde may also cause 

airway inflammation—including 

eosinophil infiltration into the airways. 

There are several studies that suggest 

that formaldehyde may increase the risk 

of asthma—particularly in the 

young.78 79

viii. Hydrogen Chloride 

Hydrogen chloride is a corrosive gas 

that can cause irritation of the mucous 

membranes of the nose, throat, and 

respiratory tract. Brief exposure to 35 

ppm causes throat irritation, and levels 

of 50 to 100 ppm are barely tolerable for 

1 hour.80 The greatest impact is on the 

upper respiratory tract; exposure to high 

concentrations can rapidly lead to 

swelling and spasm of the throat and 

suffocation. Most seriously exposed 

persons have immediate onset of rapid 

breathing, blue coloring of the skin, and 

narrowing of the bronchioles. Exposure 

to HCl can lead to RADS, a chemicallyor irritant-induced type of asthma. 

Children may be more vulnerable to 

corrosive agents than adults because of 

the relatively smaller diameter of their 

airways. Children may also be more 

vulnerable to gas exposure because of 

increased minute ventilation per kg and 

failure to evacuate an area promptly 

when exposed. Hydrogen chloride has 

not been classified for carcinogenic 

effects.81

ix. Hydrogen Fluoride 

Acute (short-term) inhalation 

exposure to gaseous HF can cause 

severe respiratory damage in humans, 

including severe irritation and 

pulmonary edema. Chronic (long-term) 

oral exposure to fluoride at low levels 

has a beneficial effect of dental cavity 

prevention and may also be useful for 

the treatment of osteoporosis. Exposure 

to higher levels of fluoride may cause 

dental fluorosis. One study reported 


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82U.S. Environmental Protection Agency. Health 

Issue Assessment: Summary Review of Health 

Effects Associated with Hydrogen Fluoride and 

Related Compounds. EPA/600/8–89/002F. 

Environmental Criteria and Assessment Office, 

Office of Health and Environmental Assessment, 

Office of Research and Development, Cincinnati, 

OH. 1989. 

83Agency for Toxic Substances and Disease 

Registry (ATSDR). 2007. Public Health Statement 

for Lead. CAS#: 7439–92–1. Atlanta, GA: U.S. 

Department of Health and Human Services, Public 

Health Service. Available on the Internet at 

http://www.atsdr.cdc.gov/ToxProfiles/phs13.html. 

84U.S. Environmental Protection Agency. 

Integrated Risk Information System (IRIS) on 

Manganese. National Center for Environmental 

Assessment, Office of Research and Development, 

Washington, DC. 1999. 

85U.S. Environmental Protection Agency. 

Integrated Risk Information System (IRIS) on Nickel 

Subsulfide. National Center for Environmental 

Assessment, Office of Research and Development, 

Washington, DC. 1999. 

86U.S. Environmental Protection Agency. 

Integrated Risk Information System (IRIS) on Nickel 

Carbonyl. National Center for Environmental 

Assessment, Office of Research and Development, 

Washington, DC. 1999. 

87Nickel (IARC Summary & Evaluation, Volume 

49, 1990), http://www.inchem.org/documents/iarc/ 

vol49/nickel.html. 

88We believe our estimate of the current level of 

acid HAP emissions based on the 2010 ICR database 

may underestimate total EGU acid HAP emissions 

due to targeting of the 2010 ICR on the best 

performing EGUs. 

menstrual irregularities in women 

occupationally exposed to fluoride via 

inhalation. The EPA has not classified 

HF for carcinogenicity.82

x. Lead 

The main target for Pb toxicity is the 

nervous system, both in adults and 

children. Long-term exposure of adults 

to Pb at work has resulted in decreased 

performance in some tests that measure 

functions of the nervous system. Lead 

exposure may also cause weakness in 

fingers, wrists, or ankles. Lead exposure 

also causes small increases in blood 

pressure, particularly in middle-aged 

and older people. Lead exposure may 

also cause anemia. 

Children are more sensitive to the 

health effects of Pb than adults. No safe 

blood Pb level in children has been 

determined. At lower levels of exposure, 

Pb can affect a child’s mental and 

physical growth. Fetuses exposed to Pb 

in the womb may be born prematurely 

and have lower weights at birth. 

Exposure in the womb, in infancy, or in 

early childhood also may slow mental 

development and cause lower 

intelligence later in childhood. There is 

evidence that these effects may persist 

beyond childhood.83

There are insufficient data from 

epidemiologic studies alone to conclude 

that Pb causes cancer (is carcinogenic) 

in humans. DHHS has determined that 

Pb and Pb compounds are reasonably 

anticipated to be human carcinogens 

based on limited evidence from studies 

in humans and sufficient evidence from 

animal studies, and EPA has determined 

that Pb is a probable human carcinogen. 

xi. Manganese 

Health effects in humans have been 

associated with both deficiencies and 

excess intakes of Mn. Chronic exposure 

to high levels of Mn by inhalation in 

humans results primarily in central 

nervous system effects. Visual reaction 

time, hand steadiness, and eye-hand 

coordination were affected in 

chronically-exposed workers. 

Manganism, characterized by feelings of 

weakness and lethargy, tremors, a 

masklike face, and psychological 

disturbances, may result from chronic 

exposure to higher levels. Impotence 

and loss of libido have been noted in 

male workers afflicted with manganism 

attributed to inhalation exposures. The 

EPA has classified Mn in Group D, not 

classifiable as to carcinogenicity in 

humans.84

xii. Nickel 

Respiratory effects have been reported 

in humans from inhalation exposure to 

Ni. No information is available 

regarding the reproductive or 

developmental effects of Ni in humans, 

but animal studies have reported such 

effects. Human and animal studies have 

reported an increased risk of lung and 

nasal cancers from exposure to Ni 

refinery dusts and nickel subsulfide. 

The EPA has classified nickel subsulfide 

as a human carcinogen and nickel 

carbonyl as a probable human 

carcinogen.85 86 The IARC has classified 

Ni compounds as carcinogenic to 

humans.87

xiii. Selenium 

Acute exposure to elemental Se, 

hydrogen selenide, and selenium 

dioxide (SeO2) by inhalation results 

primarily in respiratory effects, such as 

irritation of the mucous membranes, 

pulmonary edema, severe bronchitis, 

and bronchial pneumonia. One Se 

compound, selenium sulfide, is 

carcinogenic in animals exposed orally. 

EPA has classified elemental Se as a 

Group D, not classifiable as to human 

carcinogenicity, and selenium sulfide as 

a Group B2, probable human 

carcinogen. 

b. Non-Hg HAP Emissions 

Fossil-fuel fired boilers emit a variety 

of metal HAP, organic HAP and HAP 

that are acid gases. Acid gas and metal 

HAP emissions are discussed below. 

i. Acid Gases 

Based on the 2010 ICR and the 

National Air Toxics Assessment (NATA) 

inventory estimates of acid gas 

emissions, U.S. EGUs emit the majority 

of HCl and HF nationally, supporting 

EPA’s view that it remains appropriate 

to regulate HAP from U.S. EGUs. Acid 

gas emissions from EGUs include HCl, 

HF, Cl2, and HCN. These pollutants are 

emitted as a result of fluorine, chlorine, 

and nitrogen components of the fuels. 

Table 4 of this preamble shows 

emissions of certain acid gases from 

EGUs, based on the 2005 NATA 

inventory. 2010 estimates of emissions 

for acid HAP from U.S. EGU are 7,900 

tpy for HCN, 106,000 tons for HCl, and 

36,000 tons for HF.88

TABLE 4—SUMMARY OF ACID GAS EMISSIONS FROM EGU SOURCES

2005 Acid HAP emissions from 

the National Air Toxics Assessment (NATA) (tpy) 

Percent of 

total U.S. 

anthropogenic 

emissions in 

2005 

U.S. EGU 

emissions 

U.S. Non-EGU 

emissions Non-EGU 

emissions 

Hydrogen Cyanide1 ..................................................................................................................... 1,200 14,000 8 

Hydrogen Chloride ....................................................................................................................... 350,000 78,000 82 

Hydrogen Fluoride ....................................................................................................................... 47,000 28,000 62 

1 Using cyanide emissions for HCN. 


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89We believe our estimate of the current level of 

metal HAP emissions based on the 2010 ICR 

database may underestimate total EGU metal HAP 

emissions due to targeting of the 2010 ICR on the 

best performing EGUs. 

90U.S. EPA. 2011. Technical Support Document: 

National-Scale Mercury Risk Assessment 

Supporting the Appropriate and Necessary Finding 

for Coal- and Oil-Fired Electric Generating Units. 

Office of Air Quality Planning and Standards. 

91U.S. EPA. 2011. Technical Support Document: 

Non-Mercury HAP Case Studies Supporting the 

Appropriate and Necessary Finding for Coal- and 

Oil-Fired Electric Generating Units. Office of Air 

Quality Planning and Standards. 

92The hazard quotient (HQ) is the estimated 

inhalation or ingestion exposure divided by the 

reference dose (RfD). 

93Strum, M., Houyoux, M., op. cit., Section 4. 

94The 2005 estimate is based on control 

configurations as of 2002, therefore it does not 

reflect reductions due to substantial control 

installations that took place between 2002 and 

2005. The 2010 estimates reflect control 

ii. Metal HAP 

U.S. EGUs are the predominant source 

of emissions nationally for many metal 

HAP, including Sb, As, Cr, Co, and Se. 

Metals are emitted primarily because 

they are present in fuels. Table 5 of this 

preamble shows selected metals emitted 

by EGUs and emission estimates based 

on data from the 2005 NATA inventory. 

2010 estimates of metal HAP emissions 

are 25 tpy for antimony (Sb), 43 tpy for 

As, 2 tpy for Be, 3 tpy for Cd, 222 tpy 

for Cr, 19 tpy for Co, 183 tpy for Mn, 

387 tpy for Ni, and 258 tpy for Se.89

Depending on the metal, EGUs account 

for between 13 and 83 percent of 

national metal HAP emissions, and as a 

result it remains appropriate to regulate 

EGUs. 

TABLE 5—SUMMARY OF METAL EMISSIONS FROM EGU SOURCES

2005 Metal HAP emissions from 

the inventory used 

for the National Air Toxics 

Assessment (NATA) (tpy) 

Percent of total 

U.S. anthropogenic emissions 

in 2005 U.S. EGU 

emissions 

U.S. Non-EGU 

emissions 

Antimony .................................................................................................................................... 19 83 19 

Arsenic ....................................................................................................................................... 200 120 62 

Beryllium .................................................................................................................................... 10 13 44 

Cadmium .................................................................................................................................... 25 38 39 

Chromium .................................................................................................................................. 120 430 22 

Cobalt ......................................................................................................................................... 54 60 47 

Manganese ................................................................................................................................ 270 1,800 13 

Nickel ......................................................................................................................................... 320 840 28 

Selenium .................................................................................................................................... 580 120 83 

3. Quantitative Risk Characterizations 

To Inform the Appropriate and 

Necessary Finding 

EPA conducted quantitative risk 

analyses to evaluate the extent of risk 

posed by emissions of HAP from U.S. 

EGUs. These analyses demonstrate that 

U.S. EGU HAP emissions do create the 

potential for risks to the public health, 

as described below. 

a. Scope of Quantitative Risk Analyses 

To evaluate the potential for public 

health hazards from emissions of Hg 

and non-Hg HAP from U.S. EGUs, EPA 

conducted quantitative risk analyses 

using several methods intended to 

address specific risk-related 

questions.90 91 Outputs from this 

assessment include: (1) The potential 

exposures to MeHg and risks associated 

with current U.S. EGU Hg emissions for 

populations most likely to be at risk 

from exposure to MeHg associated with 

U.S. EGU Hg emissions; (2) excess 

deposition of Hg in nearby locations 

within 50 kilometers (km) of EGUs that 

might result in Hg deposition 

‘‘hotspots’’; (3) for populations living in 

the vicinity of EGUs, the maximum 

individual risks (MIR) associated with 

U.S. EGU non-Hg HAP emissions, for 

both cancer and non-cancer risks, 

compared to established health 

benchmarks (e.g., greater than one in a 

million for cancer risks, and a HQ 

exceeding one for chronic non-cancer 

risks).92

To evaluate the potential for health 

risks associated with U.S. EGU Hg 

emissions, EPA conducted a national 

scale assessment of the impacts of U.S. 

EGU Hg emissions on exposures to 

MeHg above the RfD, and as a 

contributor to exposures above the RfD 

in conjunction with exposures from 

other U.S. and non-U.S. Hg emissions. 

To evaluate risks of U.S. EGU Hg 

‘‘hotspots,’’ EPA conducted a national 

scale assessment based on the Hg 

deposition modeling used in the 

national-scale Hg risk assessment. To 

evaluate inhalation risks of U.S. EGU 

non-Hg HAP emissions, EPA recently 

conducted 16 case studies at EGUs. EPA 

selected these case studies based on 

HAP emissions information from the 

ICR. For each case study, EPA estimated 

the MIR for cancer and non-cancer 

health effects for each HAP emitted by 

the case study U.S. EGU facility. Cancer 

risks for non-Hg HAP are estimated as 

the number of excess cancer cases per 

million people. This section briefly 

describes the methods used in the 

analyses and the results for the nationalscale Hg risk analysis and the non-Hg 

HAP inhalation risk case studies. 

b. Emissions for Hg and Non-Hg HAP 

The national-scale Hg risk analysis is 

based on modeling Hg deposition 

associated with 2005 U.S. EGU Hg 

emissions and 2016 projected Hg 

emissions. 

The 2005 base case includes 105 tons 

of Hg and 430,000 tons of HCl from all 

sources, of which 53 tons of Hg and 

350,000 tons of HCl are from EGUs. The 

2016 projected total Hg emissions from 

all sources used in the risk modeling are 

64 tons and HCl emissions are 140,000 

tons, with 29 tons of Hg and 74,000 tons 

of HCl from EGUs. U.S. EGU Hg 

emissions accounted for 50 percent of 

total U.S. Hg emissions in 2005 and are 

projected to account for 45 percent of 

such emissions in 2016. Details 

regarding the emissions used in these 

analyses are provided in the emissions 

memorandum, ‘‘Emissions Overview: 

Hazardous Air Pollutants in Support of 

the Proposed Toxics Rule’’.93

Between 2005 and 2010, Hg emissions 

in the U.S. have declined as a result of 

state regulations of Hg or Federal 

regulatory and enforcement actions that 

required installation of SO2 scrubbers at 

EGUs which decreased Hg emissions.94


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information reported to EPA as part of the recent 

2010 ICR in late 2009. 

The 2010 ICR shows the EGU Hg and 

HCl totals are lower than in 2005, at 29 

tons and 106,000 tons respectively. 

Given that the 2010 emissions for Hg 

are much closer to the 2016 projected 

emissions than to the 2005 emissions, 

we focus on the results from 2016 from 

the national-scale Hg risk analysis 

described below, as the projected 

emissions are almost the same as 

current HAP emissions from EGUs. 

c. National-Scale Hg Risk Modeling 

i. Purpose and Scope of Analysis 

The national-scale risk assessment for 

Hg focuses on risk associated with Hg 

released from U.S. EGUs that deposits to 

watersheds within the continental U.S., 

bioaccumulates in fish, and then is 

consumed as MeHg in fish eaten by 

subsistence fishers and other freshwater 

self-caught fish consumers. The risk 

assessment is intended to assess risk for 

scenarios representing high-end selfcaught fish consumers active at inland 

freshwater lakes and streams. This 

reflects our goal of determining whether 

U.S. EGUs represent a potential public 

health hazard for the group of fish 

consumers likely to experience the 

highest risk attributable to U.S. EGUs. In 

defining the high fish consuming 

populations included in the analysis, 

we have used information from studies 

of fish consumption to ensure that we 

have identified fisher populations that 

are likely active to some extent across 

the watersheds included in this analysis 

(i.e., they are not purely hypothetical). 

The risk assessment considered the 

magnitude and prevalence of the risk to 

public health posed by current U.S. 

EGU Hg emissions and the remaining 

risk posed by U.S. EGU Hg emissions 

after imposition of the requirements of 

the CAA, as described more fully below. 

In both cases, we assess the contribution 

of U.S. EGUs to potential risks from 

MeHg exposure relative to total MeHg 

risk associated with Hg deposited by 

other sources both domestic and 

international. 

Risk from Hg exposures occurs 

primarily through the consumption of 

fish that have bioaccumulated MeHg 

originally deposited to watersheds 

following atmospheric release and 

transport. The population that is most at 

risk from consumption of MeHg in fish 

is children born to mothers who were 

exposed to MeHg during pregnancy 

through fish consumption. The type of 

fish consumption likely to lead to the 

greatest exposure to MeHg attributable 

to U.S. EGUs is associated with fishing 

activity at inland freshwater rivers and 

lakes located in regions with elevated 

U.S. EGU Hg deposition. Thus we focus 

on MeHg exposure to women of 

childbearing age who consume selfcaught freshwater fish on a regular 

basis, e.g., once a day to once every 

several days. 

As noted above, current U.S. EGU Hg 

emissions as reflected in the 2010 ICR 

are closer to 2016 projected emissions 

than to the 2005 emissions. For this 

reason, in discussing risk estimates, we 

focus on the 2016 results rather than the 

2005 results. 

The risk assessment compares the 

U.S. EGU incremental contribution to 

total potential exposure with the RfD 

and also evaluates the percent of total 

Hg exposures from all sources 

contributed by U.S. EGUs (i.e., the 

fraction of total risk associated with U.S. 

EGUs) to individual watersheds for 

which we have fish tissue MeHg data. 

We used this information to assess 

whether a public health hazard is 

associated with U.S. EGU emissions. 

Our focus is on women of child-bearing 

age in subsistence fishing populations 

who consume freshwater fish that they 

or their family caught. These 

populations are likely to experience the 

greatest risk from Hg exposure when 

fishing at inland (freshwater) locations 

that receive the highest levels of U.S. 

EGU-attributable Hg deposition. We also 

acknowledge that additional 

populations are likely exposed to MeHg 

from consuming fish caught in nearcoastal, e.g., estuarine environments. 

However, there is high uncertainty 

about the relationship of MeHg levels in 

those fish and deposition of Hg from 

U.S. EGUs, and as such we have not 

included those types of fish 

consumption in our analysis. However, 

it is likely that the range of potential 

exposures to U.S. EGU Hg deposition 

across inland watersheds captures the 

types of potential exposures that occur 

in near-coastal environments, and, thus, 

likely represents potential risks from 

consumption of fish caught in those 

environments. 

Consumption rates for the high-end 

fishing populations included in the risk 

assessment are based on studies in the 

published literature, and are 

documented in the TSD accompanying 

this finding. 

We do not estimate risks associated 

with commercial fish consumption 

because of the expected low 

contribution of U.S. EGU Hg to this type 

of fish, relative to non-U.S. Hg 

emissions, and the high levels of 

uncertainty in mapping U.S. EGU Hg 

emissions to concentrations of MeHg in 

ocean-going fish. The population 

affected by those U.S. EGU Hg 

emissions that go into the global pool of 

Hg will potentially be much larger than 

the population of the U.S. Thus, the 

impacts of U.S. EGUs on global 

exposures to Hg, while highly uncertain, 

adds additional support to the finding 

that Hg emissions from U.S. EGUs pose 

a hazard to public health. 

ii. Risk Characterization Framework 

EPA assessed risk from potential 

exposure to MeHg through fish 

consumption at a subset of watersheds 

across the country for which we have 

measured fish tissue MeHg data. This 

risk assessment uses estimates of 

potential exposure for subsistence fisher 

populations to generate risk metrics 

based on comparisons of MeHg 

exposure to the reference dose. We are 

focusing on exposures above the RfD 

because it represents a sensitive risk 

metric that captures a wide range of 

neurobehavioral health effects. 

Reductions in exposure to MeHg are 

also expected to result in reductions in 

specific adverse effects including lost IQ 

points, and we discuss the risk analysis 

related to IQ loss in the National Scale 

Mercury Risk Assessment TSD. 

For the analysis, we have developed 

a risk characterization framework for 

integrating two types of U.S. EGUattributable risk estimates. This 

framework estimates the percent of 

watersheds where populations may be 

at risk due to potential exposures to 

MeHg attributable to U.S. EGU. The 

analysis is limited to those watersheds 

for which we have fish tissue MeHg 

samples, a total of approximately 2,400 

out of 88,000 watersheds in the U.S. 

This total percent of watersheds 

includes ones that either have 

deposition of Hg from U.S. EGUs that is 

sufficient to lead to potential exposures 

that exceed the reference dose, even 

without considering the contributions 

from other U.S. and non-U.S. sources, or 

have deposition of Hg from U.S. EGUs 

that contributes at least 5 percent to 

total Hg deposition from all sources, in 

watersheds where potential exposures 

to MeHg from all sources (U.S. EGU, 

U.S. non-EGU, and non-U.S.) exceed the 

RfD. 

This framework allows EPA to 

consider whether U.S. EGUs, evaluated 

without consideration of other sources, 

or in combination with other sources of 

Hg, pose a potential public health 

hazard. 

iii. Analytical Approach 

Several elements of this risk analysis 

including spatial scale, estimates of Hg 

deposition, estimates of fish tissue 

MeHg concentrations, estimates of fish 

consumptions rates, and calculation of 


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95U.S. Geological Survey and U.S. Department of 

Agriculture, Natural Resources Conservation 

Service, 2009, Federal guidelines, requirements, 

and procedures for the national Watershed 

Boundary Dataset: U.S. Geological Survey 

Techniques and Methods 11–A3, 55 p. 

96Mercury Maps—A Quantitative Spatial Link 

Between Air Deposition and Fish Tissue Peer 

Reviewed Final Report. U.S. EPA, Office of Water, 

EPA–823–R–01–009, September, 2001. 

97http://water.epa.gov/scitech/swguidance/ 

fishshellfish/fishadvisories/. 

MeHg exposure are discussed in detail 

in the National Scale Mercury Risk 

Assessment TSD accompanying this 

finding, and are briefly summarized 

below. 

Watersheds can be defined at varying 

levels of spatial resolution. For the 

purposes of this risk analysis, we have 

selected to use watersheds classified 

using 12-digit Hydrologic Unit Codes 

(HUC12),95 representing a fairly refined 

level of spatial resolution with 

watersheds generally 5 to 10 km on a 

side, which is consistent with research 

on the relationship between changes in 

Hg deposition and changes in MeHg 

levels in aquatic biota. 

After estimating total MeHg risk based 

on modeling consumption of fish at 

each of these watersheds, the ratio of 

U.S. EGU to total Hg deposition over 

each watershed (estimated using 

Community Multi-scale Air Quality 

modeling) is used to estimate the U.S. 

EGU-attributable fraction of total MeHg 

risk. This apportionment of total risk 

between the U.S. EGU fraction and the 

fraction associated with all other 

sources of Hg deposition is based on the 

EPA’s Office of Water’s Mercury Maps 

(MMaps) approach that establishes a 

proportional relationship between Hg 

deposition over a watershed and 

resulting fish tissue Hg levels, assuming 

a number of criteria are met.96

The fish tissue dataset for the risk 

assessment includes fish tissue Hg 

samples from the years 2000 to 2009, 

with samples distributed across 2,461 

HUC12s. The samples are more heavily 

focused on locations east of the 

Mississippi River. The fish tissue 

samples come primarily from three 

sources: the National Listing of Fish 

Advisory (NLFA) database managed by 

EPA; 97 the U.S. Geologic Survey 

(USGS), which manages a compilation 

of Hg datasets as part of its 

Environmental Mercury Mapping and 

Analysis (EMMA) program, and EPA’s 

National River and Stream Assessment 

(NRSA) study data. Most of the 

watersheds with measured fish tissue 

MeHg data had multiple measurements. 

This assessment used the 75th 

percentile fish tissue value at each 

watershed as the basis for exposure and 

risk characterization, based on the 

assumption that subsistence fishers 

would favor larger fish which have the 

potential for higher bioaccumulation. 

The use of the 75th percentile fish tissue 

MeHg value as the basis for risk 

characterization reflects our overall goal 

of modeling realistic high-end fishing 

behavior; in this case, reflecting 

individuals who target somewhat larger 

fish for purposes of supplementing their 

diets (the average fisher may eat a 

variety of different sized fish, but in 

order to capture higher potential MeHg 

exposure scenarios, it is realistic to 

assume that some fishers may favor 

somewhat larger fish). 

Deposition of Hg for the continental 

U.S. was estimated using the 

Community Multiscale Air Quality 

model v4.7.1 (http://www.cmaqmodel.org), applied at a 12 km grid 

resolution. 

The CMAQ modeling was used to 

estimate total annual Hg deposition 

from U.S. and non-U.S. anthropogenic 

and natural sources over each 

watershed. In addition, CMAQ 

simulations were conducted where U.S. 

EGU Hg emissions were set to zero to 

determine the contribution of U.S. EGU 

Hg emissions to total Hg deposition. 

U.S. EGU-related Hg deposition 

characterized at the watershed-level for 

2005 and 2016 is summarized in Table 

6 of this preamble for the complete set 

of 88,000 HUC12 watersheds. 

Table 6 is intended to demonstrate the 

wide variation across watersheds in the 

contribution of EGU emissions to 

deposition. The percentiles of total Hg 

deposition and U.S. EGU-attributable 

deposition are not linked, e.g., the 99th 

percentile of the percent of total 

deposition attributable to U.S. EGUs is 

based on the distribution of total Hg 

deposition, and the 99th percentile of 

U.S. EGU-attributable Hg deposition is 

based on the distribution of U.S. EGUattributable deposition. These 

percentiles do not occur at the same 

watershed. 

TABLE 6—COMPARISON OF TOTAL AND U.S. EGU-ATTRIBUTABLE Hg DEPOSITION (μg/m2) FOR THE 2005 AND 2016 

SCENARIOS * 

Statistic 

2005 2016 

Total Hg 

deposition 

U.S. EGUattributable 

Hg deposition 

Total Hg 

deposition 

U.S. EGUattributable 

Hg deposition 

Mean ................................................................................................................................ 19.41 0.89 18.66 0.34 

Median ............................................................................................................................. 17.25 0.24 16.59 0.15 

75th percentile ................................................................................................................. 23.69 1.07 22.83 0.46 

90th percentile ................................................................................................................. 30.78 2.38 29.90 0.85 

95th percentile ................................................................................................................. 36.85 3.60 35.16 1.18 

99th percentile ................................................................................................................. 58.32 7.77 56.23 2.41 

* Statistics are based on CMAQ results interpolated to the watershed-level and are calculated using all ∼88,000 watersheds in the U.S. 

To give a better idea of the 

relationship between total deposition 

and U.S. EGU-attributable deposition, 

we also summarize the percent of total 

Hg deposition attributable to U.S. EGUs 

(by percentile) in Table 7. Table 7 shows 

the high variability in the percent 

contribution from U.S. EGU Hg 

emissions. Tables 6 and 7 cannot be 

directly compared, as the watershed 

with the 99th percentile U.S. EGUattributable deposition is not the same 

watershed as the watershed with the 

99th percentile U.S. EGU-attributable 

fraction of total Hg deposition. A 

watershed can have a high U.S. EGUattributable fraction of total deposition 

and still have overall low Hg deposition. 


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98The MMaps approach implements a simplified 

form of the IEM–2M model applied in EPA’s 

Mercury Study Report to Congress (Mercury 

Maps—A Quantitative Spatial Link Between Air 

Deposition and Fish Tissue Peer Reviewed Final 

Report. U.S. EPA, Office of Water, EPA–823–R–01– 

009, September, 2001). By simplifying the 

assumptions inherent in the freshwater ecosystem 

models that were described in the Report to 

Congress, the MMaps model showed that these 

models converge at a steady-state solution for MeHg 

concentrations in fish that are proportional to 

changes in Hg inputs from atmospheric deposition 

(e.g., over the long term fish concentrations are 

expected to decline proportionally to declines in 

atmospheric loading to a watershed). This solution 

only applies to situations where air deposition is 

the only significant source of Hg to a water body, 

and the physical, chemical, and biological 

characteristics of the ecosystem remain constant 

over time. EPA recognizes that concentrations of 

MeHg in fish across all ecosystems may not reach 

steady state and that ecosystem conditions affecting 

Hg dynamics are unlikely to remain constant over 

time. EPA further recognizes that many water 

bodies, particularly in areas of historic gold and Hg 

mining in western states, contain significant nonair sources of Hg (note, however, that as described 

below, we have excluded those watersheds 

containing gold mines or with other non-EGU 

related anthropogenic Hg releases exceeding 

specified thresholds). 

99The risk assessment is not designed to track the 

detailed temporal profile associated with changes in 

fish tissue MeHg levels following changes in Hg 

deposition. Rather, we are focusing on estimating 

risk in the future, assuming that near steady state 

conditions have been reached (following a 

simulated change in Hg deposition). Additional 

detail regarding the temporal profile issue and other 

related factors (e.g., methylation potential across 

watersheds) is discussed in Section 1.3 and in 

Appendix E of the National Scale Mercury Risk 

Assessment TSD). 

100A number of criteria had to be met for a study 

to be used in providing explicit consumption rates 

for the high-end fisher populations of interest in 

this analysis. For example, studies had to provide 

estimates of self-caught fish consumption and not 

conflate these estimates with consumption of 

commercially purchased fish. Furthermore, these 

studies had to focus on freshwater fishing activity, 

or at least have the potential to reflect significant 

contributions from that category, such that the fish 

consumption rates provided in a study could be 

reasonably applied in assessing freshwater fishing 

activity. Studies also had to provide statistical 

estimates of fish consumptions (i.e., means, 

medians, 90th percentiles, etc). Given our interest 

in higher-end consumption rates, the studies also 

had to either provide upper percentile estimates, or 

support the derivation of those estimates (e.g., 

provide medians and a standard deviations). 

Studies of activity at specific watersheds (e.g., creel 

surveys), while informative in supporting the 

presence of higher-end consumption rates, could 

not be used as the basis for defining our high-end 

consumption rates since there would be greater 

uncertainty in extrapolating activity at a specific 

river or lake more broadly to fishing populations in 

a region. Therefore, we focused on studies 

characterizing fishing activity more broadly than at 

a specific fishing location. 

TABLE 7—COMPARISON OF PERCENT OF TOTAL Hg DEPOSITION ATTRIBUTABLE TO U.S. EGUS FOR 2005 AND 2016 * 

Statistic 2005 

(percent) 

2016 

(percent) 

Mean ................................................................................................................................................................................ 5 2 

Median ............................................................................................................................................................................. 1 1 

75th percentile ................................................................................................................................................................. 6 3 

90th percentile ................................................................................................................................................................. 13 5 

95th percentile ................................................................................................................................................................. 18 6 

99th percentile ................................................................................................................................................................. 30 11 

* Values are based on CMAQ results interpolated to the watershed-level and reflect trends across all ∼88,000 watersheds in the U.S. 

U.S. EGUs are estimated to contribute 

up to 30 percent of total Hg deposition 

in 2005 and up to 11 percent in 2016. 

EPA estimates the relationship 

between the EGU-attributable Hg 

deposition and EGU-attributable fish 

tissue MeHg concentrations using an 

assumption of linear proportionality 

based on the agency’s MMaps approach. 

The MMaps assumption specifies that, 

under certain conditions (e.g., Hg air 

deposition is the primary source of Hg 

loading to a watershed and near steadystate conditions have been reached), a 

fractional change in Hg deposition to a 

watershed will ultimately be reflected in 

a matching proportional change in the 

levels of MeHg in fish.98 99 This 

assumption holds in watersheds where 

air deposition is the primary source of 

Hg loadings, and as a result, watersheds 

where this is not the case are removed 

from the risk analysis. The practical 

application of the MMaps approach is 

that U.S. EGUs will account for the 

same proportion of fish tissue MeHg in 

a watershed as they do for Hg 

deposition. MMaps is discussed in 

greater detail in section 1.3 and 

Appendix E of the National Scale 

Mercury Risk Assessment TSD. Patterns 

of U.S. EGU-attributable fish tissue 

MeHg concentrations are summarized in 

Table 8 of this preamble. Table 8 of this 

preamble compares total and U.S. EGUattributable fish tissue MeHg 

concentrations for the 2005 and 2016 

scenarios by watershed percentile. 

TABLE 8—COMPARISON OF TOTAL AND U.S. EGU-ATTRIBUTABLE FISH TISSUE MeHg CONCENTRATIONS FOR 2005 AND

2016 

Statistic 

Fish tissue MeHg concentration (ppm) 

2005 2016 

Total U.S. EGUattributable Total U.S. EGUattributable 

Mean ................................................................................................................................ 0.31 0.024 0.29 0.008 

50th Percentile ................................................................................................................. 0.23 0.014 0.20 0.005 

75th Percentile ................................................................................................................. 0.39 0.032 0.36 0.011 

90th Percentile ................................................................................................................. 0.67 0.056 0.63 0.019 

95th Percentile ................................................................................................................. 0.91 0.079 0.87 0.026 

99th Percentile ................................................................................................................. 1.34 0.150 1.29 0.047 

Because the focus of this analysis is 

on higher-consumption self-caught 

fisher populations active at inland 

freshwater locations, we identified 

surveys of higher consumption fishing 

populations active at inland freshwater 

rivers and lakes within the continental 

U.S. to inform the selection of 

consumption rate scenarios.100


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101Reflecting the fact that higher levels of selfcaught fish consumption (approaching subsistence) 

have been associated with poorer populations, we 

only assessed this generalized high-end female 

consumer scenario at those watersheds located in 

U.S. Census tracts with at least 25 individuals 

living below the poverty line (this included the vast 

majority of the 2,461 watersheds and only a handful 

were excluded due to this criterion). 

102As noted earlier, each high-end fish 

consuming female population included in the 

analysis was assessed for a subset of these 

watersheds, depending on which of those 

watersheds intersected a U.S. Census tract 

containing a ‘‘source population’’ for that fish 

consuming population. Of the populations assessed, 

the low-income female subsistence fishing 

population scenario was assessed for the largest 

portion (2,366) of the 2,461 watersheds. 

103Morgan, 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. 

104Because of the MMaps assumption of linear 

proportionality between deposition and exposures, 

a 5 percent U.S. EGU contribution to deposition 

will produce an equivalent 5 percent U.S. EGU 

contribution to MeHg exposures. 

105Burger, J., K. Pflugh, L. Lurig, L. Von Hagen, 

and S. Von Hagen. 1999. Fishing in Urban New 

Jersey: Ethnicity Affects Information Sources, 

Perception, and Compliance. Risk Analysis 19(2): 

217–229. 

106Burger, J., Stephens, W., Boring, C., Kuklinski, 

M., Gibbons, W.J., & Gochfield, M. (1999). Factors 

in exposure assessment: Ethnic and socioeconomic 

differences in fishing and consumption of fish 

caught along the Savannah River. Risk Analysis, 

19(3). 

107Chemicals 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, 

California Environmental Protection Agency, July 

1997. 

108Corburn, 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). 

109Specifically, upper percentile risk estimates 

for the high-end female consumer assessed at the 

national level were notably higher than matching 

percentile estimates for the Hmong, Vietnamese, 

Hispanic, and Tribal populations. By contrast, risk 

estimates for whites in the southeast were 

somewhat higher than the high-end female 

consumer, while risk estimates for blacks in the 

southeast were notably higher (see summary of risk 

estimates in the TSD supporting this finding). 

110The National Scale Mercury Risk Assessment 

TSD discusses the greater uncertainty in 

characterizing the magnitude of high-end fish 

consumption for these specialized populations due, 

in particular, to the lower sample sizes associated 

with the survey data (see Appendix C, Table C–1). 

Information on the studies used to 

develop the high end fish consumption 

scenarios for the risk analysis is 

provided in the National Scale Mercury 

Risk Assessment TSD. 

Generally all of the studies identified 

high-end percentile consumption rates 

(90th to 99th percentiles for the 

populations surveyed) ranging from 

approximately one fish meal every few 

days to a fish meal a day (i.e., 120 grams 

per day (g/day) to greater than 500 g/day 

fish consumption). We used this trend 

across the studies to support application 

of a generalized female high-end fish 

consumption scenario (high-end female 

consumer scenario) across most of the 

2,461 watersheds.101

iv. Risk Related to Exposure to MeHg in 

Fish and Assessment of Contribution of 

U.S. EGUs to MeHg Exposure and Risk 

For the scenario representing highend female fish consumption, we 

estimated total exposure to MeHg at 

each of the 2,461 watersheds.102

Estimates of total Hg exposure were 

generated by combining 75th percentile 

fish tissue values with the consumption 

rates for female subsistence fishers. A 

cooking loss factor (reflecting the fact 

that the preparation of fish can result in 

increased Hg concentrations) was also 

included in exposure calculations.103

Our estimates of total percent of 

watersheds where female subsistence 

fishing populations may be at risk from 

exposure to U.S. EGU-attributable MeHg 

are as high as 28 percent. The upper end 

estimate of 28 percent of watersheds 

reflects the 99th percentile fish 

consumption rate for that population, 

and a benchmark of 5 percent U.S. EGU 

contribution to total Hg deposition in 

the watershed. Any contribution of Hg 

emissions from EGUs to watersheds 

where potential exposures from total Hg 

deposition exceed the RfD is a hazard to 

public health, but for purposes of our 

analyses we evaluated only those 

watersheds where we determined EGUs 

contributed 5 percent or more to 

deposition to the watershed. EPA 

believes this is a conservative approach 

given the increasing risks associated 

with incremental exposures above the 

RfD. Of the total number of watersheds 

where populations may be at risk from 

exposure to EGU-attributable MeHg, we 

estimate that up to 22 percent of 

watersheds included in this analysis 

could potentially have populations at 

risk based on consideration of the U.S. 

EGU attributable fraction (e.g., 5, 10, 15, 

or 20 percent) of total Hg deposition 

over watersheds with total risk judged 

to represent a public health hazard 

(MeHg total exposure greater than the 

RfD).104 Of the total number of 

watersheds where populations may be 

at risk from exposures to U.S. EGUattributable MeHg, we estimate that up 

to 12 percent of watersheds included in 

this analysis could potentially have 

populations at risk because the U.S. 

EGU incremental contribution to 

exposure is above the RfD, even before 

consideration of contributions to 

exposures from U.S. non-EGU and nonU.S. sources. In other words, for this 12 

percent of watersheds, even if there 

were no other sources of Hg exposure, 

exposures associated with deposition 

attributable to U.S. EGUs would place 

female high-end consumers above the 

MeHg RfD. The upper end estimate of 

12 percent of watersheds reflects a 

scenario using the 99th percentile fish 

consumption rate. 

The two estimates of percent of 

watersheds where populations may be 

at risk from EGU-attributable Hg do not 

sum to the total estimates of 28 percent 

because some watersheds where U.S. 

EGUs contribute greater than 5 percent 

to total Hg deposition also have U.S. 

EGU attributable exposures that exceed 

the RfD without consideration of 

exposures from other U.S. and non-U.S. 

Hg sources. 

Exposures based on the 99th 

percentile consumption rate represent 

close to maximum potential individual 

risk estimates. These consumption rates 

are based on data reported by fishers in 

surveys, and, thus, represent actual 

consumption rates in U.S. populations. 

There are also a number of case studies 

in other locations, such as poor urban 

areas, which provide additional 

evidence that high fish consumption 

occurs in a number of locations 

throughout the U.S.105 106 107 108

However, EPA does not have 

sufficiently complete data on the 

specific locations where these high selfcaught fish consuming populations 

reside and fish, and as a result, there is 

increased uncertainty about the 

prevalence of populations who are highend consumers of fish caught in the set 

of watersheds included in the analysis. 

Populations matching the high-end fish 

consumption scenario could be 

restricted to a subset of these 

watersheds, or could be more heavily 

focused at watersheds with higher or 

lower U.S. EGU-attributable fish tissue 

MeHg (and consequently higher or 

lower U.S. EGU-attributable risk). 

With regard to the other fisher 

populations included in the full risk 

assessment described in the TSD 

(Vietnamese, Laotians, Hispanics, blacks 

and whites in the southeast, and tribes 

in the vicinity of the Great Lakes), our 

risk estimates suggests that the high-end 

female consumer assessed at the 

national-level generally provides 

coverage (in terms of magnitude of risk) 

for all of these fisher populations except 

blacks and whites in the southeast.109 110


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111The sensitivity analyses completed for the risk 

assessment focused on assessing sources of 

uncertainty associated with the application of the 

MMaps approach, because this was a critical 

element in the risk assessment and identified early 

on as a key source of potential uncertainty. Given 

the schedule of the analysis, we did not have time 

to complete a full influence analysis to identify 

those additional modeling elements that might 

introduce significant uncertainty and therefore 

should be included in a sensitivity analysis. 

Appendix F, Table F–2 of the Mercury Risk TSD 

provides a qualitative discussion of key sources of 

uncertainty and their potential impact on the risk 

assessment. 

112 In addition to non-air Hg sources of loadings, 

some regions of concern may also have longer lag 

period associated with the linkage between Hg 

deposition such that the fish tissue MeHg levels we 

are using are actually associated with older 

historical Hg deposition patterns. 

v. Variability and Uncertainty 

(Including Discussion of Sensitivity 

Analyses) 

There are some uncertainties in EPA’s 

analyses which could lead to under or 

over prediction of risk to public health 

from U.S. EGU Hg emissions. Based on 

sensitivity analyses we have conducted, 

we conclude that even under different 

assumptions about the applicability of 

the MMaps proportionality assumption, 

Hg from U.S. EGUs constitutes a hazard 

to public health due to the percent of 

watersheds where U.S. EGUs cause or 

contribute to exposures to MeHg above 

the RfD. 

Key sources of uncertainty potentially 

impacting the risk analysis include: 

(1) Uncertainty in predicting Hg 

deposition over watersheds using 

CMAQ; (2) uncertainty in predicting 

which watersheds will be subject to 

high-end fishing activity and the nature 

of that activity (e.g., frequency of 

repeated activity at a given watershed 

and the types/sizes of fish caught); (3) 

uncertainty in using MMaps to 

apportion exposure and risk between 

different sources, including U.S. EGUs, 

and predicting changes in fish tissue 

MeHg levels for future scenarios; and (4) 

potential under-representation of 

watersheds highly impacted by U.S.- 

attributable Hg deposition due to 

limited MeHg sampling. In the National 

Scale Mercury Risk Assessment TSD, 

we describe in greater detail key sources 

of uncertainty impacting the risk 

analysis, including their potential 

impact on the risk estimates and the 

degree to which their potential impact 

is characterized as part of the analysis. 

As part of the analysis, we have also 

completed a number of sensitivity 

analyses focused on exploring the 

impact of uncertainty related to the 

application of the MMaps approach in 

apportioning exposure and risk 

estimates between sources (U.S. EGU 

and total) and in predicting changes in 

fish tissue MeHg levels.111 These 

sensitivity analyses evaluated: (1) The 

effect of including watersheds that may 

be disproportionately impacted by nonair Hg sources; 112 and (2) the 

representativeness of the MMaps 

approach, which was tested for lakes, 

when applied to streams and rivers (in 

the analysis, the MMaps was applied to 

watersheds including a mixture of 

streams, rivers, and lakes). The results 

of the limited sensitivity analyses we 

were able to conduct suggest that 

uncertainties due to application of 

MMaps would not affect our finding 

that U.S. EGU-attributable Hg 

deposition poses a hazard to public 

health. 

We also examined the potential for 

under-representation of watersheds 

highly impacted by U.S.-attributable Hg 

deposition due to limited MeHg 

sampling, by identifying watersheds 

that did not have fish tissue MeHg 

samples, but had U.S. EGU-attributable 

Hg deposition at least as high as 

watersheds that were identified as being 

at risk of potential exposures greater 

than the RfD. Comparing the pattern of 

U.S. EGU-attributable Hg deposition 

across all watersheds with that for 

watersheds containing fish tissue MeHg 

data shows that while we have some 

degree of coverage for watersheds with 

high U.S. EGU-attributable deposition, 

this coverage is limited, especially in 

areas of Pennsylvania which have high 

levels of U.S. EGU-attributable 

deposition. For this reason, we believe 

that the actual number of watersheds 

where populations may be at risk from 

exposures to U.S. EGU-attributable 

MeHg could be substantially larger than 

the number estimated based on the 

available fish tissue MeHg sampling 

data. 

d. U.S. EGU Case Studies of Cancer and 

Non-Cancer Inhalation Risks for Non-Hg 

HAP 

EPA conducted 16 case studies to 

estimate the potential for human health 

impacts from current emissions of HAP 

other than Hg from EGUs. A refined 

chronic inhalation risk assessment was 

performed for each case study facility. 

The results of this analysis were that 4 

(out of 16) facilities posed a lifetime 

cancer risk of greater than 1 in 1 million 

(the maximum was 10 in 1 million) and 

3 more posed a risk at 1 in 1 million. 

Risk was driven by Ni (the oil-fired unit) 

and Cr∂6 (the coal-fired units). 

i. Case Study Selection 

An initial set of eight case study 

facilities was selected based on several 

factors. First, we considered facilities 

with the highest estimated cancer and 

non-cancer risks using the 2005 

National Emissions Inventory (NEI) data 

and the Human Exposure Model (HEM). 

The 2005 NEI data were used because 

the initial set of case study facilities was 

selected before we received the bulk of 

the emissions data from the 2010 ICR. 

Other factors considered in the selection 

included whether facilities had 

implemented emission control measures 

since 2005, and their proximity to 

residential areas. After the receipt of 

more data through the 2010 ICR, 

additional case study facilities were 

selected, based on the magnitude of 

emissions, heat input values 

(throughput), and level of emission 

control. There were a total of 16 case 

study facilities, 15 that use coal as fuel, 

and 1 that uses oil. 

ii. Methods 

Annual emissions estimates for each 

EGU (including those in the initial set 

of case study facilities) were developed 

using data from the 2010 ICR. The 

results for the initial set indicated that 

Ni, Cr∂6, and As were the cancer risk 

drivers, and that non-cancer risks did 

not produce any hazard index (HI) 

estimates exceeding one. Although the 

non-cancer risks were low (the 

maximum chronic noncancer HI was 

0.4), they were driven by emissions of 

Ni, As, and HCl. For the reasons 

discussed above, emissions were 

estimated only for Ni, Cr∂6, and As for 

the additional case study facilities. 

Additional details on the emissions 

used in the modeling are provided in a 

supporting memorandum to the docket 

for this action (Non-Hg Case Study 

Chronic Inhalation Risk Assessment for 

the Utility MACT ‘‘Appropriate and 

Necessary’’ Analysis) (Non-Hg Memo). 

For each of the 16 case study facilities, 

we conducted refined dispersion 

modeling with EPA’s AERMOD 

modeling system (U.S. EPA, 2004) to 

calculate annual ambient 

concentrations. Average annual 

concentrations were calculated at 

census block centroids. 

We calculated the MIR for each 

facility as the cancer risk associated 

with a continuous lifetime (24 hours per 

day, 7 days per week, and 52 weeks per 

year for a 70-year period) exposure to 

the maximum concentration at the 

centroid of an inhabited census block, 

based on application of the unit risk 

estimate from EPA’s IRIS, which is a 

human health assessment program that 

evaluates quantitative and qualitative 

risk information on effects that may 

result from exposure to environmental 

contaminants. For Ni compounds, we 


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113U.S. EPA, 1986, Guidelines for the Health Risk 

Assessment of Chemical Mixtures, EPA–630–R–98– 

002. http://www.epa.gov/NCEA/raf/pdfs/

chem_mix/chemmix_1986.pdf. 

114U.S. EPA, 2000. Supplementary Guidance for 

Conducting Health Risk Assessment of Chemical 

Mixtures. EPA–630/R–00–002. http://www.epa.gov/ 

ncea/raf/pdfs/chem_mix/chem_mix_08_2001.pdf. 

115Crump, Kate L., and Trudeau, Vance L. 

Mercury-induced reproductive impairment in fish. 

Environmental Toxicology and Chemistry. Vol. 28, 

No. 5, 2009. 

116U.S. Environmental Protection Agency (EPA). 

1997. Mercury Study Report to Congress. Volume 

V: Health Effects of Mercury and Mercury 

Compounds. EPA–452/R–97–007. U.S. EPA Office 

of Air Quality Planning and Standards, and Office 

of Research and Development. 

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

EPA). 2005. Regulatory Impact Analysis of the Final 

Clean Air Mercury Rule. Office of Air Quality 

Planning and Standards, Research Triangle Park, 

NC., March; EPA report no. EPA–452/R–05–003. 

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

ecas/regdata/RIAs/mercury_ria_final.pdf. 

117Evers, David C., Savoy, Lucas J., DeSorbo, 

Christopher R., Yates, David E., Hanson, William, 

Taylor, Kate M., Siegel, Lori S., Cooley, John H. Jr., 

Bank, Michael S., Major, Andrew, Munney, 

Kenneth, Mower, Barry F., Vogel, Harry S., Schoch, 

Nina, Pokras, Mark, Goodale, Morgan W., Fair, Jeff. 

Adverse effects from environmental mercury loads 

on breeding common loons. Ecotoxicology. 17:69– 

81, 2008. 

118Adams, Evan M., and Frederick, Peter C. 

Effects of methylmercury and spatial complexity on 

foraging behavior and foraging efficiency in juvenile 

used 65 percent of the IRIS URE for 

nickel subsulfide. The determination of 

this value is discussed in the Non-Hg 

Memo, and the value is receiving peer 

review as discussed in section later. To 

assess the risk of non-cancer health 

effects from chronic exposures, 

following the approach recommended 

in EPA’s Mixtures Guidelines,113 114 we 

summed the HQs for all HAP that affect 

a common target organ system to obtain 

the HI for that target organ system 

(target-organ-specific HI, or TOSHI). The 

HQ for chronic exposures is the 

estimated chronic exposure (again, 

based on the estimated annual average 

ambient concentration at each nearby 

census block centroid) divided by the 

chronic non-cancer reference level, 

which is usually the EPA reference 

concentration (RfC). In cases where an 

IRIS RfC is not available, EPA utilizes 

the following prioritized sources for 

chronic dose-response values: (1) The 

Agency for Toxic Substances and 

Disease Registry (ATSDR) Minimum 

Risk Level (MRL), and (2) the California 

Environmental Protection Agency 

chronic Reference Exposure Level 

(REL). In this assessment, we used the 

IRIS RfC values for Cr∂6 and HCl, the 

ATSDR MRL for Ni compounds, and the 

California Environmental Protection 

Agency REL for As. 

iii. Results 

The highest estimated lifetime cancer 

risk from any of the 16 case study 

facilities was 10 in 1 million (1 × 10¥5), 

driven by Ni emissions from the 1 case 

study facility with oil-fired units. For 

the facilities with coal-fired units, there 

were 3 with maximum cancer risks 

greater than 1 in 1 million (the highest 

was 8 in 1 million), all driven by Cr∂6, 

and there were 4 with maximum cancer 

risks at 1 in 1 million. All of the 

facilities had non-cancer TOSHI values 

less than one, with a maximum HI value 

of 0.4 (also driven by Ni emissions from 

the one case study facility with oil-fired 

units). The maximum chronic impacts 

of HCl emissions were all less than 10 

percent of its chronic RfC. Because of 

uncertainties in their emission rates, 

other acid gases (Cl2, HF, and HCN) 

were not included in the assessment of 

noncancer impacts. Because EGUs are 

not generally co-located with other 

source categories, facility-wide HAP 

emissions and risks are equal to those 

associated with the EGU source 

category. 

The cancer risk estimates from this 

assessment indicate that the EGU source 

category is not eligible for delisting 

under CAA section 112(c)(9)(B)(i), 

which specifies that a category may be 

delisted only when the Administrator 

determines ‘‘* * * that no source in the 

category (or group of sources in the case 

of area sources) emits such HAP 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 * * *’’ We note that, because 

these case studies do not cover all 

facilities in the category, and because 

our assessment does not include the 

potential for impacts from different EGU 

facilities to overlap one another (i.e., 

these case studies only look at facilities 

in isolation), the maximum risk 

estimates from the case studies may 

underestimate true maximum risks. 

e. Peer-Review of Quantitative Risk 

Analyses 

The Agency has determined that the 

National-Scale Mercury Risk Analysis 

supporting EPA’s 2011 review of U.S. 

EGU health impacts should be peerreviewed. In addition, the Agency has 

determined that the characterization of 

the chemical speciation for the 

emissions of Cr and Ni should be peerreviewed. The Agency has evaluated the 

other components of the analyses 

supporting this finding and determined 

that the remaining aspects of the case 

study analyses for non-Hg HAP use 

methods that have already been subject 

to adequate peer-review. As a result, the 

Agency is limiting the peer-review to 

the National-Scale Mercury Risk 

Analysis and the speciation of 

emissions for Cr and Ni. Due to the 

court-ordered schedule for this 

proposed rule, EPA will conduct these 

peer reviews as expeditiously as 

possible after issuance of this proposed 

rule and will publish the results of the 

peer reviews and any EPA response to 

them before the final rule. 

4. Qualitative Assessment of Potential 

Environmental Risks From Exposures of 

Ecosystems Through Hg and Non-Hg 

HAP Deposition 

Adverse effects on fish and wildlife 

have been observed to be occurring 

today which are the result of elevated 

exposures to MeHg, although these 

effects have not been quantitatively 

assessed. 

Elevated MeHg concentrations in fish 

and wildlife can occur not only in areas 

of high Hg deposition. Elevated MeHg 

concentrations can also occur in diverse 

locations, including watersheds that 

receive average or even relatively low 

Hg deposition, but are particularly 

sensitive to Hg pollution, for example, 

they have higher than average 

methylation rates due to high levels of 

sulfur deposition. Such locations are 

characterized by moderate deposition 

levels that have generated high Hg 

concentrations in biota compared to the 

surrounding landscape receiving a 

similar Hg loading. These Hg-sensitive 

watersheds readily transport inorganic 

Hg, convert the inorganic Hg to MeHg, 

and bioaccumulate this MeHg through 

the food web. Areas of enhanced MeHg 

in fish and wildlife are not constrained 

to a single Hg source, because 

ecosystems respond to the combined 

effects of Hg pollution from multiple 

sources. 

A review of the literature on effects of 

Hg on reproduction in fish115 reports 

adverse reproductive effects for 

numerous species including trout, bass 

(large and smallmouth), northern pike, 

carp, walleye, salmon, and others from 

laboratory and field studies. Mercury 

also affects avian species. In previous 

reports 116 much of the focus has been 

on large fish-eating species, in particular 

the common loon. Breeding loons 

experience significant adverse effects 

including behavioral (reduced nestsitting), physiological (flight feather 

asymmetry) and reproductive (chicks 

fledged/territorial pair) effects.117

Other fish-eating bird species such as 

the white ibis and great snowy egret 

experience a range of adverse effects 

due to exposure to Hg. The white ibis 

has been observed to have decreased 

foraging efficiency 118 and decreased 


jlentini on DSKJ8SOYB1PROD with PROPOSALS2
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white ibises (Eudocimus albus). Environmental 

Toxicology and Chemistry. Vol 27, No. 8, 2008. 119Frederick, Peter, and Jayasena, Nilmini. 

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. 120Sepulveda, Maria S., Frederick, Peter C., 

Spalding, Marilyn G., and Williams, Gary E. Jr. 

Mercury contamination in free-ranging great egret 

nestlings (Ardea albus) from southern Florida, USA. 

Environmental Toxicology and Chemistry. Vol. 18, 

No.5, 1999. 

121Hoffman, David J., Henny, Charles J., Hill, 

Elwood F., Grover, Robert A., Kaiser, James L., 

Stebbins, Katherine R. 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. 

122Brasso, Rebecka L., and Cristol, Daniel A. 

Effects of mercury exposure in the reproductive 

success of tree swallows (Tachycineta bicolor). 

Ecotoxicology. 17:133–141, 2008. 

123Hallinger, Kelly K., Cornell, Kerri L., Brasso, 

Rebecka L., and Cristol, Daniel A. Mercury 

exposure and survival in free-living tree swallows 

(Tachycineta bicolor). Ecotoxicology. Doi: 10.1007/ 

s10646–010–0554–4, 2010. 

124Hawley, Dana M., Hallinger, Kelly K., Cristol, 

Daniel A. Compromised immune competence in 

free-living tree swallows exposed to mercury. 

Ecotoxicology. 18:499–503, 2009. 

125 Gorissen, Leen, Snoeijs, Tinne, Van Duyse, 

Els, and Eens, Marcel. Heavy metal pollution affects 

dawn singing behavior in a small passerine bird. 

Oecologia. 145:540–509, 2005. 

126Scheuhammer, Anton M., Meyer Michael W., 

Sandheinrich, Mark B., and Murray, Michael W. 

Effects of environmental methylmercury on the 

health of wild birds, mammals, and fish. Ambio. 

Vol.36, No.1, 2007. 

127Evans, Chris D., Monteith, Don, T., Fowler, 

David, Cape, J. Neil, and Brayshaw, Susan. 

Hydrochloric Acid: An Overlooked Driver of 

Environmental Change, Env. Sci. Technol., DOI: 

10.1021/es10357u. 

128More details are provided in the National 

Scale Mercury Risk Assessment TSD. 

reproductive success and altered pair 

behavior.119 These effects include 

significantly more unproductive nests, 

male/male pairing, reduced courtship 

behavior and lower nestling production 

by exposed males. In egrets, Hg has been 

implicated in the decline of the species 

in south Florida 120 and studies show 

liver and possibly kidney effects.121

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,122 lower 

survival,123 and had compromised 

immune competence.124 The great tit 

has exhibited reduced singing behavior 

and smaller song repertoire in areas of 

high contamination.125

In mammals, adverse effects from Hg 

including mortality have been observed 

in mink and river otter, both fish eating 

species. Other adverse effects may 

include increased activity, poorer maze 

performance, abnormal startle reflex, 

and impaired escape and avoidance 

behavior.126 EPA is also concerned 

about the potential impacts of HCl and 

other acid gas emissions on the 

environment. When HCl gas encounters 

water in the atmosphere, it forms an 

acidic solution of hydrochloric acid. In 

areas where the deposition of acids 

derived from emissions of sulfur and 

NOX are causing aquatic and/or 

terrestrial acidification, with 

accompanying ecological impacts, the 

deposition of hydrochloric acid would 

further exacerbate these impacts. Recent 

research127 has, in fact, determined that 

deposition of airborne HCl has had a 

greater impact on ecosystem 

acidification than anyone had 

previously thought, although direct 

quantification of these impacts remains 

an uncertain process. 

5. Potential for Deposition ‘‘Hotspots’’ in 

Areas Near U.S. EGUs 

Although it has been characterized 

and addressed as a global issue, Hg from 

U.S. EGUs is shown to deposit in higher 

quantities close to emission sources, 

and around some sources can be as high 

as 3 times the regional average 

deposition. EPA evaluated the potential 

for ‘‘hot spot’’ deposition near U.S. EGU 

emission sources on a national scale, 

based on the CMAQ modeled Hg 

deposition for 2005 and 2016.128 We 

calculated the excess deposition within 

50 km of U.S. EGU sources by first 

calculating the average U.S. EGU 

attributable Hg deposition within a 500 

km radius around the U.S. EGU source. 

This deposition represents the likely 

regional contribution around the EGU. 

We then calculated the average U.S. 

EGU attributable Hg deposition within 

50 km of the U.S. EGUs to characterize 

local deposition plus regional 

deposition near the EGU facility. Excess 

local deposition is then the 50 km 

radius average deposition minus the 500 

km radius average deposition. Summary 

statistics for the excess local deposition 

are provided in Table 9 of this 

preamble. Table 9 of this preamble 

shows both the mean excess deposition 

around all U.S. EGUs, and the mean 

excess deposition around just the top 10 

percent of Hg emitting U.S. EGUs. Table 

9 of this preamble also shows the excess 

Hg deposition as a percent of the 

average regional deposition to provide 

context for the magnitude of the local 

excess deposition. In 2005, for all U.S. 

EGU, the excess was around 120 percent 

of the average deposition, while for the 

top 10 percent of Hg emitting U.S. EGU, 

local deposition was around 3.5 times 

the regional average. By 2016, although 

the absolute excess deposition falls, the 

local excess still remains around 3 times 

the regional average for the highest 10 

percent of Hg emitting U.S. EGUs. 

TABLE 9—EXCESS LOCAL DEPOSITION OF Hg BASED ON 2005 CMAQ MODELED Hg DEPOSITION

50 km-Radius-average excess local 

deposition values (μg/m2) 

Mean across EGUs (percent of 

regional average deposition) 

2005 2016 

All U.S. EGU sites with Hg emissions > 0 (672 sites) .................................................................................... 1.65 (119%) 0.36 (93%) 

Top ten percent U.S. EGU in Hg emissions (67 sites) ................................................................................... 4.89 (352%) 1.18 (302%) 

This analysis shows that there is 

excess deposition of Hg in the local 

areas around EGUs, especially those 

with high Hg emissions. Although this 

is not necessarily indicative of higher 

risk of adverse effects from consumption 

of MeHg contaminated fish from 

waterbodies around the U.S. EGUs, it 

does indicate an increased chance that 

Hg from U.S. EGUs will impact local 

waterbodies around the EGU sources, 

and not just impact regional deposition. 

6. Emissions Controls for Emissions of 

Hg and Non-Hg HAP Are Available and 

Effective 

Analyses of currently available 

control technologies for Hg, acid gases, 


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and non-Hg metal HAP show that 

significant reductions in these 

pollutants can be achieved from EGUs 

with significant coincidental reductions 

in the emissions of other pollutants as 

well. 

a. Availability of Hg Emissions Control 

Options 

The control of Hg in a coal 

combustion flue gas is highly dependent 

upon the form (or species) of the Hg. 

The Hg can be present in one of three 

forms: as Hg0, as a vapor of Hg∂2 (e.g., 

mercuric chloride, Hg(Cl2)), or as HgP

(e.g., adsorbed on fly ash or unburned 

carbon). The specific form of the Hg in 

the flue gas will strongly influence the 

effectiveness of available control 

technology for Hg control. The form (or 

‘‘speciation’’) of the Hg is determined by 

the flue gas chemistry and by the timetemperature profile in the post 

combustion environment. During coal 

combustion, Hg is released into the 

exhaust gas as Hg0. This vapor may then 

continue through the flue gas cleaning 

equipment and exit the stack as gaseous 

Hg0 or it may be oxidized to Hg∂2

compounds (such as HgCl2) via 

homogeneous (gas-gas) or heterogeneous 

(gas-solid) reactions. The primary 

homogeneous oxidation mechanism is 

the reaction with gas-phase chlorine (Cl 

radical or possibly, HCl) to form HgCl2. 

Although this mechanism is 

thermodynamically favorable, it is 

thought to be kinetically limited due to 

rapid cooling of the flue gas stream. 

Heterogeneous oxidation reactions 

occur on the surface of fly ash and 

unburned carbon. It is thought that induct chlorination of the surface of the 

fly ash, unburned carbon, or injected 

activated carbon sorbent is the first step 

to heterogeneous oxidation and surface 

binding of vapor-phase Hg0 in the flue 

gas stream (i.e., the formation of HgP). 

Mercury control can occur as a ‘‘cobenefit’’ of conventional control 

technologies that have been installed for 

other purposes. Particulate Hg can be 

effectively removed along with other 

flue gas PM (including non-Hg metal 

HAP) in the primary or secondary PM 

control device. For units using 

electrostatic precipitators (ESPs), the 

effectiveness will depend upon the 

amount of HgP entering the ESP. Units 

that burn coals with higher levels of 

native chlorine and that produce more 

unburned carbon can see good Hg 

removal in the ESP. Fabric filters (FF) 

have been shown to provide very high 

levels of control when there is adequate 

halogen to convert the Hg to the 

oxidized form. Units with wet FGD 

scrubbers can achieve high levels of Hg 

control—provided that the Hg is present 

in the oxidized (i.e., the soluble) form. 

A selective catalytic reduction (SCR) 

catalyst can enhance the Hg removal by 

catalytically converting Hg0 to Hg∂2, 

making it more soluble and more likely 

to be captured in the scrubber solution. 

Halogen additives (usually bromide 

salts, but chloride salts may also be 

used) can also be added directly to the 

coal or injected into the boiler to 

enhance the oxidation of Hg. 

Activated carbon injection (ACI) is the 

most successfully demonstrated Hgspecific control technology. In this case, 

a powdered AC sorbent is injected into 

the duct upstream of the primary or a 

secondary PM control device. The 

carbon is injected to maximize contact 

with the flue gas. Mercury binds on the 

surface of the carbon to form HgP, which 

is then removed in the PM control 

device. Conventional (i.e., nonhalogenated) AC is effective when 

capturing Hg that is already 

predominantly in the oxidized state or 

when there is sufficient flue gas 

halogens to promote oxidation of the Hg 

on the AC surface. Pre-halogenated (i.e., 

brominated) AC has been shown to be 

very effective when used in 

combination with low chlorine coals 

(such as U.S. western subbituminous 

coals). Activated carbons can suffer 

from poor performance when used with 

high sulfur coals. Firing high sulfur 

coals (especially when an SCR is also 

used) can result in sulfur trioxide (SO3) 

vapor in the flue gas stream. The SO3

competes with Hg for binding sites on 

the surface of the AC (or unburned 

carbon) and limits the effectiveness of 

the injected AC. 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. 

Mingling of AC with the fly ash can 

affect the viability for use of the 

captured fly ash as an additive in 

concrete production. Use of the 

TOXECONTM configuration can keep the 

fly ash and the AC separate. This 

configuration consists of the primary 

PM control device (ESP or FF) followed 

by a secondary downstream pulsejet FF. 

The AC is injected prior to the 

secondary FF. The fly ash is captured in 

the primary PM control device and the 

AC and Hg are captured in the 

downstream secondary FF. 

b. Availability of PM or Metal HAP 

Emissions Control Options 

Electrostatic precipitators and FFs are 

the most commonly applied PM control 

technologies in U.S. coal-fired EGUs. 

Newer units have tended to install FFs, 

which usually provide better 

performance than ESPs. An existing 

facility that wants to upgrade the PM 

control may choose to replace the 

current equipment with newer, better 

performing equipment. The facility may 

also consider installation of a 

downstream secondary PM control 

device—such as a secondary FF. A wet 

ESP (WESP) can be installed 

downstream of a wet FGD scrubber for 

control of condensable PM. 

c. Availability of Acid Gas Emissions 

Control Options 

Acid gases are likely to be removed in 

typical FGD systems due to their 

solubility or their acidity (or both). The 

acid-gas HAP—HCl, HF, and HCN 

(representing the ‘‘cyanide 

compounds’’)—are water-soluble 

compounds, more soluble in water than 

is SO2. This indicates that HCl, HF, and 

HCN should be more easily removed 

from a flue gas stream in a typical FGD 

system than will SO2, even when only 

plain water is used. Hydrogen chloride 

is also a strong acid and will react easily 

in acid-base reactions with the caustic 

sorbents (e.g., lime, limestone) that are 

commonly used in FGD systems. 

Hydrogen fluoride is a weaker acid, 

having a similar acid dissociation 

constant as that of SO2. Cyanide is the 

weakest of these acid gases. In the slurry 

streams, composed of water and sorbent 

(e.g., lime, limestone) used in both wetscrubber and dry spray dryer absorber 

FGD systems, acid gases and SO2 are 

absorbed by the slurry mixture and react 

to form alkaline salts. In fluidized bed 

combustion (FBC) systems, the acid 

gases and SO2 are adsorbed by the 

sorbent (usually limestone) that is 

added to the coal and an inert material 

(e.g., sand, silica, alumina, or ash) as 

part of the FBC process. Hydrogen 

chloride and HF have also been shown 

to be effectively removed using DSI 

where a dry, alkaline sorbent (e.g., 

hydrated lime, trona, sodium carbonate) 

is injected upstream of a PM control 

device. Chlorine in the fuel coal may 

also partition in small amounts to Cl2. 

This is normally a very small fraction 

relative to the formation of HCl. Limited 

testing has shown that Cl2 gas is also 

effectively removed in FGD systems. 

Although Cl2 is not strictly an acidic 

gas, it is grouped here with the ‘‘acid gas 

HAP’’ because it is controlled using the 

same technologies. 

d. Expected Impact of Available 

Controls on HAP Emissions from EGUs 

In 2016, EGUs are projected to 

account for an estimated 45 percent of 

anthropogenic Hg (excluding fires) in 

the continental U.S. Application of 

available Hg controls in 2016 that would 

be required under section 112 reduces 


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129 It is generally assumed that the same types of 

controls that reduce PM will also reduce metals, 

because they are components of the PM. 

130This value is 38 percent of 1,140 tons, which 

is the total tonnage of the metals listed in Table 5, 

based on the 2010 ICR emissions data. 

131 Governing Council of the United Nations 

Environment Programme http://www.unep.org/ 

hazardoussubstances/Mercury/Negotiations/ 

Mandates/tabid/3321/language/en-US/ 

Default.aspx. 

Hg emissions from 29 down to 6 tons, 

achieving a 23 tpy reduction of Hg from 

EGUs, which results in a 79 percent 

reduction in U.S. EGU emissions, and a 

36 percent reduction of total 

anthropogenic Hg emissions nationally. 

In 2016, EGUs are projected to 

account for 53 percent of total U.S. 

anthropogenic HCl. Application of 

available HCl controls in 2016 that 

would be required under section 112 

achieves a 68,000 tpy reduction in HCl 

emissions (a 91 percent reduction in 

EGU emissions), resulting in a 49 

percent reduction of anthropogenic 

emissions nationally. 

Metal HAP emissions are a 

component of PM, and are expected to 

be reduced along with PM as a result of 

application of PM controls. In 2016, 

application of controls required under 

section 112 is expected to provide an 

average reduction in PM for the 

continental U.S. of 38 percent. Although 

no specific projection of metals is 

available for 2016, applying the 38 

percent reduction in PM to the 2010 ICR 

emissions levels of anthropogenic 

metals,129 results in reductions of 

approximately 430 tons of metals per 

year.130

EPA believes these projected 

reductions in Hg, acid gases, and metal 

HAP emissions demonstrate the 

effectiveness of available controls. 

6. Consideration of the Role of U.S. EGU 

Hg Emissions in the Global Effort To 

Decrease Hg Loadings in the 

Environment 

This would allow the U.S. to 

demonstrate effective technologies to 

reduce Hg; such leadership could 

provide confidence to other countries 

that they can succeed in meeting their 

commitments. Mercury pollution is a 

significant international environmental 

challenge, and it is well understood that 

efforts that reduce Hg emissions in other 

countries will reduce Hg that impacts 

U.S. public health and the environment. 

Recognizing this, EPA and others in the 

U.S. Government are actively involved 

in international efforts to reduce Hg 

pollution. These efforts include global 

negotiations aimed at concluding a 

legally-binding agreement to reduce Hg 

that were initiated in February 2009 

under the UNEP.131 Negotiation of the 

agreement is not expected to be 

completed until early 2013. Once the 

international process is complete, the 

agreement must be ratified domestically 

before the agreement will become 

binding in the U.S. The agreement is 

expected to cover major man-made 

sources of air Hg emissions, including 

coal-fired EGUs. Current negotiations 

are considering the application of best 

available technologies and practices to 

reduce air Hg emissions significantly. 

Regulations such as the proposed rule 

demonstrate the U.S. commitment to 

addressing the global Hg problem by 

decreasing the largest source of Hg 

emissions in the U.S. and serve to 

encourage other countries to address Hg 

emissions from their own sources. 

7. 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 extensive analyses summarized 

above confirm that it remains 

appropriate and necessary today to 

regulate EGUs under section 112. It is 

appropriate to regulate emissions from 

coal- and oil-fired EGUs under CAA 

section 112 because: (1) Hg and non-Hg 

HAP continue to pose a hazard to public 

health, and U.S. EGU emissions cause 

and/or contribute to this hazard; (2) Hg 

and some non-Hg HAP pose a hazard to 

the environment; (3) U.S. EGU 

emissions, accounting for 45 percent of 

U.S. Hg emissions, are still the largest 

domestic source of U.S. Hg emissions 

(by 2016, EPA projects that U.S. EGU Hg 

emissions will be over 6 times larger 

than the next largest source, which is 

iron and steel manufacturing), as well as 

the largest source of HCl and HF 

emissions, and a significant source of 

other HAP emissions; (4) Hg emissions 

from individual EGUs leads to hot spots 

of deposition in areas directly 

surrounding those individual EGUs, 

and, thus, deposition is not solely the 

result of regionally transported 

emissions, and will not be adequately 

addressed through reductions in 

regional levels of Hg emissions, 

requiring controls to be in place at all 

U.S. EGU sources that emit Hg; (5) Hg 

emissions from EGUs affect not only 

deposition, exposures, and risk today, 

but may contribute to future deposition, 

exposure and risk due to the processes 

of reemission of Hg that occur given the 

persistent nature of Hg in the 

environment—the delay in issuing Hg 

regulations under section 112 has 

already resulted in several hundred 

additional tons of Hg being emitted to 

the environment, and that Hg will 

remain part of the global burden of Hg; 

and (6) effective controls for Hg and 

non-Hg HAP are available for U.S. EGU 

sources. 

EPA concludes that Hg emissions 

from U.S. EGUs are a public health 

hazard today due to their contribution 

to Hg deposition that leads to potential 

MeHg exposures above the RfD. EPA 

also concludes that U.S. EGU Hg 

emissions contribute to environmental 

concentrations of Hg that are harmful to 

wildlife and can affect production of 

important ecosystem services, including 

recreational hunting and fishing, and 

wildlife viewing. EPA further concludes 

that non-Hg HAP emissions from U.S. 

EGU are a public health hazard because 

they contribute to elevated cancer risks. 

Finally, EPA concludes that U.S. 

EGU’s HCl and HF emissions contribute 

to acidification in sensitive ecosystems 

and, therefore, pose a risk of adverse 

effects on the environment. 

a. U.S. EGU Hg Emissions Continue To 

Pose a Hazard to Public Health and the 

Environment 

The CAA does not define what 

constitutes a hazard to public health. As 

noted earlier, the agency must use its 

scientific and technical expertise to 

determine what constitutes a hazard to 

public health in the context of Utility 

Hg emissions. Congress did provide 

guidance as to what it considered an 

important benchmark for public health 

hazards, particularly in regard to Hg. In 

section 112(n)(1)(C), Congress required 

the NIEHS to determine ‘‘the threshold 

level of Hg exposure below which 

adverse human health effects are not 

expected to occur.’’ This threshold level 

is represented by the RfD, and as such, 

the RfD is the benchmark for 

determining hazards to public health 

that is most consistent with Congress’s 

interpretation of adverse health effects. 

As a result, our assessment of the hazard 

to public health posed by U.S. EGU Hg 

emissions is focused on comparisons to 

the RfD of exposures caused or 

contributed to by U.S. EGU Hg 

emissions. 

As described above, almost all (98 

percent) of the more than 2,400 

watersheds for which we have fish 

tissue data exceed the RfD, above which 

there is the potential for an increased 

risk of adverse effects on human health. 

U.S. EGU-attributable deposition of Hg 

contributes to a large number of those 

watersheds in which total potential 

exposures to MeHg from all sources 

exceed the RfD and, thus, pose a hazard 

to public health. For our analysis, we 

focused on the watersheds to which 

EGUs contributed at least 5 percent of 

the total Hg deposition and related 


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132An analysis of the impact of sampling location 

limitations on coverage of high U.S. EGU deposition 

watersheds is provided in the National Scale 

Mercury Risk Assessment TSD. 

MeHg exposures at a watershed, or 

contributed enough Hg deposition 

resulting in potential MeHg exposures 

above the RfD, regardless of the 

additional deposition from other 

sources of Hg deposition. We believe 

this is a conservative approach because 

any contribution of Hg to watersheds 

where potential exposures to MeHg 

exceed the RfD poses a public health 

hazard. Thus, because we are finding a 

large percentage 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, as we believe that there 

are additional watersheds that have 

contributions at lower percent 

benchmarks. 

In total, 28 percent of sampled 

watersheds have populations that are 

potentially at risk from exposure to 

MeHg based on the contribution of U.S. 

EGUs, either because U.S. EGU 

attributable deposition is sufficient to 

cause potential exposures to exceed the 

reference dose even before considering 

the deposition from other U.S. and nonU.S. sources, or because the U.S. EGU 

attributable deposition contributes 

greater than 5 percent of total deposition 

and total exposure from all sources is 

greater than the reference dose. At the 

99th percentile fish consumption level 

for subsistence fishers, 22 percent of 

sampled watersheds where total 

potential exposures to MeHg exceed the 

RfD have a contribution from U.S. EGUs 

of at least 5 percent of Hg deposition. 

Although the most complete estimate 

of potential risk is based on total 

exposures to Hg, including that due to 

deposition from U.S. EGU sources, U.S. 

non-EGU sources, and global sources, 

the deposition resulting from U.S. EGU 

Hg emissions is large enough in some 

watersheds that persons consuming 

contaminated fish would have 

exposures that exceed the RfD even 

before taking into account the 

deposition from other sources. At the 

99th percentile fish consumption level 

for subsistence fishers, in 12 percent of 

the sampled watersheds, U.S. EGUs are 

responsible for deposition that causes 

the RfD to be exceeded, even before 

considering the additional deposition 

from other sources. 

In addition, we believe the estimate of 

where populations may be at risk from 

U.S. EGU-attributable Hg deposition is 

likely understated because the data on 

fish tissue MeHg concentrations is 

limited in some regions of the U.S., such 

as Pennsylvania, with very high U.S. 

EGU attributable Hg deposition, and it 

is possible that watersheds with 

potentially high MeHg exposures were 

excluded from the risk analysis.132 In 

addition, due to limitations in our 

models and available data, we have not 

estimated risks in near-coastal waters, 

and some of these waters, including the 

Chesapeake Bay, have EGU-attributable 

Hg deposition. 

Further, scientific studies have found 

strong evidence of adverse impacts on 

species of fish-eating birds with high 

bird-watching value, including loons, 

white ibis, and great snowy egrets. 

Studies have also shown adverse effects 

on insect-eating birds including many 

songbirds. Adverse effects in fish-eating 

mammals, such as mink and otter, 

include neurological responses 

(impaired escape and avoidance 

behavior) which can influence survival 

rates. Because EGUs contribute to Hg 

deposition in the U.S., we reasonably 

conclude that EGUs are contributing to 

the identified adverse environmental 

effects. 

Mercury emitted into the atmosphere 

persists for years, and once deposited, 

can be reemitted into the atmosphere 

due to a number of processes, including 

forest fires and melting of snow packs. 

As a result, Hg emitted today can have 

impacts for many years. In fact, Hg 

emitted by U.S. EGUs in the past, 

including over the last decade, is still 

having impacts on concentrations of Hg 

in fish today. 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. 

Although we are not able to quantify the 

impact of U.S. EGU emissions on the 

global pool of Hg, U.S. EGUs do 

contribute to that global pool. 

Controlling Hg emissions from U.S. 

EGUs helps to reduce the potential for 

environmental hazard from Hg now and 

in the future. These findings 

independently support a determination 

that it is appropriate to regulate HAP 

emissions from EGUs. 

b. U.S. EGU Non-Hg HAP Emissions 

Continue To Pose a Hazard to Public 

Health and the Environment 

EPA recently conducted 16 case 

studies of U.S. EGUs for which we had 

2007 to 2009 emissions data (based on 

the 2010 ICR) and that we anticipated 

would have relatively higher emissions 

of non-Hg HAP compared to other U.S. 

EGUs. Of the 16 facilities modeled, 4 

facilities, 3 coal and 1 oil facility, have 

estimated risks of greater than 1 in 1 

million for the most exposed individual. 

Although section 112(n)(1)(A) does not 

specify what constitutes a hazard to 

public health for the purposes of the 

appropriate and necessary finding, CAA 

section 112(c)(9) is instructive. As 

explained in section III.A above, for 

carcinogenic HAP, section 112(c)(9) 

contains a test for delisting source 

categories based on lifetime risk of 

cancer. That test reflects Congress’ view 

as to the level of health effects 

associated with HAP emissions that 

Congress thought warranted continued 

regulation under section 112. 

Specifically, section 112(c)(9) provides 

that a source category can be delisted 

only if no source emits HAP in 

quantities which may cause a lifetime 

risk of cancer greater than 1 in 1 million 

to the most exposed individual. As 

noted above, the results of the case 

study risk analysis confirm that sources 

in the EGU source category emit HAP in 

quantities that cause a lifetime risk of 

cancer greater than 1 in 1 million. Given 

Congress’ determination that categories 

of sources which emit HAP resulting in 

a lifetime cancer risk greater than 1 in 

1 million should not be removed from 

the section 112(c) source category list 

and should continue to be regulated 

under 112, we believe risks above that 

level represent a hazard to public health 

such that it is appropriate to regulate 

EGUs under section 112. 

Although our case studies did not 

identify significant chronic non-cancer 

risks from acid gas emissions from the 

specific EGUs assessed, the 

Administrator remains concerned about 

the potential for acid gas emissions to 

add to already high atmospheric levels 

of other chronic respiratory toxicants 

and to environmental loading and 

degradation due to acidification. EGUs 

emit over half of the nationwide 

emissions of HCl and HF, based on 2010 

emissions estimates. In addition, given 

that many sensitive ecosystems across 

the country are experiencing 

acidification, it is appropriate to reduce 

emissions of this magnitude which carry 

the potential to aggravate acidification. 

The Administrator concludes that, in 

addition to the regulation of non-Hg 

HAP which cause elevated cancer risks, 

it is appropriate to regulate those HAP 

which are not known to cause cancer 

but are known to contribute to chronic 

non-cancer toxicity and environmental 

degradation, such as the acid gases. 

These findings independently support 

a determination that it is appropriate to 

regulate HAP emissions from EGUs. 


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c. Effective Controls Are Available To 

Reduce Hg and Non-Hg HAP Emissions 

Particle-bound Hg can be effectively 

removed along with other flue gas PM 

(including non-Hg metal HAP) in 

primary or secondary PM control 

devices. Electrostatic precipitators, FF, 

and wet FGD scrubbers are all effective 

at removing Hg, with the degree of 

effectiveness depending on the specific 

characteristics of the EGU and fuel 

types. These devices are all effective in 

removing metal HAP as well. Activated 

carbon injection is the most successfully 

demonstrated Hg-specific control 

technology, although performance may 

be reduced when used with high sulfur 

coals. Acid gases are readily removed in 

typical FGD systems due to their 

solubility or their acidity (or both). The 

availability of controls for HAP 

emissions from EGUs supports the 

appropriate finding because sources will 

be able to reduce their emissions 

effectively and, thereby, reduce the 

hazards posed by HAP emissions from 

EGUs. 

d. The Administrator Finds That It 

Remains Necessary To Regulate Coaland Oil-Fired EGUs Under CAA Section 

112 

EPA determined that in 2016 the 

hazards posed to human health and the 

environment by HAP emissions from 

EGUs will not be addressed; therefore, 

it is necessary to regulate EGUs under 

section 112. In addition, it is necessary 

to regulate EGUs under section 112 

because the only way to ensure 

permanent reductions in U.S. EGU 

emissions of HAP and the associated 

risks to public health and the 

environment is through standards set 

under section 112. 

The Agency first evaluates whether it 

is necessary to regulate HAP emissions 

from EGUs ‘‘after imposition of the 

requirements of the CAA.’’ As explained 

above, we interpret that phrase to 

require the Agency to consider only 

those requirements that Congress 

directly imposed on EGUs through the 

CAA as amended in 1990 and for which 

EPA could reasonably predict HAP 

emission reductions at the time of the 

Study. Nonetheless, the Agency 

recognizes that it has discretion to look 

beyond the Utility Study in determining 

whether it is necessary to regulate EGUs 

under section 112. Because several years 

have passed since the December 2000 

Finding, we conducted an additional, 

updated analysis, examining a broad 

array of diverse requirements. 

Specifically, we analyzed EGU HAP 

emissions remaining in 2016. Our 

analysis included the proposed 

Transport Rule; CAA section 112(g); the 

ARP; Federal, state, and citizen 

enforcement actions related to criteria 

pollutant emissions from EGUs; and 

some state rules related to criteria 

pollutant emissions. We included state 

requirements and citizen and state 

enforcement action settlements 

associated with criteria pollutants 

because those requirements may have a 

basis under the CAA. We did not, 

however, conduct an analysis to 

determine whether the requirements 

are, in fact, based on requirements of the 

CAA. As such, we believe there may be 

instances where we should not have 

considered certain state rules or state 

and citizen suit enforcement settlements 

in our analysis, because those 

requirements are based solely in state 

law and are not required by Federal law. 

We did not include in our analysis any 

state-only requirements or voluntary 

actions to reduce HAP emissions 

because we knew there was no Federal 

backstop for those requirements and 

actions. 

Our analysis confirms that Hg 

emissions from EGUs remaining in 2016 

still pose a hazard to public health and 

the environment and, for that reason, it 

remains necessary to regulate EGUs 

under section 112. Specifically, we 

estimate that U.S. EGU emissions of Hg 

after imposition of the requirements of 

the CAA will be 29 tpy in 2016, the 

same as the level of Hg emitted today. 

As we stated above, we evaluated the 

hazards to public health and the 

environment from Hg based on the 

estimated Hg emissions in 2016 and 

found that a hazard exists. Because a 

hazard remains after imposition of the 

requirements of the CAA, it is necessary 

to regulate EGUs. 

It is necessary to regulate HAP 

emissions from EGUs, even though the 

hazards from Hg will not be resolved 

through regulation under section 112. 

EPA finds that incremental reductions 

in Hg are important because as exposure 

above the RfD increases the likelihood 

and severity of adverse effects increases. 

EGUs are the largest source of Hg in 

the U.S. and, thus, contribute to the risk 

associated with exposure to MeHg. By 

reducing Hg emissions from U.S. EGUs, 

this proposed rule will help to reduce 

the risk to public health and the 

environment from Hg exposure. 

We also find that it is necessary to 

regulate EGUs under section 112 based 

on non-Hg HAP emissions because we 

cannot be certain that the identified 

cancer risks attributable to EGUs will be 

addressed through imposition of the 

requirements of the CAA. In addition, 

the environmental hazards posed by 

acidification will not be fully addressed 

through imposition of the CAA. 

We also find it necessary to regulate 

EGUs because regulation under section 

112 is the only way to ensure that HAP 

emissions reductions that have been 

achieved since 2005 remain permanent. 

The difference between the 53 ton 

2005 estimate and the 2010 ICR-based 

estimate of total EGU emissions may be 

overstated. While EPA has estimated 

2010 total EGU Hg emissions of 29 tons 

based on data from the 2010 ICR 

database, this may underestimate total 

2010 EGU Hg emissions due to the fact 

that emission factors used to develop 

the estimates may not accurately 

account for larger emissions from units 

with more poorly performing emission 

controls. The 2010 ICR by which the 

data used to develop the factors was 

collected was designed to provide the 

agency the data to determine the 

appropriate MACT levels and was not 

designed to collect data to fully 

characterize all units’ Hg emissions, 

particularly those that might have 

poorly performing controls. EPA tested 

only 50 randomly selected units that 

were not selected for testing as best 

performing units (the bottom 85 percent 

of units), and we used that small sample 

to attempt to characterize the lower 

performing units. Because the 50 units 

were randomly selected, we do not 

believe we have sufficiently 

characterized the units that have poorly 

performing controls. In addition, the 

methodology for estimating the 2005 

and 2010 emission estimates are not the 

same. The 2005 estimate is based on 

control configurations as of 2002, 

therefore, it does not reflect reductions 

due to control installations that took 

place between 2002 and 2005. As a 

result, the apparent difference between 

2005 and 2010 is overstated. There are 

real factors that explain why Hg 

reductions would have occurred 

between 2005 and 2010. The actual 

reductions between 2005 and 2010 are 

attributable to state Hg regulations and 

to CAIR and Federal enforcement 

actions that achieve Hg reductions as a 

co-benefit of controls for PM, NOX, and 

SO2 emissions. However, there are no 

national, Federally binding regulations 

for Hg. State Hg regulations can 

potentially change or be revoked 

without EPA approval, and reductions 

that occur as a co-benefit of criteria 

pollutant regulations can also change. 

Furthermore, companies can change 

their criteria pollutant compliance 

strategies and use methodologies that do 

not achieve the same level of Hg or 

other HAP co-benefit (e.g., purchasing 

allowances in a trading program instead 

of using add-on controls). 


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133U.S. Environmental Protection Agency. 2006. 

Revision of the metabolically-derived ventilation 

rates within the Exposure Factors Handbook. 

(External review draft) Washington, DC: Office of 

Research and Development. EPA/600/R–06/129A. 

http://oaspub.epa.gov/eims/ 

eimscomm.getfile?p_download_id=460261. 

134Foos, B., M. Marty, J. Schwartz, W. Bennett, 

J. Moya, A. M. Jarabek, and A. G. Salmon. 2008. 

Focusing on children’s Inhalation Dosimetry and 

Health Effects for Risk Assessment: An 

Introduction. J Toxicol Environ Health 71A: 149– 

165. 

135National Academy of Sciences. 2000. 

Toxicological Effects of Methylmercury. 

Washington, DC: National Academy Press. http:// 

books.nap.edu/catalog/ 

9899.html?onpi_newsdoc071100. 

136P. Grandjean, P. Weihe, R.F. White, F. Debes, 

S. Araki, K. Yokoyama, K. Murata, N. Sorensen, R. 

Dahl and P.J. Jorgensen. 1997. Cognitive deficit in 

7-year-old children with prenatal exposure to 

methylmercury. Neurotoxicology and Teratology 19 

(6):417–28. 

137T. Kjellstrom, P. Kennedy, S. Wallis and C. 

Mantell. 1986. Physical and mental development of 

children with prenatal exposure to mercury from 

fish. Stage 1: Preliminary tests at age 4. Sweden: 

Swedish National Environmental Protection Board. 

138U.S. Environmental Protection Agency. 2005. 

Supplemental Guidance for Assessing Susceptibility 

from Early-Life Exposure to Carcinogens. 

Washington, DC: Risk Assessment Forum. EPA/630/ 

R-03/003F http://www.epa.gov/raf/publications/

pdfs/childrens_supplement_final.pdf 

139Pope, C.A. and D.W. Dockery. 1992. Acute 

health effects of PM10 pollution on symptomatic 

and asymptomatic children. Am Rev Respir Dis 145: 

1123–1128. 

140 Gauderman, W.J., R. McConnell, F. Gilliland, 

S. London, et al. 2000. Association between air 

pollution and lung function growth in Southern 

California children. Am J Respir Crit Care Med 162: 

1283–1390. 

141McGwinn, G. Jr., J. Lienert, and J.I. Kennedy 

Jr. 2010. Formaldehyde Exposure and Asthma in 

Children: A Systematic Review. Environ Health 

Perspect 118: 313–317. 

As with Hg, the most recent data on 

U.S. EGU HCl and HF emissions show 

a significant reduction between 2005 

and 2010. These reductions in HCl and 

HF are the co-benefit of controls 

installed to meet other CAA 

requirements, including enforcement 

actions, and to a lesser extent, state 

regulations. There is no guarantee other 

than regulation under section 112 that 

these significant decreases in HCl and 

HF emissions will be permanent. 

Although we do not have estimates for 

the remaining HAP emitted from EGUs, 

we believe it is likely that such 

emissions have also decreased between 

2005 and 2010. Thus, the Administrator 

finds it necessary to regulate HAP 

emissions from EGUs to ensure that 

HAP emissions reductions are 

permanent. 

Finally, direct control of Hg emissions 

affecting U.S. deposition is only 

possible through regulation of U.S. 

emissions; we are unable to control 

global emissions directly. Although the 

U.S. is actively involved in international 

efforts to reduce Hg pollution, the 

ability of the U.S. to argue effectively in 

these negotiations for strong 

international policies to reduce Hg air 

emissions depends in large part on our 

domestic policies, programs and 

regulations to control Hg. 

All of these findings independently 

support a finding that it is necessary to 

regulate EGUs under section 112. 

Therefore, given the Agency’s finding 

that it remains appropriate and 

necessary to regulate coal- and oil-fired 

EGUs under CAA section 112, EPA is 

confirming its inclusion of coal- and oilfired EGUs on the list of source 

categories regulated under CAA section 

112(c). 

8. Implications of Hazards to Public 

Health for Children and Environmental 

Justice Communities 

Children are at greatest risk of adverse 

health effects from exposures to Hg, and 

this risk is amplified for children in 

minority and low income communities 

who subsist on locally-caught fish. 

Today’s proposed rule is therefore an 

important step in addressing disparate 

impacts on children and environmental 

justice (EJ) communities. 

Children are more vulnerable than 

adults to many HAP, because of 

differences in physiology, higher per 

body weight breathing rates and 

consumption, rapid development of the 

brain and bodily systems, and behaviors 

that increase chances for exposure. Even 

before birth, the developing fetus may 

be exposed to HAP through the mother 

that affect development and 

permanently harm the individual. 

Infants and children breathe at much 

higher rates per body weight than 

adults, with infants under one year of 

age having a breathing rate up to five 

times that of adults.133 In addition, 

children breathe through their mouths 

more than adults and their nasal 

passages are less effective at removing 

pollutants, which leads to a higher 

deposition fraction in their lungs.134

Crawling and frequent hand-to-mouth 

activity lead to infants’ higher levels of 

ingestion of contaminants deposited 

onto soil or in dust. Infants’ 

consumption of breast milk can pass 

along high levels of accumulated 

persistent bioaccumulative pollutants 

from their mothers. Children’s dietary 

intake also exceeds that of adults, per 

body weight, posing a potential added 

risk from persistent HAP that 

accumulate in food. In addition to the 

greater exposure, the less-well 

developed detoxification pathways and 

rapidly developing systems and organs 

put children at potentially greater risk. 

Mercury is the HAP from EGUs of 

most concern to early life stages. The 

adverse affects of Hg on developing 

neuropsychological systems is wellestablished and permanent. The 

prenatal period of development has 

been established to be the most sensitive 

lifestage to the neurodevelopmental 

effects of MeHg.135 Children who are 

exposed to low concentrations of MeHg 

prenatally are at increased risk of poor 

performance on neurobehavioral tests, 

such as those measuring attention, fine 

motor function, language skills, visualspatial abilities, and verbal 

memory.136 137 Impaired cognitive 

development from exposures to MeHg 

prenatally and in early childhood affect 

the individual into adulthood, by 

affecting learning and potential future 

earnings, and contributing to behavioral 

problems. 

Other HAP related to EGU emissions 

present greater risks to children as well. 

For example, mutagenic carcinogens 

such as Cr∂6 have a larger impact 

during young lifestages, given the rapid 

development of the corporal systems.138

Exposure at a young age to these 

carcinogens could lead to a higher risk 

of developing cancer later in life. 

The adverse effects of individual nonHg HAP may be more severe for 

children, particularly the youngest age 

groups, than adults. A number of 

epidemiologic studies suggest that 

children are more vulnerable than 

adults to lower respiratory symptoms 

associated with PM.139 140 Non-Hg metal 

HAP may behave similarly to particulate 

matter, at least in terms of the 

deposition fraction that reaches 

children’s lungs. As with Hg, Pb and Cd 

are known to affect children’s 

neurologic development. A metaanalysis of seven studies has shown an 

association between exposure to 

formaldehyde, another HAP of concern, 

and development of asthma in 

children.141

Within communities overburdened 

with environmental exposures, the 

youngest lifestages are likely the most 

vulnerable. Looking at the health effects 

for children in those communities can 

be an important part of appropriately 

assessing community risks. 

EPA has also considered the effects of 

this rule on EJ communities. The nature 

of exposures to Hg is such that 

populations with high levels of selfcaught fish consumption are likely to be 

disproportionately affected. EPA’s risk 

analysis identified many EJ 

communities, including Laotian, 

Vietnamese, Hispanic, AfricanAmerican, tribal, and low income 

communities, as having higher levels of 

subsistence fishing activities. 

Consequently, individuals in these 


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142U.S. EPA. 2005. Technical Support Document: 

Methodology Used to Generate Deposition, Fish 

Tissue Methylmercury Concentrations, and 

Exposure for Determining Effectiveness of Utility 

Emission Controls. 

143U.S. EPA. 2005. Technical Support Document: 

Methodology Used to Generate Deposition, Fish 

Tissue Methylmercury Concentrations, and 

Exposure for Determining Effectiveness of Utility 

Emission Controls. 

144The HQ is the ratio of observed or modeled 

exposures to the RfD. 

145See the National Scale Mercury Risk 

Assessment Technical Support Document. 

communities are potentially exposed to 

levels of MeHg in fish that may result 

in these individuals’ exposure 

exceeding the RfD. These EJ populations 

are thus at higher risk for the health 

effects associated with exposures to 

MeHg, which include impacts on 

neurological functions that can cause 

children to struggle in school. In EJ 

populations which often face numerous 

other stressors that can result in lower 

educational performance, the additional 

burdens imposed by exposure to Hg 

may cause significant and long-lasting 

impacts on children that continue into 

adulthood, affecting learning potential 

and measures of IQ, including future 

earnings and indicators of quality of life. 

9. The Analysis Supporting the 2005 

Action Was Subject to Technical 

Limitations and These Flaws 

Undermine the Basis for the 2005 

Action 

In 2005, EPA conducted a set of 

technical analyses to support a revision 

to the 2000 appropriate and necessary 

finding.142 In those analyses, EPA made 

several assumptions that were not 

justified based on scientific or technical 

grounds, and which we have corrected 

in our technical analysis supporting our 

current confirmatory finding that it is 

appropriate and necessary to regulate 

coal- and oil-fired EGUs under section 

112. 

a. Interpretation of the MeHg Reference 

Dose and Incremental U.S. EGUAttributable Exposures 

In the 2005 analysis, EPA made the 

following statement: 

The RfD provides a useful reference 

point for comparisons with measured or 

modeled exposure. The Agency defines 

the RfD as an exposure level below 

which the Agency believes exposures 

are likely to be without an appreciable 

risk over a lifetime of exposure. For the 

purposes of assessing population 

exposure due to EGUs, we create an 

index of daily intake (IDI). The IDI is 

defined as the ratio of exposure due 

solely to EGUs to an exposure of 0.1 μg/ 

kg bw/day. The IDI is defined so that an 

IDI of 1 is equal to an incremental 

exposure equal to the RfD level, 

recognizing that the RfD is an absolute 

level, while the IDI is based on 

incremental exposure without regard to 

absolute levels. Note that an IDI value 

of 1 would represent an absolute 

exposure greater than the RfD when 

background exposures are 

considered.143

Upon further consideration, EPA 

concludes that it did not have a 

scientific or technical justification for 

creating a metric other than the HQ 144

to compare U.S. EGU-attributable 

exposures to the RfD. As EPA 

recognized in 2005, the RfD is an 

absolute level above which the potential 

risks of exposures increase, based on 

total exposures to MeHg. The concept of 

the IDI was created by EPA in 2005 

solely to support its interpretation that 

it must assess hazards to public health 

solely based on U.S. EGU emissions 

with no consideration of exposures to 

MeHg arising from other sources of Hg 

deposition. As noted above, nothing in 

section 112(n)(1)(A) prohibits 

consideration of HAP emissions from 

U.S. EGUs in conjunction with HAP 

emissions from other sources of HAP, 

including sources outside the U.S. 

Indeed, such an approach would ignore 

the manner in which the public is 

actually exposed to HAP emission. By 

focusing on whether incremental 

exposures attributable to U.S. EGU Hg 

emissions exceeded the RfD without 

consideration of other exposures, EPA 

implied that U.S. EGU Hg emissions 

were not causing a hazard to public 

health even though such emissions were 

increasing risks in locations where the 

RfD was already exceeded due to total 

exposures from all Hg sources, 

including U.S. EGU emissions. This is a 

serious flaw in EPA’s 2005 assessment, 

due to reasons we discuss below. 

Ninety-eight percent of watersheds 

with fish tissue MeHg samples have Hg 

deposition levels such that total 

potential exposure to MeHg exceeds the 

RfD, and many have exposures that are 

many times the RfD.145 As a result, in 

almost all watersheds with fish tissue 

MeHg samples, any additional Hg will 

increase potential risk. Thus, U.S. EGUattributable Hg deposition is 

contributing to increased potential risk. 

The Agency believes the assessment of 

potential risk due to Hg emissions from 

U.S. EGUs must consider both the 

extent to which U.S. EGUs contribute to 

such risk along with other sources, and 

the extent to which U.S. EGUattributable deposition leads to 

exposures that exceed the RfD even 

before considering the contributions of 

other sources of Hg. The Agency has 

conducted such an evaluation in the 

national-scale MeHg risk analysis 

presented above. In 2005, as a result of 

relying on a flawed, non-scientific 

approach for comparing MeHg 

exposures to the RfD, and a failure to 

consider cumulative risk 

characterization metrics, EPA 

incorrectly determined that U.S. EGU 

emissions of Hg did not constitute a 

hazard to public health. As discussed 

above, EPA has revised this 

determination and concluded that U.S. 

EGU Hg emissions are a hazard to 

public health because they cause 

exposures to exceed the RfD or 

contribute to exposures in watersheds 

where total exposures to MeHg exceed 

the RfD. 

b. Interpretation of Populations Likely 

To Be at Risk and Conclusions 

Regarding Acceptable Risk 

In addition to developing a flawed 

exposure indicator based on only U.S. 

EGU attributable exposure (the IDI), 

EPA also erred in finding that exposures 

above the RfD (an IDI greater than 1) did 

not pose an ‘‘unacceptable risk’’ (e.g., 

did not pose a hazard to public health). 

EPA cited three reasons for the finding 

in 2005: (1) Lack of confidence in the 

risk estimates; (2) lack of seriousness of 

the health effects of MeHg; and (3) small 

size of the population at risk and low 

probability of risks in that population. 

EPA was not justified in making its 

determination based on these three 

factors. 

In the 2005 Action, EPA cited the 

underpinnings of the RfD as introducing 

a degree of conservatism. In fact, 

however, as discussed above, EPA has 

stated consistently, including in the RfD 

issued in 2001, that the RfD for Hg is a 

level above which there is the potential 

for increased risk. Only at levels at or 

below the RfD does the Agency 

maintain that exposures are without 

significant risk. EPA’s interpretation in 

2005 was a departure from prior EPA 

policy as it concerns exposures to Hg 

and was in error. 

In the 2005 Action, EPA identified 

risk of poor performance on 

neurobehavioral tests, such as those 

measuring attention, fine motor 

function, language skills, visual-spatial 

abilities (like drawing), and verbal 

memory as the primary health effects of 

MeHg exposures. Although not stated 

explicitly, it is implicit in the 2005 

Action that EPA did not consider these 

health effects to be serious. The Agency 

did not, and could not have, provided 

any scientific or policy rationale for 

dismissing these serious public health 

effects. For example, as mentioned 


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146Burger, J., K. Pflugh, L. Lurig, L. Von Hagen, 

and S. Von Hagen. 1999. Fishing in Urban New 

Jersey: Ethnicity Affects Information Sources, 

Perception, and Compliance. Risk Analysis 19(2): 

217–229. 

147Burger, J., Stephens, W., Boring, C., Kuklinski, 

M., Gibbons, W.J., & Gochfield, M. (1999). Factors 

in exposure assessment: Ethnic and socioeconomic 

differences in fishing and consumption of fish 

caught along the Savannah River. Risk Analysis, 

19(3). 

148Chemicals 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, 

California Environmental Protection Agency, July 

1997. 

149Tai, S. 1999. ‘‘Environmental Hazards and the 

Richmond Laotian American Community: A Case 

Study in Environmental Justice.’’ Asian Law Journal 

6: 189. 

150Corburn, 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). 

above, there are potentially serious 

implications of the identified effects on 

learning potential and measures of IQ, 

including future earnings and indicators 

of quality of life. EPA was not justified 

in dismissing these health effects as not 

serious without providing evidence or 

justification, which it could not do 

based on the information available at 

the time or today. 

In the 2005 Action, EPA made several 

statements in the technical analysis 

suggesting that the probability that an 

IDI of 1 would be exceeded (e.g., that 

U.S. EGU attributable exposures would 

be greater than the RfD) was low due to 

the rare occurrence of high consumption 

rate populations in high deposition 

watersheds. The 2005 analysis showed 

that 15 percent of watersheds would 

have U.S. EGU-attributable potential 

exposures that were twice the RfD for 

the highest fish consumption rates. EPA 

dismissed this high percent of 

watersheds by stating that those high 

fish consumption rates would only 

occur in Native American populations, 

and that those populations lived in 

locations that were not heavily 

impacted by U.S. EGU Hg deposition. 

Information was available at the time 

of the 2005 analysis indicating that 

other populations besides Native 

Americans engaged in subsistence 

fishing activities that would result in 

consumption rates similar to Native 

Americans. EPA chose to selectively use 

information only on Native American 

consumption rates and erroneously 

concluded that subsistence fishing 

activities would not occur in a wider set 

of locations. This choice was in error, as 

EPA should have investigated whether 

other subsistence populations could fish 

in locations heavily impacted by U.S. 

EGU emissions (e.g., watersheds with 

the top 15 percent of U.S. EGUattributable fish tissue MeHg levels). A 

search of the literature available in 2005 

reveals several studies that identified 

additional fishing populations with 

subsistence or near subsistence 

consumption rates, including urban 

fishing populations (including lowincome populations),146 147 148 Laotian 

communities,149 and Hispanics. In fact, 

EPA participated in 1999 in a project 

investigating exposures of poor, 

minority communities in New York City 

to a number of contaminants including 

Hg, and should thus have been aware 

that these populations can have very 

high consumption rates.150 If EPA had 

conducted a thorough investigation in 

2005, it should have concluded that 

populations with the potential for 

subsistence-level fish consumption rates 

occur in many watersheds, and, thus, 

could not have concluded that 

exposures above the RfD (IDI greater 

than 1) were not likely. 

Thus, based on the errors EPA made 

in the 2005 Action related to evaluating 

the risks from MeHg exposures 

attributable to U.S. EGUs, EPA’s 

technical determination in 2005 that 

risks were acceptable based on that 

analysis was not justified. As a result 

the technical determination in 2005 

which supported the finding of no 

public health hazard, and the 

determination that it was not 

appropriate or necessary to regulate 

HAP from U.S. EGUs was in error. 

IV. Summary of This Proposed 

NESHAP 

This section summarizes the 

requirements proposed in this proposed 

rule. Our rationale for the proposed 

requirements is provided in Section V of 

this preamble. 

A. What source categories are affected 

by this proposed rule? 

This proposed rule affects coal- and 

oil-fired EGUs. 

B. What is the affected source? 

An existing affected source for this 

proposed rule is the collection of coaland oil-fired EGUs within a single 

contiguous area and under common 

control. A new affected source is a coalor oil-fired EGU for which construction 

or reconstruction began after May 3, 

2011. 

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

as: 

a fossil fuel-fired combustion unit of more 

than 25 megawatts electric (MWe) that serves 

a generator that produces electricity for sale. 

A unit that cogenerates steam and electricity 

and supplies more than one-third of its 

potential electric output capacity and more 

than 25 MWe output to any utility power 

distribution system for sale is also an electric 

utility steam generating unit. 

If an EGU burns coal (either as a 

primary fuel or as a supplementary 

fuel), or any combination of coal with 

another fuel (except 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. As noted below, EPA 

is proposing a definition to determine 

whether the combustion unit is ‘‘fossil 

fuel fired’’ such that it is an EGU for 

purposes of this proposed rule. The unit 

must be capable of combusting more 

than 73 megawatt-electric (MWe) (250 

million British thermal units per hour, 

MMBtu/hr) heat input (equivalent to 25 

MWe electrical output) of coal or oil. In 

addition, using the construct of the 

definition of ‘‘oil-fired’’ from the ARP, 

we are proposing that 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 to be considered a ‘‘fossil 

fuel fired’’ EGU subject to this proposed 

rule. If a new or existing EGU is not 

coal- or oil-fired, and the unit burns 

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 percent or more of the annual heat 

input during any 1 of those calendar 

years, the unit is considered to be 

natural gas-fired and would not be 

subject to this proposed rule. As 

discussed later, we believe that this 

definition will address those situations 

where either an EGU fires coal or oil on 

only a limited basis or co-fires limited 

amounts of coal or oil with other nonfossil fuels (e.g., biomass). 

To the extent a unit combusts solid 

waste, that unit is not an EGU under 

section 112, but rather would be subject 

to CAA section 129. 

The Small Entity Representatives 

(SERs) serving on the Small Business 

Advocacy Review Panel (SBAR) 

established under the Small Business 

Regulatory Enforcement Fairness Act 

(SBREFA) suggested that EPA consider 

developing an area-source (i.e., those 

EGUs emitting less than 10 tpy of any 

one HAP or less than 25 tpy of any 

combination of HAP) vs. major-source 

(i.e., those EGUs emitting 10 tpy or more 

of any one HAP or 25 tpy of more of any 


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151As we have explained in other rules, 

determining what constitutes GACT involves 

considering the control technologies and 

management practices that are generally available to 

the area sources in the source category. We also 

consider the standards applicable to major sources 

in the same industrial sector to determine if the 

control technologies and management practices are 

transferable and generally available to area sources. 

In appropriate circumstances, we may also consider 

technologies and practices at area and major 

sources in similar categories to determine whether 

such technologies and practices could be 

considered generally available for the area source 

category at issue. Finally, in determining GACT for 

a particular area source category, we consider the 

costs and economic impacts of available control 

technologies and management practices on that 

category. 

combination of HAP) distinction for this 

source category. The proposed rule 

treats all EGUs the same and proposes 

MACT standards for all units. 

Nothing in the CAA requires that we 

issue GACT standards for area sources. 

Indeed, here, the data show that similar 

HAP emissions and control technologies 

are found on both major and area 

sources greater than 25 MWe. 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, 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. There are 

EGUs that are physically quite large that 

are area sources, and EGUs that are 

small that are major sources. Both large 

and small EGUs are represented in the 

MACT floor pools for acid gas, Hg, and 

non-Hg metal HAP. Finally, given that 

EPA is regulating both major and area 

source EGUs at the same time in this 

rulemaking, a common control strategy 

consequently appears warranted for 

these emissions. 

If area sources tend to be very 

different from major sources and the 

capacity to control those sources is 

different, we could exercise our 

discretion under section 112(d)(5) to set 

GACT standards for area sources. But, as 

explained above, that is not the case 

here. Accordingly, we believe it is 

appropriate to set MACT standards for 

both major and area source EGUs. EPA 

solicits comment on its proposed 

approach. Specifically, we solicit 

comments on whether there would be a 

basis for considering area sources to be 

significantly different from major 

sources with respect to issues relevant 

to standard setting. Commenters should 

also explain the basis of their suggested 

approach and how that approach would 

lead to similar health and 

environmental benefits, including data 

that would underpin a GACT 

analysis.151

C. Does this proposed rule apply to me? 

This proposed rule applies to you if 

you own or operate a coal- or oil-fired 

EGU as defined in this proposed rule. 

D. Summary of Other Related DC Circuit 

Court Decisions 

In March 2007, the DC Circuit Court 

issued an opinion (Sierra Club v. EPA, 

479 F.3d 875 (DC Cir. 2007)) (Brick 

MACT) vacating and remanding CAA 

section 112(d) NESHAP for the Brick 

and Structural Clay Ceramics source 

categories. Some key holdings in that 

case were: 

• Floors for existing sources must 

reflect the average emission limitation 

achieved by the best-performing 12 

percent of existing sources, not levels 

EPA considers to be achievable by all 

sources (479 F.3d at 880–81); 

• EPA cannot set floors of ‘‘no 

control.’’ The DC Circuit Court reiterated 

its prior holdings, including National 

Lime Ass’n. v. EPA (233 F.3d625 (DC 

Cir. 2000)) (National Lime II), 

confirming that EPA must set floor 

standards for all HAP emitted by the 

source, including those HAP that are not 

controlled by at-the-stack control 

devices (479 F.3d at 883); 

• EPA cannot ignore non-technology 

factors that reduce HAP emissions. 

Specifically, the DC Circuit Court held 

that ‘‘EPA’s decision to base floors 

exclusively on technology even though 

non-technology factors affect emissions 

violates the Act.’’ (479 F.3d at 883.) The 

DC Circuit Court also reiterated its 

position stated in Cement Kiln Recycling 

Coalition v. EPA, 255 F.3d 855 (DC Cir. 

2001) that CAA section 112(d)(3) 

‘‘requires floors based on the emission 

level actually achieved by the best 

performers (those with the lowest 

emission levels).’’ 

Based on the Brick MACT decision, 

we believe a source’s performance 

resulting from the presence or absence 

of HAP in fuel materials must be 

accounted for in establishing floors (i.e., 

a low emitter due to low HAP fuel 

materials can still be a best performer). 

In addition, the fact that a specific level 

of performance is unintended is not a 

legal basis for excluding the source’s 

performance from consideration. 

National Lime II; 233 F.3d at 640. 

The Brick MACT decision also stated 

that EPA may account for variability in 

setting floors. The DC Circuit Court 

found that ‘‘EPA may not use emission 

levels of the worst performers to 

estimate variability of the best 

performers without a demonstrated 

relationship between the two.’’ 479 F.3d 

at 882. 

A second DC Circuit Court opinion is 

also relevant to this proposal. In Sierra 

Club v. EPA, 551 F.3d 1019 (DC Cir. 

2008), the DC Circuit Court vacated the 

portion of the regulations contained in 

the General Provisions which exempt 

major sources from NESHAP during 

periods of startup, shutdown and 

malfunction (SSM). The regulations (in 

40 CFR 63.6(f)(1) and 63.6(h)(1)) 

provided that sources need not comply 

with the relevant CAA section 112(d) 

standard during SSM events and instead 

must ‘‘minimize emissions * * * to the 

greatest extent which is consistent with 

safety and good air pollution control 

practices.’’ As a result of the DC Circuit 

Court decision, sources must comply 

with the emission standards at all times 

and we are addressing SSM in this 

proposed rulemaking. Discussion of this 

issue may be found later in this 

preamble. 

A third relevant DC Circuit Court 

opinion is National Lime II (233 F.3d 

625), where, in considering whether 

EPA may use PM, a criteria pollutant, as 

a surrogate for metal HAP, the DC 

Circuit Court stated that EPA ‘‘may use 

a surrogate to regulate hazardous 

pollutants if it is ‘reasonable’ to do so’’ 

and laid out criteria establishing a threepart analysis for determining whether 

the use of PM as a surrogate for non-Hg 

metal HAP was reasonable. The DC 

Circuit Court found that PM is a 

reasonable surrogate for HAP if: (1) 

‘‘HAP metals are invariably present in 

* * * PM;’’ (2) ‘‘PM control technology 

indiscriminately captures HAP metals 

along with other particulates;’’ and (3) 

‘‘PM control is the only means by which 

facilities ‘achieve’ reductions in HAP 

metal emissions.’’ 233 F.3d at 639. If 

these criteria are satisfied and the PM 

emission standards reflect what the best 

sources achieve—complying with CAA 

section 7412(d)(3)—‘‘EPA is under no 

obligation to achieve a particular 

numerical reduction in HAP metal 

emissions.’’ We have considered this 

case in evaluating whether the surrogate 

standards we propose to establish in 

this proposed rule are reasonable. 

E. EPA’s Response to the Vacatur of the 

2005 Action 

After the vacatur of the Revision Rule, 

EPA evaluated the HAP and other 

emissions data available to establish 

CAA section 112(d) standards for coaland oil-fired EGUs and determined that 

additional HAP emission data were 

required. EPA initiated an information 

collection effort entitled ‘‘Electric Utility 

Steam Generating Unit Hazardous Air 

Pollutant Emissions Information 


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25022 Federal Register / Vol. 76, No. 85 / Tuesday, May 3, 2011 / Proposed Rules 

Collection Effort’’ (OMB Control Number 

2060–0631). This information collection 

(2010 ICR) was conducted by EPA’s 

Office of Air and Radiation (OAR) 

pursuant to CAA section 114 to assist 

the Administrator in developing 

emissions standards for coal- and oilfired EGUs pursuant to CAA section 

112(d). CAA section 114(a) states, in 

pertinent part: 

For the purpose of * * * (iii) carrying out 

any provision of this Chapter * * * (1) the 

Administrator may require any person who 

owns or operates any emission source * * * 

to * * * (D) sample such emissions (in 

accordance with such procedures or 

methods, at such locations, at such intervals, 

during such periods and in such manner as 

the Administrator shall prescribe); (E) keep 

records on control equipment parameters, 

production variables or other indirect data 

when direct monitoring of emissions is 

impractical * * *; (G) provide such other 

information as the Administrator may 

reasonably require * * * 

Prior to issuance of the information 

collection effort, information necessary 

to identify all coal- and oil-fired EGUs 

as defined in CAA section 112(a)(8) was 

publicly available for EGUs owned and 

operated by publicly-owned utility 

companies, Federal power agencies, 

rural electric cooperatives, investorowned utility generating companies, 

and nonutility generators (such units 

include, but may not be limited to, 

independent power producers (IPPs), 

qualifying facilities, and combined heat 

and power (CHP) units). The most 

recent information available was for 

2005, and the available information 

generally did not include any 

information on permitted HAP emission 

limits; or monitoring, recordkeeping, 

and reporting requirements for HAP 

emissions; and we did not have 

complete HAP emissions data for any 

EGU. Additionally, we had little current 

information on the fuel amounts 

received, fuel sources, fuel shipment 

methods, or results of previously 

conducted fuel analyses for coal- and 

oil-fired EGUs, or for results from tests 

conducted since January 1, 2005. We 

did not have emissions test results that 

would provide data for emissions of a 

variety of pollutants, including: PM, PM 

with an aerodynamic diameter equal to 

or less than 2.5 micrometers (PM2.5); 

SO2; HCl/HF/HCN; metal HAP 

(including compounds of Sb, As, Be, Cd, 

Cr, Co, Pb, Mn, Ni, and Se); Hg; total 

organic hydrocarbons (THC); volatile 

organic compounds (VOC); and carbon 

monoxide (CO). 

To obtain the information necessary 

to evaluate coal- and oil-fired EGUs, 

EPA developed a two-phase ICR and 

published the first notice in the Federal 

Register for comment consistent with 

the requirements of the PRA. 74 FR 

31725 (July 2, 2009). We received 

comments from industry and other 

interested parties. We also met with 

industry and other interested parties, 

and published a revised ICR in the 

Federal Register for another round of 

comments consistent with the PRA. 74 

FR 58012 (November 10, 2009). OMB 

approved the ICR on December 24, 

2009, and we sent the ICR to owners 

and operators of EGUs on December 31, 

2010. 

As stated above, the ICR contained 

two phases or components. The first 

component solicited information from 

all potentially affected units. EPA 

provided the survey in electronic 

format; however, written responses were 

also accepted. The survey was 

submitted to all coal- and oil-fired EGUs 

listed in the 2007 version of the DOE’s 

Energy Information Administration’s 

(EIA) Forms 860 and 923, ‘‘Annual 

Electric Generator Report,’’ and ‘‘Power 

Plant Operations Report,’’ respectively. 

The second component required the 

owners/operators of a limited number of 

coal-and oil-fired EGUs to conduct stack 

testing in accordance with an EPAapproved protocol. Some coal-fired 

units were selected to be tested because 

we determined based on the information 

available that the units were among the 

top performing 15 percent of sources in 

the coal subcategory for certain types of 

HAP. Best-performing coal-fired units to 

be tested were selected to cover three 

groups of HAP that may be regulated 

through the use of surrogate standards: 

(1) Non-Hg metallic HAP (e.g., As, Pb, 

Se); (2) acid gas HAP (e.g., HCl, HF, 

HCN); (3) and non-dioxin/furan organic 

HAP. We also required the non-Hg 

metallic HAP sources to test for Hg even 

though Hg is to be regulated separately 

and not covered by any non-Hg metallic 

HAP surrogacy. Fifty coal-fired units 

were also selected at random from the 

entire population of coal-fired EGUs to 

test for dioxin/furan organic HAP. An 

additional 50 coal-fired units were 

selected at random from among those 

units not selected as being ‘‘top 

performing’’ units to represent those 

coal-fired units not comprising the topperforming units in the three HAP 

surrogate groups; these 50 randomly 

selected units were required to test for 

all HAP except dioxin/furan organic 

HAP. Data from this last grouping was 

collected so we could estimate the HAP 

emission reductions associated with the 

proposed standards. Oil-fired units to be 

tested were also selected at random to 

test for HAP in all three groups of HAP 

noted above, in addition to testing for 

Hg and dioxin/furan. 

The testing consisted of three runs at 

the sampling location and was in 

accordance with a specified emission 

test method. The owner/operator of each 

selected EGU was also required to 

collect and analyze, in accordance with 

an acceptable procedure, three fuel 

samples from the fuel fed to the EGU 

during each stack test. Additional 

details of the required sampling may be 

found in Docket entry EPA–HQ–OAR– 

2009–0234–0062. 

In phase one, all coal- and oil-fired 

EGUs identified by EPA as being 

potentially subject sources under the 

definition in CAA section 112(a)(8), 

including all integrated gasification 

combined cycle (IGCC) EGUs and all 

EGUs fired by petroleum coke, were 

required to submit information to EPA. 

The sources were required to provide 

information on the current operational 

status of the unit, including applicable 

controls installed, along with emissions 

information from the preceding 5 years. 

This information was necessary for EPA 

to fully characterize the category and 

update our database of coal- and oilfired EGUs. 

Phase two was the testing phase. As 

stated above, coal-fired units to be 

tested were selected to cover five HAP 

or groups of HAP, three of which may 

be regulated through the use of 

surrogate pollutant standards and were 

chosen because EPA determined the 

units were best performing units for one 

or more of the three HAP surrogate 

groups. In the stack testing, each facility 

was required to test after the last control 

device or at the stack if the stack is not 

shared with other units using different 

controls. In this way, the facility would 

test before any ‘‘dilution’’ by gases from 

a separately-controlled unit. Under 

certain circumstances, however, testing 

after a common control device or at the 

common stack was allowed. 

EPA selected for testing the sources 

that the Agency believed, based on a 

variety of factors and information 

available to the Agency at the time, were 

the best performing sources for the three 

HAP surrogate groups for which they 

were required to test. In targeting the 

best performing sources, EPA required 

testing for approximately 15 percent of 

all coal-fired EGUs for the 3 HAP 

surrogate groups—non-Hg metal HAP 

and PM; non-dioxin/furan organic HAP, 

total hydrocarbon, CO, and VOC; and 

acid gas HAP and SO2. As we stated in 

response to comments on the proposed 

2010 ICR, we targeted the best 

performing coal-fired sources for certain 

HAP groups because the statute requires 

the Agency to set the MACT floor at the 

‘‘average emission limitation achieved 

by the best performing 12 percent of the 


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152Although the combination of extended 

sampling times and stack chemistry for many units 

in this source category rendered the test method for 

HCN unreliable, yielding suspect HCN results, we 

still consider SO2 or HCl emissions to be adequate 

surrogates for HCN emissions. 

153 Gullett, BK, et al. Effect of Cofiring Coal on 

Formation of Polychlorinated Dibenzo-p-Dioxins 

and Dibenzofurans during Waste Combustion. 

Environmental Science and Technology. Vol. 34, 

No. 2:282–290. 2000. 

154Raghunathan, K, and Gullett, BK. Role of 

Sulfur in Reducing PCDD and PCDF Formation. 

Environmental Science and Technology. Vol. 30, 

No. 6:1827–1834. 1996. 

155Li., H, et al. Chlorinated Organic Compounds 

Evolved During the combustion of Blends of Refusederived Fuels and Coals. Journal of Thermal 

Analysis. Vol. 49:1417–1422. 1997. 

existing sources (for which the 

Administrator has information)’’ in the 

category. By targeting the best 

performing 15 percent of coal-fired 

EGUs for testing in the 3 HAP groups, 

we concluded that we would have 

emissions data on the best performing 

12 percent of all existing coal-fired 

EGUs. In this proposed rule, we used 

data from sources representing the best 

performing 12 percent of all sources in 

any category or subcategory to establish 

the CAA section 112(d) standards for 

the 3 HAP groups because we believe 

we have identified the best performing 

12 percent of sources for those 

subcategories with 30 or more sources. 

For Hg from coal-fired units, we used 

the top 12 percent of the data obtained 

because, even though we required Hg 

testing for the units testing for the nonHg metallic HAP, we did not believe 

those units represented the top 

performing 12 percent of sources for Hg 

in the category at the time we issued the 

ICR and we made no assertions to that 

effect. For oil-fired units, we also used 

the top 12 percent of the data obtained 

because we were unable, based on the 

information available, to determine the 

best performing oil-fired units. The 

primary reason for our inability to 

identify best performing oil-fired units 

is that such units are generally 

uncontrolled or controlled only with an 

ESP. The approach for both coal- and 

oil-fired EGUs was discussed with, and 

agreed upon by, several industry and 

environmental organization 

stakeholders prior to finalizing the ICR. 

The acid-gas HAP, HCl and HF, are 

water-soluble compounds and are more 

soluble in water than is SO2. (Cyanide, 

representing the ‘‘cyanide compounds,’’ 

and Cl2 gas are also water-soluble and 

are considered ‘‘acid-gas HAP’’ in this 

proposal.) Hydrogen chloride also has a 

large acid dissociation constant (i.e., 

HCl is a strong acid) and it, thus, will 

react easily in an acid-base reaction 

with caustic sorbents (e.g., lime, 

limestone). The same is true for HF. 

This indicates that both HCl and HF 

will be more rapidly and readily 

removed from a flue gas stream than 

will SO2, even when only plain water is 

used. In FBC systems, the acid gases and 

SO2 are adsorbed by the sorbent (usually 

limestone) that is added to the coal and 

an inert material (e.g., sand, silica, 

alumina, or ash) as part of the FBC 

process. 

Hydrogen chloride and HF have also 

been shown to be effectively removed 

using DSI where a dry, alkaline sorbent 

(e.g., hydrated lime, trona, sodium 

carbonate) is injected upstream of a PM 

control device. 

Chlorine in the fuel coal may also 

partition in small amounts to Cl2. This 

is normally a very small fraction relative 

to the formation of HCl. Limited testing 

has shown that Cl2 gas is also effectively 

removed in FGD systems. Although Cl2

is not strictly an acidic gas, it is grouped 

here with the ‘‘acid gas HAP’’ because it 

is controlled using the same 

technologies. 

Because the technologies for removal 

of the acid gases are primarily those that 

are also used for FGD, we consider 

emissions of SO2, a commonly 

measured pollutant, as a potential 

surrogate for emissions of the acid-gas 

HAP HCl, HF, HCN, and Cl2. Although 

use of SO2 as a surrogate for acid gas 

HAP has not been used in any CAA 

section 112 rules by EPA, it has been 

used in a number of state permitting 

actions (see Docket entry EPA–HQ– 

OAR–2009–0234–0062). Hydrogen 

chloride has been used as a surrogate for 

the acid gas HAP in other Agency 

actions (e.g., Portland Cement NESHAP, 

75 FR 54970, September 9, 2010 (final 

rule); major and area source Industrial, 

Commercial, and Institutional Boilers 

and Process Heaters NESHAP 

(collectively, Boiler NESHAP), 75 FR 

32005, June 4, 2010; 75 FR 31895, June 

4, 2010 (proposed rules; the final rules 

were signed on February 21, 2011)), and 

we propose to use HCl as a surrogate for 

all the acid gas HAP, with an alternative 

equivalent standard using SO2 as a 

surrogate. In addition, we gathered 

sufficient data on HCl, HF, and HCN 152

to establish individual emission 

limitations if warranted. 

EPA identified the units with the 

newest FGD controls installed for 

testing of acid gas HAP based on our 

analysis that FGD controls are the best 

at reducing acid gas HAP emissions. 

EPA also believes that the units with the 

newest FGD systems represent those 

units having to comply with the most 

recent, and, therefore, likely most 

stringent, emission limits for SO2. We 

determined that efforts by units to 

comply with stringent SO2 limits would 

also likely represent the top performers 

with regard to acid gas HAP emissions. 

Specifics of the required testing may be 

found in Docket entry EPA–HQ–OAR– 

2009–0234–0062. 

Dioxin/furan emissions data were 

obtained in support of the 1998 Utility 

Report to Congress. However, 

approximately one-half of those data 

were listed as being below the minimum 

detection level (MDL) for the given test. 

Dioxin/furan emissions from coal-fired 

EGUs are generally considered to be 

low, presumably because of the 

insufficient amounts of available 

chlorine. As a result of previous work 

conducted on municipal waste 

combustors (MWC), it has also been 

proposed that the formation of dioxins 

and furans in exhaust gases is inhibited 

by the presence of sulfur.153 Further, it 

has been suggested that if the sulfur-tochlorine ratio (S:Cl) in the flue gas is 

greater than 1.0, then formation of 

dioxins/furans is inhibited.154 155 The 

vast majority of the coal analyses 

provided through the 1999 ICR effort 

indicated S:Cl values greater than 1.0. 

As a result, EPA expected that 

additional data gathering efforts would 

continue the trend of data being at or 

below the MDL. Even so, EPA believed 

it necessary to collect some additional 

data so that the trend could be affirmed 

or rejected for EGUs. If the trend were 

rejected, then EPA would be able to 

establish an emission limit for dioxin/ 

furan; however, if the trend were 

affirmed, then EPA would need to seek 

alternatives to an emissions limit, such 

as a work practice standard. The latter 

approach might become necessary 

because measurements made at or below 

MDL generally indicate the presence, 

but not the exact quantity, of a 

substance. In addition, measurements 

made at or below the MDL have an 

accuracy on the order of plus or minus 

50 percent, whereas other 

environmental measurements used by 

EPA in other rulemakings exhibit 

accuracies of plus or minus up to 15 

percent. Sampling and analytical 

methods for dioxins/furans have 

improved since the 1990’s work, so their 

MDLs are expected to have decreased. 

Moreover, for this sampling effort, we 

required sampling periods to be 

extended up to eight times longer than 

normal to collect more sample volume, 

thus, hopefully improving detection 

capability. Note that although longer 

sampling periods can be obtained 

during short term emissions testing, 

maintaining such longer sampling times 


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becomes impractical, if not infeasible, 

for continuous monitoring. 

For these reasons, we selected 50 

units at random from the entire coalfired EGU population to conduct 

emission testing for dioxins/furans. EPA 

has identified AC as a potential control 

technology for dioxin/furan control 

based on results of previous work done 

on MWC units, and several of the units 

that were selected for testing have ACI 

systems that had been installed for Hg 

control. Specifics of the required testing 

may be found in Docket entry EPA–HQ– 

OAR–2009–0234–0062. 

Emissions of CO, VOC, and/or THC 

have, in the past, been used as 

surrogates for the non-dioxin/furan 

organic HAP based on the theory that 

efficient combustion leads to lower 

organic emissions (Portland Cement 

NESHAP—THC (75 FR 54970; 

September 9, 2010); Boiler NESHAP— 

CO (75 FR 32005, June 4, 2010; 75 FR 

31895, June 4, 2010 (proposed rules; the 

final rules were signed on February 21, 

2011)); Hazardous Waste Combustor 

NESHAP—CO (64 FR 52828; September 

30, 1999)). Although indications are that 

organic HAP emissions are low (and 

perhaps below the MDL), there were 

very few emissions data available for 

these compounds from coal-fired EGUs 

and we determined that it was necessary 

to obtain additional information on 

which to establish standards for these 

HAP. EPA identified the newest units as 

being representative of the most 

modern, and, thus, presumed most 

efficient units. The 170 newest units 

were selected and were required to test 

for CO, VOC, and THC; specifics of the 

required testing may be found in Docket 

entry EPA–HQ–OAR–2009–0234–0062. 

Emissions of certain non-Hg metallic 

HAP (i.e., Sb, Be, Cd, Cr, Co, Pb, Mn, 

and Ni) have been assumed to be well 

controlled by PM control devices. 

However, Hg and other non-Hg metallic 

HAP (i.e., As and Se), have the potential 

to exist in both the particulate and 

vapor phases, and, therefore, may not be 

well controlled by PM control devices 

alone. Also, it has been shown through 

recent stack testing that certain of these 

HAP (i.e., As and Se) may condense on 

(or as) very fine PM in the emissions 

from coal-fired units. There are very few 

recent emissions test data available 

showing the potential control of these 

metallic HAP from coal-fired EGUs. 

EPA identified the units with the 

newest PM controls installed as the 

units to test for non-Hg metal HAP. EPA 

believed that these units represent those 

units having to comply with the most 

recent, and, therefore, likely most 

stringent, emission limits for PM. EPA 

believes units complying with stringent 

PM limits represent the top performers 

with regard to non-Hg metallic HAP 

emissions, even for those HAP that may 

at times form in other than the 

particulate phase. The units selected 

also included a number with ACI 

installed. The 170 units with the newest 

PM controls installed were selected and 

were required to test after that specific 

PM control (or at the stack if the PM 

control device is not shared with one or 

more other units); specifics of the 

required testing may be found in Docket 

entry EPA–HQ–OAR–2009–0234–0062. 

The capture of Hg is dependent on 

several factors including the chloride 

content of the coal, the sulfur content of 

the coal, the amount of unburned 

carbon present in the fly ash, and the 

flue gas temperature profile. All of these 

factors affect the chemical form (the 

speciation) of Hg in the flue gas. 

Mercury may exist as Hg0, as Hg+2 (or 

reactive gaseous Hg, RGM) or as Hgp. 

Based on available data, EPA believes 

that sorbent injection (including ACI) 

has the potential to be a very effective 

technology for controlling Hg emissions 

in coal-fired plants, and some units 

using ACI for Hg control were among 

those selected for testing. EPA had no 

direct stack test results showing how 

effectively these ACI-equipped plants 

reduce their Hg emissions. The 

effectiveness of ACI is highly dependent 

upon the type of sorbent used (i.e., 

chemically treated versus conventional 

AC) and on the amount injected. 

Further, previous data-gathering efforts 

had shown that FFs are capable of 

providing highly effective control of 

certain species of Hg and, in some cases, 

as high or higher than that achieved by 

ACI (ACI is not always used to achieve 

maximum reductions in Hg but, rather, 

to achieve permit requirements). Thus, 

testing for Hg was included with the 

testing for the non-Hg metallic HAP. 

To be able to assess the impact of the 

standards (e.g., reduction in HAP 

emissions over current conditions), EPA 

selected at random 50 units from the 

population of coal-fired units not 

selected in any of the above groups to 

test; specifics of the required testing 

may be found in Docket entry EPA–HQ– 

OAR–2009–0234–0062. We did not use 

the data gathered for the Utility Study 

because those data are outdated and 

lack sufficient detail. Thus, EPA 

believed that gathering these data was 

necessary to assess the emissions of this 

important source category. 

All IGCC units were also required to 

test; specifics of the required testing 

may be found in Docket entry EPA–HQ– 

OAR–2009–0234–0062. 

EPA was able to identify the best 

performing coal-fired units for the three 

HAP surrogate groups but the data 

obtained in support of the Utility Study 

and the December 2000 Finding do not 

indicate that any oil-fired units control 

beyond some ESP use and the data do 

not show any correlation between the 

PM control at oil-fired units and 

emissions of non-Hg metallic HAP from 

those units. Further, no oil-fired EGU 

has been constructed in decades and no 

oil-fired EGU has a FGD system 

installed, eliminating the potential basis 

for the use of compliance with an SO 2

emissions limit that resulted in the 

installation of an FGD system as a basis 

for selecting best performers for the 

acid-gas HAP from such units. Thus, 

EPA had no basis for determining which 

oil-fired units may be the ‘‘best 

performers.’’ Therefore, EPA required 

that 66 units selected at random from 

the population of known oil-fired units 

test their stack emissions; specifics of 

the required testing may be found in 

Docket entry EPA–HQ–OAR–2009– 

0234–0062. 

All petroleum coke-fired units 

identified were required to test; 

specifics of the required testing may be 

found in Docket entry EPA–HQ–OAR– 

2009–0234–0062. 

Pursuant to CAA section 112(q)(3), 

CAA section 112 as in effect prior to the 

1990 CAA amendments remains in 

effect for radionuclide emissions from 

coal-fired EGUs at the Administrator’s 

discretion. For this reason, we did not 

require testing for radionuclides. We are 

also not proposing standards for 

radionuclides in this action. 

F. What is the relationship between this 

proposed rule and other combustion 

rules? 

1. CAA Section 111 

Revised NSPS for SO2, NOX, and PM 

were promulgated 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, we are proposing 

certain amendments to 40 CFR part 60, 

subpart Da. In developing this proposed 

rule, we considered the monitoring 

requirements, testing requirements, and 

recordkeeping requirements of the 

existing NSPS to avoid duplicating 

requirements to the extent possible. 

2. CAA Section 112 

EPA has previously developed other 

non-EGU combustion-related NESHAP 

under CAA section 112(d) in addition to 

today’s proposed rule for coal- and oilfired EGUs. EPA signed final NESHAP 

for major and area source Boiler 

NESHAP on February 21, 2011 (to be 


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156Heat 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 IB). 

codified at 40 CFR part 63, subpart 

DDDDD and subpart JJJJJJ, respectively) 

and promulgated standards for 

stationary combustion turbines (CT) on 

March 5, 2004 (69 FR 10512; 40 CFR 

part 63 subpart YYYY). In addition to 

these two NESHAP, on February 21, 

2011, EPA also signed final CAA section 

129 standards for commercial and 

institutional solid waste incinerator 

(CISWI) units, including energy 

recovery units (to be codified at 40 CFR 

part 60, subparts CCCC (NSPS) and 

DDDD (emission guidelines) and a 

definition of non-hazardous secondary 

materials that are solid waste (Nonhazardous Solid Waste Definition Rule, 

to be codified at 40 CFR part 241, 

subpart B). EGUs and IB that combust 

fossil fuel and solid waste, as that term 

is defined by the Administrator 

pursuant to the Resource Conservation 

and Recovery Act (RCRA), will be 

subject to section 129 (e.g., CISWI 

energy recovery units), unless they meet 

one of the exemptions in CAA section 

129(g). CAA section 129 standards are 

discussed in more detail below. 

The two IB NESHAP, CT NESHAP, 

and this proposed 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 (MWe or Btu/hr), 

the boiler/furnace technology, or the 

portion of their electrical output (if any) 

for sale to any utility power distribution 

systems. See CAA section 112(a)(8) 

(defining EGU) earlier. 

All of the MWe ratings quoted in the 

proposed rule are considered to be the 

original nameplate rated capacity of the 

unit. Cogeneration is defined as the 

simultaneous production of power 

(electricity) and another form of useful 

thermal energy (usually steam or hot 

water) from a single fuel-consuming 

process. 

The CT rule regulates HAP emissions 

from all simple-cycle and combinedcycle stationary CTs producing 

electricity or steam for any purpose. 

Because of their combustion technology, 

simple-cycle and combined-cycle 

stationary CTs (with the exception of 

IGCC units that burn gasified coal or 

petroleum coke syngas) are not 

considered EGUs for purposes of this 

proposed rule. 

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., no sales 

are made to the national electrical 

distribution grid) is considered an IB 

unit. A fossil fuel-fired combustion unit 

that serves a generator that produces 

electricity for sale is not considered to 

be an EGU under the proposed rule if 

the size of the combustion unit is less 

than or equal to 25 MWe. Units under 

that size would be subject to one of 

appropriate Boiler NESHAP. Further, 

EPA interprets the CAA section 

112(a)(8) definition such that a noncogeneration unit must both have a 

combustion unit of more than 25 MWe 

and supply more than 25 MWe to any 

utility power distribution system for 

sale to be considered an EGU pursuant 

to this proposed rule so as to be 

consistent with the cogeneration 

definition in CAA section 112(a)(8). 

Such units that sell less than 25 MWe 

of their power generation to the grid 

would be subject to the appropriate 

Boiler NESHAP. 

As noted earlier, natural gas-fired 

EGU’s were not included in the 

December 2000 listing. Thus, this 

proposed rule would not regulate a unit 

that otherwise meets the CAA section 

112(a)(8) definition of an EGU but 

combusts natural gas exclusively or 

natural gas in combination with another 

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. Such units are 

considered to be natural gas-fired EGUs 

and would not be subject to this 

proposed rule. 

The CAA does not define the terms 

‘‘fossil fuel’’ and ‘‘fossil fuel fired;’’ 

therefore, we are proposing definitions 

for both terms. The definition of ‘‘fossil 

fuel fired’’ will determine the 

applicability of the proposed rule to 

combustion units that sell electricity to 

the utility power distribution system. A 

number of units that may otherwise 

meet the CAA section 112(a)(8) EGU 

definition fire primarily non-fossil fuels 

(e.g., biomass). However, these units 

generally startup using either natural 

gas or oil and may use these fuels (or 

coal) during normal operation for flame 

stabilization. We have included a 

definition that will establish the scope 

of applicability based in part on the 

amount of fossil fuel combustion 

necessary to make a unit become ‘‘fossil 

fuel fired,’’ and the units that combust 

primarily non-fossil fuel will be subject 

to this proposed rule should they fire 

more than that amount of coal or oil. 

Specifically, EPA is proposing that an 

EGU must be capable of combusting 

more than 73 MWe (250 MMBtu/hr) 

heat input 156 (equivalent to 25 MWe 

output) of coal or oil to be considered 

an EGU subject to this proposed rule. To 

be ‘‘capable of combusting’’ coal or oil, 

a unit would need to have fossil fuels 

allowed in their permits and have the 

appropriate fuel handling facilities onsite (e.g., coal handling equipment, 

including for purposes of example, but 

not limited to, coal storage area, belts 

and conveyers, pulverizers, etc.; oil 

storage facilities). In addition, EPA is 

proposing that an EGU 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 to be considered a fossil fuel-fired 

EGU subject to this proposed rule. Units 

that do not meet these definitions 

would, in most cases, be considered IB 

units subject to one of the Boiler 

NESHAP. Thus, for example, a biomassfired 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. EPA has 

based its threshold value on the 

definition of ‘‘oil-fired’’ in the ARP 

found at 40 CFR 72.2. As EPA has no 

data on such use for (e.g.) biomass cofired 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. EPA solicits 

comment on the use of these definitions. 

Commenters suggesting alternate 

definitions (including thresholds) 

should provide detailed information in 

support of their comment (e.g., 3- to 

5-year average fossil fuel use under 

conditions of startup and flame 

stabilization). 

Also, a cogeneration facility that sells 

electricity to any utility power 

distribution system equal to more than 

one-third of their potential electric 

output capacity and more than 25 MWe 

is considered to be an EGU if it is fossil 

fuel fired as that term is defined above. 

For such units, EPA is proposing that 

the unit must be capable of combusting 

sufficient coal or oil to generate 25 MWe 

from the fossil fuel alone, and must 

provide for sale to any utility power 

distribution system electricity equal to 


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more than one-third of their potential 

electric output capacity and greater than 

25 MWe electrical output. However, a 

cogeneration facility that meets the 

above definition of an EGU during any 

portion of a month would be subject to 

the proposed EGU rule for the 

succeeding 6 calendar months 

(combustion units that begin 

combusting solid waste must 

immediately comply with an applicable 

CAA section 129 standard (e.g., CISWI 

standards applicable to energy recovery 

units)). 

We recognize that different section 

112 rules may impact a particular unit 

at different times. For example there 

will likely be some cogeneration units 

that are determined to be covered under 

the Boiler NESHAP. Such unit may 

make a decision to increase/decrease the 

proportion of production output being 

supplied to the electric utility grid, thus 

causing the unit to meet the EGU 

cogeneration criteria (i.e., greater than 

one-third of its potential output capacity 

and greater than 25 MWe). A unit 

subject to one of the Boiler NESHAP 

that increases its electricity output and 

meets the definition of an EGU would 

be subject to the proposed EGU 

NESHAP for the 6-month period after 

the unit meets the EGU definition. 

Assuming the unit 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. 

This approach is consistent with that 

taken on the CISWI rulemaking. 

EPA solicits comment on the extent to 

which this situation might occur and 

whether the 6-month period is 

appropriate. Given the differences 

between the rules, should EPA address 

reclassification of the sources between 

the rules, particularly with regard to 

initial and ongoing compliance 

requirements and schedules? (As noted 

above, EPA is proposing to consider as 

an EGU any cogeneration unit that 

meets the definition noted earlier during 

any month in a year.) We specifically 

solicit comments as to how to address 

sources that may meet the definition of 

an EGU for only parts of a year. We also 

solicit comment on whether we should 

include provisions similar to those 

included in the final CISWI rule to 

address units that combust different 

fuels at different times. See Final CISWI 

Rule, 40 CFR 60.2145, http:// 

www.epa.gov/airquality/combustion/ 

docs/20110221ciswi.pdf. 

Another situation 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, the emissions have to 

either be apportioned to the appropriate 

source or the more stringent emission 

limit must be met. Data needed to 

apportion emissions are not currently 

required by this proposed rule or the 

final Boiler NESHAP. Therefore, EPA is 

proposing that compliance with the 

more stringent emission limit be 

demonstrated. 

EPA solicits comment on the extent to 

which this situation might occur. Given 

potential differences between the rules, 

how should EPA address apportionment 

of the emissions to the individual 

sources with regard to initial and 

ongoing compliance requirements? EPA 

specifically requests comment on the 

appropriateness of a mass balance-type 

methodology to determine pollutant 

apportionment between sources both 

pre-APCD and post-APCD. 

3. CAA Section 129 

Units that combust ‘‘non-hazardous 

solid waste’’ as defined by the 

Administrator under RCRA are 

regulated under the provisions of CAA 

section 129. On February 21, 2011, EPA 

signed the final Non-Hazardous Solid 

Waste Definition Rule. Any EGU that 

combusts any solid waste as defined in 

that final rule is a solid waste 

incineration unit subject to CAA section 

129. 

In the Non-Hazardous Solid Waste 

Definition Rule, 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 the 

discarded coal refuse is processed in the 

same manner as currently mined coal 

refuse, the coal refuse would not be a 

solid waste and, therefore, the 

combustion of such material would not 

subject the unit to regulation under 

CAA section 129. By contrast, the unit 

would be subject to this rule if it meets 

the definition of EGU. If the unit 

combusts solid waste, it would be 

subject to emission standards under 

CAA section 129. See, e.g., CISWI rule. 

Coal refuse properly processed is a 

product fossil fuel (i.e., not a solid 

waste) if it is not a solid waste; thus, 

combustion units that otherwise meet 

the CAA section 112(a)(8) EGU 

definition that combust coal refuse that 

is product fuel not a solid waste are 

EGUs subject to this proposed rule. For 

this proposed rule, we assumed that all 

units that combust coal refuse and 

otherwise meet the definition of a coalfired EGU combust newly mined coal 

refuse or coal refuse from legacy piles 

that has been processed such that it is 

not a solid waste. We request comment 

on this assumption and whether there 

are any units combusting coal refuse 

that is a solid waste such that the units 

would be solid waste incineration units 

instead of EGUs. 

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

exempts from regulation under CAA 

section 129 

‘‘* * * 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 

other forms of useful energy (such as heat) 

which are used for industrial, commercial, 

heating or cooling purposes * * *’’ 

Thus, qualifying small power 

production facilities and cogeneration 

facilities that burn a homogeneous 

waste would be exempt from regulation 

under CAA section 129. If the 

‘‘homogeneous waste’’ material 

combusted is a fossil fuel, then the units 

that are exempt from regulation under 

CAA section 129 and that otherwise 

meet the definition of an EGU under 

CAA section 112(a)(8) would be covered 

under this proposed rule. For example, 

a unit that combusts only coal refuse 

that is a solid waste would be subject to 

this proposed rule if the unit met the 

definition of EGU and the coal refuse 

was determined to be a ‘‘homogenous 

waste’’ as that term is defined in the 

final CAA section 129 CISWI standards 

(the final rule was signed on February 

21, 2011, but has not yet been published 

in the Federal Register). 

G. What emission limitations and work 

practice standards must I meet? 

We are proposing the emission 

limitations presented in Tables 10 and 

11 of this preamble. Within the two 

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

emission limitations were developed for 

new and existing sources for five 

subcategories, two for coal-fired EGUs, 

one for coal- and solid oil-derived IGCC 

EGUs, and two for oil-fired EGUs, which 

we developed based on unit type. 

We are proposing that new or existing 

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

coal and meet the proposed definition of 

‘‘fossil fuel fired.’’ We are proposing that 

an EGU is considered to be a ‘‘coal-fired 

unit designed for coal greater than or 

equal to 8,300 Btu/lb’’ if the EGU: (1) 

Combusts coal; (2) meets the proposed 

definition of ‘‘fossil fuel fired;’’ and (3) 

burns any coal in an EGU designed to 

burn a coal having a calorific value 

(moist, mineral matter-free basis) of 


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157U.S. Department of Energy, Wabash River Coal 

Gasification Repowering Project. Project 

Performance Summary; Clean Coal Technology 

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

greater than or equal to 19,305 

kilojoules per kilogram (kJ/kg) (8,300 

British thermal units per pound (Btu/ 

lb)) in an EGU with a height-to-depth 

ratio of less than 3.82. We are proposing 

that the EGU is considered to be a ‘‘coalfired unit designed for coal less than 

8,300 Btu/lb’’ if the EGU: (1) Combusts 

coal; (2) meets the proposed definition 

of ‘‘fossil fuel fired;’’ and (3) burns any 

virgin coal in an EGU designed to burn 

a nonagglomerating fuel having a 

calorific value (moist, mineral matterfree basis) of less than 19,305 kJ/kg 

(8,300 Btu/lb) in an EGU with a heightto-depth ratio of 3.82 or greater. 

We are proposing that the EGU is 

considered to be an IGCC unit if the 

EGU: (1) Combusts gasified coal or solid 

oil-derived (e.g., petroleum coke); (2) 

meets the proposed definition of ‘‘fossil 

fuel fired;’’ and (3) is classified as an 

IGCC unit. We are not proposing to 

subcategorize IGCC EGUs based on the 

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

petroleum coke). Based on information 

available to the Agency, although the 

fuel characteristics of coal and petcoke 

are quite different, the syngas products 

are very similar from both feedstocks.157

We are proposing that the EGU is 

considered to be ‘‘liquid oil’’ fired if the 

EGU burns liquid oil and meets the 

proposed definition of ‘‘fossil fuel fired.’’ 

We are proposing that the EGU is 

considered to be ‘‘solid oil-derived fuelfired’’ if the EGU burns any solid oilderived fuel (e.g., petroleum coke) and 

meets the proposed definition of ‘‘fossil 

fuel fired.’’ 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. 

TABLE 10—EMISSION LIMITATIONS FOR COAL-FIRED AND SOLID OIL-DERIVED FUEL-FIRED EGUS 

Subcategory Total particulate matter Hydrogen chloride Mercury 

Existing coal-fired unit designed for coal 

≥ 8,300 Btu/lb.

0.030 lb/MMBtu (0.30 lb/MWh) 0.0020 lb/MMBtu (0.020 lb/ 

MWh).

1.0 lb/TBtu (0.0.008 lb/GWh). 

Existing coal-fired unit designed for coal 

< 8,300 Btu/lb.

0.030 lb/MMBtu (0.30 lb/MWh) 0.0020 lb/MMBtu (0.020 lb/ 

MWh).

11.0 lb/TBtu (0.20 lb/GWh) 4.0 

lb/TBtu * (0.040 lb/GWh *). 

Existing—IGCC ........................................ 0.050 lb/MMBtu (0.30 lb/MWh) 0.00050 lb/MMBtu (0.0030 lb/ 

MWh).

3.0 lb/TBtu (0.020 lb/GWh). 

Existing—Solid oil-derived ........................ 0.20 lb/MMBtu (2.0 lb/MWh) ..... 0.0050 lb/MMBtu (0.080 lb/ 

MWh).

0.20 lb/TBtu (0.0020 lb/GWh). 

New coal-fired unit designed for coal 

≥ 8,300 Btu/lb.

0.050 lb/MWh ............................ 0.30 lb/GWh .............................. 0.000010 lb/GWh. 

New coal-fired unit designed for coal 

< 8,300 Btu/lb.

0.050 lb/MWh ............................ 0.30 lb/GWh .............................. 0.040 lb/GWh. 

New—IGCC .............................................. 0.050 lb/MWh * .......................... 0.30 lb/GWh * ............................ 0.000010 lb/GWh *. 

New—Solid oil-derived ............................. 0.050 lb/MWh ............................ 0.00030 lb/MWh ........................ 0.0020 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-electric output (gross). 

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

* Beyond-the-floor limit as discussed elsewhere. 

TABLE 11—EMISSION LIMITATIONS FOR LIQUID OIL-FIRED EGUS 

Subcategory Total HAP metals * Hydrogen chloride Hydrogen fluoride 

Existing—Liquid oil ................................... 0.000030 lb/MMBtu ...................

(0.00030 lb/MWh) ......................

0.00030 lb/MMBtu .....................

(0.0030 lb/MWh) ........................

0.00020 lb/MMBtu. 

(0.0020 lb/MWh). 

New—Liquid oil ........................................ 0.00040 lb/MWh ........................ 0.00050 lb/MWh ........................ 0.00050 lb/MWh. 

* Includes Hg. 

Pursuant to CAA section 112(h), we 

are proposing a work practice standard 

for organic HAP, including emissions of 

dioxins and furans, from all 

subcategories of EGU. The work practice 

standard being proposed for these EGUs 

would require the implementation of an 

annual performance (compliance) test 

program as described elsewhere in this 

preamble. We are proposing work 

practice standards because the data 

confirm that the significant majority of 

the measured organic HAP emissions 

from EGUs are below the detection 

levels of the EPA test methods, and, as 

such, EPA considers it impracticable to 

reliably measure emissions from these 

units. As discussed later in this 

preamble, EPA believes the inaccuracy 

of a majority of measurements coupled 

with the extended sampling times used, 

fulfill the criteria for these HAP to be 

subject to a work practice standard 

under CAA section 112(h). 

We are proposing a beyond-the-floor 

standard for Hg only for all existing 

coal-fired units designed for coal less 

than 8,300 Btu/lb based on the use of 

ACI for Hg control, as described 

elsewhere in this preamble. We are 

proposing a beyond-the-floor standard 

for all pollutants for new IGCC units 

based on the new-source limits for coalfired units designed for coal greater than 

or equal to 8,300 Btu/lb as described 

elsewhere in this preamble. 

As noted elsewhere in this preamble, 

we are proposing to use total PM as a 

surrogate for the non-Hg 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 fuelfired EGUs. For liquid oil-fired EGUs, 

we are proposing total HAP metal, HCl, 

and HF emission limitations. 


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In addition, we are proposing three 

alternative standards for certain 

subcategories: (1) SO2 (as an alternative 

equivalent to HCl for all subcategories 

with add-on FGD systems); (2) 

individual non-Hg metallic HAP (as an 

alternate to PM for all subcategories 

except liquid oil-fired); (3) total non-Hg 

metallic HAP (as an alternate to PM for 

all subcategories except liquid oil-fired); 

and (4) individual metallic HAP (as an 

alternate to total metal HAP) for the 

liquid oil-fired subcategory. These 

alternative proposed standards are 

discussed elsewhere in this preamble. 

H. What are the startup, shutdown, and 

malfunction (SSM) requirements? 

The DC Circuit Court vacated portions 

of two provisions in EPA’s CAA section 

112 regulations governing the emissions 

of HAP during periods of SSM. Sierra 

Club v. EPA, 551 F.3d 1019 (DC Cir. 

2008), cert. denied, 130 S. Ct. 1735 (U.S. 

2010). Specifically, the DC Circuit Court 

vacated the SSM exemption contained 

in 40 CFR 63.6(f)(1) and 40 CFR 

63.6(h)(1), that are part of a regulation, 

commonly referred to as the ‘‘General 

Provisions Rule,’’ that EPA promulgated 

under CAA section 112. When 

incorporated into CAA section 112(d) 

regulations for specific source 

categories, these two provisions exempt 

sources from the requirement to comply 

with the otherwise applicable CAA 

section 112(d) emission standard during 

periods of SSM. 

Consistent with Sierra Club, EPA is 

proposing standards in this rule that 

apply at all times. In proposing the 

standards in this rule, EPA has taken 

into account startup and shutdown 

periods and, for the reasons explained 

below, has not proposed different 

standards for those periods. The 

standards that we are proposing are 30 

boiler operating day averages. EGUs, 

especially solid fuel-fired EGUs, do not 

normally startup and shutdown 

frequently and typically use cleaner 

fuels (e.g., natural gas or oil) during the 

startup period. Based on the data before 

the Agency, we are not establishing 

different emissions standards for startup 

and shutdown. 

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. 

Periods of startup, normal operations, 

and shutdown are all predictable and 

routine aspects of a source’s operations. 

However, by contrast, malfunction is 

defined as a ‘‘sudden, infrequent, and 

not reasonably preventable failure of air 

pollution control and monitoring 

equipment, process equipment or a 

process to operate in a normal or usual 

manner * * *.’’ 40 CFR 63.2. EPA has 

determined that malfunctions should 

not be viewed as a distinct operating 

mode and, therefore, any emissions that 

occur at such times do not need to be 

factored into development of CAA 

section 112(d) standards, which, once 

promulgated, apply at all times. In 

Mossville Environmental Action Now v. 

EPA, 370 F.3d 1232, 1242 (DC Cir. 

2004), the DC Circuit Court upheld as 

reasonable standards that had factored 

in variability of emissions under all 

operating conditions. However, nothing 

in CAA section 112(d) or in case law 

requires that EPA anticipate and 

account for the innumerable types of 

potential malfunction events in setting 

emission standards. See, Weyerhaeuser 

v. Costle, 590 F.2d 1011, 1058 (DC 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.’’) 

Further, it is reasonable to interpret 

CAA section 112(d) as not requiring 

EPA to account for malfunctions in 

setting emissions standards. For 

example, we note that CAA section 112 

uses the concept of ‘‘best performing’’ 

sources in defining MACT, the level of 

stringency that major source standards 

must meet. Applying the concept of 

‘‘best performing’’ to a source that is 

malfunctioning presents significant 

difficulties. The goal of best performing 

sources is to operate in such a way as 

to avoid malfunctions of their units. 

Moreover, even if malfunctions were 

considered a distinct operating mode, 

we believe it would be impracticable to 

take malfunctions into account in 

setting CAA section 112(d) standards for 

EGUs. As noted above, by definition, 

malfunctions are sudden and 

unexpected events and it would be 

difficult to set a standard that takes into 

account the myriad different types of 

malfunctions that can occur across all 

sources in the category. Moreover, 

malfunctions can vary in frequency, 

degree, and duration, further 

complicating standard setting. 

In the unlikely event that a source 

fails to comply with the applicable CAA 

section 112(d) standards as a result of a 

malfunction event, EPA would 

determine an appropriate response 

based on, among other things, the good 

faith efforts of the source to reduce the 

likelihood that malfunctions would 

occur, minimize emissions during 

malfunction periods, including 

preventative and corrective actions, as 

well as root cause analyses to ascertain 

and rectify excess emissions. EPA 

would also consider whether the 

source’s failure to comply with the CAA 

section 112(d) standard was, in fact, 

‘‘sudden, infrequent, not reasonably 

preventable’’ and was not instead 

‘‘caused in part by poor maintenance or 

careless operation.’’ See 40 CFR 63.2 

(definition of malfunction). 

Finally, 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 

(September 20, 1999); Policy on Excess 

Emissions During Startup, Shutdown, 

Maintenance, and Malfunctions 

(February 15, 1983)). EPA is, therefore, 

proposing 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 

are proposing 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 section 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 


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the narrow definition of malfunction in 

40 CFR 63.2 (sudden, infrequent, not 

reasonably preventable and not caused 

by poor maintenance and/or careless 

operation). For example, to successfully 

assert the affirmative defense, the source 

must prove by a preponderance of the 

evidence that excess emissions ‘‘[w]ere 

caused by a sudden, infrequent, and 

unavoidable failure of air pollution 

control and monitoring equipment, 

process equipment, or a process to 

operate in a normal or usual manner 

* * *.’’ The criteria also are designed to 

ensure that steps are taken to correct the 

malfunction, to minimize emissions in 

accordance with 40 CFR 63.10000(b) 

and to prevent future malfunctions. For 

example, the source must prove by a 

preponderance of the evidence that 

‘‘[r]epairs were made as expeditiously as 

possible when the applicable emission 

limitations were being exceeded * * *’’ 

and that ‘‘[a]ll possible steps were taken 

to minimize the impact of the excess 

emissions on ambient air quality, the 

environment and human health * * *’’ 

In any judicial or administrative 

proceeding, the Administrator may 

challenge the assertion of the affirmative 

defense and, if the respondent has not 

met its burden of proving all of the 

requirements in the affirmative defense, 

appropriate penalties may be assessed 

in accordance with CAA section 113. 

See also 40 CFR part 22.77. 

I. What are the testing requirements? 

We are proposing that the owner or 

operator of a new or existing coal- or oilfired 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 concentration of a regulated 

pollutant under proposed 40 CFR part 

63, subpart UUUUU (e.g., Hg CEMS, 

SO2 CEMS, or HCl CEMS) or sorbent 

trap monitoring systems, the initial 

performance test would consist of all 

valid data recorded with the certified 

monitoring system in the first 30 

operating days after the compliance 

date. For units using CEMS to measure 

a surrogate for a regulated pollutant (i.e., 

PM CEMS), initial stack testing of the 

surrogate and the regulated pollutant 

conducted during the same compliance 

test period and under the same process 

(e.g., fuel) and control device operating 

conditions would be required, and an 

operating limit would be established. 

Affected units would be required to 

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 total PM 

emission limit, then you would conduct 

HAP metals and PM emissions testing 

during the same compliance test period 

and under the same process (e.g., fuel) 

and control device operating conditions 

initially and every 5 years using EPA 

Methods 29, 5, and 202. Continuous 

compliance would be determined using 

a PM CEMS with an operating limit 

established based on the filterable PM 

values measured using Method 5. If you 

elect to comply with the total HAP 

metals emission limit or the individual 

HAP metals emissions limits, then you 

would conduct total PM and HAP 

metals testing during the same 

compliance test period and under the 

same process (e.g., fuel) and control 

device operating conditions at least 

once every 5 years and, to demonstrate 

continuous compliance, you would 

conduct total or individual HAP metals 

emissions testing every 2 months (or 

every month if you have no PM control 

device) using EPA Method 29. Note that 

the filter temperature for each Method 

29 or 5 emissions test is to be 

maintained at 160 ± 14 °C (320 ± 25 °F) 

and that the material in Method 29 

impingers is to be analyzed for metals 

content. 

(2) Coal-fired, IGCC, and solid oilderived fuel-fired units would be 

required to use a Hg CEMS or sorbent 

trap monitoring system for continuous 

compliance using the continuous Hg 

monitoring provisions of proposed 

Appendix A to proposed 40 CFR part 

63, subpart UUUUU. The initial 

performance test would consist of all 

valid data recorded with the certified Hg 

monitoring system in the first 30 boiler 

operating days after the compliance 

date. 

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

fuel-fired units and new or 

reconstructed IGCC units that have SO2

emission controls and elect to use SO2

CEMS for continuous compliance, an 

initial stack test for SO2 would not be 

required. Instead the first 30 days of SO2

CEMS data would be used to determine 

initial compliance. For units with or 

without SO2 or HCl emission controls 

that elect to use HCl CEMS, an initial 

stack test for HCl would not be required. 

Instead the first 30 days of HCl CEMS 

data would be used to determine initial 

compliance. For units without HCl 

CEMS and without SO2 or HCl 

emissions control devices, you would be 

required to conduct HCl emissions 

testing every month using EPA Method 

26 if no entrained water droplets exist 

in the exhaust gas or Method 26A if 

entrained water droplets exist in the 

exhaust gas. For units without SO2 or 

HCl CEMS but with SO2 emissions 

control devices, you would conduct HCl 

testing at least every 2 months using 

EPA Method 26 or 26A. For units 

without SO2 or HCl CEMS and without 

SO2 emissions control devices, you 

would conduct HCl emissions testing 

every month using EPA Method 26A if 

entrained water droplets exist in the 

exhaust gas or Method 26A or 26 if no 

entrained water droplets exist in the 

exhaust gas. 

(4) For all required performance stack 

tests, you would conduct concurrent 

oxygen (O2) or carbon dioxide (CO2) 

emission testing using EPA Method 3A 

and then, use an appropriate equation, 

selected from among Equations 19–1 

through 19–9 in EPA Method 19 to 

convert measured pollutant 

concentrations to lb/MMBtu values. 

Multiply the lb/MMBtu value by one 

million to get the lb/TBtu value (if 

applicable). 

(5) For liquid oil-fired units, initial 

performance testing would be 

conducted as follows. For non-Hg HAP 

metals, use EPA Method 29. For Hg, 

conduct emissions testing using EPA 

Method 29 or Method 30B. For acid 

gases, conduct HCl and HF testing using 

EPA Methods 26A or 26. Conduct 

additional performance testing for Hg at 

least annually; conduct additional 

performance tests for HAP metals and 

acid gases every 2 months if the EGU 

has emission controls for metals or acid 

gases, and every month if the EGU does 

not have these controls. 

(6) For existing units that qualify as 

low emitting EGUs (LEEs), conduct 

subsequent performance tests for the 

LEE qualified pollutants every 5 years 

and perform fuel analysis monthly. 

Except for liquid oil-fired units, those 

EGUs with PM emissions control 

devices, without HCl CEMS but with 

HCl control devices, or for LEE, we are 

proposing that you monitor during 

initial performance testing specified 

operating parameters that you would 

use to demonstrate ongoing compliance. 

You would calculate the minimum (or 

maximum, depending on the parameter 

measured) hourly parameter values 

measured during each run of a 3-run 

performance test. The average of the 

three minimum (or maximum) values 

from the three runs for each applicable 

parameter would establish a sitespecific operating limit. The applicable 

operating parameters for which 

operating limits would be required to be 

established are based on the emissions 

limits applicable to your unit as well as 

the types of add-on controls on the unit. 

The following is a summary of the 

operating limits that we are proposing to 

be established for the various types of 

the following units: 


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(1) For units without wet or dry FGD 

scrubbers that must comply with an HCl 

emission limit, you must measure the 

average chlorine content level in the 

input fuel(s) during the HCl 

performance test. This is your maximum 

chlorine input operating limit. 

(2) For units with wet FGD scrubbers, 

you must measure pressure drop and 

liquid flow rate of the scrubber during 

the performance test, and determine the 

maximum value for each test run. The 

average of the minimum hourly value 

for the three test runs establishes your 

minimum site-specific pressure drop 

and liquid flow rate operating levels. If 

different average parameter levels are 

measured during the Hg and HCl tests, 

the highest of the average values 

becomes your site-specific operating 

limit. If you are complying with an HCl 

emission limit, you must measure pH of 

the scrubber effluent during the 

performance test for HCl and determine 

the minimum hourly value for each test 

run. The average of the three minimum 

hourly values from the three test runs 

establishes your minimum pH operating 

limit. 

(3) For units with dry scrubbers or 

DSI (including ACI), you would be 

required to measure the sorbent 

injection rate for each sorbent used 

during the performance tests for HCl 

and Hg and determine the minimum 

hourly rate of injected sorbent for each 

test run. The average of the three test 

run minimum values established during 

the performance tests would be your 

site-specific minimum sorbent injection 

rate operating limit. If different sorbents 

and/or injection rates are used during 

the Hg and HCl performance testing, the 

highest value for each sorbent becomes 

your site-specific operating limit for the 

respective HAP. If the same sorbent is 

used during the Hg and HCl 

performance testing, but at different 

injection rates, the highest average value 

for each sorbent becomes your sitespecific operating limit. The type of 

sorbent used (e.g., conventional AC, 

brominated AC, trona, hydrated lime, 

sodium carbonate, etc.) must be 

specified. 

(4) For units with FFs in combination 

with wet scrubbers, you must measure 

the pH, pressure drop, and liquid flow 

rate of the wet scrubber during the 

performance test and calculate the 

minimum hourly value for each test run. 

The average of the minimum hourly 

values from the three test runs 

establishes your site-specific pH, 

pressure drop, and liquid flow rate 

operating limits for the wet scrubber. 

(5) For units with an ESP in 

combination with wet scrubbers, you 

must measure the pH, pressure drop, 

and liquid flow rate of the wet scrubber 

during the HCl performance test and 

you must measure the voltage and 

current of each ESP collection field 

during the Hg and PM performance test. 

You would then be required to calculate 

the minimum hourly value of these 

parameters for each of the three test 

runs. The average of the three minimum 

hourly values would establish your sitespecific minimum pH, pressure drop, 

and liquid flow rate operating limit for 

the wet scrubber and the minimum 

voltage and current operating limits for 

the ESP. 

(6) For liquid oil-fired or LEEs, you 

would be required to measure the Hg, 

Cl, and HAP metal content of the inlet 

fuel that was burned during the Hg, HCl 

and HF, and HAP metal emissions 

performance testing. The fuel content 

value for each of these compounds is 

your maximum fuel inlet operating limit 

for each of these compounds. 

(7) For units with FFs, you must 

measure the output of the bag leak 

detection system (BLDS) sensor 

(whether in terms of relative or absolute 

PM loading) during each Hg, PM, and 

metals performance test. You would 

then be required to calculate the 

minimum hourly value of this output 

for each test run. The average of the 

minimum hourly BLDS values would 

establish your site-specific maximum 

BLDS sensor output and current 

operating limit for the BLDS. 

(8) For units with an ESP, you must 

measure the voltage and current of each 

ESP collection field during each Hg, 

PM, and metals performance test. You 

would then be required to calculate the 

minimum hourly value of these 

parameters for each test run. The 

average of the three minimum hourly 

values would establish your site-specific 

minimum voltage and current operating 

limits for the ESP. 

(9) Note that you establish the 

minimum (or maximum) hourly average 

operating limits based on measurements 

done during performance testing; 

should you desire to have differing 

operating limits which correspond to 

other loads, you should conduct testing 

at those other loads to determine those 

other operating limits. 

Instead of operating limits for dioxins 

and furans and non-dioxin/furan 

organic HAP, we are proposing that 

owners or operators of units submit 

documentation that a ‘‘tune up’’ meeting 

the requirements of the proposed rule 

was conducted. Such a ‘‘tune-up’’ would 

require the owner or operator of a unit 

to: 

(1) As applicable, inspect the burner, 

and clean or replace any components of 

the burner as necessary (you may delay 

the burner inspection until the next 

scheduled unit shutdown, but you must 

inspect each burner at least once every 

18 months); 

(2) Inspect the flame pattern, as 

applicable, and make any adjustments 

to the burner necessary to optimize the 

flame pattern. The adjustment should be 

consistent with the manufacturer’s 

specifications, if available; 

(3) Inspect the system controlling the 

air-to-fuel ratio, as applicable, and 

ensure that it is correctly calibrated and 

functioning properly; 

(4) Optimize total emissions of CO 

and NOX. This optimization should be 

consistent with the manufacturer’s 

specifications, if available; 

(5) Measure the concentration in the 

effluent stream of CO and NOX in ppm, 

by volume, and oxygen in volume 

percent, before and after the 

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); and 

(6) Maintain on-site and submit, if 

requested by the Administrator, an 

annual report containing: 

(i) The concentrations of CO and NOX

in the effluent stream in ppm by 

volume, and oxygen in volume percent, 

measured before and after the 

adjustments of the EGU; 

(ii) A description of any corrective 

actions taken as a part of the 

combustion adjustment; and 

(iii) The type and amount of fuel used 

over the 12 months prior to the 

adjustment, but only if the unit was 

physically and legally capable of using 

more than one type of fuel during that 

period. 

Many, if not most, EGUs have 

planned annual outages, and the 

inspection and tune up procedure was 

designed to occur during this normal 

occurrence. Nonetheless, we are 

proposing a maximum period of up to 

18 months between inspections and 

tune ups to account for those EGUs with 

unusual planned outage schedules. We 

seek comment on the appropriateness of 

this period. 

J. What are the continuous compliance 

requirements? 

1. Continuous Compliance 

Requirements 

To demonstrate continuous 

compliance with the emission 

limitations, we are proposing the 

following requirements: 

(1) For IGCC units or units 

combusting coal or solid oil-derived fuel 

and electing to use PM as a surrogate for 

non-Hg HAP metals, you would install, 

certify, and operate PM CEMS in 


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accordance with Performance 

Specification (PS) 11 in Appendix B to 

40 CFR part 60, and to perform periodic, 

on-going quality assurance (QA) testing 

of the CEMS according to QA Procedure 

2 in Appendix F to 40 CFR part 60. An 

operating limit (PM concentration) 

would be set during performance testing 

for initial compliance; the hourly 

average PM concentrations would be 

averaged on a rolling 30 boiler operating 

day basis. Each 30 boiler operating day 

average would have to meet the PM 

operating limit. 

IGCC units or units combusting coal 

or solid oil-derived fuel and electing to 

comply with the total non-Hg HAP 

metals emissions limit, would 

demonstrate continuous compliance by 

conducting Method 29 testing every two 

months if PM controls are installed or 

every month if no PM controls are 

installed. As an option, PM CEMS could 

be used to demonstrate continuous 

compliance as described above. IGCC 

units or units combusting coal or solid 

oil-derived fuel and electing to comply 

with the individual non-Hg HAP metals 

emissions limits, would have the option 

to demonstrate continuous compliance 

only by conducting Method 29; again, 

testing would be conducted every two 

months if PM controls are installed or 

every month if no PM controls are 

installed. IGCC units or units 

combusting coal or solid oil-derived fuel 

with PM controls but not using PM 

CEMS to demonstrate continuous 

compliance would also be required to 

conduct parameter monitoring and meet 

operating limits established during 

performance testing. Units using FFs 

would be required to install and operate 

BLDS. As mentioned earlier, the BLDS 

output would be required to be less than 

or equivalent with the average BLDS 

output determined during performance 

testing. Moreover, a source owner or 

operator would be required to operate 

the FFs such that the sum duration of 

alarms from the BLDS would not exceed 

5 percent of the process operating time 

during any 6-month period. Units using 

an ESP would be required to install and 

operate sensors to detect and measure 

current and voltage for each field in the 

ESP. As mentioned earlier, the current 

and voltage values for each field in the 

ESP would need to be greater than or 

equivalent with the maximum test run 

averages determined during 

performance testing. 

(2) For IGCC units or units 

combusting coal or solid oil-derived 

fuel, we are proposing that Hg CEMS or 

sorbent trap monitoring systems be 

installed, certified, maintained, 

operated, and quality-assured in 

accordance with proposed Appendix A 

to 40 CFR part 63, subpart UUUUU, and 

that Hg levels (averaged on a rolling 30 

boiler operating day basis) be 

maintained at or below the applicable 

Hg emissions limit. Given that the 

proposed Appendix A QA procedures 

for Hg CEMS are based on a Hg 

emissions trading rule (CAMR), and this 

proposal is for a not-to-exceed NESHAP, 

EPA solicits comments on whether 

these Hg CEMS QA procedures should 

be adjusted. Further, we are proposing 

that each pair of sorbent traps be used 

to collect Hg samples for no more than 

14 operating days, and that the traps be 

replaced in a timely manner to ensure 

that Hg emissions are sampled 

continuously. In requiring continuous 

Hg monitoring, we assumed that most, 

if not all, of the units that were subject 

to CAMR purchased Hg CEMS and/or 

sorbent trap systems prior to the rule 

vacatur, and that many of these 

monitoring systems are currently 

installed and in operation. The Agency’s 

conclusion regarding Hg CEMS 

purchases and installation is based in 

part on the significant number of units 

(over 100) that voluntarily opted to 

submit Hg CEMS data for the 2010 ICR. 

We also considered the steps taken by 

the industry to prepare for CAMR, and 

the fact that many state regulations 

currently require the installation and 

operation of Hg CEMS in order to 

demonstrate compliance with various 

SIP and consent decrees. 

(3) For new or reconstructed IGCC 

units or coal-fired or solid oil-derived 

fuel-fired units with SO2 emissions 

control devices, we are proposing two 

compliance options for acid gases. First, 

an SO2 or an HCl CEMS could be 

installed and certified. We are 

proposing that the SO2 monitor be 

certified and quality-assured according 

to 40 CFR part 75 or PS 2 or 6 and 

Procedure 1 in Appendices B and F, 

respectively, of 40 CFR part 60. We 

believe this is reasonable, because 

nearly all utility units are subject to the 

ARP, and coal-fired ARP units already 

have certified SO2 monitors in place 

that meet Part 75 requirements. For HCl 

monitors, PS 15 or 6 in Appendix B to 

40 CFR part 60 would be used for 

certification and, tentatively, Procedure 

1 of Appendix F to 40 CFR part 60 

would be followed for on-going QA. 

Note that a PS specific to HCl CEMS 

has not been promulgated yet, but we 

expect to publish one prior to the 

compliance date of this proposed rule 

and to make it available to source 

owners and operators. In the meantime, 

the FTIR CEMS (PS 15) may be an 

appropriate choice for measuring 

continuous HCl concentrations. Hourly 

data from the SO2 or HCl monitor would 

be converted to the units of the emission 

standard and averaged on a rolling 30 

boiler operating day basis. Each 30 

boiler operating day average would have 

to meet the applicable SO2 or HCl limit. 

The second option that we are 

proposing would be for units without 

SO2 or HCl CEMS but with SO2

emissions control devices. For these 

units, parameter operating limits, 

established during performance testing, 

would be monitored continuously, 

along with the already-mentioned 

frequent (every 2 months) HCl 

emissions testing. For units with wet 

FGD scrubbers, we are proposing that 

you monitor pressure drop and liquid 

flow rate of the scrubber continuously 

and maintain 12-hour block averages at 

or above the operating limits established 

during the performance test. You must 

monitor the pH of the scrubber and 

maintain the 12-hour block average at or 

above the operating limit established 

during the performance test to 

demonstrate continuous compliance 

with the HCl emission limits. 

For units with dry scrubbers or DSI 

systems, we are proposing that you 

continuously monitor the sorbent 

injection rate and maintain it at or above 

the operating limits established during 

the performance tests. 

(4) For liquid oil-fired units, we are 

proposing to require testing as follows. 

HAP metals testing would be performed 

every other month if a unit has a nonHg HAP metals control device, and 

every month if the unit does not have 

a non-Hg metals control device. We 

propose to require HCl and HF testing 

every other month if a unit has HCl and 

HF control devices, and monthly if the 

unit does not have these emissions 

controls. 

(5) For each unit using PM, HCl, SO2, 

or Hg CEMS for continuous compliance, 

we are proposing that you install, 

certify, maintain, operate and qualityassure the additional CEMS (e.g., CEMS 

that measure oxygen or CO2

concentration, stack gas flow rate, and 

moisture content) needed to convert 

pollutant concentrations to units of the 

emission standards or operating limits. 

Where appropriate, we have proposed 

that these additional CEMS may be 

certified and quality-assured according 

to 40 CFR part 75. Once again, we 

believe this is reasonable because 

almost all coal-fired utility units already 

have these monitors in place, under the 

ARP. 

(6) For limited-use liquid oil 

combustion units, we are proposing that 

those units be allowed to demonstrate 

compliance with the Hg emission limit, 

the HAP metals, or the HCl and HF 

emissions limits separately or in 


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combination based on fuel analysis 

rather than performance stack testing, 

upon request by you and approval by 

the Administrator. Such a request 

would require the owner/operator to 

follow the requirements in 40 CFR 

63.8(f), which presents the procedure 

for submitting a request to the 

Administrator to use alternative 

monitoring, and, among other things, 

explain why a unit should be 

considered for eligibility, including, but 

not limited to, use over the previous 

5 years and projected use over the next 

5 years. Approval from the 

Administrator would be required before 

you could use this alternative 

monitoring procedure. If approval were 

granted by the Administrator, we are 

proposing that you would maintain fuel 

records that demonstrate that you 

burned no new fuels or fuels from a new 

supplier such that the Hg, the non-Hg 

HAP metal, the fluorine, or the chlorine 

content of the inlet fuel was maintained 

at or below your maximum fuel Hg, 

non-Hg HAP metal, fluorine, or chlorine 

content operating limit set during the 

performance stack tests. If you plan to 

burn a new fuel, a fuel from a new 

mixture, or a new supplier’s fuel that 

differs from what was burned during the 

initial performance tests, then you must 

recalculate the maximum Hg, HAP 

metal, fluorine, and/or chlorine input 

anticipated from the new fuels based on 

supplier data or own fuel analysis, using 

the methodology specified in Table 6 of 

this proposed rule. If the results of 

recalculating the inputs exceed the 

average content levels established 

during the initial test then, you must 

conduct a new performance test(s) to 

demonstrate continuous compliance 

with the applicable emission limit. 

(7) For existing LEEs, we are 

proposing that those units that qualify 

be allowed to demonstrate continuous 

compliance with the Hg emission limit, 

the non-Hg HAP metals, or the HCl 

emissions limits separately or in 

combination based on fuel analysis 

rather than performance stack testing. 

LEE would be those units where 

performance testing demonstrates that 

emissions are less than 50 percent of the 

PM or HCl emissions limits, less than 10 

percent of the Hg emissions limits, or 

less than 22.0 pounds per year (lb/yr) of 

Hg. Note that for LEE emissions testing 

for total PM, total HAP metals, 

individual HAP metals, HCl, and HF, 

the required minimum sampling 

volumes shown in Table 2 or this 

proposed rule must be increased 

nominally by a factor of two. The LEE 

cutoff of 22.0 lb/yr represents about 5 

percent of the nationwide Hg mass 

emissions from the coal-fired units 

represented in the 2010 ICR. Most of the 

units that emit less than 22.0 lb/yr 

would be smaller units with relatively 

low heat input capacities. The 22.0 lb/ 

yr threshold was determined by 

summing the total Hg emissions from 

the 1,091 units in operation and 

determining the 5th percentile of the 

total mass. The units were then ranked 

by their annual Hg mass emissions. At 

the point in the rankings where the 

cumulative mass was equivalent to the 

5th percentile value calculated, the 

annual mass emissions of that unit (22.0 

lb/yr) was selected as the threshold. 

Five percent of the total mass was 

chosen as a cut point because comments 

received on CAMR indicated that 

5 percent of the total mass was a 

reasonable cut point. At this 5th 

percentile threshold, approximately 394 

smaller units out of the 1,091 total units 

would have the option of using this Hg 

monitoring methodology. 

Under the proposed alternative 

compliance option, you would maintain 

fuel records that demonstrate that you 

burned no new fuels or fuels from a new 

supplier such that the Hg, non-Hg HAP 

metal, or the chlorine content of the 

inlet fuel was maintained at or below 

your maximum fuel Hg, non-Hg HAP 

metal, fluorine, or chlorine content 

operating limit set during the 

performance stack tests. If you plan to 

burn a new fuel, a fuel from a new 

mixture, or a new supplier’s fuel that 

differs from what was burned during the 

initial performance tests, then you must 

recalculate the maximum Hg, non-Hg 

HAP metal, and/or the maximum 

chlorine input anticipated from the new 

fuels based on supplier data or own fuel 

analysis, using the methodology 

specified in Table 6 of this proposed 

rule. If the results of recalculating the 

inputs exceed the average content levels 

established during the initial test then, 

you must conduct a new performance 

test(s) to demonstrate continuous 

compliance with the applicable 

emission limit. 

(8) For all EGUs, we are proposing 

that you maintain daily records of fuel 

use that demonstrate that you have 

burned no materials that are considered 

solid waste. 

If an owner or operator would like to 

use a control device other than the ones 

specified in this section to comply with 

this proposed rule, the owner/operator 

should follow the requirements in 40 

CFR 63.8(f), which establishes the 

procedure for submitting a request to 

the Administrator to use alternative 

monitoring. 

2. Streamlined Approach to Continuous 

Compliance 

EPA is proposing to simplify 

compliance with the proposed rule by 

harmonizing its monitoring and 

reporting requirements, to the extent 

possible, with those of 40 CFR part 75. 

With a few exceptions, the utility 

industry is already required to monitor 

and report hourly emissions data 

according to Part 75 under the Title IV 

ARP and other emissions trading 

programs. The Agency is, therefore, 

proposing Hg monitoring requirements 

that are consistent with Part 75 and 

similar to those that had been 

promulgated for the vacated CAMR 

regulation. We are proposing that hourly 

Hg emission data be reported to EPA 

electronically, on a quarterly basis. At 

this time, we are proposing not to apply 

the same electronic reporting for 

certification and QA test data from HCl 

or PM CEMS but are instead relying on 

the existing provisions in Parts 60 and 

63. 

Our rationale for this is as follows. We 

considered two possible Hg monitoring 

and reporting options to demonstrate 

continuous compliance. The first option 

would be for Hg CEMS and sorbent trap 

systems to be certified and qualityassured according to PS 12A and 12B in 

Appendix B to 40 CFR part 60. 

Procedure 5 in Appendix F to Part 60 

would be followed for on-going QA. 

Semiannual hard copy reporting of 

‘‘deviations’’ would be required, along 

with data assessment reports (DARs). 

Even though this option would not 

require electronic reporting of either 

hourly Hg emissions data or QA test 

results, it still would require affected 

sources to have a data handling system 

(DAHS) that: (1) Is programmed to 

capture data from the Hg CEMS; (2) uses 

the criteria in Appendix F to Part 60 to 

validate or invalidate the Hg data; 

(3) calculates hourly averages for Hg 

concentration and for the auxiliary 

parameters (e.g., flow rate, O2 or CO2

concentration) that are needed to 

convert Hg concentrations to the units 

of the emission standard; (4) calculates 

30 boiler operating day rolling average 

Hg emission rates; and (5) identifies any 

deviations that must be reported to the 

Agency. 

The second option would simply 

integrate Hg emissions data and QA test 

results into the existing Part 75- 

compliant DAHS that is installed at the 

vast majority of the coal-fired EGUs. We 

obtained feedback from several DAHS 

vendors indicating that the cost of 

modifying the existing Part 75 DAHS 

systems to accommodate hourly 

reporting of Hg CEMS and sorbent trap 


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data would be similar, and in some 

cases, less than the cost of the first 

option. Also, there would be little or no 

cost to industry for the flow rate, CO2, 

or O2, and moisture monitors needed to 

convert Hg concentration to the units of 

the standard, because, as previously 

noted, almost all of the EGUs already 

have these monitors in place. In view of 

these considerations, we have decided 

in favor of this second option for Hg. 

Requiring the reporting of hourly Hg 

emissions data from EGUs would be 

advantageous, both to EPA and 

industry. The DAHS could be 

automated to demonstrate compliance 

with the standard on a continuous basis. 

The data could then be submitted to the 

Agency electronically, thereby 

eliminating the need for the Agency to 

request additional information for 

compliance determinations and program 

implementation. 

Today’s proposed rule would also 

require quarterly electronic reporting of 

hourly SO2 CEMS data, PM CEMS data, 

and HCl CEMS data (for sources electing 

to demonstrate continuous compliance 

using certified CEMS), as well as 

electronic summaries of emission test 

results (for sources demonstrating 

continuous compliance by periodic 

stack testing), and semiannual 

electronic ‘‘deviation’’ reports (for 

sources that monitor parameters or 

assess compliance in other ways). As 

discussed in detail in the paragraphs 

below, requiring electronic reporting in 

lieu of traditional hard copy reports 

would enable utility sources to 

demonstrate continuous compliance 

with the applicable emissions 

limitations of this proposed rule, using 

a process that is familiar to them and 

consistent with the procedures that they 

currently follow to comply with ARP 

and other mass-based emissions trading 

programs. 

Currently, utility sources that are 

subject to the ARP and other EPA 

emissions trading programs use the 

Emissions Collection and Monitoring 

Plan System (ECMPS) to process and 

evaluate continuous monitoring data 

and other information in an electronic 

format for submittal to the Agency. In 

addition to receiving hourly emissions 

data, this system supports the 

maintenance of an electronic 

‘‘monitoring plan’’ and is designed to 

receive the results of monitoring system 

certification test data and ongoing QA 

test data. Emissions data are submitted 

quarterly through ECMPS, and users are 

given feedback on the quality of their 

reports before the data are submitted. 

This allows them to make corrections or 

otherwise address issues with the 

reports prior to making their official 

submittals. Despite the stringency and 

thoroughness of the data validation 

checks performed by the ECMPS 

software, the implementation of this 

process has resulted in very few errant 

reports being submitted each quarter. 

This has saved both industry and the 

Agency countless hours of valuable 

time, which in years past, was spent 

troubleshooting errors in the quarterly 

reports. EPA is proposing to apply the 

same basic quarterly data collection 

process to Hg, HCl, and PM CEMS data, 

and to modify ECMPS to be able to 

accommodate summarized stack test 

data and semiannual deviation reports. 

The ECMPS process divides 

electronic data into three categories, the 

first of which is monitoring plan data. 

The electronic monitoring plan is 

maintained as a separate entity, and can 

be updated 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 that is 

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 have 

established electronic monitoring plans 

that describe their required SO2, flow 

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

moisture monitoring systems. The 

ECMPS monitoring plan format could 

easily accommodate this same type of 

information for Hg, HCl, and PM CEMS, 

with the addition of a few codes for the 

new parameters. 

The second type of data collected 

through ECMPS is certification and QA 

test data. This includes data from 

linearity checks, relative accuracy test 

audits (RATAs), cycle time tests, 7-day 

calibration error tests, and a number of 

other QA tests that are required to 

validate the emissions data. The results 

of these tests can be submitted to EPA 

as soon as the results are received, 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 are included in the quarterly 

electronic reports, along with the hourly 

emissions data. 

The ECMPS system is already set up 

to receive and process certification and 

QA data from SO2, CO2, O2, flow rate, 

and moisture monitoring systems that 

are installed, certified, maintained, 

operated, and quality-assured according 

to Part 75. EGUs routinely submit these 

data to EPA under the ARP and other 

emissions trading programs. 

To accommodate the certification and 

QA tests for Hg CEMS and sorbent trap 

monitoring systems, relatively few 

changes would have to be made to the 

structure and functionality of ECMPS, 

because most of the tests are the same 

ones that are required for other gas 

monitors. More substantive changes to 

the system would be required to receive 

and process the certification and QA 

tests required for HCl and PM CEMS, 

and to receive summarized stack test 

results, and the types of data provided 

in semiannual compliance reports; 

however, we believe these changes are 

implementable. Another modification 

that could be made to ECMPS would be 

to disable the Part 75 bias test (which is 

required for certain types of monitors 

under EPA’s emissions trading 

programs) for Hg, HCl, and PM CEMS, 

if bias adjustment of the data from these 

monitors is believed to be unnecessary 

or inappropriate for compliance with 

the proposed rule. We are proposing to 

make this modification and solicit 

comment on it. 

The third type of data collected 

through ECMPS is the emissions data, 

which, as previously noted, is reported 

on a quarterly schedule. The reports 

must be submitted 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. Direct measurements 

made with CEMS, such as gas 

concentrations, are reported 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 qualityassured 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 Hg, HCl, and PM 

CEMS. 

The ECMPS reporting structure is 

quite flexible, which makes it useful for 

assessing compliance with various 

emission limits. The Derived Hourly 

Value (DHV) record provides the means 

whereby a wide variety of quantities 

that can be calculated from the hourly 

emissions data can be reported. For 

instance, if an emission limit is 

expressed in units of lb/MMBtu, the 


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DHV record can be used to report hourly 

pollutant concentration values in these 

units of measure, since the lb/MMBtu 

values can be derived from the hourly 

pollutant and diluent gas (CO2 or O2) 

concentrations reported in the MHV 

records. ECMPS can also accommodate 

multiple DHV records for a given hour 

in which more than one derived value 

is required to be reported. Therefore, if 

hourly Hg, HCl, and PM concentration 

data are reported through ECMPS, 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), could 

be used to report hourly data in the 

units of the emission standards (e.g., lb/ 

MMBtu, lb/TBtu, lb/GWh, etc.). 

The ARP and other emissions trading 

programs that report emissions data to 

EPA using Part 75 are required to 

provide 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 may not be appropriate. Today’s 

proposed rule would not require the use 

of missing data substitution for Hg 

monitoring systems. We intend to 

extend this concept to HCl and PM 

CEMS, if we receive data from those 

types of monitors. Hours when a 

monitoring system is out of service 

would simply be counted as hours of 

monitor down time, to be counted 

against the percent monitor availability. 

We solicit comment on this proposed 

approach. 

As previously stated, EPA is 

proposing to add Hg monitoring 

provisions as Appendix A to 40 CFR 

part 63, subpart UUUUU, and to require 

these provisions to be used to document 

continuous compliance with the 

proposed rule, for units that cannot 

qualify as LEEs. Proposed Appendix A 

would consolidate all of the Hg 

monitoring provisions in one place. 

Today’s proposed rule would provide 

two basic Hg continuous monitoring 

options: Hg CEMS and sorbent trap 

monitoring systems. 

Proposed Appendix A would require 

the Hg CEMS and sorbent trap 

monitoring systems to be initially 

certified and then to undergo periodic 

QA testing. The certification tests 

required for the Hg CEMS would be a 

7-day calibration error test, a linearity 

check, using NIST-traceable elemental 

Hg standards, a 3-level system integrity 

check (similar to a linearity check), 

using NIST-traceable oxidized Hg 

standards, a cycle time test, and a 

RATA. A bias test would not be 

required. The performance 

specifications for the required 

certification tests, which are 

summarized in Table A–1 of proposed 

Appendix A, would be the same as 

those that were published in support of 

CAMR. For ongoing QA of the Hg 

CEMS, proposed Appendix A would 

require daily calibrations, weekly 

single-point system integrity checks, 

quarterly linearity checks (or 3-level 

system integrity checks) and annual 

RATAs. These QA test requirements and 

the applicable performance criteria, 

which, once again, are the same as the 

ones we had published in support of 

CAMR, are summarized in Table A–3 in 

proposed Appendix A. For sorbent trap 

monitoring systems, a RATA would be 

required for initial certification, and 

annual RATAs would be required for 

ongoing QA. The performance 

specification for these RATAs would be 

the same as for the RATAs of the Hg 

CEMS. Bias adjustment of the measured 

Hg concentration data would not be 

required. However, for routine, day-today operation of the sorbent trap 

system, proposed Appendix A provides 

the owner or operator the option to 

follow the procedures and QA/QC 

criteria in PS 12B in Appendix B to 40 

CFR part 60. Performance Specification 

12B is nearly identical to the vacated 

Appendix K to Part 75. The Part 75 

concepts of: (1) Determining the due 

dates for certain QA tests on the basis 

of ‘‘QA operating quarters’’; and (2) grace 

periods for certain QA tests, would 

apply to both Hg CEMS and sorbent trap 

monitoring systems. 

Mercury concentrations measured by 

Hg CEMS or sorbent trap systems would 

be used together with hourly flow rate, 

diluent gas, moisture, and electrical 

load data, to express the Hg emissions 

in units of the proposed rule, on an 

hourly basis (i.e., lb/TBtu or lb/GWh). 

Proposed section 6 of Appendix A 

provides the necessary equations for 

these unit conversions. These hourly 

values could then be ‘‘rolled up’’ within 

the DAHS into the proper 30 boiler 

operating day averaging period, to 

assess compliance. A report function 

could be added to ECMPS to show the 

results of these calculations, and to 

highlight any values in excess of the 

standard. 

The proposed rule would specify 

record keeping and reporting 

requirements for the two Hg monitoring 

methodologies. Essential information 

pertaining to each methodology would 

be represented in the electronic 

monitoring plan. Hourly Hg 

concentration data would be reported in 

all cases. However, for the sorbent trap 

option, a single Hg concentration value 

would be reported for extended periods 

of time, since a sorbent trap monitoring 

system does not provide hour-by-hour 

measurements of Hg concentration. The 

results of all required certification and 

QA tests would also be reported. 

Missing data substitution for Hg 

concentration would not be required for 

hours in which quality-assured data are 

not obtained. Special codes would be 

reported to identify these hours. 

Of all the types of NESHAP 

compliance data that could be brought 

into ECMPS (i.e., CEMS data, stack test 

summaries, and semiannual compliance 

reports), the easiest to implement would 

be the Hg monitoring data, because, as 

noted above, we had published specific 

Hg monitoring and reporting provisions 

in Part 75 prior to the vacatur of CAMR, 

and had made considerable progress in 

modifying ECMPS to receive these data. 

Today’s proposed rule provides detailed 

regulatory language in proposed 

Appendix A to 40 CFR part 63, subpart 

UUUUU, pertaining to the monitoring of 

Hg emissions and reporting the data 

electronically. 

We are requesting comment on these 

proposed compliance approaches and 

on whether our proposed ‘‘one stop 

shopping’’ approach to reporting MACT 

compliance information electronically is 

desirable. In your comments, we ask 

you to consider the merits of requiring 

reporting of results from PM CEMS and 

HCl CEMS to ECMPS and consequent 

development of a monitoring and 

reporting scheme for these CEMS that is 

compatible with ECMPS. If you favor 

our proposed streamlined continuous 

compliance approach, we request input 

on how to make the reporting process 

user-friendly and efficient. EPA believes 

that if the essential data that are 

reported under the Agency’s emissions 

trading programs and the proposed rule 

are all sent to the same place, this could 

significantly reduce the burden on 

industry and bring about national 

consistency in assessing compliance. 

K. What are the notification, 

recordkeeping, and reporting 

requirements? 

All new and existing sources would 

be required to comply with certain 

requirements of the General Provisions 

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

identified in Table 10 of this proposed 

rule. The General Provisions include 

specific requirements for notifications, 

recordkeeping, and reporting. 

Each owner or operator would be 

required to submit a notification of 

compliance status report, as required by 

§ 63.9(h) of the General Provisions. This 


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proposed rule would require the owner 

or operator to include in the notification 

of compliance status report 

certifications of compliance with rule 

requirements. 

Except for units that use CEMS for 

continuous compliance, semiannual 

compliance reports, as required by 

§ 63.10(e)(3) of subpart A, would be 

required for semiannual reporting 

periods, indicating whether or not 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 previously discussed, 

we are proposing to use the ECMPS 

system to receive the essential 

information contained in these 

semiannual compliance reports 

electronically. For units using CEMS, 

quarterly electronic reporting of hourly 

Hg and associated (O2, CO2, flow rate, 

and/or moisture) monitoring data, as 

well as electronic reporting of 

monitoring plan data and certification 

and QA test results, would be required, 

also through ECMPS. 

This proposed rule would require 

records to demonstrate compliance with 

each emission limit and work practice 

standard. These recordkeeping 

requirements are specified directly in 

the General Provisions to 40 CFR part 

63, and are identified in Table 9 of this 

proposed rule. 

Records of continuously monitored 

parameter data for a control device if a 

device is used to control the emissions 

or CEMS data would be required. 

We are proposing that you must keep 

the following records: 

(1) All reports and notifications 

submitted to comply with this proposed 

rule. 

(2) Continuous monitoring data as 

required in this proposed rule. 

(3) Each instance in which you did 

not meet each emission limit and each 

operating limit (i.e., deviations from this 

proposed rule). 

(4) Daily hours of operation by each 

source. 

(5) Total fuel use by each affected 

liquid oil-fired source electing to 

comply with an emission limit based on 

fuel analysis for each 30 boiler operating 

day period along with a description of 

the fuel, the total fuel usage amounts 

and units of measure, and information 

on the supplier and original source of 

the fuel. 

(6) Calculations and supporting 

information of chlorine fuel input, as 

required in this proposed rule, for each 

affected liquid oil-fired source with an 

applicable HCl emission limit. 

(7) Calculations and supporting 

information of Hg and HAP metal fuel 

input, as required in this proposed rule, 

for each affected source with an 

applicable Hg and HAP metal (or PM) 

emission limit. 

(8) A signed statement, as required in 

this proposed rule, indicating that you 

burned no new fuel type and no new 

fuel mixture or that the recalculation of 

chlorine input demonstrated that the 

new fuel or new mixture still meets 

chlorine fuel input levels, for each 

affected source with an applicable HCl 

emission limit. 

(9) A signed statement, as required in 

this proposed rule, indicating that you 

burned no new fuels and no new fuel 

mixture or that the recalculation of Hg 

and/or HAP metal fuel input 

demonstrated that the new fuel or new 

fuel mixture still meets the Hg and/or 

HAP metal fuel input levels, for each 

affected source with an applicable Hg 

and/or HAP metal emission limit. 

(10) A copy of the results of all 

performance tests, fuel analyses, 

performance evaluations, or other 

compliance demonstrations conducted 

to demonstrate initial or continuous 

compliance with this proposed rule. 

(11) A copy of your site-specific 

monitoring plan developed for this 

proposed rule as specified in 63 CFR 

63.8(e), if applicable. 

We are also proposing to require that 

you submit the following additional 

notifications: 

(1) Notifications required by the 

General Provisions. 

(2) Initial Notification no later than 

120 calendar days after you become 

subject to this subpart. 

(3) Notification of Intent to conduct 

performance tests and/or compliance 

demonstration at least 60 calendar days 

before the performance test and/or 

compliance demonstration is scheduled. 

(4) Notification of Compliance Status 

60 calendar days following completion 

of the performance test and/or 

compliance demonstration. 

L. Submission of Emissions Test Results 

to EPA 

EPA must have performance test data 

to conduct effective reviews of CAA 

sections 112 and 129 standards, as well 

as for many other purposes including 

compliance determinations, emission 

factor development, and annual 

emission rate determinations. In 

conducting these required reviews, EPA 

has found it ineffective and time 

consuming, not only for us, but also for 

regulatory agencies and source owners 

and operators, to locate, collect, and 

submit performance test data because of 

varied locations for data storage and 

varied data storage methods. In recent 

years, though, stack testing firms have 

typically collected performance test data 

in electronic format, making it possible 

to move to an electronic data submittal 

system that would increase the ease and 

efficiency of data submittal and improve 

data accessibility. 

Through this proposal, EPA is 

presenting a step to increase the ease 

and efficiency of data submittal and 

improve data accessibility. Specifically, 

EPA is proposing that owners and 

operators of EGUs submit electronic 

copies of required performance test 

reports to EPA’s WebFIRE database. The 

WebFIRE database was constructed to 

store performance test data for use in 

developing emission factors. A 

description of the WebFIRE database is 

available at http://cfpub.epa.gov/ 

oarweb/index.cfm?action=fire.main. 

As proposed above, data entry would 

be through an electronic emissions test 

report structure called the Electronic 

Reporting Tool (ERT). The ERT would 

be able to transmit the electronic report 

through EPA’s Central Data Exchange 

(CDX) network for storage in the 

WebFIRE database making submittal of 

data very straightforward and easy. A 

description of the ERT can be found at 

http://www.epa.gov/ttn/chief/ert/ 

ert_tool.html. 

The proposal to submit performance 

test data electronically to EPA would 

apply only to those performance tests 

conducted using test methods that will 

be supported by the ERT. The ERT 

contains a specific electronic data entry 

form for most of the commonly used 

EPA reference methods. A listing of the 

pollutants and test methods supported 

by the ERT is available at http:// 

www.epa.gov/ttn/chief/ert/ert_tool.html. 

We believe that industry would benefit 

from this proposed approach to 

electronic data submittal. Having these 

data, EPA would be able to develop 

improved emission factors, make fewer 

information requests, and promulgate 

better regulations. 

One major advantage of the proposed 

submittal of performance test data 

through the ERT is a standardized 

method to compile and store much of 

the documentation required to be 

reported by this rule. Another advantage 

is that the ERT clearly states what 

testing information would be required. 

Another important proposed benefit of 

submitting these data to EPA at the time 

the source test is conducted is that it 

should substantially reduce the effort 

involved in data collection activities in 

the future. When EPA has performance 

test data in hand, there will likely be 

fewer or less substantial data collection 

requests in conjunction with 

prospective required residual risk 

assessments or technology reviews. This 


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would result in a reduced burden on 

both affected facilities (in terms of 

reduced manpower to respond to data 

collection requests) and EPA (in terms 

of preparing and distributing data 

collection requests and assessing the 

results). 

State, local, and tribal agencies could 

also benefit from more streamlined and 

accurate review of electronic data 

submitted to them. The ERT would 

allow for an electronic review process 

rather than a manual data assessment 

making review and evaluation of the 

source provided data and calculations 

easier and more efficient. Finally, 

another benefit of the proposed data 

submittal to WebFIRE electronically is 

that these data would 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, EPA would be 

able to ensure that emission factors, 

when updated, represent the most 

current range of operational practices. In 

summary, in addition to supporting 

regulation development, control strategy 

development, and other air pollution 

control activities, having an electronic 

database populated with performance 

test data would save industry, state, 

local, tribal agencies, and EPA 

significant time, money, and effort 

while also improving the quality of 

emission inventories and, as a result, air 

quality regulations. In this action, as 

previously stated, EPA is proposing a 

step to improve data accessibility. 

Specifically, we are proposing that you 

submit, to an EPA database, electronic 

copies of reports of certain performance 

tests required under the proposed rule 

through our ERT; however, we request 

comment on the feasibility of using a 

modified version of ECMPS, which the 

utility industry already is familiar with 

and uses for reporting under the Title IV 

ARP and other emissions trading 

programs, to provide this information. 

ECPMS could be modified to allow 

electronic submission of periodic data, 

including, but not limited to, 30 day 

averages of parametric data, 30 day 

average fuel content data, stack test 

results, and performance of tune up 

records. These data will need to be 

submitted and reviewed, and we believe 

electronic submission via a specific 

format already in use for other 

submissions eases understanding, 

affords transparency, ensures 

consistency, and saves time and money. 

We seek comment on alternatives to 

the use of a modified ECMPS for 

electronic data submission. Commenters 

should describe alternate means for 

supplying these data and information on 

associated reliability, the cost, the ease 

of implementation, and the 

transparency to the public of the 

information. 

V. Rationale for This Proposed 

NESHAP 

A. How did EPA determine which 

subcategories and sources would be 

regulated under this proposed 

NESHAP? 

As stated above, EPA added coal- and 

oil-fired EGUs to the CAA section 112(c) 

list on December 20, 2000. This 

proposed rule proposes standards for 

the subcategories of coal- and oil-fired 

EGUs as defined in this preamble. 

Sources in these subcategories may 

potentially include combustion units 

that are at times IB units or solid waste 

incineration units subject to other 

standards under CAA section 112 or to 

standards under CAA section 129. We 

request comment on whether the 

proposed rule should address how 

sources that change fuel input (e.g., 

burn solid waste or biomass), or 

otherwise take action that would change 

the source’s applicability (e.g., stop or 

start selling electricity to the utility 

power distribution system), must 

demonstrate continuous compliance 

with all applicable standards. Note that 

units subject to another CAA section 

112 standard or to solid waste 

incineration unit standards established 

under CAA section 129 are not subject 

to this proposed rule during the period 

of time they are subject to the other 

CAA section 112 or 129 standards. 

The scope of the EGU source category 

is limited to coal- and oil-fired units 

meeting the CAA section 112(a)(8) 

definition and the proposed definition 

of ‘‘fossil fuel fired’’ discussed above. 

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. For example, differences 

between given types of units can lead to 

corresponding differences in the nature 

of emissions and the technical 

feasibility of applying emission control 

techniques. In the December 2000 

listing, EPA initially established and 

listed two subcategories of fossil fuelfired EGUs: Coal-fired and oil-fired. The 

design, operating, and emissions 

information that EPA has reviewed 

indicates that there are significant 

design and operational differences in 

unit design that distinguish different 

types of EGUs within these two 

subcategories, and, because of these 

differences, we have proposed to 

establish two subcategories for coalfired EGUs, two subcategories for oilfired EGUs, and an IGCC subcategory for 

gasified coal and solid oil-derived fuel 

(e.g., petroleum coke), as stated above 

and discussed further below. 

EGU systems are designed for specific 

fuel types and will encounter problems 

if a fuel with characteristics other than 

those originally specified is fired. 

Changes to the fuel type would 

generally require extensive changes to 

the fuel handling and feeding system 

(e.g., liquid oil-fired EGUs cannot fire 

solid fuel without extensive 

modification). Additionally, the burners 

and combustion chamber would need to 

be redesigned and modified to handle 

different fuel types and account for 

increases or decreases in the fuel 

volume. In some cases, the changes may 

reduce the capacity and efficiency of the 

EGU. An additional effect of these 

changes would be extensive retrofitting 

needed to operate using a different fuel. 

These effects must be considered 

whether one is discussing two fuel types 

(e.g., coal vs. oil) or two ranks or forms 

of fuel within a given fuel type (e.g., 

gasified vs. solid coal or solid oilderived fuel). 

The design of the EGU, which is 

dependent in part on the type of fuel 

being burned, impacts the degree of 

combustion, and may impact the level 

and kind of HAP emissions. EGUs emit 

a number of different types of HAP 

emissions. Organic HAP are formed 

from incomplete combustion and are 

primarily influenced by the design and 

operation of the unit. The degree of 

combustion may be greatly influenced 

by three general factors: Time, 

turbulence, and temperature. On the 

other hand, the amount of fuel-borne 

HAP (non-Hg metals, Hg, and acid 

gases) is primarily dependent upon the 

composition of the fuel. These fuelborne HAP emissions generally can be 

controlled by either changing the fuel 

property before combustion or by 

removing the HAP from the flue gas 

after combustion. 

We first examined the HAP emissions 

results to determine if subcategorization 

by unit design type was warranted. 

Normally, any basis for subcategorizing 

(e.g., type of unit) must be related to an 

effect on emissions, rather than some 

difference which does not affect 

emissions performance. We concluded 

that the data were sufficient for one or 


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more HAP for determining that a 

distinguishable difference in 

performance exists based on the 

following five unit design types: coalfired units designed to burn coal with 

greater than or equal to 8,300 Btu/lb (for 

Hg emissions only); coal-fired units 

designed to burn coal with less than 

8,300 Btu/lb (for Hg emissions only); 

IGCC units; liquid oil units; and solid 

oil-derived units. For other types of 

units noted above (e.g., FBC, stoker, 

wall-fired, tangential (T)-fired), there 

was no significant difference in 

emissions that would justify 

subcategorization. Because in the five 

cases different types of units have 

different emission characteristics for 

one or more HAP, we have determined 

that these types of units should be 

subcategorized. Accordingly, we 

propose to subcategorize EGUs based on 

the five unit types. 

For Hg emissions from coal-fired 

units, we have determined that different 

emission limits for the two 

subcategories are warranted. There were 

no EGUs designed to burn a 

nonagglomerating virgin coal having a 

calorific value (moist, mineral matterfree 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 coal-fired 

units, the data did not show any 

difference in the level of the HAP 

emissions and, therefore, we have 

determined that it is not reasonable to 

establish separate emissions limits for 

the other HAP. 

For all HAP emissions from oil-fired 

units, we have determined that two 

subcategories are warranted. EGUs 

designed to burn a solid fuel (e.g., 

petroleum coke) derived from the 

refining of petroleum (oil) are of a 

different design, and have different 

emissions, than those designed to burn 

liquid oil. In addition, EGUs designed to 

burn liquid oil cannot, in fact, 

accommodate the solid fuel derived 

from the refining of oil. Thus, we are 

proposing to subcategorize oil-fired 

EGUs into two subcategories based on 

the type of units designed to burn oil in 

its different physical states. 

EGUs employing IGCC technology 

combust a synthetic gas derived from 

solid coal or solid oil-derived fuel. No 

solid fuel is directly combusted in the 

unit during operation (although a coalor solid oil-derived fuel is fired), and 

both the process and the emissions from 

IGCC units are different from units that 

combust solid coal or petroleum coke. 

Thus, we are proposing to subcategorize 

IGCC units as a distinct type of EGU for 

this proposed rule. EPA solicits 

comment on these subcategorization 

approaches. 

Additional subcategories have been 

evaluated, including those suggested by 

the SERs serving on the SBAR 

established under the SBREFA. These 

suggestions include subcategorization of 

lignite coal vs. other coal ranks; 

subcategorization of Fort Union lignite 

coal vs. Gulf Coast lignite coal vs. other 

coal ranks; subcategorization by EGU 

size (i.e., MWe); subcategorization of 

base load vs. peaking units (e.g., low 

capacity utilization units); 

subcategorization of wall-fired vs. Tfired units; and subcategorization of 

small, non-profit-owned units vs. other 

units. 

EPA has reviewed the available data 

and does not believe that these 

suggested approaches merit 

subcategorization. For example, there 

are both large and small units among the 

EGUs comprising the top performing 12 

percent of sources and small entities 

may own minor portions of large EGUs 

and/or individual EGUs themselves. In 

addition, because the proposed format 

of the standards is lb/MMBtu (or TBtu 

for Hg), the size should only affect the 

rate at which a unit generates electricity 

and, with a lower electricity generation 

rate, there is less fuel consumption and, 

therefore, less emissions of fuel-borne 

HAP (i.e., acid gas and metal HAP). 

Further, with the exception of IGCC and 

as noted elsewhere regarding boiler 

height-to-depth ratio, there is no 

indication that EGU type (e.g., wallfired, T-fired, FBC, stoker-fired), has any 

impact on HAP emission levels as all of 

these types are within the top 

performing 12 percent of sources. There 

is also little indication that operating 

load has any significant impact on HAP 

emissions or on the type of control 

demonstrated on the unit. 

EPA solicits comment on whether we 

should further subcategorize the source 

category. In commenting, commenters 

should provide a definition or threshold 

that would distinguish the proposed 

subcategory from the remainder of the 

EGU population and, to support this 

distinction, an estimate of how many 

EGUs would be impacted by the 

subcategorization approach, the amount 

of time such impacted units operate, the 

extent to which such impacted units 

would move out of and back into the 

subcategory in a given year (or other 

period of time), and any other 

information the commenter believes is 

pertinent. For example, if a commenter 

were to suggest subcategorizing low 

capacity factor or peaking units from the 

remainder of the EGU population, in 

addition to the suggested threshold 

capacity factor, information on the 

number of such units that would be 

impacted, the amount of time such units 

are running (capacity utilization), the 

extent to which such units are low 

capacity factor units in a given year vs. 

operating at a higher capacity factor, 

and data from the units when operating 

both as peaking units and as baseload 

units (among other information) would 

need to be provided to support the 

comment. Commenters should further 

explain how their suggested 

subcategorizations constitute a ‘‘size,’’ 

‘‘type,’’ or ‘‘class,’’ as those terms are 

used in CAA section 112(d)(1). 

B. How did EPA select the format for 

this proposed rule? 

This proposed rule includes 

numerical emission limitations for PM, 

Hg, and HCl (as well as for other 

alternate constituents or groups). 

Numerical emission limitations provide 

flexibility for the regulated community, 

because they allow a regulated source to 

choose any control technology, 

approach, or technique to meet the 

emission limitations, rather than 

requiring each unit to use a prescribed 

control method that may not be 

appropriate in each case. 

We are proposing numerical emission 

rate limitations as a mass of pollutant 

emitted per heat energy input to the 

EGU for the fuel-borne HAP for existing 

sources. The most typical units for the 

limitations are lb/MMBtu of heat input 

(or, in the case of Hg, lb/TBtu). The 

mass per heat input units are consistent 

with other Federal and many state EGU 

regulations and allows easy comparison 

between such requirements. 

Additionally, this proposed rule 

contains an option to monitor inlet 

chlorine, fluorine, non-Hg metal, and Hg 

content in the liquid oil to meet outlet 

emission rate limitations. This is 

reasonable because oil-fired units may 

choose to remove these fuel-borne HAP 

from the oil before combustion in lieu 

of installing air pollution control 

devices. This option can only be done 

on a mass basis by liquid oil-fired EGUs. 

We request comment on the viability of 

this approach for IGCC units. 


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We are proposing numerical emission 

rate limitations as a mass of pollutant 

emitted per megawatt- or gigawatt-hour 

(MWh or GWh) gross output from the 

EGU for the fuel-borne HAP for new 

sources and as an alternate format for 

existing sources. An outlet numerical 

emission limit is also consistent with 

the format of other regulations (e.g., the 

EGU NSPS, 40 CFR part 60, subpart Da). 

EGUs can emit a wide variety of 

compounds, depending on the fuel 

burned. Because of the large number of 

HAP potentially present and the 

disparity in the quantity and quality of 

the emissions information available, 

EPA grouped the HAP into five 

categories based on available 

information about the pollutants and on 

experiences gained on other NESHAP: 

Hg, non-Hg metallic HAP, inorganic 

(i.e., acid gas) HAP, non-dioxin/furan 

organic HAP, and dioxin/furan organic 

HAP. The pollutants within each group 

have similar characteristics and can be 

controlled with the same techniques. 

For example, non-Hg metallic HAP can 

be controlled with PM controls. We 

chose to look at Hg separately from 

other metallic HAP due to its different 

chemical characteristics and its different 

control technology feasibility. 

Next, EPA identified compounds that 

could be used as surrogates for all the 

compounds in each pollutant category. 

Existing technologies that have been 

installed to control emissions of other 

(e.g., criteria) pollutants are expected to 

provide coincidental or ‘‘co-benefit’’ 

control of some of the HAP. For 

example, technologies for PM control 

(e.g., ESP, FF) can effectively remove Hg 

that is bound to particulate such as 

injected sorbents, unburned carbon, or 

other fly ash particles. Similarly, PM 

control technologies are effective at 

reducing emissions of the non-Hg metal 

HAP that are present in the fly ash as 

solid particulate. Flue gas 

desulfurization technologies typically 

remove SO2 using acid-base 

neutralization reactions (usually via 

contact with alkaline solids or slurries). 

This approach is also effective for other 

acid gases as well, including the acid 

gas HAP (HCl, HF, Cl2, and HCN). 

EGUs routinely measure operating 

parameters (flow rates, temperatures, 

pH, pressure drop, etc.) and flue gas 

composition for process control and 

monitoring and for emission compliance 

and verification. Some of these 

routinely or more easily-measured 

parameters or components may serve as 

surrogates or indicators of the level of 

control of one or more of the HAP that 

may not be easily or routinely measured 

or monitored. The use of more easilymeasured components or process 

conditions as surrogates or predictors of 

HAP emissions can greatly simplify 

monitoring requirements under this 

proposed rule and, in some cases, 

provide more reliable results. 

In order to evaluate potential 

surrogacy relationships, the EPA Office 

of Research and Development (ORD), in 

collaboration with OAR, conducted a 

series of tests in the Agency’s 

Multipollutant Control Research Facility 

(MPCRF), a pilot-scale combustion and 

control technology research facility 

located at EPA’s Research Triangle Park 

campus in North Carolina. The 

combustor is rated at 4 MMBtu/hr 

(approximately 1.2 megawatt-thermal 

(MWt)). It is capable of firing all ranks 

of pulverized coal, natural gas, and fuel 

oil. The facility is equipped with low 

NOX burners and an SCR unit for NOX

control. The system can be configured to 

allow the flue gas to flow through either 

an ESP or a FF for PM control. The 

facility also uses a wet lime-based FGD 

scrubber for control of SO2 emissions. 

The system is well equipped with CEMS 

for on-line measurement of O2, CO2, 

NOX (nitrogen oxide, NO, and nitrogen 

dioxide, NO2), SO2, CO, Hg, and THC. 

There are multiple sampling ports 

throughout the flue gas flow path. The 

facility is designed for ease of 

modification so that various control 

technologies and configurations can be 

tested. The facility has a series of heat 

exchangers to remove heat such that the 

flow path of the flue gas has a similar 

time-temperature profile to that seen in 

a typical full-scale coal-fired EGU. 

Eleven independent tests were 

performed in the MPCRF in order to 

examine potential surrogacy 

relationships. Three types of coal 

(eastern bituminous, subbituminous, 

and Gulf Coast lignite) were tested. The 

PM control was also varied; in some 

tests, the ESP was used whereas the FF 

was used in others. Three potential 

surrogacy relationships were examined 

during the testing program. The 

potential for use of PM control as a 

surrogate for the control of the non-Hg 

metal HAP (Be, As, Cd, Co, Cr, Mn, Ni, 

Pb, Sb, and Se) was examined. The 

potential for use of HCl or SO2 control 

as a surrogate for other acid gases (HCl, 

HF, Cl2) was studied. In addition, 

several potential surrogate relationships 

were examined for the non-dioxin/furan 

organic HAP. No surrogate studies were 

conducted for Hg; we have not 

identified any surrogates for Hg and, 

thus, are regulating Hg directly. No 

surrogacy studies were conducted for 

dioxin/furan organic HAP because we 

believed the S:Cl ratio in the flue gas 

would be greater than 1.0, meaning that 

the formation of dioxins/furans would 

be inhibited. Moreover, it was 

anticipated that levels of these 

compounds would be very low, and, as 

mentioned earlier in the preamble, the 

approved 2010 ICR sampling methods 

for dioxin/furan organic HAP required 

8-hour sampling periods; such a long 

sampling period was not practical in our 

pilot system and would not be practical 

on a continuous basis. 

The results of the program indicated 

that the control of all non-Hg metal HAP 

(except Se) was consistently similar to 

the control of the bulk total PM (PMtotal). 

The average PMtotal control during the 

tests was 99.5 percent. All of the nonHg metal HAP were controlled along 

with the PMtotal at levels greater than 95 

percent for measurements taken for 

particulate control using both the ESP 

and the FF. Average control for the test 

series for each of the metals was (for all 

coals and all configurations): Sb—95.3 

percent; As—98.0 percent; Be—98.5 

percent; Cd—98.7 percent; Cr—98.0 

percent; Co—99.3 percent; Pb—99.2 

percent; Mn—99.5 percent; and Ni— 

97.6 percent. 

The results for Se control were less 

consistent. When subbituminous coal 

was fired, the control of Se was 

consistently very good (average 98.9 

percent), regardless of the PM control 

device being used. When using the FF 

as the primary PM control device, the Se 

control was consistently very good 

(average 99.2 percent) regardless of the 

coal being fired. Control of Se when the 

ESP was the primary PM control device 

was variable. When subbituminous coal 

was fired, the control of Se through the 

ESP was greater than 99 percent. When 

lignite was fired, the control through the 

ESP was about 80 percent. However, 

when the eastern bituminous coal was 

fired, the Se control through the ESP 

ranged from zero to 73 percent. 

The variability in the performance of 

Se control with coal rank and PM 

control device can be explained by the 

known behavior and chemistry of Se in 

the combustion and flue gas 

environments. Selenium is a metalloid 

that sits just below sulfur on the 

periodic table and is, chemically, very 

similar to sulfur. In the high 

temperature combustion environment, 

Se is likely to be present as gas phase 

SeO2 (as, similarly, sulfur is likely to be 

present as gaseous SO2). Much like SO2, 

SeO2 is a weak acid gas. The testing in 

the pilot-scale combustion facility 

showed that Se in the flue gas entering 

the PM control device tended to be 

predominantly in the gas phase (55 to 

90 percent) when firing eastern 

bituminous coal and predominantly in 

the solid phase when firing 

subbituminous coal (greater than 95 


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Federal Register / Vol. 76, No. 85 / Tuesday, May 3, 2011 / Proposed Rules 25039 

percent) and Gulf Coast lignite (80 

percent). This is explained by the large 

difference in calcium (Ca) content of 

those fuels. The ash from the 

bituminous coal contained 1.4 weight 

percent Ca, whereas the ashes from the 

subbituminous coal and Gulf Coast 

lignite contained Ca at 10.0 weight 

percent and 9.0 weight percent, 

respectively. The alkaline Ca in the fly 

ash effectively neutralized the SeO2 acid 

gas, forming a particulate that is easily 

removed in the PM control device. The 

bituminous fuel contained insufficient 

free Ca to completely neutralize the 

SeO2 and the much increased levels of 

SO2 in that flue gas. The good 

performance through the FF (regardless 

of the fuel being fired) can be attributed 

to the increased contact between the gas 

stream and the filter cake on the FF. 

This allows more of the SeO2 to adsorb 

or condense on fly ash particles—either 

alkaline particles or unburned carbon. 

Because SeO2 behaves very similarly to 

its sulfur analog, SO2, it can be expected 

to also be removed effectively in 

standard FGD technologies (wet 

scrubbers, dry scrubbers, DSI, etc.). 

Therefore, Se will either fall in to the 

category of ‘‘non-Hg metal HAP’’ and be 

effectively removed in a PM control 

device, or it will fall into the category 

of ‘‘acid gas HAP’’ as gaseous SeO2 and 

be effectively removed using FGD 

technologies. 

Two of the 11 tests were specifically 

designated for testing of surrogacy 

relationships relating to the acid gas 

HAP. Eastern bituminous coal was fired 

and duct samples were taken upstream 

and downstream of the lime-based wet 

FGD scrubber. Those tests showed, as 

expected, very high levels of control for 

HCl (greater than 99.9 percent control). 

The control of HF was greater than 92 

percent for the first run and greater than 

76 percent for the second run. The 

control of Cl2 was greater than 76 

percent for the first run and greater than 

92 percent for the second run. (Note that 

both of these control efficiencies were 

likely much higher than the reported 

values because the outlet measurements 

were below the MDL for both HF and 

Cl2. The control efficiencies were 

calculated using the MDL value.) The 

control efficiency for SO2 for the runs 

was greater than 98 percent. 

Tests were also conducted to examine 

potential surrogacy relationships for the 

non-dioxin/furan organic HAP. The 

amounts of Hg, non-Hg metals, HCl, HF, 

and Cl2 in the flue gas are directly 

related to the amounts of Hg, non-Hg 

metals, chlorine, and fluorine in the 

coal. Control of these components 

generally requires downstream control 

technology. However, the presence of 

the organics in the flue gas is not related 

to the composition of the fuel but rather 

they are a result of incomplete or poor 

combustion. Control of the organics is 

often achieved by improving 

combustion conditions to minimize 

formation or to maximize destruction of 

the organics in the combustion 

environment. 

During the pilot-scale tests, sampling 

was conducted for semi-volatile and 

volatile organic HAP and aldehydes. 

On-line monitors also collected data on 

THC, CO, O2, and other processing 

conditions. Total hydrocarbons and CO 

have been used previously as surrogates 

for the presence of non-dioxin/furan 

organics. Carbon monoxide has often 

been used as an indicator of combustion 

conditions. Under conditions of ideal 

combustion, a carbon-based or 

hydrocarbon fuel will completely 

oxidize to produce only CO2 and water. 

Under conditions of incomplete or nonideal combustion, a greater amount of 

CO will be formed. 

With complex carbon-based fuels, 

combustion is rarely ideal and some CO 

and concomitant organic compounds 

are expected to be formed. Because CO 

and organics are both products of poor 

combustion, it is logical to expect that 

limiting the concentration of CO would 

also limit the production of organics. 

However, it is very difficult to develop 

direct correlations between the average 

concentration of CO and the amount of 

organics produced during the prescribed 

sampling period in the MPCRF (which 

was 4 hours for the pilot-scale tests 

described here). This is especially true 

for low values of CO as one would 

expect corresponding low quantities of 

organics to be produced. Samples of 

coal combustion flue gas have mostly 

shown very low quantities of the 

organic compounds of interest. Some of 

the flue gas organics may also be 

destroyed in the high temperature post 

combustion zone (whereas the CO 

would remain stable). Semi-volatile 

organics may also condense on PM and 

be removed in the PM control device. 

The average CO from the pilot-scale 

tests ranged from 23 to 137 ppm for the 

bituminous coals tests, from 43 to 48 

ppm for the subbituminous coal tests 

and from 93 to 129 ppm for the Gulf 

Coast lignite tests. However, it was 

difficult to correlate that concentration 

to the quantity of organics produced for 

several reasons. The most difficult 

problems are associated with the large 

number of potential organics that can be 

produced (both those on the HAP list 

and those that are not on the HAP list). 

This is further complicated by the 

organic compounds tending to be at or 

below the MDL in coal combustion flue 

gas samples. Further, there are 

complications associated with the CO 

concentration values. Some of the runs 

with very similar average concentrations 

of CO had very different maximum 

concentrations of CO (i.e., some of the 

runs had much more stable emissions of 

CO whereas others had some 

excursions, or ‘‘spikes,’’ in CO 

concentration). For example, one of the 

bituminous runs had an average CO 

concentration of 69 ppm but a 

maximum concentration of 1,260 ppm 

(due to a single ‘‘spike’’ of CO during a 

short upset). Comparatively, another 

bituminous run had a higher average CO 

concentration at 137 ppm but a much 

lower maximum CO value at 360 ppm. 

In the pilot tests, the THC 

measurement was inadequate as the 

detection limit of the instrument was 

much too high to detect changes in the 

very low concentrations of 

hydrocarbons in the flue gas. 

Based on the testing described above 

and the emissions data received under 

the 2010 ICR, we are proposing 

surrogate standards for the non-Hg 

metallic HAP and the non-metallic 

inorganic (acid gas) HAP. For the nonHg metallic HAP, we chose to use PM 

as a surrogate. Most, if not all, non-Hg 

metallic HAP emitted from combustion 

sources will appear on the flue gas flyash. Therefore, the same control 

techniques that would be used to 

control the fly-ash PM will control nonHg metallic HAP. PM was also chosen 

instead of specific metallic HAP because 

all fuels do not emit the same type and 

amount of metallic HAP but most 

generally emit PM that includes some 

amount and combination of all the 

metallic HAP. The use of PM as a 

surrogate will also eliminate the cost of 

performance testing to comply with 

numerous standards for individual nonHg metals. Because non-Hg metallic 

HAP may preferentially partition to the 

small size particles (i.e., fine particle 

enrichment), we considered using PM2.5

as the surrogate, but we determined that 

total PM (filterable (i.e., PM2.5) plus 

condensable) was the more appropriate 

surrogate for two reasons. The test 

method (201A) for measuring PM2.5 is 

only applicable for use in exhaust stacks 

without entrained water droplets. 

Therefore, the test method for 

measuring PM2.5 is not applicable for 

units equipped with wet scrubbers 

which are in use at many EGUs today 

and may be necessary at some 

additional units to achieve the proposed 

HCl emission limitations. Thus, we are 

proposing to use total PM, instead of 

PM2.5, as the surrogate for non-Hg 

metals. However, as discussed 

elsewhere, we are also proposing 


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alternative individual non-Hg metallic 

HAP emission limitations as well as 

total non-Hg metallic HAP emission 

limitations for all subcategories (total 

metal HAP emission limitation for the 

liquid oil-fired subcategory). 

For non-metallic inorganic (acid gas) 

HAP, EPA is proposing setting an HCl 

standard and using HCl as a surrogate 

for the other non-metallic inorganic 

HAP for all subcategories except the 

liquid oil-fired subcategory. The 

emissions test information available to 

EPA indicate that the primary nonmetallic inorganic HAP emitted from 

EGUs are acid gases, with HCl present 

in the largest amounts. Other inorganic 

compounds emitted are found in 

smaller quantities. As discussed earlier, 

control technologies that reduce HCl 

indiscriminately control other inorganic 

compounds such as Cl2 and other acid 

gases (e.g., HF, HCN, SeO2). Thus, the 

best controls for HCl are also the best 

controls for other inorganic acid gas 

HAP. Therefore, HCl is a good surrogate 

for inorganic HAP because controlling 

HCl will result in control of other 

inorganic HAP emissions (as no liquid 

oil-fired EGU has an FGD system 

installed, there is no effective control in 

use and the surrogacy argument is 

invalid). As discussed elsewhere, EPA is 

also proposing to set an alternative 

equivalent SO2 emission limit for coalfired EGUs with some form of FGD 

system installed as: (1) The controls for 

SO2 are also effective controls for HCl 

and the other acid gas-HAP; and (2) 

most, if not all, EGUs already have SO2

CEMS in-place. Thus, SO2 CEMS could 

serve as the compliance monitoring 

mechanism for such units. EGUs 

without an FGD system installed would 

not be able to use the alternate SO2

emission limit, and EGUs must operate 

their FGD at all times to use the 

alternate SO2 emission limit. 

EPA is proposing work practice 

standards for non-dioxin/furan organic 

and dioxin/furan organic HAP. The 

significant majority of measured 

emissions from EGUs of these HAP were 

below the detection levels of the EPA 

test methods, and, as such, EPA 

considers it impracticable to reliably 

measure emissions from these units. As 

the majority of measurements are so 

low, doubt is cast on the true levels of 

emissions that were measured during 

the tests. Overall, 1,552 out of 2,334, 

total test runs for dioxin/furan organic 

HAP contained data below the detection 

level for one or more congeners, or 67 

percent of the entire data set. In several 

cases, all of the data for a given run 

were below the detection level; in few 

cases were the data for a given run all 

above the detection level. For the nondioxin/furan organic HAP, for the 

individual HAP or constituent, between 

57 and 89 percent of the run data were 

comprised of values below the detection 

level. Overall, the available test methods 

are technically challenged, to the point 

of providing results that are 

questionable for all of the organic HAP. 

For example, for the 2010 ICR testing, 

EPA extended the sampling time to 8 

hours in an attempt to obtain data above 

the MDL. However, even with this 

extended sampling time, such data were 

not obtained making it questionable that 

any amount of effort, and, thus, 

expense, would make the tests viable. 

Based on the difficulties with accurate 

measurements at the levels of organic 

HAP encountered from EGUs and the 

economics associated with units trying 

to apply measurement methodology to 

test for compliance with numerical 

limits, we are proposing a work practice 

standard under CAA section 112(h). 

We do not believe that this approach 

is inconsistent with that taken on other 

NESHAP where we also had issues with 

data at or below the MDL (e.g., Portland 

Cement NESHAP; Boiler NESHAP). In 

the case of the Portland Cement 

NESHAP, the MDL issue was with HCl 

(a single compound HAP as opposed to 

the oftentimes multi-congener organic 

HAP), and in data from only 3 of 21 

facilities. As noted elsewhere in this 

preamble, we dealt with similar MDL 

issues with HCl in establishing the 

limits in this proposed rule. In the case 

of the Boiler NESHAP, the MDL issue 

was with the organic HAP. For that 

rulemaking, the required sampling time 

during conducting of the associated ICR 

was 4 hours, as opposed to the 8 hours 

required in the 2010 ICR. Further, a 

review of the data indicates that the 

dioxin/furan HAP levels (a component 

of the organic HAP) were at least 7 times 

greater, on average, for coal-fired IB 

units and 3 times greater, on average, for 

oil-fired IB units than from similar 

EGUs. We think this difference is 

significant from a testing feasibility 

perspective. 

For all the other HAP, as stated above, 

we are proposing to establish numerical 

emission rate limitations; however, we 

did consider using a percent reduction 

format for Hg (e.g., the percent 

efficiency of the control device, the 

percent reduction over some input 

amount, etc.). 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 

EPA’s desire to promote, and give credit 

for, coal preparation practices that 

remove Hg and other HAP before firing 

(i.e., coal washing or beneficiation, 

actions that may be taken at the mine 

site rather than at the site of the EGU). 

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. In addition, 

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, 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. 

EPA believes, however, that an emission 

rate format allows for, and promotes, the 

use of precombustion HAP removal 

processes because such practices will 

help sources assure they will comply 

with the proposed standard. 

Furthermore, a percent reduction 

requirement would 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 55,002; September 9, 

2010), EPA believes that a percent 

reduction format negates the 

contribution of HAP inputs to EGU 

performance and, thus, may be 

inconsistent with the DC Circuit Court’s 

rulings as restated in Brick MACT (479 

F.3d at 880) that say, in effect, that it is 

the emissions achieved in practice (i.e., 

emissions to the atmosphere) that 

matter, not how one achieves those 

emissions. The 2010 ICR data confirm 

the point relating to plant inputs likely 

playing a role in emissions in that they 

indicate that some EGUs are achieving 

lower Hg emissions to the atmosphere at 

a lower Hg percent reduction (e.g., 75 to 

85 percent) than are other EGUs with 

higher percent reductions (e.g., 90 

percent or greater). For all of these 

reasons, we are proposing to establish 

numerical emission standards for HAP 

emissions from EGUs with the 

exception of the organic HAP standard 

which is in the form of work practices. 

C. How did EPA determine the proposed 

emission limitations for existing EGUs? 

All standards established pursuant to 

CAA section 112(d)(2) must reflect 

MACT, the maximum degree of 

reduction in emissions of air pollutants 

that the Administrator, taking into 

consideration the cost of achieving such 

emissions reductions, and any nonair 


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158Earlier data were not used due to concerns 

related to changes in test and analytical methods. 

quality health and environmental 

impacts and energy requirements, 

determines is achievable for each 

category. For existing sources, MACT 

cannot be less stringent than the average 

emission limitation achieved by the best 

performing 12 percent of existing 

sources (for which the Administrator 

has emissions information) for 

categories and subcategories with 30 or 

more sources or the best performing 5 

sources for subcategories with less than 

30 sources. This requirement 

determines the MACT floor for existing 

EGUs. However, EPA may not consider 

costs or other impacts in determining 

the MACT floor. EPA must consider 

cost, nonair quality health and 

environmental impacts, and energy 

requirements in connection with any 

standards that are more stringent than 

the MACT floor (beyond-the-floor 

controls). 

D. How did EPA determine the MACT 

floors for existing EGUs? 

EPA must consider available 

emissions information to determine the 

MACT floors. For each pollutant, we 

calculated the MACT floor for a 

subcategory of sources by ranking all the 

available emissions data obtained 

through the 2010 ICR158 from units 

within the subcategory from lowest 

emissions to highest emissions (on a lb/ 

MMBtu basis), and then taking the 

numerical average of the test results 

from the best performing (lowest 

emitting) 12 percent of sources. 

Therefore, the MACT floor limits for 

each of the HAP and HAP surrogates are 

calculated based on the performance of 

the lowest emitting (best performing) 

sources in each of the subcategories. 

As discussed above, for coal-fired 

EGUs, EPA established the MACT floors 

for non-Hg metallic HAP and nonmetallic inorganic (acid gas) HAP based 

on sources representing 12 percent of 

the number of sources in the 

subcategory. For Hg from coal-fired 

units and all HAP from oil-fired units, 

EPA established the MACT floors based 

on sources representing 12 percent of 

the sources for which the Agency had 

emissions information. The IGCC and 

solid oil-fired EGU subcategories each 

have less than 30 units so the MACT 

floors were determined using the 5 best 

performing sources (or 2 sources for 

IGCC because there are only 2 such 

sources in the subcategory). The MACT 

floor limitations for each of the HAP 

and HAP surrogates (PM, Hg, and HCl) 

are calculated based on the performance 

of the lowest emitting (best performing) 

sources in each of the subcategories. 

The initial sort of the respective data to 

determine the MACT floor pool for 

analysis was made on the ‘‘lb/MMBtu’’ 

formatted data; this same pool of EGUs 

was then used for the ‘‘lb/MWh’’ 

analysis and all analyses were based on 

the data provided through the 2010 ICR. 

We used the emissions data for those 

best performing affected sources to 

determine the emission limitations to be 

proposed, with an accounting for 

variability. EPA must exercise its 

judgment, based on an evaluation of the 

available data, to determine the level of 

emissions control that has been 

achieved by the best performing sources 

under variable conditions. The DC 

Circuit Court has recognized that EPA 

may consider variability in estimating 

the degree of emission reduction 

achieved by best-performing sources in 

setting MACT floors. See Mossville 

Envt’l Action Now v. EPA, 370 F.3d 

1232, 1241–42 (DC Cir 2004) (holding 

EPA may consider emission variability 

in estimating performance achieved by 

best-performing sources and may set the 

floor at a level that best-performing 

source can expect to meet ‘‘every day 

and under all operating conditions’’). 

In determining the MACT floor 

limitations, we first determine the floor, 

which is the level achieved in practice 

by the average of the top 12 percent of 

similar sources for subcategories with 

more than 30 sources. We then assess 

variability of the best performers by 

using a statistical formula designed to 

estimate a MACT floor level that is 

achieved by the average of the best 

performing sources with some 

confidence (e.g., 99 percent confidence) 

if the best performing sources were able 

to replicate the compliance tests in our 

data base. Specifically, the MACT floor 

limit is an upper prediction limit (UPL) 

calculated with the Student’s t-test 

using the TINV function in Microsoft 

Excel. The Student’s t-test has also been 

used in other EPA rulemakings (e.g., 

NSPS for Hospital/Medical/Infectious 

Waste Incinerators; NESHAP for IB and 

Portland Cement) in accounting for 

variability. A prediction interval for a 

future observation, or an average of 

future observations, is an interval that 

will, with a specified degree of 

confidence, contain the next (or the 

average of some other pre-specified 

number of) randomly selected 

observation(s) from a population. In 

other words, the prediction interval 

estimates what the range of future 

values, or average of future values, will 

be, based upon present or past 

background samples taken. Given this 

definition, the UPL represents the value 

which we can expect the mean of three 

future observations (3-run average) to 

fall below, based upon the results of an 

independent sample from the same 

population. In other words, if we were 

to randomly select a future test 

condition from any of these sources (i.e., 

average of 3 runs), we can be 99 percent 

confident that the reported level will 

fall at or below the UPL value. To 

calculate the UPL, we used the average 

(or sample mean) and an estimate of the 

standard deviation, which are two 

statistical measures calculated from the 

available data. The average is a measure 

of centrality of the distribution. 

Symmetric distributions such as the 

normal are centered around the average. 

The standard deviation is a common 

measure of the dispersion of the data set 

around the average. 

We first determined the distribution 

of the emissions data for the bestperforming 12 percent of units within 

each subcategory prior to calculating 

UPL values. When the sample size is 15 

or larger, one can assume based on the 

Central Limit theorem, that the 

sampling distribution of the average or 

sampling mean of emission data is 

approximately normal, regardless of the 

parent distribution of the data. This 

assumption justifies selecting the 

normal-distribution based UPL equation 

for calculating the floor. 

When the sample size is smaller than 

15 and the distribution of the data is 

unknown, the Central Limit Theorem 

can’t be used to support the normality 

assumption. Statistical tests of the 

kurtosis, skewness, and goodness of fit 

are then used to evaluate the normality 

assumption. To determine the 

distribution of the best performing 

dataset, we first computed the skewness 

and kurtosis statistics and then 

conducted the appropriate small-sample 

hypothesis tests. The skewness statistic 

(S) characterizes the degree of 

asymmetry of a given data distribution. 

Normally distributed data have a 

skewness of zero (0). A skewness 

statistic that is greater (less) than 0 

indicates that the data are 

asymmetrically distributed with a right 

(left) tail extending towards positive 

(negative) values. Further, the standard 

error of the skewness statistic (SES) can 

be approximated by SES = SQRT(6/N) 

where N is the sample size. According 

to the small sample skewness 

hypothesis test, if S is greater than two 

times the SES, the data distribution can 

be considered non-normal. The kurtosis 

statistic (K) characterizes the degree of 

peakedness or flatness of a given data 

distribution in comparison to a normal 

distribution. Normally distributed data 

have a kurtosis of 0. A kurtosis statistic 

that is greater (less) than 0 indicates a 


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relatively peaked (flat) distribution. 

Further, the standard error of the 

kurtosis statistic (SEK) can be 

approximated by SEK = SQRT(24/N) 

where N is the sample size. According 

to the small sample kurtosis hypothesis 

test, if K is greater than two times the 

SEK, the data distribution is typically 

considered to be non-normal. 

The skewness and kurtosis hypothesis 

tests were applied to both the reported 

test values and the lognormal values 

(using the LN() function in Excel) of the 

reported test values. If S and K of the 

reported data set were both less than 

twice the SES and SEK, respectively, the 

dataset was classified as normally 

distributed. If neither S nor K, or only 

one of these statistics, were less than 

twice the SES or SEK, respectively, then 

we looked at the skewness and kurtosis 

hypothesis test results conducted for the 

natural log-transformed data. Then, the 

distribution most similar to a normal 

distribution was selected as the basis for 

calculating the UPL. If the results of the 

skewness and kurtosis hypothesis tests 

were mixed for the reported values and 

the natural log-transformed reported 

values, we chose the normal 

distribution to be conservative. We 

believe this approach is more accurate 

and obtained more representative 

results than a more simplistic normal 

distribution assumption. 

Because some of the MACT floor 

emission limitations are based on the 

average of a 3-run test, and compliance 

with these limitations will be based on 

the same, the UPL for data considered 

to be normally distributed is calculated 

by: 

Where: 

n = the number of test runs 

m = the number of test runs in the 

compliance average 

b = mean of the data from top performing 

sources calculated as 

t(0.99, n–1) is the 99th percentile of the TStudent distribution with n–1 degrees of 

freedom 

s2 = variance of the data from top performing 

sources calculated as 

This calculation was performed using 

the following Excel function: 

Normal distribution: 99% UPL = 

AVERAGE(Test Runs in Top 12%) + 

[STDEV(Test Runs in Top 12%) × 

TINV(2 × probability, n–1 degrees of 

freedom)*SQRT((1/n)+(1/3))], for a onetailed t-value (with 2 × probability), 

probability of 0.01, and sample size of 

n. 

Data from only a single unit was used 

in establishing the new-source floor. 

Analysis based solely in these singledata-point-per-unit observations does 

not capture any within source 

variability. When additional 

information (e.g., stack averages) from 

the past 5 years (from the 2010 ICR) was 

available, we combined the current and 

past data and calculated an estimate of 

the variance term, s2, that intends to 

include the within and between source 

variability. The most recent data (e.g., 

single floor average) were used to 

calculate the average in the UPL 

equation. The UPL equation for this case 

was calculated as: 

UPL = 

Where: 

m = the number of test runs in the 

compliance average 

N = the number of units involved in 

calculating the average (a single 

measurement (e.g., floor average) per 

unit) 

ni = number of data points (e.g., stack 

averages) collected in the past for the ith

source 

number of data points (floor average plus 

stack averages) available to calculate the 

variance 

df = n¥1 

xi = current information (e.g., single floor 

average) for the ith source 

yi = past information (e.g., stack average) for 

the ith source 

m = the number of future test runs in the 

compliance average 

b = mean of the data from top performing 

sources calculated as 


jlentini on DSKJ8SOYB1PROD with PROPOSALS2EP03MY11.000</GPH> EP03MY11.001</GPH> EP03MY11.002</GPH> EP03MY11.003</GPH> EP03MY11.004</GPH> EP03MY11.005</GPH>
Federal Register / Vol. 76, No. 85 / Tuesday, May 3, 2011 / Proposed Rules 25043 

s2 = variance calculated as 

t

df,.99 = quantile t-distribution with df 

degrees of freedom at 99 percent 

confidence level df = degrees of 

freedom = n ¥ 1 

The calculation of this UPL was 

performed using the following Excel 

function: 

Normal distribution: 99% UPL = 

AVERAGE(Test Runs in Top 12%) + 

[STDEV(Test Runs in Top 12%, stack 

averages) × TINV(2 × probability, (n–1) 

degrees of freedom)*SQRT((1/N)+(1⁄3))], 

for a one-tailed t-value (with 2 × 

probability), probability of 0.01, and 

sample size of n. 

The UPL, to test compliance based on 

a 3-run average and assuming lognormal data, is calculated by (Bhaumik 

and Gibbons, 2004): 

s√ = the variance estimate of the log 

transformed data from the top 

performing sources calculated as: 

z99 = the 99th-percentile of the log-normal 

distribution estimated using the 

trapezoidal rule approach from the 

following equation 


jlentini on DSKJ8SOYB1PROD with PROPOSALS2EP03MY11.006</GPH> EP03MY11.007</GPH> EP03MY11.008</GPH> EP03MY11.009</GPH> EP03MY11.010</GPH> EP03MY11.011</GPH>
25044 Federal Register / Vol. 76, No. 85 / Tuesday, May 3, 2011 / Proposed Rules 

159American Society of Mechanical Engineers, 

Reference Method Accuracy and Precision 

(ReMAP): Phase 1, Precision of Manual Stack 

Emission Measurements, CRTD Vol. 60, February 

2001. 

The calculation of the log-normal 

based UPL was performed using the 

following Excel function: 

Normal distribution: 99% UPL = 

EXP(AVERAGE(LN(Test Runs in Top 

12%)) + VAR(LN(Test Runs in Top 

12%))/2) + (99TH-PERCENTILE 

LOGNORMAL DISTRIBUTION/m)* 

SQRT(m*EXP(2* AVERAGE(LN(Test 

Runs in Top 12%))+ VAR(LN(Test Runs 

in Top 12%)))*(EXP(VAR(LN(Test Runs 

in Top 12%)))-1)+m∧2* EXP(2* 

AVERAGE(LN(Test Runs in Top 12%))+ 

VAR(LN(Test Runs in Top 

12%)))*(VAR(LN(Test Runs in Top 

12%))/n+ VAR(LN(Test Runs in Top 

12%))∧2/(2*(n–1)))). 

The 99th percentile of the log-normal 

distribution, z.99, was calculated 

following Bhaumik and Gibbons (2004). 

Test method measurement 

imprecision can also be a component of 

data variability. At very low emissions 

levels, as encountered in some of the 

data used to support this proposed rule, 

the inherent imprecision in the 

pollutant measurement method has a 

large influence on the reliability of the 

data underlying the regulatory floor or 

beyond-the-floor emissions limit. Of 

particular concern are those data that 

are reported near or below a test 

method’s pollutant detection capability. 

In our guidance for reporting pollutant 

emissions used to support this proposed 

rule, we specified the criteria for 

determining test-specific MDL. Those 

criteria ensure that there is about a 1 

percent probability of an error in 

deciding that the pollutant measured at 

the MDL is present when in fact it was 

absent. Such a probability is also called 

a false positive or the alpha, Type I, 

error. Another view of this probability is 

that one is 99 percent certain of the 

presence of the pollutant measured at 

the MDL. Because of matrix effects, 

laboratory techniques, sample size, and 

other factors, MDLs normally vary from 

test to test. We requested sources to 

identify (i.e., flag) data which were 

measured below the MDL and to report 

those values as equal to the test-specific 

MDL. 

Variability of data due to 

measurement imprecision is inherently 

and reasonably addressed in calculating 

the floor emissions limit when the data 

distribution, which would include the 

results of all tests, is significantly above 

the MDL. Should the data distribution 

shift such that some or many test results 

are below the MDL but are reported as 

MDL values, as is the case for some of 

our database, then other techniques 

need to be used to account for data 

variability. Indeed, under such a shift, 

the distribution becomes truncated on 

the lower end, leading to an artificial 

overabundance of values occurring at 

the MDL. Such an artificial 

overabundance of values could, if not 

adjusted, lead to erroneous floor 

calculations; those unadjusted floor 

calculations may be higher than 

otherwise expected, because no values 

reported below the MDL are included in 

the calculation. There is a concern that 

a floor emissions limit based on a 

truncated data base may not account 

adequately for data measurement 

variability and that a floor emissions 

limit calculated using values at or near 

the MDL may not account adequately 

for data measurement variability, 

because the measurement error 

associated with those values provides a 

large degree of uncertainty—up to 100 

percent. 

Despite our concern that accounting 

for measurement imprecision should be 

an important consideration in 

calculating the floor emissions limit, we 

did not adjust the calculated floor for 

the data used for this proposed rule 

because we do not know how to develop 

such an adjustment. We remain open to 

considering approaches for making such 

an adjustment, particularly when those 

approaches acknowledge our inability to 

detect with certainty those values below 

the MDL. We request comment on 

approaches suitable to account for 

measurement variability in establishing 

the floor emissions limit when based on 

measurements at or near the MDL. 

As noted above, the confidence level 

that a value measured at the detection 

level is greater than 0 is about 99 

percent. The expected measurement 

imprecision for an emissions value 

occurring at or near the MDL is about 

40 to 50 percent. Pollutant measurement 

imprecision decreases to a consistent 

relative 10 to 15 percent for values 

measured at a level about three times 

the MDL.159 One approach that we 

believe could be applied to account for 

measurement variability would require 

defining a MDL that is representative of 

the data used in establishing the floor 

emissions limitations and also 

minimizes the influence of an outlier 

test-specific MDL value. The first step in 

this approach would be to identify the 

highest test-specific MDL reported in a 

data set that is also equal to or less than 

the floor emissions limit calculated for 

the data set. This approach has the 

advantage of relying on the data 

collected to develop the floor emissions 

limit while to some degree minimizing 

the effect of a test(s) with an 

inordinately high MDL (e.g., the sample 

volume was too small, the laboratory 

technique was insufficiently sensitive, 

or the procedure for determining the 

detection level was other than that 

specified). 

The second step would be to 

determine the value equal to three times 

the representative MDL and compare it 

to the calculated floor emissions limit. 

If three times the representative MDL 

were less than the calculated floor 

emissions limit, we would conclude 

that measurement variability is 

adequately addressed and we would not 

adjust the calculated floor emissions 

limit. If, on the other hand, the value 

equal to three times the representative 

MDL were greater than the calculated 

floor emissions limit, we would 

conclude that the calculated floor 

emissions limit does not account 

entirely for measurement variability. We 

then would use the value equal to three 

times the MDL in place of the calculated 

floor emissions limit to ensure that the 

floor emissions limit accounts for 

measurement variability. This adjusted 

value would ensure measurement 

variability is adequately addressed in 

the floor or the emissions limit. This 

check was part of the variability 

analysis for all new MACT floors that 

had below detection level (BDL) or 

detection level limited (DLL) run data 

present in the best controlled data set 

and resulted in the MACT floors being 

three times the MDL rather than the 

UPL in a limited number of instances 

(see ‘‘MACT Floor Analysis (2011) for 

the Subpart UUUUU—National 

Emission Standards for Hazardous Air 

Pollutants: Coal- and Oil-fired Electric 

Utility Steam Generating Units’’ (MACT 

Floor Memo) in the docket). We request 

comment on this approach. 

As previously discussed, we account 

for variability in setting floors, not only 

because variability is an element of 

performance, but because it is 

reasonable to assess best performance 

over time. For example, we know that 

the HAP emission data from the best 

performing units are, for the most part, 

short-term averages, and that the actual 

HAP emissions from those sources will 

vary over time. If we do not account for 

this variability, we would expect that 

even the units that perform better than 

the floor on average could potentially 

exceed the floor emission levels a part 

of the time which would mean that 

variability was not properly taken into 

account. This variability may include 

the day-to-day variability in the total 

fuel-borne HAP input to each unit; 

variability of the sampling and analysis 

methods; and variability resulting from 

site-to-site differences for the best 


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Federal Register / Vol. 76, No. 85 / Tuesday, May 3, 2011 / Proposed Rules 25045 

performing units. EPA’s consideration 

of variability accounted for that 

variability exhibited by the data 

representing multiple units and 

multiple data values for a given unit 

(where available). We calculated the 

MACT floor based on the UPL (upper 

99th percentile) as described earlier 

from the average performance of the best 

performing units, Student’s t-factor, and 

the variability of the best performing 

units. 

We believe 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. 

Both the analysis of the measured 

emissions from units representative of 

the top 12 percent, and the variability 

analysis, are reasonably designed to 

provide a meaningful estimate of the 

average performance, or central 

tendency, of the best controlled 12 

percent of units in a given subcategory. 

A detailed discussion of the MACT 

floor methodology is presented in the 

MACT Floor Memo in the docket. 

1. Determination of MACT for the Fuelborne HAP for Existing Sources 

In developing the proposed MACT 

floor for the fuel-borne HAP (non-Hg 

metals, acid gases, and Hg), as described 

earlier, we are using PM as a surrogate 

for non-Hg metallic HAP (except for the 

liquid oil-fired subcategory) and HCl as 

a surrogate for the acid gases (except for 

the liquid oil-fired subcategory). Table 

12 of this preamble presents the number 

of units in each of the subcategories, 

along with the number of units 

comprising the best performing units 

(top 12 percent). Table 12 of this 

preamble also shows the average 

emission level of the top 12 percent, and 

the MACT floor including consideration 

of variability (99 percent UPL of top 12 

percent). 

TABLE 12—SUMMARY OF MACT FLOOR RESULTS FOR EXISTING SOURCES

Subcategory Parameter PM HCl Mercury 

Coal-fired unit designed for coal 

≥ 8,300 Btu/lb.

No. of sources in subcategory ... 1,091 ........................... 1,091 ........................... 1,061. 

No. in MACT floor ...................... 131 .............................. 131 .............................. 40. 

Avg. of top 12% .......................... 0.02 lb/MMBtu ............ 0.0003 lb/MMBtu ........ 0.01 lb/TBtu. 

99% UPL of top 12% ................. 0.030 lb/MMBtu .......... 0.0020 lb/MMBtu ........ 1.0 lb/TBtu. 

Coal-fired unit designed for coal 

< 8,300 Btu/lb.

No. of sources in subcategory ... 1,091 ........................... 1,091 ........................... 30. 

No. in MACT floor ...................... 131 .............................. 131. ............................. 2. 

1.* 

Avg. of top 12% .......................... 0.02 lb/MMBtu ............ 0.0003 lb/MMBtu ........ 1 lb/TBtu. 

(1 lb/TBtu *). 

99% UPL of top 12% ................. 0.030 lb/MMBtu .......... 0.0020 lb/MMBtu ........ 11.0 lb/TBtu. 

(4.0 lb/TBtu *). 

IGCC ............................................ No. of sources in subcategory ... 2 .................................. 2 .................................. 2. 

No. in MACT floor ...................... 2 .................................. 2 .................................. 2. 

Avg. ............................................ 0.03 lb/MMBtu ............ 0.0002 lb/MMBtu ........ 0.9 lb/TBtu. 

99% UPL .................................... 0.050 lb/MMBtu .......... 0.00050 lb/MMBtu ...... 3.0 lb/TBtu. 

Solid oil-derived ........................... No. of sources in subcategory ... 10 ................................ 10 ................................ 10. 

No. in MACT floor ...................... 5 .................................. 5 .................................. 5. 

Avg. of top 5 ............................... 0.04 lb/MMBtu ............ 0.002 lb/MMBtu .......... 0.09 lb/TBtu. 

99% UPL of top 5 ....................... 0.20 lb/MMBtu ............ 0.0050 lb/MMBtu ........ 0.20 lb/TBtu. 

Total metals ** ............ HCl .............................. Mercury. 

Liquid oil ...................................... No. of sources in subcategory ... 154 .............................. 154 .............................. 154. 

No. in MACT floor ...................... 7 .................................. 7 .................................. 7. 

Avg. of top 12% .......................... 0.00002 lb/MMBtu ...... 0.0001 lb/MMBtu ........ NA. 

99% UPL of top 12% ................. 0.000030 lb/MMBtu .... 0.00030 lb/MMBtu ...... NA. 

* Beyond-the-floor limit as discussed elsewhere. 

** Includes Hg. 

NA = Not applicable. 

For the ‘‘Coal-fired unit designed for 

coal < 8,300 Btu/lb’’ subcategory, we 

used 12 percent of the available data (11 

data points), or 2 units, in setting the 

existing source floor for Hg. For the 

IGCC subcategory, we used data from 

both units in setting the existing source 

floor. For the oil-fired subcategory, we 

did not include data obtained from 

EGUs co-firing natural gas in the 

existing-source MACT floor analysis 

because those emissions are not 

representative of EGUs firing 100 

percent fuel oil. 

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. 

Further, we are proposing a total metals 

limit for oil-fired EGUs that includes 

Hg, in lieu of a PM limit, based on 

compliance through fuel analysis. We 

solicit comment on whether a PM limit 

or a total metals limit based on stack 

testing is an appropriate alternative. We 

recognize that PM is not an appropriate 

surrogate for Hg because Hg is not 

controlled to the same extent by the 

technologies which control emissions of 

other HAP metals, but we are soliciting 

comment as to whether there is 

anything unique as to oil-fired EGUs 

that would allow us to conclude that 

PM is an appropriate surrogate for all 

HAP metal emissions from such units. 

We further solicit comment on whether 

we should be setting a separate standard 

for Hg if we require end-of-stack testing 

for a total metals limit. Based on the 

data we have, that Hg limit would be 

0.050 lb/MMBtu (0.000070 lb/GWh) for 

existing oil-fired units and 0.00010 lb/ 

GWh for new oil-fired units. In this 

regard, we request additional Hg 

emissions data from oil-fired EGUs. 

Although we have some data, additional 


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data would aid in our development of 

the standards for such units. 

2. Determination of the Work Practice 

Standard 

CAA section 112(h)(1) states that the 

Administrator may prescribe a work 

practice standard or other requirements, 

consistent with the provisions of CAA 

sections 112(d) or (f), in those cases 

where, in the judgment of the 

Administrator, it is not feasible to 

enforce an emission standard. CAA 

section 112(h)(2)(B) further defines the 

term ‘‘not feasible’’ in this context to 

apply when ‘‘the application of 

measurement technology to a particular 

class of sources is not practicable due to 

technological and economic 

limitations.’’ 

As noted earlier, the significant 

majority of the measured emissions 

from EGUs of dioxin/furan and nondioxin/furan organic HAP are at or 

below the MDL of the EPA test methods 

even though we required 8 hour test 

runs. As such, EPA considers it 

impracticable to reliably measure 

emissions from these units. As 

mentioned earlier, because the expected 

measurement imprecision for an 

emissions value occurring at or near the 

MDL is about 40 to 50 percent, we are 

uncertain of the true levels of organic 

HAP emissions that would be obtained 

during any test program. Overall, the 

fact that the organic HAP emission 

levels found at EGUs are so near the 

MDL achievable by the available test 

methods indicates that the results 

obtained are questionable for all of the 

organic HAP. 

Because the levels of organic HAP 

emissions from EGUs are so low (at or 

below the MDL of the available test 

methods), there is no indication that 

expending additional cost (i.e., 

extending the sampling time) would 

provide the regulated community the 

ability to test for these HAP that would 

provide reliable, technically viable 

results. In fact, the 2010 ICR testing 

required a longer testing period than 

normally used and the results were still 

predominantly below the MDL. Because 

of the technical infeasibility, the 

economic infeasibility is that sources do 

not have a way to demonstrate 

compliance that is legitimate and we 

conclude no additional cost will 

improve the results. 

Based on this analysis, and 

considering the fact that regardless of 

the cost, the resulting emissions data 

would be suspect due to the detection 

level issues, the Administrator is 

proposing under CAA section 112(h) 

that it is not feasible to enforce emission 

standards for dioxin/furan and nondioxin/furan organic HAP because of 

the technological and economic 

infeasibility described above. Thus, a 

work practice, as discussed below, is 

being proposed to limit the emission of 

these HAP for existing EGUs. 

For existing units, the only work 

practice we identified that would 

potentially control these HAP emissions 

is an annual performance test. Organic 

HAP are formed from incomplete 

combustion of the fuel. The objective of 

good combustion is to release all the 

energy in the fuel while minimizing 

losses from combustion imperfections 

and excess air. The combination of the 

fuel with the O2 requires temperature 

(high enough to ignite the fuel 

constituents), mixing or turbulence (to 

provide intimate O2-fuel contact), and 

sufficient time (to complete the 

process), sometimes referred to the three 

Ts of combustion. Good combustion 

practice (GCP), in terms of combustion 

units, could be defined as the system 

design and work practices expected to 

minimize the formation and maximize 

the destruction of organic HAP 

emissions. We maintain that the 

proposed work practice standards will 

promote good combustion and thereby 

minimize the organic HAP emissions we 

are proposing to regulate in this manner. 

E. How did EPA consider beyond-thefloor options for existing EGUs? 

Once the MACT floors were 

established for each subcategory, we 

considered various regulatory options 

more stringent than the MACT floor 

level of control (i.e., technologies or 

other work practices that could result in 

lower emissions) for the different 

subcategories. 

Except for one subcategory, we could 

not identify better HAP emissions 

reduction approaches that could achieve 

greater emissions reductions of HAP 

than the control technology 

combination(s) (e.g., FF, carbon 

injection, scrubber, and GCP) that we 

expect will be used to meet the MACT 

floor levels of control (and that are 

already in use on EGUs comprising the 

top performing 12 percent of sources), 

though we did consider duplicate 

controls (e.g., multiple scrubbers) in 

series and found the cost of that option 

unreasonable. 

Fuel switching to natural gas is an 

option that would reduce HAP 

emissions. We determined that fuel 

switching was not an appropriate 

beyond-the-floor option. First, natural 

gas supplies are not available in some 

areas. Natural gas pipelines are not 

available in all regions of the U.S., and 

natural gas may not be available as a 

fuel for many EGUs. Moreover, even 

where pipelines provide access to 

natural gas, supplies of natural gas may 

not be adequate, especially during peak 

demand (e.g., the heating season). Under 

such circumstances, there would be 

some units that could not comply with 

a requirement to switch to natural gas. 

While the combined capital cost and 

O&M costs for a coal-to-gas retrofit 

could be less than that of a combined 

retrofit with ACI and either DSI or FGD, 

the increased fuel costs of coal-to-gas 

cause its total incremental COE at a 

typical EGU is likely to be significantly 

larger than the incremental COE of the 

other retrofit options available. For 

example, an EPA analysis detailed in an 

accompanying TSD found that the 

incremental COE of coal-to-gas was 4 to 

22 times the cost of alternatives, 

although the magnitude of the 

difference would change with 

alternative fuel price assumptions. EPA, 

therefore, concludes that the coal-to-gas 

option is not a cost-effective means of 

achieving HAP reductions for the 

purposes of this proposed rule. 

Additional detail on the economics of 

coal-to-gas conversion and illustrative 

calculations of additional emission 

reductions versus cost impacts are 

provided in the ‘‘Coal-to-Gas 

Conversion’’ TSD in the docket. 

As noted earlier, no EGU 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 a EGU with a heightto-depth ratio of 3.82 or greater was 

found among the top performing 12 

percent of sources for Hg emissions, 

even though some of these units 

employed ACI. EPA has learned that the 

units of this design that were using ACI 

during the testing were using ACI to 

meet their permitted Hg emission levels. 

However, EPA believes that the control 

level being achieved is still not that 

which could be achieved if ACI were 

used to its fullest extent. Therefore, EPA 

is proposing to establish a beyond-thefloor emission limit for existing 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 a 

EGU with a height-to-depth ratio of 3.82 

or greater. The proposed emission limit 

is 4 lb/TBtu for existing EGUs in this 

class. This proposed emission limit is 

based on use of the data from the top 

performing unit in the subcategory 

made available to the Agency through 

the 2010 ICR; the same statistical 

analyses were conducted as were done 

to establish the MACT floor values for 

the other HAP. EPA notes that our 

analysis shows that the technology 

installed to achieve the MACT floor 


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limit would be the same technology 

used to achieve the beyond-the-floor 

MACT limit and, thus, proposing to go 

beyond-the-floor is reasonable. EPA 

solicits comment on whether it is 

appropriate to propose a beyond-thefloor limit for existing EGUs in this 

subcategory. 

To assess the impacts on the existing 

EGUs in this subcategory to implement 

the proposed beyond-the-floor limit, 

EPA conducted analyses using 

approaches as discussed in the 

memoranda ‘‘Beyond-the-Floor Analysis 

(2011) for the Subpart UUUUU— 

National Emission Standards for 

Hazardous Air Pollutants: Coal- and Oilfired Electric Utility Steam Generating 

Units’’ and ‘‘Emission Reduction Costs 

for the Beyond-the-Floor Mercury Rate 

in the Toxics Rule’’ in the docket. The 

cost effectiveness of the beyond-thefloor option ranged from $17,375 to 

$21,393/lb Hg removed in the two 

approaches. The total costs of the nonair environmental impacts for the 

proposed beyond-the-floor limit for this 

subcategory are estimated as $12,310. 

Non-air quality health impacts were 

evaluated, but no incremental health 

impacts were attributable to installation 

of FF and ACI, because these 

technologies do not expose electric 

utility employees or the public to any 

additional health risks above the risks 

attributable to current utility operations 

involving compressed air systems, 

confined spaces, and exposure to fly 

ash. 

EPA is aware that there may be other 

means of enhancing the removal of Hg 

from the flue gas stream (e.g., spraying 

a halogen such as chlorine or bromine 

on the coal as it is fed to the EGU). EPA 

has information that indicates that such 

means were employed by an unknown 

number of EGUs during the period of 

time they were testing to provide data 

in compliance with the 2010 ICR (see 

McMeekin memo in the docket). Thus, 

we believe that the performance of such 

means is reflected in the MACT floor 

analysis. However, EPA has no data 

upon which to assess whether any other 

technology would provide additional 

control to that already shown by the use 

of ACI and, thus, we are not proposing 

to use such technologies as the basis for 

a beyond-the-floor analysis. EPA solicits 

comment on this approach. 

EPA believes the best potential way of 

reducing Hg emissions from existing 

IGCC units is to remove Hg from the 

syngas before combustion. For example, 

an existing industrial coal gasification 

unit has demonstrated a process, using 

a sulfur-impregnated AC bed, which has 

proven to yield over 90 percent Hg 

removal from the coal syngas. 

(Rutkowski 2002.) We considered using 

carbon bed technology as beyond-thefloor for existing IGCC units. However, 

we have no detailed data to support this 

position at this time and, thus, are not 

proposing a beyond-the-floor limit for 

existing IGCC units. EPA requests 

comments on whether the use of this or 

other control techniques have been 

demonstrated to consistently achieve 

emission levels that are lower than 

levels from similar sources achieving 

the proposed existing MACT floor level 

of control. Comments should include 

information on emissions, control 

efficiencies, reliability, current 

demonstrated applications, and costs, 

including retrofit costs. 

We considered proposing beyond-thefloor requirements for Hg in the other 

subcategories and for the other HAP in 

all of the subcategories. Activated 

carbon injection is used on EGUs 

designed for coal greater than or equal 

to 8,300 Btu/lb and, therefore, its effect 

on Hg removal has already been 

accounted for in the MACT floor. 

Further, EPA has no information that 

would indicate that ACI would provide 

significantly lower emission levels 

given the MACT floor Hg standard, and 

it is also possible that existing sources 

in this subcategory will utilize ACI to 

comply with the MACT floor limit. 

Activated carbon injection has not been 

demonstrated on liquid oil-fired EGUs. 

Similarly, ACI has not been 

demonstrated on solid oil-derived fuelfired EGUs. EPA has no information that 

would indicate that ACI would provide 

significantly lower Hg emission levels 

on units operating at the level of the 

MACT floor. For the non-Hg metallic 

and acid gas HAP, there is no 

technology that would achieve 

additional control over that being 

shown by units making up the floor. 

Additional combinations of controls 

(e.g., dual FGD systems in series) could 

be used but at a significant additional 

cost and, given the MACT floor level of 

control, a minimal additional reduction 

in HAP emissions. For the organic HAP, 

EPA is not aware of any measures 

beyond those proposed here that would 

result in lower emissions. Therefore, 

EPA is not proposing beyond-the-floor 

limitations other than as noted above. 

F. Should EPA consider different 

subcategories? 

EPA has attempted to identify 

subcategories that provide the most 

reasonable basis for grouping and 

estimating the performance of generally 

similar units using the available data. 

We believe that the subcategories we 

selected are appropriate. 

EPA requests comments on whether 

additional or different subcategories 

should be considered. Comments 

should include detailed information 

regarding why a new or different 

subcategory is appropriate (based on the 

available data and on the statutory 

constraint of ‘‘class, type or size’’), how 

EPA should define any additional and/ 

or different subcategories, how EPA 

should account for varied or changing 

fuel mixtures, and how EPA should use 

the available data to determine the 

MACT floor for any new or different 

subcategories. 

G. How did EPA determine the proposed 

emission limitations for new EGUs? 

All standards established pursuant to 

CAA section 112 must reflect MACT, 

the maximum degree of reduction in 

emissions of air pollutants that the 

Administrator, taking into consideration 

the cost of achieving such emissions 

reductions, and any nonair quality 

health and environmental impacts and 

energy requirements, determines is 

achievable for each category. The CAA 

specifies that MACT for new EGUs shall 

not be less stringent than the emission 

control that is achieved in practice by 

the best-controlled similar source. This 

minimum level of stringency is the 

MACT floor for new units. However, 

EPA may not consider costs or other 

impacts in determining the MACT floor. 

EPA must consider cost, nonair quality 

health and environmental impacts, and 

energy requirements in connection with 

any standards that are more stringent 

than the MACT floor (beyond-the-floor 

controls). 

H. How did EPA determine the MACT 

floor for new EGUs? 

Similar to the MACT floor process 

used for existing EGUs, the approach for 

determining the MACT floor must be 

based on available emissions test data. 

Using such an approach, we calculated 

the MACT floor for a subcategory of 

sources by ranking the 2010 ICR 

emissions data from EGUs within the 

subcategory from lowest to highest (on 

a lb/MMBtu basis) to identify the best 

controlled similar source. The MACT 

floor limitations for each of the HAP 

and HAP surrogates (PM, Hg, and HCl) 

are calculated based on the performance 

(numerical average) of the lowest 

emitting (best controlled) source for 

each pollutant in each of the 

subcategories. 

The MACT floor limitations for new 

sources were calculated using the same 

formula as was used for existing sources 

with one exception. For the new source 

calculations, the results of the three 

individual emission test runs were used 


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instead of the 3-run average that was 

used in determining the existing-source 

MACT floor. This was done to be able 

to provide some measure of variability. 

As previously discussed, we account for 

variability of the best-controlled source 

in setting floors, not only because 

variability is an element of performance, 

but because it is reasonable to assess 

best performance over time. We 

calculated the MACT floor based on the 

UPL (upper 99th percentile) as 

described earlier from the average 

performance of the best controlled 

similar source, Student’s t-factor, and 

the total variability of the bestcontrolled source. 

This approach reasonably ensures that 

the emission limit selected as the MACT 

floor adequately represents the average 

level of control actually achieved by the 

best controlled similar source, 

considering ordinary operational 

variability. 

A detailed discussion of the MACT 

floor methodology is presented in the 

MACT Floor Memo in the docket. 

The approach that we use to calculate 

the MACT floors for new sources is 

somewhat different from the approach 

that we use to calculate the MACT 

floors for existing sources. Although the 

MACT floors for existing units are 

intended to reflect the performance 

achieved by the average of the best 

performing 12 percent of sources, the 

MACT floors for new units are meant to 

reflect the emission control that is 

achieved in practice by the best 

controlled similar source. Thus, for 

existing units, we are concerned about 

estimating the central tendency of a set 

of multiple units, whereas for new 

units, we are concerned about 

estimating the level of control that is 

representative of that achieved by a 

single best controlled source. As with 

the analysis for existing sources, the 

new EGU analysis must account for 

variability. 

1. Determination of MACT for the FuelBorne HAP for New Sources 

In developing the MACT floor for the 

fuel-borne HAP (PM, HCl, and Hg), as 

described earlier, we are using PM as a 

surrogate for non-Hg metallic HAP and 

HCl as a surrogate for the acid gases 

(except for the liquid oil-fired 

subcategory). Table 13 of this preamble 

presents for each subcategory and fuelborne HAP the average emission level of 

the best controlled similar source and 

the MACT floor which accounts for 

variability (99 percent UPL). 

TABLE 13—SUMMARY OF MACT FLOOR RESULTS FOR NEW SOURCES

Subcategory Parameter PM HCl Mercury 

Coal-fired unit designed for coal ≥ 8,300 

Btu/lb.

Avg. of top performer .............................. 0.03 lb/MWh ....... 0.2 lb/GWh ......... 0.00001 lb/GWh. 

99% UPL of top performer (test runs) .... 0.050 lb/MWh ..... 0.30 lb/GWh ....... 0.000010 lb/ 

GWh. 

Coal-fired unit designed for coal < 8,300 

Btu/lb.

Avg. of top performer .............................. 0.03 lb/MWh ....... 0.2 lb/GWh ......... 0.02 lb/GWh. 

99% UPL of top performer (test runs) .... 0.050 lb/MWh ..... 0.30 lb/GWh ....... 0.040 lb/GWh. 

IGCC ........................................................ Avg. of top performer .............................. N/A ..................... N/A ..................... N/A. 

99% UPL of top performer (test runs) .... 0.050 lb/MWh * ... 0.30 lb/GWh * ..... 0.000010 lb/ 

GWh.* 

Solid oil-derived ....................................... Avg. of top performer .............................. 0.04 lb/MWh ....... 0.0003 lb/MWh ... 0.0007 lb/GWh. 

99% UPL of top performer (test runs) .... 0.050 lb/MWh ..... 0.00030 lb/MWh 0.0020 lb/GWh. 

Total metals ** HCl Mercury 

Liquid oil .................................................. Avg. of top performer .............................. 0.00009 lb/ 

MMBtu.

0.0002 lb/MWh ... NA. 

99% UPL of top performer (test runs) .... 0.00040 lb/ 

MMBtu.

0.00050 lb/MWh NA. 

* Beyond-the-floor as discussed elsewhere. 

** Includes Hg. 

NA = Not applicable. 

2. Determination of the Work Practice 

Standard 

We are proposing a work practice 

standards for non-dioxin/furan organic 

and dioxin/furan organic HAP under 

CAA section 112(h) that would require 

the implementation of an annual 

performance test program for new EGUs. 

This proposal for new EGUs is based on 

the same reasons discussed previously 

for existing EGUs. That is, the measured 

emissions from EGUs of these HAP are 

routinely below the detection limits of 

the EPA test methods, and, as such, EPA 

considers it impracticable to reliably 

measure emissions from these units. 

Thus, the work practice discussed 

above for existing EGUs is being 

proposed to limit the emissions of nondioxin/furan organic and dioxin/furan 

organic HAP for new EGUs. 

We request comments on this 

approach. 

I. How did EPA consider beyond-thefloor for new units? 

The MACT floor level of control for 

new EGUs is based on the emission 

control that is achieved in practice by 

the best controlled similar source within 

each of the subcategories. No 

technologies were identified that would 

achieve HAP reduction greater than the 

new source floors for the subcategories, 

except for multiple controls in series 

(e.g., multiple FFs) which we consider 

to be unreasonable from a cost 

perspective. 

Fuel switching to natural gas is a 

potential regulatory option beyond the 

new source floor level of control that 

would reduce HAP emissions. However, 

natural gas supplies are not available in 

some areas. Thus, this potential control 

option may be unavailable to many 

sources in practice. Limited emissions 

reductions in combination with the high 

cost of fuel switching and 

considerations about the availability 

and technical feasibility of fuel 

switching makes this an unreasonable 

regulatory option that was not 

considered further. As discussed above, 

the uncertainties associated with nonair 

quality health and environmental 

impacts also argue against determining 

that fuel switching is reasonable 

beyond-the-floor option. In addition, 


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160Letter from Matthew Stuckey, State of Indiana, 

to Mack Sims, Duke Energy Indiana. Operating 

permit fo Edwardsport Generating Station IGCC. 

Undated. 

161 DOE. Overview—Bituminous & Natural Gas to 

Electricity; Overview of Bituminous Baseline Study. 

From: Cost and Performance Baseline for Fossil 

Energy Plants, Vol. 1, DOE/NETL–2007/1281, May 

2007. 

162Before considering whether to exercise her 

discretion under CAA section 112(d)(4) for a 

particular pollutant, the Administrator must first 

conclude that a health threshold has been 

established for the pollutant. 

163Hydrogen chloride can serve as a surrogate for 

the other acid gases in a technology-based MACT 

standard, because the control technology that 

would be used to control HCl would also reduce the 

other acid gases. By contrast, HCl would not be an 

appropriate surrogate for a health-based emission 

standard that is protective against the potential 

adverse health effects from the other acid gases, 

because these gases (e.g., HF) can act on biological 

organisms in a different manner than HCl, and each 

of the acid gases affects human health with a 

different dose-response relationship. 

even if we determined that natural gas 

supplies were available in all regions, 

we would still not adopt this fuel 

switching option because it would 

effectively prohibit new construction of 

coal-fired EGUs and we do not think 

that is a reasonable approach to 

regulating HAP emissions from EGUs. 

Although, as discussed earlier for 

existing EGUs, EPA is proposing to 

establish a beyond-the-floor emission 

limit for Hg for existing EGUs designed 

to burn a nonagglomerating fuel having 

a calorific value (moist, mineral matterfree basis) of 19,305 kJ/kg (8,300 Btu/lb) 

or less in a EGU with a height-to-depth 

ratio of 3.82 or greater, EPA is not 

proposing to go beyond-the-floor for 

new EGUs in this subcategory. The 

proposed emission limit of 0.04 lb/GWh 

for new EGUs in this subcategory is 

based on use of ACI on a new unit and, 

we believe, reflects a level of 

performance achievable and, as noted 

above, no technologies were identified 

that would achieve HAP reduction 

greater than the new source floors for 

the subcategories, except for multiple 

controls in series (e.g., multiple FFs) 

which we consider to be unreasonable 

from a cost perspective. 

As discussed earlier, because of a lack 

of data, EPA is not proposing beyondthe-floor emission limits for existing 

IGCC units. However, EPA believes that 

the new-source limits derived from the 

data obtained from the two operating 

IGCC units are not representative of 

what a new IGCC unit could achieve. 

Therefore, EPA looked to the permit 

issued for the Duke Energy Edwardsport 

IGCC facility currently under 

construction.160 The permitted limits for 

this unit are similar to the limits derived 

from the existing units. Because of 

advances in technology, EPA does not 

believe that even these permitted levels 

are representative of what a modern 

IGCC unit could achieve. The emissions 

from IGCC units are normally predicted 

to be similar to or lower than those from 

traditional pulverized coal (PC) boilers. 

For example, DOE projects that future 

IGCC units will be able to meet a PM 

(filterable) emissions limit of 0.0071 lb/ 

MMBtu, a SO2 emissions limit of 0.0127 

lb/MMBtu, and a Hg emissions limit of 

0.571 lb/TBtu.161 Therefore, we are 

proposing that the new-source limits for 

new IGCC units be identical to those of 

new coal-fired units designed for coal 

greater than or equal to 8,300 Btu/lb. 

However, EPA has no information upon 

which to base the costs and non-air 

quality health, environmental, and 

energy impacts of this proposed 

approach. EPA solicits comment on this 

approach. Commenters should provide 

data that support their comment, 

including costs, emissions data, or 

engineering analyses. 

Similarly, for the reasons discussed 

earlier for existing EGUs, EPA is not 

proposing any other beyond-the-floor 

emission limitations. EPA requests 

comments on whether the use of any 

control techniques have been 

demonstrated to consistently achieve 

emission levels that are lower than 

levels from similar sources achieving 

the proposed new-source MACT floor 

levels of control. Comments should 

include information on emissions, 

control efficiencies, reliability, current 

demonstrated applications, and costs, 

including retrofit costs. 

J. Consideration of Whether To Set 

Standards for HCl and Other Acid Gas 

HAP Under CAA Section 112(d)(4) 

We are proposing to set a 

conventional MACT standard for HCl 

and, for the reasons explained 

elsewhere, are proposing that the HCl 

limit also serve as a surrogate for other 

acid gas HAP. We also considered 

whether it was appropriate to exercise 

our discretionary authority to establish 

health-based emission standards under 

CAA section 112(d)(4) for HCl and each 

of the other relevant HAP acid gases: 

Cl2, HF, SeO2, and HCN 162 (because if 

it were regulated under CAA section 

112(d)(4), HCl may no longer be the 

appropriate surrogate for these other 

HAP).163 This section sets forth the 

requirements of CAA section 112(d)(4); 

our analysis of the information available 

to us that informed the decision on 

whether to exercise discretion; 

questions regarding the application of 

CAA section 112(d)(4); and our 

explanation of how this case relates to 

prior decisions EPA has made under 

CAA section 112(d)(4) with respect to 

HCl. 

As a general matter, CAA section 

112(d) requires MACT standards at least 

as stringent as the MACT floor to be set 

for all HAP emitted from major sources. 

However, CAA section 112(d)(4) 

provides that for HAP with established 

health thresholds, the Administrator has 

the discretionary authority to consider 

such health thresholds when 

establishing emission standards under 

CAA section 112(d). This provision is 

intended to allow EPA to establish 

emission standards other than 

conventional MACT standards, in cases 

where a less stringent emission standard 

will still ensure that the health 

threshold will not be exceeded, with an 

ample margin of safety. In order to 

exercise this discretion, EPA must first 

conclude that the HAP at issue has an 

established health threshold and must 

then provide for an ample margin of 

safety when considering the health 

threshold to set an emission standard. 

It is clear the Administrator may 

exercise her discretionary authority 

under CAA section 112(d)(4) only with 

respect to pollutants with a health 

threshold. Where there is an established 

threshold, the Administrator interprets 

CAA section 112(d)(4) to allow her to 

weigh additional factors, beyond any 

established health threshold, in making 

a judgment whether to set a standard for 

a specific pollutant based on the 

threshold, or instead follow the 

traditional path of developing a MACT 

standard after determining a MACT 

floor. In deciding whether to exercise 

her discretion for a threshold pollutant 

for a given source category, the 

Administrator interprets CAA section 

112(d)(4) to allow her to take into 

account factors such as the following: 

the potential for cumulative adverse 

health effects due to concurrent 

exposure to other HAP with similar 

biological endpoints, from either the 

same or other source categories, where 

the concentration of the threshold 

pollutant emitted from the given source 

category is below the threshold; the 

potential impacts on ecosystems of 

releases of the pollutant; and reductions 

in criteria pollutant emissions and other 

co-benefits that would be achieved by a 

MACT standard. Each of these factors is 

directly relevant to the health and 

environmental outcomes at which CAA 

section 112 is fundamentally aimed. If 

the Administrator does determine that it 

is appropriate to set a standard based on 

a health threshold, she must develop 

emission standards that will ensure the 

public will not be exposed to levels of 

the pertinent HAP in excess of the 


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164EPA has not classified HF, Cl2, SeO2, or HCN 

with respect to carcinogenicity. However, at this 

time the Agency is not aware of any data that would 

suggest any of these HAP are carcinogens. 

165 ‘‘Sensitive subgroups’’ may refer to particular 

life stages, such as children or the elderly, or to 

those with particular medical conditions, such as 

asthmatics. 

166California EPA considered acute toxicity and 

established a 1-hour reference exposure level (REL) 

of 2.1 milligrams per cubic meter (mg/m3). An REL 

is the concentration level at or below which no 

adverse health effects are anticipated for a specified 

exposure duration. RELs are designed to protect the 

most sensitive individuals in the population by the 

inclusion of margins of safety. 

167 Dockery DW, Cunningham J, Damokosh AI, 

Neas LM, Spengler JD, Koutrakis P, Ware JH, 

Raizenne M, Speizer FE. 1996. Health Effects of 

Acid Aerosols on North American Children: 

Respiratory Symptoms. Environmental Health 

Perspectives 104(5):500–504; Raizenne M, Neas LM, 

Damokosh AI, Dockery DW, Spengler JD, Koutrakis 

P, Ware JH, Speizer FE. 1996. Health Effects of Acid 

Aerosols on North American Children: Pulmonary 

Function. Environmental Health Perspectives 

104(5):506–514. 

168Evans, CD, Monteith, DT, Fowler, D, Cape, JN, 

and Brayshaw, S. Hydrochloric Acid: an Overlooked 

Driver of Environmental Change, Env. Sci. 

Technol., DOI: 10.1021/es10357u. 

health threshold, with an ample margin 

of safety. 

EPA has exercised its discretionary 

authority under CAA section 112(d)(4) 

in a handful of prior rules setting 

emissions standards for other major 

source categories, including the Boiler 

NESHAP issued in 2004, which was 

vacated on other grounds by the DC 

Circuit Court. In the Pulp and Paper 

NESHAP (63 FR 18765; April 15, 1998), 

and Lime Manufacturing NESHAP (67 

FR 78054; December 20, 2002), EPA 

invoked CAA section 112(d)(4) for HCl 

emissions for discrete units within the 

facility. In those rules, EPA concluded 

that HCl had an established health 

threshold (in those cases it was 

interpreted as the RfC for chronic 

effects) and HCl was not classified as a 

human carcinogen. In light of the 

absence of evidence of carcinogenic 

risk, the availability of information on 

non-carcinogenic effects, and the 

limited potential health risk associated 

with the discrete units being regulated, 

EPA concluded that it was appropriate 

to exercise its discretion under CAA 

section 112(d)(4) for HCl under the 

circumstances of those rules. EPA did 

not set an emission standard based on 

the health threshold; rather, the exercise 

of EPA’s discretion in those cases in 

effect exempted HCl from the MACT 

requirement. In more recent rules, EPA 

decided not to propose a health-based 

emission standard for HCl emissions 

under CAA section 112(d)(4) for 

Portland Cement facilities (75 FR 54970 

(September 9, 2010), and for Industrial, 

Commercial, and Institutional Boilers, 

(75 FR 32005; June 4, 2010 

proposal(major); the final major source 

rule was signed on February 21, 2011 

but has not yet been published). EPA 

has never implemented a NESHAP that 

used CAA section 112(d)(4) with respect 

to HF, Cl2, SeO2, or HCN.164

Because any emission standard under 

CAA section 112(d)(4) must consider 

the established health threshold level, 

with an ample margin of safety, in this 

rulemaking EPA has considered the 

adverse health effects of the HAP acid 

gases, beginning with HCl and including 

HF, Cl2, SeO2, and HCN. Research 

indicates that HCl is associated with 

chronic respiratory toxicity. In the case 

of HCl, this means that chronic 

inhalation of HCl can cause tissue 

damage in humans. Among other things, 

it is corrosive to mucous membranes 

and can cause damage to eyes, nose, 

throat, and the upper respiratory tract as 

well as pulmonary edema, bronchitis, 

gastritis, and dermatitis. Considering 

this respiratory toxicity, EPA has 

established a chronic RfC for the 

inhalation of HCl of 20 micrograms per 

cubic meter (μg/m3). An RfC is defined 

as an estimate (with uncertainty 

spanning perhaps an order of 

magnitude) of a continuous inhalation 

exposure to the human population 

(including sensitive subgroups 165) that 

is likely to be without an appreciable 

risk of deleterious effects during a 

lifetime. The development of the RfC for 

HCl reflected data only on its chronic 

respiratory toxicity. It did not take into 

account effects associated with acute 

exposure,166 and, in this situation, the 

IRIS health assessment did not evaluate 

the potential carcinogenicity of HCl (on 

which there are very limited studies). 

As a reference value for a single 

pollutant, the RfC also did not reflect 

any potential cumulative or synergistic 

effects of an individual’s exposure to 

multiple HAP or to a combination of 

HAP and criteria pollutants. As the RfC 

calculation focused on health effects, it 

did not take into account the potential 

environmental impacts of HCl. 

With respect to the potential health 

effects of HCl, we note the following: 

(1) Chronic exposure to 

concentrations at or below the RfC is not 

expected to cause chronic respiratory 

effects; 

(2) Little research has been conducted 

on its carcinogenicity. The one 

occupational study of which we are 

aware found no evidence of 

carcinogenicity; 

(3) There is a significant body of 

scientific literature addressing the 

health effects of acute exposure to HCl 

(for a summary, see California Office of 

Health Hazard Assessment, 2008. Acute 

Toxicity Summary for Hydrogen 

Chloride, http://www.oehha.ca.gov/air/ 

hot_spots/2008/ 

AppendixD2_final.pdf#page=112 EPA, 

2001). In addition, we note that several 

researchers have shown associations 

between acid gases and reduced lung 

function and asthma in North American 

children.167 However, we currently lack 

information on the peak short-term 

emissions of HCl from EGUs, which 

might allow us to determine whether a 

chronic health-based emission standard 

for HCl would ensure that acute 

exposures will not pose any health 

concerns, and; 

(4) We are aware of no studies 

explicitly addressing the toxicity of 

mixtures of HCl with other respiratory 

irritants. However, many of the other 

HAP (and criteria pollutants) emitted by 

EGUs also are respiratory irritants, and 

in the absence of information on 

interactions, EPA assumes an additive 

cumulative effect (Supplementary 

Guidance for Conducting Health Risk 

Assessment of Chemical Mixtures. 

http://cfpub.epa.gov/ncea/cfm/

recordisplay.cfm?deid=20533). The fact 

that EGUs can be located in close 

proximity to a wide variety of industrial 

facilities makes predicting and assessing 

all possible mixtures of HCl and other 

emitted air pollutants difficult, if not 

impossible. 

In addition to potential health 

impacts, the Administrator also has 

evaluated the potential for 

environmental impacts when 

considering whether to exercise her 

discretion under CAA section 112(d)(4). 

When HCl gas encounters water in the 

atmosphere, it forms an acidic solution 

of hydrochloric acid. In areas where the 

deposition of acids derived from 

emissions of sulfur and NOX are causing 

aquatic and/or terrestrial acidification, 

with accompanying ecological impacts, 

the deposition of hydrochloric acid 

could exacerbate these impacts. Recent 

research 168 has suggested that 

deposition of airborne HCl has had a 

greater impact on ecosystem 

acidification than previously thought, 

although direct quantification of these 

impacts remains an uncertain process. 

We maintain it is appropriate to 

consider potential adverse 

environmental effects in addition to 

adverse health effects when setting an 

emission standard for HCl under CAA 

section 112(d)(4). 

Because the statute requires an ample 

margin of safety, it would be reasonable 

to set any CAA section 112(d)(4) 

emission standard for a pollutant with 

a health threshold at a level that at least 


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169See S. Rep. No. 101–228, 101st Cong. 1st sess. 

At 172. 

170For those facilities modeled, the hazard index 

for HCl ranged from 0.05 to 0.005 (see Non-Hg Case 

Study Chronic Inhalation Risk Assessment for the 

Utility MACT ‘‘Appropriate and Necessary’’ 

Analysis in the docket). 

assures that persons exposed to 

emissions of the pollutant would not 

experience the adverse health effects on 

which the threshold is based due to 

sources in the controlled category or 

subcategory. In the case of this proposed 

rulemaking, we have concluded that we 

do not have sufficient information at 

this time to establish what the healthbased emission standards would be for 

HCl or the other acid gases from EGUs 

alone, much less for EGUs and other 

sources of acid gas HAP located at or 

near facilities with EGUs. 

Finally, we considered the fact that 

setting conventional MACT standards 

for HCl as well as PM (as a surrogate for 

HAP metals) would result in significant 

reductions in emissions of other 

pollutants, most notably SO2, PM, and 

other non-HAP acid gases (e.g., 

hydrogen bromide) and would likely 

also result in additional reductions in 

emissions of Hg and other HAP metals 

(e.g., Se). The additional reductions of 

SO2 alone attributable to the proposed 

limit for HCl are estimated to be 2.1 

million tons in the third year following 

promulgation of the proposed HCl 

standard. These are substantial 

reductions with substantial public 

health benefits. Although NESHAP may 

directly address only HAP, not criteria 

pollutants, Congress did recognize, in 

the legislative history to CAA section 

112(d)(4), that NESHAP would have the 

collateral benefit of controlling criteria 

pollutants as well and viewed this as an 

important benefit of the air toxics 

program.169 Therefore, even where EPA 

concludes a HAP has a health threshold, 

the Agency may consider the collateral 

benefits of controlling criteria pollutants 

as a factor in determining whether to 

exercise its discretion under CAA 

section 112(d)(4). 

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 of setting a conventional 

MACT standard for HCl and the other 

acid gas HAP, the Administrator is 

proposing not to exercise her discretion 

to use CAA section 112(d)(4). 

This conclusion is not contrary to 

EPA’s prior decisions noted earlier 

where we found it appropriate to 

exercise the discretion to invoke the 

authority in CAA section 112(d)(4) for 

HCl, because the circumstances in this 

case differ from previous 

considerations. EGUs differ from the 

other source categories for which EPA 

has exercised its authority under CAA 

section 112(d)(4) in ways that affect 

consideration of any health threshold 

for HCl. EGUs are much more likely to 

be significant emitters of acid gas HAP 

and non-HAP than are other source 

categories. In fact, they are the largest 

anthropogenic emitter of HCl and HF in 

the U.S, emitting roughly half of the 

estimated nationwide total HCl and HF 

emissions in 2010. Our case study 

analyses of the chronic impacts of EGUs 

did not indicate any significant 

potential for them to cause any 

exceedances of the chronic RfC for HCl 

due to their emissions alone.170

However, we do not have adequate 

information on the other acid gas HAP 

to include them in our analysis, and did 

not consider their impacts in concert 

with other emitters of HCl (such as IB 

units) to develop estimates of 

cumulative exposures to HCl and other 

acid gas HAP in the vicinity of EGUs. In 

addition, EGUs may be located at 

facilities in heavily populated urban 

areas where many other sources of HAP 

exist. These factors make an analysis of 

the health impact of emissions from 

these sources on the exposed population 

significantly more complex than for 

many other source categories, and, 

therefore, make it more difficult to 

establish an ample margin of safety 

without significantly more information. 

Absent the information necessary to 

provide a credible basis for developing 

alternative health-based emission 

standards for all acid gases, and for all 

the other reasons discussed above, EPA 

is choosing not to exercise its discretion 

under CAA section 112(d)(4) for these 

pollutants from EGUs. 

K. How did we select the compliance 

requirements? 

We are proposing testing, monitoring, 

notification, and recordkeeping 

requirements that are adequate to assure 

continuous compliance with the 

requirements of this proposed rule. 

These requirements are described 

elsewhere in this preamble. We selected 

these requirements based upon our 

determination of the information 

necessary to ensure that the emission 

standards and work practices are being 

followed and that emission control 

devices and equipment are maintained 

and operated properly. These proposed 

requirements ensure compliance with 

this proposed rule without imposing a 

significant additional burden for units 

that must implement them. 

We are proposing that units using 

continuous monitoring systems for PM, 

HCl, and Hg demonstrate initial 

compliance by performance testing for 

non-Hg HAP metals and the surrogate 

PM, for HCl and its surrogate SO2, and 

for Hg, and then to perform subsequent 

performance testing every 5 years for 

non-Hg HAP metals and PM and for HCl 

and SO2. To ensure continuous 

compliance with the proposed Hg 

emission limits in-between the 

performance tests, this proposed rule 

would require coal-fired units to use 

either CEMS or sorbent trap monitoring 

systems, with an option for very low 

emitters to use a less rigorous method 

based on periodic stack testing. These 

requirements are found in proposed 

Appendix A to 40 CFR part 63, subpart 

UUUUU. For PM and HCl, affected units 

that elect to install CEMS would use the 

CEMS to demonstrate continuous 

compliance. However, units equipped 

with devices that control PM and HCl 

emissions but do not elect to use CEMS, 

would determine suitable parameter 

operating limits, to monitor those 

parameters on a continuous basis, and 

to conduct emissions testing every other 

month. Units combusting liquid oil on 

a limited basis would, upon request and 

approval, be allowed to determine limits 

for metals, chlorine, and Hg 

concentrations in fuel and to measure 

subsequent fuel metals, chlorine, and 

Hg concentrations monthly; and low 

emitting units would be allowed to 

determine limits for metals, chlorine, 

and Hg concentrations in fuel and to 

measure subsequent fuel metals, 

chlorine, and Hg concentrations 

monthly. 

Additionally, this proposed rule 

would require annual maintenance be 

performed so that good combustion 

continues. Such an annual check will 

serve to ensure that dioxins, furans, and 

other organic HAP emissions continue 

to be at or below MDLs. 

We evaluated the feasibility and cost 

of applying PM CEMS to EGUs. Several 

electric utility companies in the U.S. 

have now installed or are planning to 

install PM CEMS. In recognition of the 

fact that PM CEMS are commercially 

available, EPA developed and 

promulgated PSs for PM CEMS (69 FR 

1786, January 12, 2004). Performance 

Specifications for PM CEMS are 

established under PS 11 in appendix B 

to 40 CFR part 60 for evaluating the 

acceptability of a PM CEMS used for 

determining compliance with the 

emission standards on a continuous 

basis. For PM CEMS monitoring, initial 

costs were estimated to be $261,000 per 


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unit and annualized costs were 

estimated to be $91,000 per unit. We 

determined that requiring PM CEMS for 

EGUs combusting coal or oil is a 

reasonable monitoring option. We are 

requesting comment on the application 

of PM CEMS to EGUs, and the use of 

data from such systems for compliance 

determinations under this proposed 

rule. 

Table 14 holds preliminary cost 

information. Note that these costs are 

based on 2010 ICR emissions test 

estimates and on values in EPA’s 

monitoring costs assessment tool. 

Particulate matter and metals and SO2

and HCl testing includes surrogacy 

testing initially and every 5 years, 

parameter monitoring includes testing 

every two months, and fuel content 

monitoring includes annual testing. 

TABLE 14—COST INFORMATION

Initial costs, 

$K 

Annual costs, 

$K 

Metals 

PM CEMS ................................................................. 261 91 

Fabric filter ................................................................ 61 109 

ESP ........................................................................... 59 114 

Acid Gases 

SO2 CEMS ................................................................ 232 66 None if existing CEMS used. 

HCl CEMS ................................................................ 233 57 

Dry sorbent injection ................................................. 10 144 Plus material costs. 

Wet scrubber ............................................................ 9 143 

Mercury 

Hg CEMS .................................................................. 271 110 

Sorbent traps ............................................................ 23 128 Minimum of 52 traps and analysis per year. 

Fuel analysis ............................................................. 10 49 

Dioxin/furan and non-dioxin/furan organic HAP 

Tune up .................................................................... 17 3 

The Agency is seeking comment on 

the cost information presented above. 

The commenters are encouraged to 

provide detailed information and data 

that will help the Agency refine its cost 

estimates for this rulemaking. 

The majority of test methods that this 

proposed rule would require for the 

performance stack tests have been 

required under many other EPA 

standards. Three applicable voluntary 

consensus standards were identified: 

American Society of Mechanical 

Engineers (ASME) Performance Test 

Code (PTC) 19–10–1981–Part 10, ‘‘Flue 

and Exhaust Gas Analyses,’’ a manual 

method for measuring the oxygen, CO2, 

and CO content of exhaust gas; ASTM 

Z65907, ‘‘Standard Method for Both 

Speciated and Elemental Mercury 

Determination,’’ a method for Hg 

measurement; and ASTM Method 

D6784–02 (Ontario Hydro), a method for 

measuring Hg. The majority of 

emissions tests upon which the 

proposed emission limitations are based 

were conducted using these test 

methods. 

When a performance test is 

conducted, we are proposing that 

parameter operating limitations be 

determined during the tests. 

Performance tests to demonstrate 

compliance with any applicable 

emission limitations are either stack 

tests or fuel analysis or a combination 

of both. 

To ensure continuous compliance 

with the proposed emission limitations 

and/or operating limits, this proposed 

rule would require continuous 

parameter monitoring of control devices 

and recordkeeping. We selected the 

following requirements based on 

reasonable cost, ease of execution, and 

usefulness of the resulting data to both 

the owners or operators and EPA for 

ensuring continuous compliance with 

the emission limitations and/or 

operating limits. 

We are proposing that certain 

parameters be continuously monitored 

for the types of control devices 

commonly used in the industry. These 

parameters include pH, pressure drop 

and liquid flow rate for wet scrubbers; 

and sorbent injection rate for dry 

scrubbers and DSI systems. You must 

also install a BLDS for FFs. These 

monitoring parameters have been used 

in other standards for similar industries. 

The values of these parameters are 

established during the initial or most 

recent performance test that 

demonstrates compliance. These values 

are your operating limits for the control 

device. 

You would be required to set 

parameters based on 4-hour block 

averages during the compliance test, 

and demonstrate continuous 

compliance by monitoring 12-hour 

block average values for most 

parameters. We selected this averaging 

period to reflect operating conditions 

during the performance test to ensure 

the control system is continuously 

operating at the same or better level as 

during a performance test demonstrating 

compliance with the emission limits. 

To demonstrate continuous 

compliance with the emission and 

operating limits, you would also need 

daily records of the quantity, type, and 

origin of each fuel burned and hours of 

operation of the affected source. If you 

are complying with the chlorine fuel 

input option, you must keep records of 

the calculations supporting your 

determination of the chlorine content in 

the fuel. 

If a liquid oil-fired EGU elected to 

demonstrate compliance with the HCl or 

individual or total HAP metal limit by 

using fuel which has a statistically 

lower pollutant content than the 

emission limit, we are proposing that 

the source’s operating limit is the 

emission limit of the applicable 

pollutant. Under this option, a source is 

not required to conduct performance 


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stack tests. If a source demonstrates 

compliance with the HCl, individual or 

total PM, or Hg limit by using fuel with 

a statistically higher pollutant content 

than the applicable emission limit, but 

performance tests demonstrate that the 

source can meet the emission 

limitations, then the source’s operating 

limits are the operating limits of the 

control device (if used) and the fuel 

pollutant content of the fuel type/ 

mixture burned. 

This proposed rule would specify the 

testing methodology and procedures 

and the initial and continuous 

compliance requirements to be used 

when complying with the fuel analysis 

options. Fuel analysis tests for total 

chloride, gross calorific value, Hg, 

individual and total HAP metal, sample 

collection, and sample preparation are 

included in this proposed rule. 

If you are a liquid oil-fired EGU and 

elect to comply based on fuel analysis, 

you will be required to statistically 

analyze, using the z-test, the data to 

determine the 90th percentile 

confidence level. It is the 90th 

percentile confidence level that is 

required to be used to determine 

compliance with the applicable 

emission limit. The statistical approach 

is required to assist in ensuring 

continuous compliance by statistically 

accounting for the inherent variability 

in the fuel type. 

We are proposing that a source be 

required to recalculate the fuel pollutant 

content only if it burns a new fuel type 

or fuel mixture and conduct another 

performance test if the results of 

recalculating the fuel pollutant content 

are higher than the level established 

during the initial performance test. 

L. What alternative compliance 

provisions are being proposed? 

We are proposing that owners and 

operators of existing affected sources 

may demonstrate compliance by 

emissions averaging for units at the 

affected source that are within a single 

subcategory. 

As part of EPA’s general policy of 

encouraging the use of flexible 

compliance approaches where they can 

be properly monitored and enforced, we 

are including emissions averaging in 

this proposed rule. Emissions averaging 

can provide sources the flexibility to 

comply in the least costly manner while 

still maintaining 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 affected 

source. 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. 

Emissions averaging would allow 

owners and operators of an affected 

source to demonstrate that the source 

complies with the proposed emission 

limits by averaging the emissions from 

an individual affected unit that is 

emitting above the proposed emission 

limits with other affected units at the 

same facility that are emitting below the 

proposed emission limits and that are 

within the same subcategory. 

This proposed rule includes an 

emissions averaging compliance 

alternative because emissions averaging 

represents an equivalent, more flexible, 

and less costly alternative to controlling 

certain emission points to MACT levels. 

We have concluded that a limited form 

of averaging could be implemented that 

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. 

EPA has concluded that it is 

permissible to establish within a 

NESHAP a unified compliance regimen 

that permits averaging within an 

affected source across individual 

affected units subject to the standard 

under certain conditions. 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 NESHAP will not be greater under 

the averaging mechanism than it could 

be if each individual affected unit 

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 unit, and the statutory 

requirement that the MACT standard 

reflect the maximum achievable 

emissions reductions is, therefore, fully 

effectuated. 

In past rulemakings, 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. 

This proposed rule would fully satisfy 

each of these criteria. First, emissions 

averaging would only be permitted 

between individual sources at a single 

existing affected source, and would only 

be permitted between individual 

sources subject to the proposed 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 is 

consistent with the CAA. In addition, 

this proposed rule would require each 

facility that intends to utilize emission 

averaging to submit an emission 

averaging plan, which provides 

additional assurance that the necessary 

criteria will be followed. In this 

emission averaging plan, the facility 

must include the identification of: (1) 

All units in the averaging group; (2) the 

control technology installed; (3) the 

process parameter that will be 

monitored; (4) the specific control 

technology or pollution prevention 

measure to be used; (5) the test plan for 

the measurement of the HAP being 

averaged; and (6) the operating 

parameters to be monitored for each 

control device. Upon receipt, the 

regulatory authority would not be able 

to approve an emission averaging plan 

containing averaging between emissions 

of different types of pollutants or 

between sources in different 

subcategories. 

This proposed rule would also 

exclude new affected sources from the 

emissions averaging provision. EPA 

believes emissions averaging is not 

appropriate for new affected sources 

because it is most cost effective to 

integrate state-of-the-art controls into 

equipment design and to install the 

technology during construction of new 

sources. One reason we allow emissions 

averaging is to give existing sources 

flexibility to achieve compliance at 

diverse points with varying degrees of 

add-on control already in place in the 

most cost-effective and technically 

reasonable fashion. This flexibility is 

not needed for new affected sources 

because they can be designed and 

constructed with compliance in mind. 

In addition, we seek comment on use 

of a discount factor when emissions 

averaging is used and on the appropriate 

value of a discount factor, if used. Such 

discount factors (e.g., 10 percent) have 

been used in previous NESHAP, 

particularly where there was variation 

in the types of units within a common 


jlentini on DSKJ8SOYB1PROD with PROPOSALS2
25054 Federal Register / Vol. 76, No. 85 / Tuesday, May 3, 2011 / Proposed Rules 

171Hazardous Organic NESHAP (59 FR 19425; 

April 22, 1994). 

172 In a letter to Senator Carper dated November 

3, 2010 (http://www.icac.com/files/public/ 

ICAC_Carper_Response_110310.pdf) David Foerter, 

the executive director of the Institute of Clean Air 

Companies (ICAC) explained that wet scrubber 

technology could be installed in 36 months, dry 

scrubber technology could be installed in 24 

months and dry sorbent injection could be installed 

in 12 months. Page 3. 

source category to ensure that the 

environmental benefit was being 

achieved. In this situation, however, the 

affected sources are more homogeneous, 

making emissions averaging a more 

straight-forward analysis. Further, with 

the monitoring and compliance 

provisions that are being proposed, 

there is additional assurance that the 

environmental benefit will be realized. 

Further, the emissions averaging 

provision would not apply to individual 

units if the unit 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. 

The emissions averaging provisions in 

this proposed 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.171

M. How did EPA determine compliance 

times for this proposed rule? 

CAA section 112 specifies the dates 

by which affected sources must comply 

with the emission standards. New or 

reconstructed units must be in 

compliance with this proposed rule 

immediately upon startup or [DATE 

THE FINAL RULE IS PUBLISHED IN 

THE FEDERAL REGISTER], whichever 

is later. Existing sources may be 

provided up to 3 years to comply with 

the final rule; if an existing source is 

unable to comply within 3 years, a 

permitting authority has the discretion 

to grant such a source up to a 1-year 

extension, on a case-by-case basis, if 

such additional time is necessary for the 

installation of controls. See section 

112(i)(3). We believe that 3 years for 

compliance is necessary to allow 

adequate time to design, install and test 

control systems that will be retrofitted 

onto existing EGUs, as well as obtain 

permits for the use of add-on controls. 

We believe that the requirements of 

the proposed rule can be met without 

adversely impacting electric reliability. 

Our analysis shows that the expected 

number of retirements is less than many 

have predicted and that these can be 

managed effectively with existing tools 

and processes for ensuring continued 

grid reliability. Further, the industry has 

adequate resources to install the 

necessary controls and develop the 

modest new capacity required within 

the compliance schedule provided for in 

the CAA. Although there are a 

significant number of controls that need 

to be installed, with proper planning, 

we believe that the compliance schedule 

established by the CAA can be met. 

There are already tools in place (such as 

integrated resource planning, and in 

some cases, advanced auctions for 

capacity) that ensure that companies 

adequately plan for, and markets are 

responsive to, future requirements such 

as the proposed rule. In addition, EPA 

itself has already begun reaching out to 

key stakeholders including not only 

sources with direct compliance 

obligations, but also groups with 

responsibility to assure an affordable 

and reliable supply of electricity 

including state Public Utility 

Commissions (PUC), Regional 

Transmission Organizations (RTOs), the 

National Electric Reliability Council 

(NERC), the Federal Energy Regulatory 

Commission (FERC), and DOE. EPA 

intends to continue these efforts during 

both the development and 

implementation of this proposed rule. It 

is EPA’s understanding that FERC and 

DOE will work with entities whose 

responsibility is to ensure an affordable, 

reliable supply of electricity, including 

state PUCs, RTOs, the NERC to share 

information and encourage them to 

begin planning for compliance and 

reliability as early as possible. This 

effort to identify and respond to any 

projected local and regional reliability 

concerns will inform decisions about 

the timing of retirements and other 

compliance strategies to ensure energy 

reliability. EPA believes that the ability 

of permitting authorities to provide an 

additional 1 year beyond the 3-year 

compliance time-frame as specified in 

CAA section 112, along with other 

compliance tools, ensures that the 

emission reductions and health benefits 

required by the CAA can be achieved 

while safeguarding completely against 

any risk of adverse impacts on 

electricity system reliability. Between 

proposal and final, EPA will work with 

DOE and FERC to identify any 

opportunities offered by the authorities 

and policy tools at the disposal of DOE 

and/or FERC that can be pursued to 

further ensure that the dual goals of 

substantially reducing the adverse 

public health impacts of power 

generation, as required by the CAA, 

while continuing to assure electric 

reliability is maintained. EPA also 

intends to continue to work with DOE, 

FERC, state PUCs, RTOs and power 

companies as this rule is implemented 

to identify and address any challenges 

to ensuring that both the requirements 

of the CAA and the need for a reliable 

electric system are met. 

In developing this proposed rule, EPA 

has performed specific analysis to assess 

the feasibility (e.g., ability of companies 

to install the required controls within 

the compliance time-frame) and 

potential impact of the proposed rule on 

reliability. 

With regards to feasibility, EPA used 

IPM to project what types of controls 

would need to be installed to meet the 

requirements of this proposed rule. This 

includes technologies to control acid 

gases (wet and dry scrubber technology 

and the use of sorbent injection), the Hg 

requirements (co-benefits from other 

controls such as scrubbers and FFs and 

Hg-specific controls such as ACI), the 

non-Hg metal requirements (upgrades 

and or replacements of existing 

particulate control devices), and other 

HAP emissions (GCP). 

Much of the power sector already has 

controls in place that remove significant 

amounts of acid gases. Today over 50 

percent of the power generation fleet 

has scrubbing technology installed and 

the industry is already working on 

installations to bring that number to 

nearly two-thirds of the fleet by 2015. 

Many of the remaining coal-fired units 

are smaller, burn lower sulfur coals, 

and/or do not operate in a base-load 

mode. Units with these types of 

characteristics are candidates to use DSI 

technology which takes significantly 

less time to install. Units that choose to 

install dry or wet scrubbing technology 

should be able to do so within the 

compliance schedule required by the 

CAA as this technology can be installed 

within the 3-year window.172 Notably, 

EPA does not project use of wet 

scrubbing technology to meet the 

requirements of this proposed rule and 

that is the technology that typically 

takes a longer time to install. 

For Hg control, those units that do not 

meet the requirements with existing 

controls have several options. 

Companies with installed scrubbers may 

be able to make modifications (such as 

the use of scrubber additives to enhance 

Hg control). Other companies may use 

supplemental controls such as ACI. 

These types of options all take 

significantly less than 3 years to install. 

Units that do not meet the non-Hg 

metal HAP requirements have several 

options such as upgrading existing 

particulate controls, installing 


jlentini on DSKJ8SOYB1PROD with PROPOSALS2
Federal Register / Vol. 76, No. 85 / Tuesday, May 3, 2011 / Proposed Rules 25055 

173Paul 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.bipartisan

policy.org/sites/default/files/Paul%20Sotkiewicz-

%20Panel%202_0.pdf, slide 6. 

174 Ibid—slide 5. 

supplemental particulate controls, or 

replacing existing particulate controls. 

These options can also be implemented 

in significantly less than 3 years. 

EPA projects that for acid gas control, 

companies will likely use dry scrubbing 

and sorbent injection technologies 

rather than wet scrubbing. For non-Hg 

metal HAP controls, EPA has assumed 

that companies with ESPs will likely 

upgrade them to FFs. As a number of 

units that were in the MACT floor for 

non-Hg HAP metals only had ESPs 

installed, this is likely a conservative 

assumption. For Hg, EPA projects that 

companies will comply through either 

the collateral reductions created by 

other controls (e.g., scrubber/SCR 

combination) or ACI. EPA has assessed 

the feasibility of installing these 

controls within the compliance window 

(see TSD) and believes that the controls 

can be reasonably installed within that 

time. Although EPA assessed the ability 

to install the controls in 3 years (and 

determined that the controls could be 

installed in that time-frame), this would 

require the control technology industry 

to ramp up quickly. Therefore, EPA also 

assessed a time-frame that would allow 

some installations to take up to 4 years. 

This time-frame is consistent with the 

CAA which allows permitting 

authorities the discretion to grant 

extensions to the compliance time-line 

of up to 1 year. This time-frame also 

allows for staggered installation of 

controls at facilities that need to install 

technologies on multiple units. 

Staggered installation allows companies 

to address such issues as scheduling 

outages at different units so that reliable 

power can be provided during these 

outage periods or 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). In other words, the additional 1- 

year extension would provide an 

additional two shoulder periods to 

schedule outages. It also provides 

additional opportunity to spread 

complex outages over multiple outage 

periods. EPA believes that while many 

units will be able to fully comply within 

3 years, the 4th 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. 

Permitting authorities are familiar 

with the operation of this provision 

because they have used it in 

implementing previous NESHAP. This 

extension can be used to address a range 

of reasons that installation schedules 

may take more than 3 years including: 

staggering installations for reliability or 

constructability purposes, or other sitespecific challenges that may arise 

related to source-specific construction 

issues, permitting, or local manpower or 

resource challenges. EPA is proposing 

that States consider applying this 

extension both to the installation of add 

on controls (e.g., a FF, or a dry scrubber) 

and the construction of on-site 

replacement power (e.g., a case when a 

coal unit is being shut down and the 

capacity is being replaced on-site by 

another cleaner unit such as a combined 

cycle or simple cycle gas turbine and 

the replacement process requires more 

than 3 years to accomplish). EPA 

believes that it is reasonable to allow the 

extension to apply to the replacement 

because EPA believes that building of 

replacement power could be considered 

‘‘installation of controls’’ at the facility. 

Because the phrase ‘‘installation of 

controls’’ could also be interpreted to 

apply only to changes made to an 

existing unit rather than the 

replacement of that existing unit with a 

new cleaner one, EPA takes comment on 

its proposal to allow the extension to 

apply to replacement power. 

EPA has also considered the impact 

that potential retirements under this 

proposed rule will have on reliability. 

When considering the impact that one 

specific action has on power plant 

retirements, it is important to 

understand that the economics that 

drive retirements are based on multiple 

factors including: Expected electric 

demand, cost of alternative generation, 

and cost of continuing to generate using 

an existing unit. EPA’s analysis shows 

that the lower cost of alternative 

generating sources (particularly the cost 

of natural gas), as well as reductions in 

demand, have a greater impact on the 

number of projected retirements than 

does the impact of the proposed rule. 

EPA’s assessment looked at the reserve 

margins in each of 32 subregions in the 

continental U.S. It shows that with the 

addition of very little new capacity, 

average reserve margins are significantly 

higher than required (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 transmission 

constraints, the number of retirements 

projected suggests that the magnitude of 

any local retirements should be 

manageable with existing tools and 

processes. Demand forecasts used were 

based on EIA projected demand growth. 

Reliability concerns caused by local 

transmission constraints can be 

addressed through a range of solutions 

including the development of new 

generation and/or demand side 

resources, and/or enhancements to the 

transmission system. 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 

large reserve margins, there are 

companies ready to implement supply 

side projects quickly. For instance, in 

the PJM Interconnection (an RTO) 

region, there are over 11,600 MW of 

capacity that have completed feasibility 

and impact studies and could be on-line 

by the third quarter of 2014.173 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 

Interconnection 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.174 Recent experience also 

shows that transmission upgrades to 

address reliability issues from plant 

closures can also occur in less than 3 

years. 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. 

EPA also examined the impact on 

reliability of unit outages to install 

control equipment. Because these 

outages usually occur in the shoulder 

months (outside summer or winter 

peaking periods) when demand is lower 

(and, thus, reserve margins are higher), 

the analysis showed that even with 

conservative estimates regarding the 

length of the outages and conservative 

estimates about how many outages 

occurred within a 1-year time-frame, 

reserve margins were maintained. With 

the potential for a 1-year compliance 

extension, outages can be further 

staggered, providing additional 

flexibility, even if some units require 

longer outages. 

Although EPA’s analysis shows that 

there is sufficient time and grid capacity 

to allow for compliance with the rule 

within the 3-year compliance window 


jlentini on DSKJ8SOYB1PROD with PROPOSALS2
25056 Federal Register / Vol. 76, No. 85 / Tuesday, May 3, 2011 / Proposed Rules 

175Cinergy Press Release, September 2nd, 2004, 

‘‘Cinergy Operating Companies to Reduce Power 

Plant Emissions, Improve Air Quality.’’ 

176 ICAC. 

177Paul M Sotkiewicz, PJM Interconnection, 

‘‘Consideration of Forthcoming Environmental 

Regulations in the Planning Process,’’ January 14, 

2011. 

178MISO Planning Advisory Committee, 

‘‘Proposed EPA Regulatory Impact Analysis,’’ 

November 23, 2010. 

(with the possibility of a 1-year 

extension), to achieve compliance in a 

timely fashion, EPA expects that sources 

will begin promptly, based upon this 

proposed rule, to evaluate, select, and 

plan to implement, source-specific 

compliance options. In doing so, we 

would expect sources to consider the 

following factors: if retirement is the 

selected compliance option, notifying 

any relevant RTO/ISO in advance in 

order to develop an appropriate 

shutdown plan that identifies any 

necessary replacement power 

transmission upgrades or other actions 

necessary to ensure consistent electric 

supply to the grid; if installation of 

control technologies is necessary, any 

source-specific space limitations, such 

that installation can be staggered in a 

timely fashion; and source-specific 

electric supply requirements, such that 

outages can be appropriately scheduled. 

Starting assessments early and 

considering the full range of options is 

prudent because it will help ensure that 

the requirements of this proposed rule 

are met as economically as possible and 

that power companies are able to 

provide reliable electric power. 

There is significant evidence that 

companies do in fact engage in such 

forward planning. For instance, in 

September of 2004 (approximately 6 

months before the CAIR and CAMR 

requirements were finalized); Cinergy 

announced that it had already begun a 

construction program to comply. This 

program involved not only preliminary 

engineering, but actual construction of 

scrubbers.175 Southern Company also 

began its engineering process well 

before those rules were finalized.176

Although EPA understands that not 

every generating company may commit 

to actual capital projects in advance of 

finalization of the rule, the CAIR 

experience shows that some companies 

do. Even if companies do not take the 

step of committing to the capital 

projects, there are actions that 

companies can take that are much less 

costly. Companies can analyze their 

unit-by-unit compliance options based 

on the proposed rule. This will put 

them in a position to begin construction 

of projects with the longest lead times 

quickly and will ensure that the 3-year 

compliance window (or 4 with 

extension from the permitting authority) 

can be met. 

It will also ensure that sufficient 

notification can be provided to RTOs/ 

ISOs so that the full range of options for 

addressing any reliability concerns can 

be considered. Although most RTOs/ 

ISOs only require 90-day notifications 

for retirements, construction schedules 

for all but the simplest retrofits will be 

longer, so sources should be able to 

notify their RTOs of their retirements 

earlier. This will also help as multiple 

sources work with their RTO/ISO to 

determine outage schedules. The RTOs/ 

ISOs also have a very important role to 

play and it appears that a number of 

them are already engaged in preparing 

for these rules. For instance, PJM 

Interconnection considered the impact 

of these anticipated rules at its January 

14, 2011, Regional Planning Process 

Task Force Meeting,177 and Midwest 

Independent Transmission System 

Operator, Inc. (MISO) has also begun a 

planning process to consider the impact 

of EPA rules.178

As discussed above, given the large 

reserve margins that exist, even after 

consideration of requirements of the 

proposed rule, EPA believes that any 

reliability issues are likely to be 

primarily local in nature and be due to 

the retirement of a unit in a load 

constrained area. As demonstrated by 

the work that PJM Interconnection and 

MISO are doing, RTOs/ISOs are 

required to do long range (at least 10 

years) capacity planning that includes 

consideration of future requirements 

such as EPA regulations. Furthermore, if 

companies within an RTO/ISO wish to 

retire a unit, they must first notify the 

RTO/ISO in advance so that any 

reliability concerns can be addressed. 

The RTOs/ISOs, have well established 

procedures to address such retirements. 

Starting assessments early and 

considering the full range of options 

will help ensure that the requirements 

of this rule are met as economically as 

possible and that power companies are 

able to provide reliable electric power 

while significantly reducing their 

impact on public health. For power 

companies this includes considering the 

range of pollution control options 

available for their existing fleet as well 

as considering the range of options for 

replacement power, in the cases where 

shutting down a unit is the more 

economic choice. The RTOs/ISOs 

should consider the full range of options 

to provide any necessary replacement 

power including the development of 

both supply and demand side resources. 

Environmental regulators should work 

with their affected sources early to 

understand their compliance choices. In 

this way, those regulators will be able to 

accurately access when use of the 1-year 

compliance extension is appropriate. By 

working with regulators early, affected 

sources will be in a position to have 

assurance that the 1-year extension will 

be granted in those situations where it 

is appropriate. 

Section X.c. describes the sensitivity 

analysis performed by EPA for an 

Energy Efficiency case, in which a 

combination of DOE appliance 

standards and State investments in 

demand-side efficiency come into place 

at the same time as compliance with the 

requirements of this rule. That analysis 

shows that even in the absence of this 

rule, moderate actions to promote 

energy efficiency would lead to 

retirement of an additional 11 GW in 

2015, of 27 GW in 2020, and of 26 GW 

in 2030, beyond the capacity already 

projected to retire in the base case. In 

effect, the timely adoption and 

implementation of energy efficiency 

policies would augment currently 

projected reserve capacities that are 

instrumental to assuring system 

reliability. 

As noted, instrumental to undertaking 

such actions are other Federal agencies 

such as DOE, ISOs and RTOs, and state 

agencies such as PUCs. Fortunately, in 

addition to helping to assure system 

reliability, timely implementation of 

energy efficiency policies offer these key 

decision-makers an additional incentive 

to take action. As the analysis shows, 

energy efficiency can reduce costs for 

ratepayers and customers. 

First, with or without the proposed 

Toxic Rule, energy efficiency policies 

are shown by the analysis to reduce the 

overall costs of generating electricity, 

with the cost reductions increasing over 

time. See Table 22. Second, when 

comparing the Toxics Rule Case without 

energy efficiency to the Toxics Rule 

Case with energy efficiency, the analysis 

suggests that if these energy efficiency 

policies were to be put into place and 

maintained over time by system 

operators, states and DOE, the costs of 

the proposed Toxics Rule are mitigated 

by these cost reductions such that the 

overall system costs are reduced by $2 

billion in 2015, $6 billion in 2020, and 

$11 billion in 2030. 

The energy savings driven by these 

energy efficiency policies mean that 

consumers will pay less for electricity as 

well. EPA has modeled national average 

retail electricity prices, including the 

energy efficiency costs that are paid by 

the ratepayer. The Toxics Rule increases 

retail prices by 3.7 percent, 2.6 percent 

and 1.9 percent in 2015, 2020 and 2030 


jlentini on DSKJ8SOYB1PROD with PROPOSALS2
Federal Register / Vol. 76, No. 85 / Tuesday, May 3, 2011 / Proposed Rules 25057 

respectively relative to the base case. If 

energy efficiency policies are 

implemented along with the Toxics 

Rule, the average retail price of 

electricity increases by 3.3 percent in 

2015 relative to the base case, but falls 

relative to the base case by about 1.6 

percent in 2020 and about 2.3 percent 

in 2030. The effect on electricity bills 

however may fall more than these 

percentages suggest as energy efficiency 

means that less electricity will be used 

by consumers of electricity. 

EPA believes that as it shares these 

results with PUCs, the commissions will 

respond in accordance with their 

ongoing imperative to ensure that 

electricity costs for ratepayers and 

consumers remains stable. Specifically, 

the opportunity created through the 

deployment of energy efficiencypromoting strategies and initiatives to 

safeguard system reliability and, 

especially, to curb cost increases that 

might otherwise result from 

implementation of the Toxics Rule 

should provide PUCs with both the 

motivation and the justification for 

providing utilities with the financial 

and regulatory support they need to 

begin planning as early as possible for 

compliance and to incorporate in their 

plans the kinds of energy efficiency 

investments needed to achieve both 

compliance and cost-minimization. 

EPA recognizes that both utilities and 

their regulators often are hesitant to take 

early action to comply with 

environmental standards because they 

avoid incurring costs that they fear may 

not be required once the final regulation 

is promulgated. EPA urges utilities and 

regulators to begin planning and 

preparations for timely compliance. The 

same concerns about consumer cost in 

some cases also dissuade utilities from 

incurring, and commissions from 

authorizing, the upfront costs associated 

with energy efficiency programs. 

However, EPA also believes that if it 

takes steps to actively disseminate the 

results of the energy efficiency analysis, 

then utilities will be that much more 

likely to begin, and regulators that much 

more likely to support, comprehensive 

assessment and planning as early as 

possible since compliance approaches 

that encompass energy efficiency 

integrated with other actions needed to 

meet the Toxics Rule’s requirements 

will result in lower costs for ratepayers 

and consumers. EPA encourages State 

environmental regulators to consider the 

extent to which a utility engages in early 

planning when making a decision 

regarding granting a 4th year for 

compliance with the Toxics Rule. 

In summary, EPA believes that the 

large reserve margins, the range of 

control options, the range of flexibilities 

to address unit shutdowns, existing 

processes to assure that sufficient 

generation exists when and where it is 

needed, and the flexibilities within the 

CAA, provide sufficient assurance that 

the CAA section 112 requirements for 

the power sector can be met without 

adversely impacting electric reliability. 

EGUs are the subject of several 

rulemaking efforts that either are or will 

soon be underway. In addition to this 

rulemaking proposal, concerning both 

hazardous air pollutants under section 

112 and criteria pollutant NSPS 

standards under section 111, EGUs are 

the subject of other rulemakings, 

including ones under section 

110(a)(2)(D) addressing the interstate 

transport of emissions contributing to 

ozone and PM air quality problems, coal 

combustion wastes, and the 

implementation of section 316(b) of the 

Clean Water Act (CWA). They will also 

soon be the subject of a rulemaking 

under CAA section 111 concerning 

emissions of greenhouse gases. 

EPA recognizes that it is important 

that each and all of these efforts achieve 

their intended environmental objectives 

in a common-sense manner that allows 

the industry to comply with its 

obligations under these rules as 

efficiently as possible and to do so by 

making coordinated investment 

decisions and, to the greatest extent 

possible, by adopting integrated 

compliance strategies. 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.’’ Thus, 

EPA recognizes that it needs to 

approach these rulemakings, to the 

extent that its legal obligations permit, 

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 the 

rulemakings must achieve. 

The upcoming rulemaking under 

section 111 regarding GHG emissions 

from EGUs may provide an opportunity 

to facilitate the industry’s undertaking 

integrated compliance strategies in 

meeting the requirements of these 

rulemakings. First, since that 

rulemaking will be finalized after a 

number of the other rulemakings that 

are currently underway are, the Agency 

will have an opportunity to take into 

account the effects of the earlier 

rulemakings in making decisions 

regarding potential GHG standards for 

EGUs. 

Second, in that rulemaking, EPA will 

be addressing both CAA section 111(b) 

standards for emissions from new and 

modified EGUs and CAA section 111(d) 

emission guidelines for states to follow 

in establishing their plans regarding 

GHG emissions from existing EGUs. In 

evaluating potential emission standards 

and guidelines, EPA may consider the 

impacts of other rulemakings on both 

emissions of GHGs from EGUs and the 

costs borne by EGUs. The Agency 

expects to have ample latitude to set 

requirements and guidelines in ways 

that can support the states’ and 

industry’s efforts in pursuing practical, 

cost-effective and coordinated 

compliance strategies encompassing a 

broad suite of its pollution-control 

obligations. EPA will be taking public 

comment on such flexibilities in the 

context of that rulemaking. 

As discussed elsewhere in this 

preamble, we invite comment on this 

proposed rule. EPA solicits comment on 

the ability of sources subject to this 

proposed rule to comply within the 

statutorily mandated 3-year compliance 

window and/or the 1-year discretionary 

extension, as well as comment on 

specific factors that could prevent a 

source from achieving, or could enable 

a source to achieve, compliance. In 

addition, EPA requests comment on the 

impact of this proposed rule on electric 

reliability, and ways to ensure 

compliance while maintaining the 

reliability of the grid. 

A number of states (or localities) have 

proactively developed plans to address 

a suite of environmental issues, an aging 

generation fleet, and electric reliability 

(e.g., plans requiring retirement of coal 

and pollution control devices such as 

the Colorado ‘‘Clean Air-Clean Jobs Act’’ 

or renewable portfolio standards that 

because of the states’ current generation 

mix could result in significant changes 

to the composition of the fossil-fuelfired portion of the fleet such as 

Hawaii’s renewable portfolio standard 

(HB–1464)). In most cases, these plans 

were developed solely under State law 

with no underlying Federal 

requirement. Furthermore, as explained 

above, many of the technologies that 

were installed or that are planned to be 

installed in response to these state plans 

are likely to result in collateral 

reductions of many HAP required to be 

reduced in today’s proposed rule. 

Although some of these state programs 

may have obtained some important 

emission reductions to date, they may 

also allow compliance time-frames for 


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25058 Federal Register / Vol. 76, No. 85 / Tuesday, May 3, 2011 / Proposed Rules 

some units that extend beyond those 

authorized under CAA section 112(i)(3). 

The Agency has a program pursuant 

to 40 CFR subpart E, whereby states can 

take delegation of section 112 emission 

standards. Among other things, states 

can seek approval of state rules to the 

extent they can demonstrate that those 

rules are no less stringent that the 

applicable section 112(d) rule. Because 

overall, some of these state programs 

may result in greater emission 

reductions, EPA is taking comment on 

whether (and if so how) such state plans 

could be integrated with the proposed 

rule requirements consistent with the 

statute. EPA also intends to engage with 

states who believe that they have such 

plans to understand whether they 

believe that there are opportunities to 

integrate the two sets of requirements in 

a manner consistent with the 

requirements of the CAA. 

EGUs are the subject of several 

rulemaking efforts that either are or will 

soon be underway. In addition to this 

rulemaking proposal, concerning both 

HAP under section 112 and criteria 

pollutant NSPS standards under section 

111, EGUs are the subject of other 

rulemakings, including ones under 

section 110(a)(2)(D) addressing the 

interstate transport of emissions 

contributing to ozone and PM air quality 

problems, coal combustion wastes, and 

the implementation of section 316(b) of 

the CWA. They will also soon be the 

subject of a rulemaking under CAA 

section 111 concerning emissions of 

greenhouse gases (GHG). 

EPA recognizes that it is important 

that each and all of these efforts achieve 

their intended environmental objectives 

in a common-sense manner that allows 

the industry to comply with its 

obligations under these rules as 

efficiently as possible and to do so by 

making coordinated investment 

decisions and, to the greatest extent 

possible, by adopting integrated 

compliance strategies. Thus, EPA 

recognizes that it needs to approach 

these rulemakings, to the extent that its 

legal obligations permit, 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 the 

rulemakings must achieve. 

The upcoming rulemaking under 

section 111 regarding GHG emissions 

from EGUs may provide an opportunity 

to facilitate the industry’s undertaking 

integrated compliance strategies in 

meeting the requirements of these 

rulemakings. First, since that 

rulemaking will be finalized after a 

number of the other rulemakings that 

are currently underway are, the agency 

will have an opportunity to take into 

account the effects of the earlier 

rulemakings in making decisions 

regarding potential GHG standards for 

EGUs. 

Second, in that rulemaking, EPA will 

be addressing both CAA section 111(b) 

standards for emissions from new and 

modified EGUs and CAA section 111(d) 

emission guidelines for states to follow 

in establishing their plans regarding 

GHG emissions from existing EGUs. In 

evaluating potential emission standards 

and guidelines, EPA may consider the 

impacts of other rulemakings on both 

emissions of GHGs from EGUs and the 

costs borne by EGUs. The Agency 

expects to have ample latitude to set 

requirements and guidelines in ways 

that can support the states’ and 

industry’s efforts in pursuing practical, 

cost-effective and coordinated 

compliance strategies encompassing a 

broad suite of its pollution-control 

obligations. EPA will be taking public 

comment on such flexibilities in the 

context of that rulemaking. 

N. How did EPA determine the required 

records and reports for this proposed 

rule? 

You would be required to comply 

with the applicable requirements in the 

NESHAP General Provisions, subpart A 

of 40 CFR part 63, as described in Table 

10 of the proposed 40 CFR part 63, 

subpart UUUUU. We evaluated the 

General Provisions requirements and 

included those we determined to be the 

minimum notification, recordkeeping, 

and reporting requirements necessary to 

ensure compliance with, and effective 

enforcement of, this proposed rule. 

We would require additional 

recordkeeping if you chose to comply 

with the chlorine or Hg fuel input 

option. You would need to keep records 

of the calculations and supporting 

information used to develop the 

chlorine or Hg fuel input operating 

limit. 

O. How does this proposed rule affect 

permits? 

The CAA requires that sources subject 

to this proposed rule be operated 

pursuant to a permit issued under EPAapproved state operating permit 

program. The operating permit programs 

are developed under Title V of the CAA 

and the implementing regulations under 

40 CFR parts 70 and 71. If you are 

operating in the first 2 years of the 

current term of your operating permit, 

you will need to obtain a revised permit 

to incorporate this proposed rule. If you 

are in the last 3 years of the current term 

of your operating permit, you will need 

to incorporate this proposed rule into 

the next renewal of your permit. 

P. Alternative Standard for 

Consideration 

As discussed above, we are proposing 

alternate equivalent emission standards 

(for certain subcategories) to the 

proposed surrogate standards in three 

areas: SO2 (in addition to HCl), 

individual non-Hg metals (for PM), and 

total non-Hg metals (for PM). The 

proposed emission limitations are 

provided in Tables 16 and 17 of this 

preamble. 

TABLE 15—ALTERNATE EMISSION LIMITATIONS FOR EXISTING COAL- AND OIL-FIRED EGUS

Subcategory 

Coal-fired unit 

designed for coal 

≥ 8,300 Btu/lb 

Coal-fired unit 

designed for coal 

< 8,300 Btu/lb 

IGCC, lb/TBtu 

(lb/GWh) 

Liquid oil, lb/TBtu 

(lb/GWh) Solid oil-derived 

SO2 ............................. 0.20 lb/MMBtu (2.0 

lb/MWh).

0.20 lb/MMBtu (2.0 

lb/MWh).

NA ............................. NA ............................. 0.40 lb/MMBtu (5.0 

lb/MWh). 

Total non-Hg metals ... 0.000040 lb/MMBtu 

(0.00040 lb/MWh).

0.000040 lb/MMBtu 

(0.00040 lb/MWh).

5.0 (0.050) ................ NA ............................. 0.000050 lb/MMBtu 

(0.001 lb/MWh). 

Antimony, Sb .............. 0.60 lb/TBtu (0.0060 

lb/GWh).

0.60 lb/TBtu (0.0060 

lb/GWh).

0.40 (0.0040) ............ 0.20 (0.0030) ............ 0.40 lb/TBtu (0.0070 

lb/GWh). 

Arsenic, As ................. 2.0 lb/TBtu (0.020 lb/ 

GWh).

2.0 lb/TBtu (0.020 lb/ 

GWh).

2.0 (0.020) ................ 0.60 (0.0070) ............ 0.40 lb/TBtu (0.0040 

lb/GWh). 

Beryllium, Be .............. 0.20 lb/TBtu (0.0020 

lb/GWh).

0.20 lb/TBtu (0.0020 

lb/GWh).

0.030 (0.0030) .......... 0.060 (0.00070) ........ 0.070 lb/TBtu 

(0.00070 lb/GWh). 

Cadmium, Cd ............. 0.30 lb/TBtu (0.0030 

lb/GWh).

0.30 lb/TBtu (0.0030 

lb/GWh).

0.20 (0.0020) ............ 0.10 (0.0020) ............ 0.40 lb/TBtu (0.0040 

lb/GWh). 


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TABLE 15—ALTERNATE EMISSION LIMITATIONS FOR EXISTING COAL- AND OIL-FIRED EGUS—Continued 

Subcategory 

Coal-fired unit 

designed for coal 

≥ 8,300 Btu/lb 

Coal-fired unit 

designed for coal 

< 8,300 Btu/lb 

IGCC, lb/TBtu 

(lb/GWh) 

Liquid oil, lb/TBtu 

(lb/GWh) Solid oil-derived 

Chromium, Cr ............. 3.0 lb/TBtu (0.030 lb/ 

GWh).

3.0 lb/TBtu (0.030 lb/ 

GWh).

3.0 (0.020) ................ 2.0 (0.020) ................ 2.0 lb/TBtu (0.020 lb/ 

GWh). 

Cobalt, Co .................. 0.80 lb/TBtu (0.0080 

lb/GWh).

0.80 lb/TBtu (0.0080 

lb/GWh).

2.0 (0.0040) .............. 3.0 (0.020) ................ 2.0 lb/TBtu (0.020 lb/ 

GWh). 

Lead, Pb ..................... 2.0 lb/TBtu (0.020 lb/ 

GWh).

2.0 lb/TBtu (0.020 lb/ 

GWh).

0.0002 lb/MMBtu 

(0.003 lb/MWh).

2.0 (0.030) ................ 11.0 lb/TBtu (0.020 

lb/GWh). 

Manganese, Mn ......... 5.0 lb/TBtu (0.050 lb/ 

GWh.

5.0 lb/TBtu (0.050 lb/ 

GWh.

3.0 (0.020) ................ 5.0 (0.060) ................ 3.0 lb/TBtu (0.040 lb/ 

GWh). 

Mercury, Hg ................ NA ............................. NA ............................. NA ............................. 0.050 lb/TBtu 

(0.00070 lb/GWh).

NA. 

Nickel, Ni .................... 4.0 lb/TBtu (0.040 lb/ 

GWh).

4.0 lb/TBtu (0.040 lb/ 

GWh).

5.0 (0.050) ................ 8.0 (0.080) ................ 9.0 lb/TBtu (0.090 lb/ 

GWh). 

Selenium, Se .............. 6.0 lb/TBtu (0.060 lb/ 

GWh).

6.0 lb/TBtu (0.060 lb/ 

GWh).

22.0 (0.20) ................ 2.0 (0.020) ................ 2.0 lb/TBtu (0.020 lb/ 

GWh). 

NA = Not applicable. 

TABLE 16—ALTERNATE EMISSION LIMITATIONS FOR NEW COAL- AND OIL-FIRED EGUS

Subcategory 

Coal-fired unit 

designed for coal 

≥ 8,300 Btu/lb 

Coal-fired unit 

designed for coal 

< 8,300 Btu/lb 

IGCC * Liquid oil, lb/GWh Solid oil-derived 

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

Total metals ................ 0.000040 lb/MWh ...... 0.000040 lb/MWh ...... 0.000040 lb/MWh ...... NA ............................. 0.00020 lb/MWh. 

Antimony, Sb .............. 0.000080 lb/GWh ...... 0.000080 lb/GWh ...... 0.000080 lb/GWh ...... 0.0020 ....................... 0.00090 lb/GWh. 

Arsenic, As ................. 0.00020 lb/GWh ........ 0.00020 lb/GWh ........ 0.00020 lb/GWh ........ 0.0020 ....................... 0.0020 lb/GWh. 

Beryllium, Be .............. 0.000030 lb/GWh ...... 0.000030 lb/GWh ...... 0.000030 lb/GWh ...... 0.00070 ..................... 0.000080 lb/GWh. 

Cadmium, Cd ............. 0.00040 lb/GWh ........ 0.00040 lb/GWh ........ 0.00040 lb/GWh ........ 0.00040 ..................... 0.0070 lb/GWh. 

Chromium, Cr ............. 0.020 lb/GWh ............ 0.020 lb/GWh ............ 0.020 lb/GWh ............ 0.020 ......................... 0.0060 lb/GWh. 

Cobalt, Co .................. 0.00080 lb/GWh ........ 0.00080 lb/GWh ........ 0.00080 lb/GWh ........ 0.0060 ....................... 0.0020 lb/GWh. 

Lead, Pb ..................... 0.00090 lb/GWh ........ 0.00090 lb/GWh ........ 0.00090 lb/GWh ........ 0.0060 ....................... 0.020 lb/GWh. 

Mercury, Hg ................ NA ............................. NA ............................. NA ............................. 0.00010 lb/GWh ........ NA. 

Manganese, Mn ......... 0.0040 lb/GWh .......... 0.0040 lb/GWh .......... 0.0040 lb/GWh .......... 0.030 ......................... 0.0070 lb/GWh. 

Nickel, Ni .................... 0.0040 lb/GWh .......... 0.0040 lb/GWh .......... 0.0040 lb/GWh .......... 0.040 ......................... 0.0070 lb/GWh. 

Selenium, Se .............. 0.030 lb/GWh ............ 0.030 lb/GWh ............ 0.030 lb/GWh ............ 0.0040 ....................... 0.00090 lb/GWh. 

* Beyond-the-floor as discussed elsewhere. 

NA = Not applicable. 

Most, if not all, coal-fired EGUs and 

solid oil-derived fuel-fired EGUs already 

have emission limitations for SO2 under 

either the Federal NSPS, individual SIP 

programs, or the Federal ARP and, as a 

result, have SO2 emission controls 

installed. Further, again most, if not all, 

coal-fired EGUs have SO2 CEMS 

installed and operating under the 

provisions of one of these programs. 

Thus, as SO2 is a suitable surrogate for 

the acid gas HAP, it could be used as an 

alternate equivalent standard to the HCl 

standard for EGUs with FGD systems 

installed and operated at normal 

capacity. An SO2 standard would ensure 

that equivalent control of the acid gas 

HAP is achieved, and some facilities 

may find it preferable to use the existing 

SO2 CEMS for compliance purposes 

rather than having to perform the 

manual HCl compliance testing. As 

noted elsewhere, this approach does not 

work for EGUs that do not have SO2

controls installed and, thus, those EGUs 

may not utilize the alternate SO2

limitations. Further, no SO2 data were 

provided by the two IGCC units; 

therefore, there is no alternative SO2

limitation being proposed for existing 

IGCC units. 

Some sources have expressed a 

preference for individual non-Hg metal 

HAP emission limitations rather than 

the use of PM as a surrogate. Thus, EPA 

has analyzed the data for that purpose 

and we are proposing both alternate 

individual HAP metal limitations and 

total HAP metal limitations for all 

subcategories except liquid oil-fired 

EGUs. These limitations provide 

equivalent control of metal HAP as the 

proposed PM limitations. 

We are soliciting comments on all 

aspects of these alternate emission 

limitations. 

VI. Background Information on the 

Proposed NSPS 

A. What is the statutory authority for 

this proposed NSPS? 

New source performance standards 

implement CAA section 111(b), and are 

issued for source categories which EPA 

has determined cause, or contribute 

significantly to, air pollution which may 

reasonably be anticipated to endanger 

public health or welfare. CAA section 

111(b)(1)(B) requires the EPA to 

periodically review and, if appropriate, 

revise the NSPS to reflect improvements 

in emissions reduction methods. 

CAA section 111 requires that the 

NSPS reflect the application of the best 

system of emissions reductions which 

the Administrator determines has been 

adequately demonstrated (taking into 

account the cost of achieving such 

reduction, any non-air quality health 

and environmental impacts and energy 

requirements). This level of control is 

commonly referred to as best 

demonstrated technology (BDT). 


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The current standards for steam 

generating units are contained in the 

NSPS for electric utility steam 

generating units (40 CFR part 60, 

subpart Da), industrial-commercialinstitutional steam generating units (40 

CFR part 60, subpart Db), and small 

industrial-commercial-institutional 

steam generating units (40 CFR part 60, 

subpart Dc). Previous standards that 

continue to apply to owners/operators 

of existing affected facilities, but which 

have been superseded for owner/ 

operators of new affected facilities, are 

contained in the NSPS for fossil-fuelfired steam generating units for which 

construction was commenced after 

August 17, 1971, but on or before 

September 18, 1978 (40 CFR part 60, 

subpart D). 

B. Summary of State of New York, et al., 

v. EPA Remand 

On February 27, 2006, EPA 

promulgated amendments to the NSPS 

for EGUs (40 CFR part 60, subpart Da) 

which established new standards for 

PM, SO2, and NOX (71 FR 9,866). EPA 

was subsequently sued on the 

amendments by multiple state 

governments, municipal governments, 

and environmental organizations 

(collectively the Petitioners). State of 

New York v. EPA, No. 06–1148 (DC 

Cir.). The Petitioners alleged that EPA 

failed to correctly identify the best 

system of emission reductions for the 

newly established SO2 and NOX

standards. The Petitioners also 

contended that EPA was required to 

establish separate emission limits for 

fine filterable PM (PM2.5) and 

condensable PM. Finally, the petitioners 

claimed the NSPS failed to reflect the 

degree of emission limitation achievable 

through the application of IGCC 

technology. Based upon further 

examination of the record, EPA 

determined that certain issues in the 

rule warranted further consideration. 

On that basis, EPA sought and, on 

September 4, 2009, was granted a 

voluntary remand without vacatur of the 

2006 amendments. 

C. EPA’s Response to the Remand 

The emission standards established 

by the 2006 final rule, which are more 

stringent than the standards in effect 

prior to the adoption of the 

amendments, remain in effect and will 

continue to apply to affected facilities 

for which construction was commenced 

after February 28, 2005, but before May 

4, 2011. Following careful consideration 

of all of the relevant factors, EPA is 

proposing to establish amended 

standards for PM, SO2, and NOX which 

would apply to owners/operators of 

affected facilities constructed, 

reconstructed, or modified after May 3, 

2011. 

In terms of the timing of our response 

to the remand, we consider it 

appropriate to propose revisions to the 

NSPS in conjunction with proposing the 

EGU NESHAP. There are some 

commonalities among the controls 

needed to comply with the requirements 

of the two rules and syncing the two 

rules so that they apply to the same set 

of new sources will allow owners/ 

operators of those sources to better plan 

to comply with both sets of 

requirements. Therefore, we are 

proposing these revisions in 

conjunction with proposing the 

NESHAP, and intend to finalize both 

rules simultaneously. 

As explained in more detail below 

and in the technical support documents, 

we have concluded that the proposed 

PM, SO2, and NOX standards set forth in 

this proposed rule reflect BDT. In 

addition, we have concluded that the 

most appropriate approach to reduce 

emissions of both filterable PM2.5 and 

condensable PM is to establish a total 

PM standard, rather than establishing 

separate standards for each form of 

PM.The total PM standard, total 

filterable PM plus condensable PM, set 

forth in this proposed rule reflects BDT 

for all forms of PM. We have concluded 

that establishing a single total PM 

standard is preferable for a number of 

reasons. First, this approach effectively 

accounts for and requires control of both 

primary forms of PM, filterable PM, 

which includes both filterable PM10 (PM 

in the stack with an aerodynamic 

diameter less than or equal to a nominal 

10 micrometers) and filterable PM2.5

(PM in the stack with an aerodynamic 

diameter less than or equal to a nominal 

2.5 micrometers) and condensable PM 

(materials that are vapors or gases at 

stack conditions but form solids or 

liquids upon release to the atmosphere). 

Second, we have concluded that the 

same control device constitutes BDT for 

both forms of filterable PM. Best 

demonstrated technology for control of 

both filterable PM10 and filterable PM2.5

emissions from steam generating units is 

based upon the use of a FF with coated 

or membrane filter media bags. Fabric 

filters control the fine particulate sizes 

that compose filterable PM2.5 and the 

coarser particulate sizes that are a 

component of filterable PM10 through 

the same means. Since a FF controls 

total filterable PM and cannot 

selectively control filterable PM2.5, 

establishing separate filterable PM2.5

and filterable PM10 standards would not 

result in any further reduction in 

emissions. Thus, although the NSPS for 

steam generating units do not establish 

individual standards for filterable PM10

and PM2.5, the NSPS PM standards for 

steam generating units do result in 

control of both of these filterable PM 

size categories based on the use of the 

control technologies identified as BDT 

and used to derive the proposed PM 

standards. Third, size fractionation of 

the PM in stacks with entrained water 

droplets (i.e., those downstream of a wet 

FGD scrubber) is challenging since the 

water droplets contain suspended and 

dissolved material which would form 

particulate after exiting the stack when 

the water droplet is evaporated. This 

challenge is exacerbated due to the 

difficulties of collecting the water 

droplets and quickly evaporating the 

water to reconstitute the suspended and 

dissolved materials in their eventual 

final size without changing their size as 

a result of shattering, agglomeration and 

deposition on the sample equipment. 

Although the Agency and others are 

working toward technologies that may 

allow particle sizing in wet stack 

conditions, there is currently no viable 

test method to determine the size 

fraction of the filterable PM for stacks 

that contain water droplets. Because 

many new EGUs are expected to use wet 

scrubbers and/or a WESP, owners/ 

operators of these units would have no 

method to determine compliance with a 

fine filterable PM standard. 

Under the existing NSPS, BDT for an 

owner/operator of a new affected facility 

is a FF for control of filterable PM and 

an FGD for control of SO2. Depending 

on the specific stack conditions and coal 

type being burned, fabric filters may 

also provide some co-benefit reduction 

in condensable PM emissions. 

Furthermore, an FGD designed for SO2

control has the co-benefit of reducing, to 

some extent, condensable PM 

emissions. Therefore, the existing NSPS 

baseline for control of condensable PM 

is a FF in combination with an FGD. We 

have concluded that the additional use 

of a WESP system in combination with 

DSI is BDT for condensable PM. We 

have concluded that it is appropriate to 

regulate both filterable and condensable 

PM under a single standard since they 

may be impacted differently by common 

controls. For example, DSI is one of the 

approaches that could be used to reduce 

the sulfuric acid mist (SO3 and H2SO4) 

portion of the condensable PM. 

However, addition of sorbent adds 

filterable PM to the system and could 

conceivably increase filterable PM 

emissions. When using a wet FGD, some 

small amount of scrubber solids 

(gypsum, limestone) can be entrained 

into the exiting gas, resulting in an 


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increase in filterable PM emissions. In 

each of these cases, technologies used to 

meet a stringent separate condensable 

PM standard could result in an increase 

in filterable PM emissions, a portion of 

which consist of fine filterable PM. This 

increase in filterable PM may challenge 

the ability of the owner/operator of the 

affected facility to meet a similarly 

stringent filterable PM standard. 

Filterable and condensable PM are often 

controlled using separate or 

complimentary technologies—though 

there are technologies, (e.g., WESP), that 

can control both filterable and 

condensable PM emissions. Often times 

the equipment is used to also control 

other pollutants such as SO2, HCl, and 

Hg. A combined PM standard allows for 

optimal design and operation of the 

control equipment. Thus, with the data 

available to us it is unclear what system 

of emissions reduction would result in 

the best overall environmental 

performance if we attempted to 

established separate filterable and 

condensable PM standards and what an 

appropriate condensable PM standard 

would be. At this time, the use of a total 

PM standard is the most effective 

indicator that the emissions standard is 

providing the best control of both 

filterable and condensable PM2.5

emissions as well as coarse filterable PM 

emissions. We are requesting comment 

on whether separate filterable PM2.5 and 

condensable PM standards would be 

appropriate and what the numerical 

values of any such standards should be. 

EPA disagrees with the petitioners 

claim that the NSPS should be based on 

the performance of IGCC units. The 

NSPS is a national standard and IGCC 

is not appropriate in every situation. 

Although IGCC units have many 

advantages, technology choice is based 

on several factors, including the goals 

and objectives of the owner or operator 

constructing a facility, the intended 

purpose or function of the facility, and 

the characteristic of the particular site. 

In addition, the emissions benefits 

resulting from reduced emissions of 

criteria pollutants are not sufficient in 

all instances to justify the higher capital 

costs of today’s IGCC units if IGCC is 

selected as BDT in establishing a 

national standard. The emissions 

benefits may, however, be sufficient to 

justify the use of IGCC in an individual 

case, after considering cost and other 

relevant factors, including those 

described above. 

D. EPA’s Response to the Utility Air 

Regulatory Group’s Petition for 

Reconsideration 

On January 28, 2009, EPA 

promulgated amendments separate from 

the above mentioned amendments to the 

NSPS for EGUs (40 CFR part 60, subpart 

Da, 74 FR 5,072). The Utility Air 

Regulatory Group (UARG) subsequently 

requested reconsideration of that 

rulemaking and EPA granted that 

reconsideration. Specific issues raised 

by UARG included the opacity 

monitoring requirements for owners/ 

operators of affected facilities subject to 

an opacity standard that are not 

required to install a continuous opacity 

monitoring system (COMS). Another 

issue raised by UARG was the opacity 

standard for owners/operators of 

affected facilities subject to 40 CFR part 

60, subpart D. We are requesting 

comments on both of these issues in this 

rulemaking. 

VII. Summary of the Significant 

Proposed NSPS Amendments 

The proposed amendments would 

amend the emission limits for PM, SO2, 

and NOX from steam generating units in 

40 CFR part 60, subpart Da. Only those 

facilities that begin construction, 

modification, or reconstruction after 

May 3, 2011 would be affected by the 

proposed amendments. In addition to 

proposing to amend the identified 

emission limits, we are also proposing 

several less significant amendments, 

technical clarifications, and corrections 

to various provisions of the existing 

utility and industrial steam generating 

unit NSPS, as explained below. 

A. What are the proposed amended 

emissions standards for EGUs? 

We are proposing to amend the PM, 

SO2, and NOX standards for owners/ 

operators of new, modified, and 

reconstructed units on which 

construction is commenced after May 3, 

2011 as follows. We are proposing a 

total PM emissions standard (filterable 

plus condensable PM) for owners/ 

operators of new and reconstructed 

EGUs of 7.0 nanograms per joule (ng/J) 

(0.055 lb/MWh) gross energy output. 

The proposed PM standard for modified 

units is 15 ng/J (0.034 lb/MMBtu) heat 

input. 

We are proposing an SO2 emissions 

standard for new and reconstructed 

EGUs of 130 ng/J (1.0 lb/MWh) gross 

energy output or a 97 percent reduction 

of potential emissions regardless of the 

type of fuel burned with the following 

exception. We are not proposing to 

amend the SO2 emissions standard for 

EGUs that burn over 75 percent coal 

refuse. We are also not proposing to 

amend the SO2 emission standard for 

owners/operators of modified EGUs 

because of the incremental cost 

effectiveness and potential site specific 

limited water availability. Without 

access to adequate water supplies 

owners/operators of existing facilities 

would not be able to operate a wet FGD. 

We are co-proposing two options for 

an amended NOX emissions standard. 

EPA’s preferred approach would 

establish a combined NOX plus CO 

standard for owners/operators of new, 

reconstructed, and modified units. The 

proposed combined standard for new 

and reconstructed EGUs is 150 ng/J (1.2 

(lb NOX + lb CO)/MWh) and the 

proposed combined standard for 

modified units is 230 ng/J (1.8 (lb NOX

+ lb CO)/MWh). EPA prefers the 

approach of establishing a combined 

standard because it provides additional 

compliance flexibility while still 

providing an equivalent or superior 

level of environmental protection. 

Alternatively, we are proposing to 

amend the NOX emission standard for 

new, modified, and reconstructed EGUs 

to 88 ng/J (0.70 lb/MWh) gross energy 

output regardless of the type of fuel 

burned and not establish any CO 

standards. 

In addition to proposing revised 

emission standards, we are also 

proposing to amend the way an owner/ 

operator of an affected facility would 

calculate compliance with the proposed 

standards. Under the existing NSPS, 

averages are calculated as the arithmetic 

average of the non out-of-control hourly 

emissions rates (i.e., hours during which 

the monitoring device has not failed a 

quality assurance or quality control test) 

during the applicable averaging period. 

For the revised standards, we are 

proposing that the average be calculated 

as the sum of the applicable emissions 

divided by the sum of the gross output 

of non out-of-control hours during the 

averaging period. We are proposing this 

change in part to facilitate moving from 

the existing PM, SO2, and NOX

standards, which exclude periods of 

startup and shutdown, to the proposed 

PM, SO2, and NOX standards, which 

would include periods of startup and 

shutdown. 

B. Would owners/operators of any EGUs 

be exempt from the proposed 

amendments? 

We are proposing several 

amendments that would exempt 

owners/operators from certain of the 

proposed amendments. First, we are 

proposing that owners/operators of 

innovative emerging technologies that 

apply for and are granted a commercial 

demonstration permit by the 

Administrator for an affected facility 

that uses a pressurized fluidized bed, a 

multi-pollutant emissions control 

system, or advanced combustion 

controls be exempt from the proposed 


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25062 Federal Register / Vol. 76, No. 85 / Tuesday, May 3, 2011 / Proposed Rules 

amended standard. Owners/operators of 

these technologies would instead 

demonstrate compliance with standards 

similar to those finalized in the 2006 

amendments. The total PM standard 

would be 0.034 lb/MMBtu heat input, 

the SO2 standard would be 1.4 lb/MWh 

gross output or a 95 percent reduction 

in potential emissions, and the NOX

standard would be 1.0 lb/MWh gross 

output. In the event we finalize a 

combined NOX/CO standard, the 

corresponding combined limit would be 

1.4 lb/MWh gross output. In addition, 

we are proposing to harmonize all of the 

steam generating unit NSPS by 

exempting all steam generating units 

combusting natural gas and/or low 

sulfur oil from PM standards and 

exempting all steam generating units 

burning natural gas from opacity 

standards. Finally, we are proposing to 

exempt owners/operators of affected 

facilities subject to 40 CFR part 60, 

subpart Eb (standards of performance 

for large MWCs), from 40 CFR part 60, 

subpart Da, exempt owners/operators of 

affected facilities subject to 40 CFR part 

60, subpart CCCC (standards of 

performance for commercial and 

industrial solid waste incineration), 

units from 40 CFR part 60, subparts Da, 

Db, and Dc, exempt owners/operators of 

affected facilities subject to 40 CFR part 

60, subpart BB (standards of 

performance for Kraft pulp mills), from 

the PM standards under 40 CFR part 60, 

subpart Db, and exempt owners/ 

operators of fuel gas combustion devices 

subject to 40 CFR part 60, subpart Ja 

(standards of performance for petroleum 

refineries), from the SO2 standard under 

40 CFR part 60, subpart Db. 

C. What other significant amendments 

are being proposed? 

A complete list of the corrections and 

technical amendments and corrections 

is available in the docket in the form of 

a redline/strikeout version of the 

existing regulatory language. These 

additional amendments are being 

proposed to clarify the intent of the 

current requirements, correct 

inaccuracies, and correct oversights in 

previous versions that were 

promulgated. The additional significant 

amendments are as follows. 

We are proposing several definitional 

changes. First, to provide additional 

flexibility and recognize the 

environmental benefit of efficient 

production of electricity we are 

proposing to expand the definition of 

the affected facility under 40 CFR part 

60, subpart Da, to include integrated 

CTs and fuel cells. Second, because 

petroleum coke is increasingly being 

burned in EGUs selling over 25 MW of 

electric output, we are proposing to 

amend the definition of petroleum to 

include petroleum coke. Next, to 

minimize permitting and compliance 

burdens and avoid situations where an 

IGCC facility switches between different 

NSPS (40 CFR part 60, subparts KKKK 

and Da), we are proposing to amend the 

definition of an IGCC facility to allow 

the Administrator to exempt owners/ 

operators from the 50 percent solidderived fuel requirement during 

construction and repair of the gasifier. 

Owners/operators of IGCC units might 

install and operate the stationary CT 

prior to completion of the gasification 

system. Under the existing standards, an 

owner/operator doing this would first be 

subject to 40 CFR part 60, subpart 

KKKK, and applicability would switch 

once the gasification system is 

completed. This outcome would not 

result in any additional reduction in 

emissions. The proposed change would 

thus reduce regulatory burden without 

decreasing environmental protection. 

Finally, both biodiesel and kerosene 

have combustion characteristics similar 

to those of distillate oil. Therefore, we 

are proposing to expand the definition 

of distillate oil in 40 CFR part 60, 

subparts Db and Dc, to include both 

biodiesel and kerosene such that units 

burning any of these fuels, either 

separately or in combination would be 

subject to the same requirements. 

Additional proposed amendments 

include deleting vacated provisions and 

additional harmonization across the 

various steam generating unit NSPS. As 

explained above, CAMR was vacated by 

the DC Circuit Court in 2008. As a 

result, the provisions added to 40 CFR 

part 60, subpart Da, by CAMR are no 

longer enforceable. Therefore, we are 

proposing to delete the provisions in 40 

CFR part 60, subpart Da, that reference 

Hg standards and Hg testing and 

monitoring provisions. In addition, 

existing 40 CFR part 60, subpart HHHH 

(Emission Guidelines and Compliance 

Times for Coal-Fired Electric Steam 

Generating Units), which was 

promulgated as part of CAMR, and was, 

therefore, also vacated by the court’s 

decision, will be removed and that 

subpart will be deleted. We are 

proposing to harmonize all of the steam 

generating unit NSPS by adding BLDS 

and ESP parameter monitoring systems 

as alternatives to the requirement to 

install a COMS in all the subparts (40 

CFR part 60, subparts D, Da, Db, and 

Dc). We are also proposing to change the 

date by which owners/operators of 

affected facilities subject to all of the 

steam generating unit NSPS are to begin 

submitting performance test data 

electronically from July 1, 2011, to 

January 1, 2012. 

VIII. Rationale for This Proposed NSPS 

The proposed new emission standards 

for EGUs would apply only to affected 

sources that begin construction, 

modification, or reconstruction after 

May 3, 2011. Based on our review of 

emission data and control technology 

information applicable to criteria 

pollutants, we have concluded that 

amendments of the PM, SO2, and NOX

emission standards are appropriate. The 

technical support documents that 

accompany the proposal describe in 

further detail how the proposed 

amendments to the NSPS reflect the 

application of the BDT for these sources 

considering the performance and cost of 

the emission control technologies and 

other environmental, health, and energy 

factors. In establishing the proposed 

revised emission limits based on BDT, 

we have to the extent that it is practical 

and reasonable to do so adopted a fuel 

and technology neutral approach and 

have expressed the proposed emission 

limits on an output basis. These 

approaches provide the level of 

emission limitation required by the 

CAA for the NSPS program while at the 

same time achieving the additional 

benefits of compliance flexibility, 

increased efficiency, and the use of 

cleaner fuels. 

The fuel and technology neutral 

approach provides a single emission 

limit for steam generating units based 

on the application of BDT without 

regard to the specific type of steam 

generating equipment or fuel being 

used. We have concluded that this 

approach provides owners/operators of 

affected facilities an incentive to 

carefully consider fuel use, boiler type, 

and control technology in planning for 

new units so as to use the most effective 

combination of add-on control 

technologies, clean fuels, and boiler 

design based on the circumstances to 

meet the emission standards. 

To develop a fuel- and technologyneutral emission limit, we first analyzed 

data on emission control performance 

from coal-fired units to establish an 

emission level that represents BDT for 

units burning coal. We adopted this 

approach because the higher sulfur, 

nitrogen, and ash contents for coal 

compared to oil or gas makes 

application of BDT to coal-fired units 

more complex than application of BDT 

to either oil- or gas-fired units. Because 

of these complexities, emission levels 

selected for coal-fired steam generating 

units using BDT would also be 

achievable by oil- and gas-fired EGUs. 

Thus, we are proposing that the 


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emission levels established through the 

application of BDT to coal-fired units 

apply to all boiler types and fuel use 

combinations. We have concluded that 

this fuel-neutral approach both satisfies 

the requirements of CAA section 111(b) 

and provides a clear incentive to use 

cleaner fuels where it is possible to do 

so. 

Where feasible, we are proposing 

output-based (gross basis) standards in 

furtherance of pollution prevention 

which has long been one of our highest 

priorities. In the current context, 

maximizing the efficiency of energy 

generation represents a key opportunity 

to further pollution prevention. An 

output-based format establishes 

emission standards that encourage unit 

efficiency by relating emissions to the 

amount of useful-energy generated, not 

the amount of fuel burned. By relating 

emission limitations to the productive 

output of the process, output-based 

emission standards encourage energy 

efficiency because any increase in 

overall energy efficiency results in a 

lower emissions rate. Output-based 

standards provide owners/operators of 

regulated sources with an additional 

compliance option (i.e., increased 

efficiency in producing useful output) 

that can result in both reduced 

compliance costs and lower emissions. 

The use of more efficient generating 

technologies reduces fossil fuel use and 

leads to multi-media reductions in 

environmental impacts both on-site and 

off-site. On-site benefits include lower 

emissions of all products of combustion, 

including HAP, as well as reducing any 

solid waste and wastewater discharges. 

Off-site benefits include the reduction of 

emissions and non-air environmental 

impacts arising from the production, 

processing, and transportation of fuels 

and the disposal of by-products of 

combustion such as fly-ash and bottomash. 

The general provisions in 40 CFR part 

60 provide that ‘‘emissions in excess of 

the level of the applicable emissions 

limit during periods of startup, 

shutdown, and malfunction (shall not 

be) considered a violation of the 

applicable emission limit unless 

otherwise specified in the applicable 

standard.’’ 40 CFR 60.8(c). EPA is 

proposing standards in this rule that 

apply at all times, including during 

periods of startup or shutdown, and 

periods of malfunction. In proposing the 

standards in this rule, EPA has taken 

into account startup and shutdown 

periods and, for the reasons explained 

below, has not proposed different 

standards for those periods. 

To establish the proposed outputbased SO2 and NOX standards, we used 

hourly pollutant emissions data and 

gross output data as reported to the 

Clean Air Markets Division (CAMD) of 

EPA. In general, retrofit existing units 

can perform as well as recently 

operational units. To establish a robust 

data set on which to base the proposed 

amendments, we analyzed emissions 

data from both older plants that have 

been retrofitted with controls and 

recently operational units. We did not 

attempt to filter out periods of startup or 

shutdown and the proposed standards, 

therefore, account for those periods. 

If any persons believe that our 

conclusion is incorrect, or that we have 

failed to consider any relevant 

information on this point, we encourage 

them to submit comments. In particular, 

we note that the general provisions in 

40 CFR part 60 require facilities to keep 

records of the occurrence and duration 

of any startup, shutdown or malfunction 

(40 CFR 60.7(b)) and either report to 

EPA any period of excess emissions that 

occurs during periods of startup, 

shutdown, or malfunction (40 CFR 

60.7(c)(2)) or report that no excess 

emissions occurred (40 CFR 60.7(c)(4)). 

Thus, any comments that contend that 

sources cannot meet the proposed 

standard during startup and shutdown 

periods should provide data and other 

specifics supporting their claim. 

In developing the proposed 30-day 

SO2 and NOX standards, we summed 

the unadjusted emissions for all nonout-of-control operating hours and 

divided that value by the sum of the 

gross electrical energy output over the 

same period. For the purposes of this 

analysis, out-of-control hours were 

defined as when either the unadjusted 

applicable emissions or gross output 

could not be determined for that 

operating hour. The reduction in 

potential SO2 emissions was calculated 

by comparing the reported SO2

emissions during a 30-day period to the 

potential emissions for that same 30-day 

period. Potential uncontrolled SO2

emissions were calculated using 

monthly delivered fuel receipts and fuel 

quality data from the EIA forms EIA– 

923, EIA–423, and FERC–423, as 

applicable. For each operating day, the 

total potential uncontrolled SO2

emissions were calculated by 

multiplying the uncontrolled SO2

emissions rate for the applicable month 

as determined using the EIA data by the 

heat input for that day. This revised 

averaging approach gives more weight 

to high load hours and more accurately 

reflects overall environmental 

performance. In addition, because low 

load hours do not factor as heavily into 

the calculated average the impact of 

including periods of startup and 

shutdown is minimized. 

Particulate matter and CO data are not 

reported to CAMD and instead were 

collected as part of the 2010 ICR. Total 

PM testing was reported as part of the 

2010 ICR and those data were used in 

both rulemakings. As part of the 2010 

ICR, owners/operators reported CO 

performance test data and whether or 

not they have a CO CEMS installed on 

their facility. We requested CO CEMS 

data from multiple units to compare the 

relationship between NOX and CO. The 

30-day combined NOX/CO standard was 

calculated using the same approach as 

for NOX and SO2. 

A. How are periods of malfunction 

addressed? 

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 60.2.) EPA has 

determined that malfunctions should 

not be viewed as a distinct operating 

mode and, therefore, any emissions that 

occur at such times do not need to be 

factored into development of CAA 

section 111 standards. Further, nothing 

in CAA section 111 or in case law 

requires that EPA anticipate and 

account for the innumerable types of 

potential malfunction events in setting 

emission standards. See, Weyerhaeuser 

v Costle, 590 F.2d 1011, 1058 (DC 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.’’) 

Further, it is reasonable to interpret 

CAA section 111 as not requiring EPA 

to account for malfunctions in setting 

emissions standards. For example, we 

note that section 111 provides that EPA 

set standards of performance which 

reflect the degree of emission limitation 

achievable through ‘‘the application of 

the best system of emission reduction’’ 

that EPA determines is adequately 

demonstrated. Applying the concept of 

‘‘the application of the best system of 

emission reduction’’ to periods during 

which a source is malfunctioning 


jlentini on DSKJ8SOYB1PROD with PROPOSALS2
25064 Federal Register / Vol. 76, No. 85 / Tuesday, May 3, 2011 / Proposed Rules 

presents difficulties. The ‘‘application of 

the best system of emission reduction’’ 

is more appropriately understood to 

include operating units in such a way as 

to avoid malfunctions. 

Moreover, even if malfunctions were 

considered a distinct operating mode, 

we believe it would be impracticable to 

take malfunctions into account in 

setting CAA section 111 standards for 

EGUs under 40 CFR part 60, subpart Da. 

As noted above, by definition, 

malfunctions are sudden and 

unexpected events and it would be 

difficult to set a standard that takes into 

account the myriad different types of 

malfunctions that can occur across all 

sources in the category. Moreover, 

malfunctions can vary in frequency, 

degree, and duration, further 

complicating standard setting. 

In the event that a source fails to 

comply with the applicable CAA section 

111 standards as a result of a 

malfunction event, EPA would 

determine an appropriate response 

based on, among other things, the good 

faith efforts of the source to minimize 

emissions during malfunction periods, 

including preventative and corrective 

actions, as well as root cause analyses 

to ascertain and rectify excess 

emissions. EPA would also consider 

whether the source’s failure to comply 

with the CAA section 111 standard was, 

in fact, ‘‘sudden, infrequent, not 

reasonably preventable’’ and was not 

instead ‘‘caused in part by poor 

maintenance or careless operation.’’ 40 

CFR 60.2 (definition of malfunction). 

Finally, EPA recognizes that even 

equipment that is properly designed and 

maintained can sometimes fail. 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 

(September 20, 1999); Policy on Excess 

Emissions During Startup, Shutdown, 

Maintenance, and Malfunctions 

(February 15, 1983)). EPA is, therefore, 

proposing to add an affirmative defense 

to civil penalties for exceedances of 

emission limits that are caused by 

malfunctions. See 40 CFR 60.41Da 

(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 are proposing 

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 40 CFR 60.46Da. 

(See 40 CFR 22.24). These 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 60.2 (sudden, 

infrequent, not reasonably preventable 

and not caused by poor maintenance 

and or careless operation). For example, 

to successfully assert the affirmative 

defense, the source must prove by a 

preponderance of the evidence that 

excess emissions ‘‘[w]ere caused by a 

sudden, infrequent, and unavoidable 

failure of air pollution control and 

monitoring equipment, process 

equipment, or a process to operate in a 

normal or usual manner * * *’’ The 

criteria also are designed to ensure that 

steps are taken to correct the 

malfunction, to minimize emissions in 

accordance with 40 CFR 60.40Da and to 

prevent future malfunctions. For 

example, the source would have to 

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 the 

burden of proving all of the 

requirements in the affirmative defense, 

appropriate penalties may be assessed 

in accordance with CAA section 113 

(see also 40 CFR part 22.77). 

B. How did EPA determine the proposed 

emission limitations? 

1. Selection of the Proposed PM 

Standard 

Controls for filterable PM are well 

established. Either an ESP or FF can 

control both coarse and fine filterable 

PM. However, controls for condensable 

PM are less developed. Condensable PM 

from a coal-fired boiler is composed 

primarily of SO3 and H2SO4 but may 

also contain smaller amounts of nitrates, 

halides, ammonium salts, and volatile 

metals such as compounds of Hg and 

Se. Controls that are expected to reduce 

emissions of condensable PM include 

the use of lower sulfur coals, the use of 

an SCR catalyst or other NOX control 

device with minimal SO2 to SO3

conversion, use of an FGD scrubber, 

injection of an alkaline sorbent 

upstream of a PM control device, and 

use of a WESP. Other control 

technologies such as FFs or ESPs may 

also provide some reduction in 

condensable PM—depending on the flue 

gas temperature and the composition of 

the fly ash and other bulk PM. It is 

unlikely that owners/operators of 

modified units could universally further 

reduce the condensable fraction of the 

PM as they already have FGD controls, 

operating the PM control at a cooler 

temperature (or relocating to a cooler 

location) are not practical options due to 

concerns with corrosion, and it is 

possible that the existing ductwork 

might not make DSI viable without 

significant adjustments. Therefore, we 

have concluded that BDT for modified 

units should be based on the use of a FF 

in combination with an FGD. Based on 

the 2010 ICR data for total PM, there are 

performance tests for 63 units below the 

existing NSPS filterable PM standard 

(0.015 lb/MMBtu), that have some type 

of SO2 control, and that use a FF. Ninety 

four percent of these performance tests 

are achieving an emissions rate of 0.034 

lb/MMBtu for total PM, and we have 

concluded that this value is an 

achievable standard for owners/ 

operators of modified units. It is also 

approximately equivalent in stringency 

to the existing filterable PM standard 

because no specific condensable PM 

controls would necessarily be required. 

However, we have concluded that new 

EGUs will factor in condensable PM 

controls. BDT for new EGUs would be 

a FF and FGD in combination with both 

DSI and a WESP. Based on the 2010 ICR 

data for total PM, there are performance 

tests for 48 units below the existing 

NSPS filterable PM standard (0.015 lb/ 

MMBtu), that have some type of SO2

control, that use a FF, and that reported 

gross electrical output during the 

performance test. Because no owners/ 

operators of EGUs are presently 

specifically attempting to control 

condensable PM beyond eliminating the 

visible blue plume that can occur from 

sulfuric acid mist emissions, we 

concluded it was appropriate to use the 

top 20 percentile of the performance test 

data for the proposed total PM standard. 

The top 20 percentile of these 

performance tests is 7.0 ng/J (0.055 lb/ 

MWh). We are soliciting comments on 

the proposed standard and are 

considering the range of 15 ng/J (0.034 

lb/MMBtu) to 5.0 ng/J (0.040 lb/MWh) 

for the final rule. We are also requesting 

comment on whether an input-based 

standard is more appropriate for 

standards where compliance is based on 

performance tests instead of CEMS. 


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2. How did EPA select the proposed SO2

standard? 

A number of SO2 control technologies 

are currently available for use with new 

coal-fired EGUs. Owners/operators of 

new steam generating projects that use 

IGCC technology can remove the sulfur 

associated with the coal in downstream 

processes after the coal has been 

gasified. Owner/operators of new steam 

generating units that use FBC 

technology can control SO2 during the 

combustion process by adding 

limestone into the fluidized-bed, and, if 

necessary, installing additional postcombustion controls. Owners/operators 

of steam generating units using PC 

combustion technology can use postcombustion controls to remove SO2

from the flue gases. Additional control 

strategies that apply to all steam 

generating units include the use of low 

sulfur coals, coal preparation to improve 

the coal quality and lower the sulfur 

content, and fuel blending with 

inherently low sulfur fuels. 

To assess the SO2 control performance 

level of EGUs, we reviewed new and 

retrofitted units with SO2 controls. 

Table 17 of this preamble shows the 

performance of several of the best 

performing units in terms of percent 

reduction in potential SO2 emissions 

identified in our analysis of coal-fired 

EGUs. 

TABLE 17—SO2 EMISSIONS PERFORMANCE DATA

Facility Time period 

Maximum 

30-day SO2

emissions rate 

(lb/MWh) 

Minimum 

30-day percent 

SO2 reduction 

Cayuga 1 ..................................................................................................................... 12/08–12/09 1.03 97.4 

Harrison 1 .................................................................................................................... 01/06–01/09 1.45 96.7 

Harrison 2 .................................................................................................................... 01/06–01/09 1.01 97.7 

Harrison 3 .................................................................................................................... 01/06–01/09 0.97 98.2 

HL Spurlock 1 .............................................................................................................. 06/09–12/09 1.83 96.9 

HL Spurlock 2 .............................................................................................................. 11/08–12/09 1.26 98.0 

HL Spurlock 3 .............................................................................................................. 01/09–12/09 1.45 96.5 

HL Spurlock 4 .............................................................................................................. 01/09–12/09 1.08 97.7 

Wansley 1 .................................................................................................................... 02/09–12/09 0.31 97.7 

Wansley 2 .................................................................................................................... 05/09–12/09 0.37 97.4 

Iatan 1 .......................................................................................................................... 04/09–12/09 0.16 98.2 

Jeffrey 2 ....................................................................................................................... 05/09–12/09 0.09 99.0 

Jeffrey 3 ....................................................................................................................... 04/09–12/09 0.13 98.5 

Trimble County 1 ......................................................................................................... 01/05–12/09 1.14 97.6 

Mountaineer 1 .............................................................................................................. 05/07–12/09 1.15 97.6 

With the exception of the HL 

Spurlock 3 and 4 units all of the listed 

units use wet limestone-based 

scrubbers. HL Spurlock 3 and 4 are FBC 

boilers that remove the majority of SO2

using limestone injection into the boiler 

and then remove additional SO2 by lime 

injection into the ductwork prior to the 

FF. Of the identified best performing 

units, we only have multiple years of 

performance data for the Harrison, 

Trimble County, and Mountaineer units. 

Based on the performance of these units, 

we have concluded that 97 percent 

reduction in potential SO2 emissions 

has been demonstrated and is 

achievable on a long term basis. This 

level of reduction has also been 

demonstrated at each separate unit at 

each location in Table 17 of this 

preamble and accounts for variability in 

performance of individual scrubbers. 

Therefore, the proposed upper limit on 

a percent reduction basis is 97 percent. 

Even though the Iatan and Jeffrey units 

are achieving a 98 percent reduction in 

potential SO2 emissions, we are not 

proposing this standard because it is 

based on relatively short-term data. 

Based on the variability in SO2

reductions from the Harrison, Trimble 

County, and Mountaineer units, we 

have concluded that short-term data do 

not necessarily take into account the 

range of operating conditions that a 

facility would be expected to operate or 

control equipment variability and 

degradation. We are soliciting 

comments on the proposed limit and are 

considering the range of 96 to 98 

percent reduction in potential SO2

emissions for the final rule. 

To determine an appropriate alternate 

numerical standard, we evaluated the 

performance of several recently 

constructed units in addition to the 

numerical standards for the units in 

Table 17 of this preamble. Table 18 of 

this preamble shows the maximum 30- 

day average SO2 emissions rate of units 

that commenced operation between 

2005 and 2008, that are emitting at 

levels below the current NSPS, and that 

reported both SO2 emissions and gross 

electric output data to CAMD. 

TABLE 18—SO2 EMISSIONS PERFORMANCE DATA FOR NEW EGUS

Facility SO2 control technology In service date 

Maximum 

30-day SO2

emissions rate 

(lb/MWh) 

Weston 4 ...................................................................... Lime-based Spray Dryer .............................................. 2008 0.61 

Cross 4 ......................................................................... Wet Limestone FGD ..................................................... 2008 1.02 

TS Power Plant 1 ......................................................... Lime-based Spray Dryer .............................................. 2008 0.56 

Wygen II ....................................................................... Lime-based Spray Dryer .............................................. 2008 0.95 

Walter Scott Jr. Energy Center 4 ................................. Lime-based Spray Dryer .............................................. 2007 0.73 

Cross 3 ......................................................................... Wet Limestone FGD ..................................................... 2007 1.06 

Springerville TS3 .......................................................... Lime-based Spray Dryer .............................................. 2006 1.04 

HL Spurlock 3 ............................................................... Fluidized Bed Limestone Injection + Lime Injection .... 2005 1.45 


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25066 Federal Register / Vol. 76, No. 85 / Tuesday, May 3, 2011 / Proposed Rules 

The HL Spurlock 3 unit is the only 

new unit that burns high sulfur coal and 

that unit could meet the proposed 

alternate percent reduction standard. 

However, it would not be expected to 

achieve a numerical standard based on 

the performance of the other units. 

Further, with the exception of the Cross 

3 and 4 units, which burn medium 

sulfur bituminous coals, the remaining 

units burn lower-sulfur subbituminous 

coals. To provide the maximum 

emissions reduction, we further 

concluded that the alternate numerical 

standard should be as stringent as the 

numerical rates achieved by the units 

used to determine the percent reduction 

standard. If the alternate numerical 

standard were less stringent than the 

emissions rate achieved by the units 

used to determine the maximum percent 

reduction, those units would not be 

required to achieve the maximum 

percent reduction that has been 

demonstrated. In addition, the 

numerical standard should account for 

variability in today’s SO2 control 

technologies and provide sufficient 

compliance margin for owners/operators 

of new units burning medium sulfur 

coals to comply with the numerical 

standard and thereby provide an 

incentive to burn cleaner fuels. The 

sulfur concentrations in the flue gas of 

EGUs burning medium and low sulfur 

coals is more diffuse than for EGUs 

burning high sulfur coals, and it has not 

been demonstrated that units burning 

these coals would be able to achieve 97 

percent reduction of potential emissions 

on a continuous basis. We are proposing 

1.0 lb/MWh as the alternate numerical 

standard because it provides a 

comparable level of performance to the 

97 percent reduction requirement and 

satisfies criteria mentioned above. The 

numerical standard would require at 

least 80 percent reduction even from the 

lowest sulfur coals and would 

accommodate the use of traditional 

spray dryer scrubbers for owner/ 

operators of new units burning coal 

with uncontrolled SO2 emissions of up 

to approximately 1.6 lb/MMBtu. 

Based on the performance of the spray 

dryer at the Springerville TS3 unit, the 

numerical standard would provide 

sufficient flexibility such that an owner/ 

operator of an EGU could burn over 90 

percent of the subbituminous coals 

presently being used in combination 

with a spray dryer. This technology 

choice provides owners/operators the 

flexibility to minimize water use and 

associated waste water discharge, as 

well as reducing additional CO2 that is 

chemically created as part of the SO2

control device. Even though there is not 

necessarily an overall greenhouse (GHG) 

reduction from using a lime-based 

instead of a limestone-based scrubber, 

lime production facilities have 

relatively concentrated CO2 streams. 

Capture and storage of CO2 at the lime 

manufacturing facility could potentially 

be easier since separation of the CO2

would not be necessary, as is the case 

with an EGU exhaust gas. Owners/ 

operators of new and reconstructed 

units burning coals with higher 

uncontrolled SO2 emissions would 

either have to use IGCC with a 

downstream process to control sulfur 

prior to combustion, FBC, or a wet SO2

scrubbing system to comply with the 

proposed standard. The proposed limit 

would allow the higher sulfur coals 

(uncontrolled emissions of greater than 

approximately 3 lb SO2/MMBtu) to 

demonstrate compliance with the 97 

percent reduction requirement as an 

alternate to the numerical limit. We are 

soliciting comments on the proposed 

limit and are considering the range of 

100 to 150 ng/J (0.80 to 1.2 lb/MWh) for 

the final rule. 

Coal refuse (also called waste coal) is 

a combustible material containing a 

significant amount of coal that is 

reclaimed from refuse piles remaining at 

the sites of past or abandoned coal 

mining operations. Coal refuse piles are 

an environmental concern because of 

acid seepage and leachate production, 

spontaneous combustion, and low soil 

fertility. Units that burn coal refuse 

provide multimedia environmental 

benefits by combining the production of 

energy with the removal of coal refuse 

piles and by reclaiming land for 

productive use. Consequently, because 

of the unique environmental benefits 

that coal refuse-fired EGUs provide, 

these units warrant special 

consideration so as to prevent the 

amended NSPS from discouraging the 

construction of future coal refuse-fired 

EGUs in the U.S. 

Coal refuse from some piles has sulfur 

contents at such high levels that they 

present potential economic and 

technical difficulties in achieving the 

same SO2 standard that we are 

proposing for higher quality coals. 

Therefore, so as not to preclude the 

development of these projects, we are 

proposing to maintain the existing SO2

emissions standard for owners/operators 

of affected facilities combusting 75 

percent or more coal refuse on an 

annual basis. 

We are proposing to maintain the 

existing SO2 standard for modified units 

to preserve the use of spray dryer FGD. 

Existing units might not have access to 

adequate water for wet FGD scrubbers 

and it is not generally cost effective to 

upgrade existing spray dryer FGD 

scrubbers to a wet FGD scrubber. In 

addition, the 90 percent sulfur 

reduction for modified units also allows 

existing modified FBCs to comply 

without the addition of post-combustion 

SO2 controls. We have concluded that it 

is not generally cost effective to add 

additional post combustion SO2 controls 

for modified fluidized beds. 

3. Selection of the Proposed NOX

Standard 

In the 2006 final NSPS amendments 

(71 FR 9866), EPA concluded that 

advanced combustion controls were 

BDT. However, upon further review we 

have concluded this was not 

appropriate. Although select existing PC 

EGUs burning subbituminous coals have 

been able to achieve annual NOX

emissions of less than 1.0 lb/MWh (e.g., 

Rush Island, Newton), PC EGUs burning 

other coal types using only combustion 

controls have not demonstrated similar 

emission rates. Lignite-fired PC EGUs 

have only demonstrated an annual NOX

emissions rate of 1.7 lb/MWh (e.g., 

Martin Lake) and the best bituminous 

fired PC EGUs using only combustion 

controls are slightly higher than 2.0 lb/ 

MWh on an annual basis (e.g., Jack 

McDonough, Brayton Point, AES 

Cayuga, Genoa). The variability in NOX

control technologies results in a 

maximum 30-day average emissions rate 

typically being 1⁄4 to 1⁄3 higher than the 

annual average emissions rate. 

Therefore, it has not been demonstrated 

that owners/operators of PC EGUs 

burning any coal type using advanced 

combustion controls could comply with 

the existing NOX standard. 

After re-evaluating the performance, 

costs, and other environmental impacts 

of adding SCR in addition to 

combustion controls, we have 

concluded that combustion controls in 

combination with SCR represents BDT 

for continuous reduction of NOX

emissions from EGUs. Therefore, the 

regulatory baseline for NOX emissions is 

defined to be combustion controls in 

combination with the installation of 

SCR controls on all new PC-fired units. 

To assess the NOX control 

performance level of EGUs, we reviewed 

new and retrofitted units with post 

combustion NOX controls. Table 19 of 

this preamble shows the performance of 

several of the best performing units 

identified in our analysis of coal-fired 

EGUs. 


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TABLE 19—NOX PERFORMANCE DATA

Facility Time period 

Maximum 30-day 

NOX

emissions rate 

(lb/MWh) 

Boiler type & primary 

coal rank 

Havana 9 ............................................................................................................ 01/05–12/09 0.70 PC, Sub. 

Walter Scott Jr. 4 ............................................................................................... 04/07–12/09 0.58 PC, Sub. 

Mirant Morgantown 1 ......................................................................................... 06/07–12/09 0.65 PC, Bit. 

Mirant Morgantown 2 ......................................................................................... 06/08–12/09 0.70 PC, Bit. 

Roxboro 2 .......................................................................................................... 01/09–12/09 0.67 PC, Bit. 

Cardinal 1 ........................................................................................................... 01/09–12/09 0.38 PC, Bit. 

Cardinal 2 ........................................................................................................... 01/09–12/09 0.46 PC, Bit. 

Cardinal 3 ........................................................................................................... 01/09–12/09 0.45 PC, Bit. 

Muskingum River 5 ............................................................................................ 01/08–12/09 0.60 PC, Bit. 

John E Amos ..................................................................................................... 06/09–12/09 0.62 PC, Bit. 

Mitchell 1 ............................................................................................................ 01/09–12/09 0.59 PC, Bit. 

Mitchell 2 ............................................................................................................ 01/09–12/09 0.54 PC, Bit. 

Weston 4 ............................................................................................................ 07/08–12/09 0.48 PC, Sub. 

H L Spurlock 4 ................................................................................................... 05/09–12/09 0.67 CFB, Bit. 

Wansley 1 .......................................................................................................... 02/09–12/09 0.67 PC, Bit. 

Wansley 2 .......................................................................................................... 01/09–12/09 0.59 PC, Bit. 

Nebraska City 2 ................................................................................................. 05/09–12/09 0.60 PC, Sub. 

TS Power 1 ........................................................................................................ 07/08–12/09 0.49 PC, Sub. 

Note: PC = pulverized coal. 

CFB = circulating fluidized bed. 

Sub = subbituminous coal. 

Bit = bituminous coal. 

All of the units listed in Table 19 of 

this preamble have demonstrated 0.70 

lb/MWh is achievable. Even though 

some units are achieving a lower 

emissions rate, the majority of units 

listed in Table 19 of this preamble have 

less than a year of operating data. 

Proposing a more stringent standard 

might not provide sufficient compliance 

margin to account for expected 

variability in the long term performance 

of NOX controls. Although not all 

affected facilities using SCR are 

currently achieving an emissions rate of 

0.70 lb/MWh, all major boiler designs 

have demonstrated combustion controls 

that are able to reduce NOX emissions 

to levels where the addition of SCR (or 

design modifications and operating 

changes to existing SCR) would allow 

compliance with a NOX emissions rate 

of 0.70 lb/MWh. We are therefore 

selecting 88 ng/J (0.70 lb/MWh) as the 

proposed NOX standard for new, 

modified, and reconstructed units. The 

range of values we are currently 

considering for the final rule is 76 to 

110 ng/J (0.60 to 0.90 lb/MWh). 

Combustion optimization for overall 

environmental performance is a balance 

between boiler efficiency, NOX

emissions, and CO emissions. Although 

a well operated boiler using combustion 

controls can achieve a high efficiency 

and both low NOX and CO emissions, 

the pollutant emissions rates are related. 

For example, NOX reduction techniques 

that rely on delayed combustion and 

lower combustion temperatures tend to 

increase incomplete combustion and 

result in a corresponding increase in CO 

emissions. Conversely, high levels of 

excess air can be used to control CO 

emissions. However, high levels of 

excess air increase NOX emissions. 

The proposed BDT for NOX is 

combustion controls plus the 

application of SCR. However, there are 

several approaches an owner/operator 

could use to comply with an individual 

NOX standard. One approach would be 

to use combustion controls to minimize 

the formation of NOX to the maximum 

extent possible and then use a less 

efficient SCR systems. This tends to 

result in high CO emissions and 

significant unburned carbon in the fly 

ash. From an environmental 

perspective, we would prefer that 

owners/operators select combustion 

controls that result in slightly higher 

NOX emissions without substantially 

increasing CO emissions, and use 

regular efficiency SCR systems. As 

compared to establishing individual 

pollutant emission standards, a 

combined NOX plus CO standard 

accounts for variability in combustion 

properties and provides additional 

compliance strategy options for the 

regulated community, while still 

providing an equivalent level of 

environmental protection. In addition, a 

combined standard provides additional 

flexibility for owners/operators to 

minimize carbon and/or ammonia in the 

fly ash such that the fly ash could still 

be used in beneficial reuse projects. 

In addition, an overly stringent NOX

standard has the potential to impede the 

ability of an owner/operator of an EGU 

from operating at peak efficiency 

thereby minimizing GHG emissions. A 

combined standard on the other hand 

allows owners/operators additional 

flexibility to operate at or near peak 

efficiency. A combined standard would 

also allow the regulated community to 

work with the local environmental 

permitting agency to minimize the 

pollutant of most concern for that 

specific area. We have previously 

established a combined NOX plus CO 

combined emissions standard for 

thermal dryers at coal preparation 

plants (40 CFR part 60, subpart Y). 

To assess the combined NOX/CO 

performance level of EGUs, we 

requested data from units identified by 

the 2010 ICR as using certified CO 

CEMS and achieving the existing NSPS 

NOX standard of 1.0 lb/MWh gross 

output. We continue to be interested in 

additional NOX and CO certified CEMS 

data from EGUs and comparable units 

using that are achieving the existing 

NSPS NOX standard of 1.0 lb/MWh 

gross output. Table 20 of this preamble 

shows the performance of the units 

identified in our analysis. 


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TABLE 20—NOX/CO PERFORMANCE DATA

Facility Time period 

Maximum 

30-day NOX

+ CO emissions rate 

(lb/MWh) 

Maximum 

30-day 

NOX/CO 

emissions 

rate 

(lb/MWh) 

Boiler type & primary coal 

rank 

Northside 1 ..................................................................................... 01/05–12/09 1.1 0.89/0.29 CFB, PC. 

Northside 2 ..................................................................................... 01/05–12/09 1.1 0.93/0.46 CFB, PC. 

Walter Scott, Jr. 4 .......................................................................... 04/07–12/09 0.95 0.58/0.42 PC, Sub. 

WA Parish 5 ................................................................................... 09/05–12/09 1.1 0.66/0.62 PC, Sub. 

WA Parish 6 ................................................................................... 06/05–12/09 1.2 0.76/0.81 PC, Sub. 

WA Parish 7 ................................................................................... 06/05–12/09 1.8 0.53/1.4 PC, Sub.

WA Parish 8 ................................................................................... 04/06–12/09 1.5 0.42/1.1 PC, Sub.

HL Spurlock 3 ................................................................................ 01/09–12/09 1.4 0.83/0.61 CFB, Bit. 

HL Spurlock 4 ................................................................................ 05/09–12/09 1.4 0.67/0.70 CFB, Bit. 

TS Power 1 .................................................................................... 04/08–12/09 0.80 0.49/0.47 PC, Sub. 

Note: PC = pulverized coal or petroleum coke. 

CFB = circulating fluidized bed. 

Sub = subbituminous coal. 

Because CO has not historically been 

a primary pollutant of concern for 

owners/operators of EGUs, it has not 

necessarily been a significant factor 

when selecting combustion control 

strategies and has not typically been 

continuously monitored. Due to the 

limited availability of CO CEMS data 

and to account for potential variability 

we are not aware of, we have concluded 

it is appropriate in this case to propose 

a standard with sufficient compliance 

margin to not inhibit the ability of 

owner/operators of EGUs to comply 

with NOX specific best available control 

technology (BACT) requirements or 

requirements that result from 

compliance with EPA’s proposed 

Transport Rule. Although 2 of the units 

shown in Table 21 of this preamble are 

operating below 1.0 lb/MWh, there are 

4 that are operating in the 1.1 to 1.2 lb/ 

MWh range. To provide a compliance 

margin and to account for situations 

where NOX might be more of a priority 

pollutant than CO, we are proposing a 

combined standard of 1.2 lb/MWh. This 

margin is apparent when comparing the 

HL Spurlock and Northside units. These 

fluidized bed boilers use selective noncatalytic reduction (SNCR) to reduce 

NOX emissions. Although the HL 

Spurlock units perform better in terms 

of NOX, the combustion controls result 

in higher CO and combined NOX/CO 

emission rates. In determining the 

appropriate combined standard for 

owner/operators of modified units, we 

used the data from the WA Parish units. 

All four of these units have been 

retrofitted to comply with stringent NOX

requirements. Owners/operators of 

modified units could potentially have a 

more difficult time controlling both 

NOX and CO because the configuration 

of the boiler cannot be changed. All 4 

of the WA Parish units have 

demonstrated that a standard of 230 

ng/J (1.8 lb/MWh) is achievable and we 

are, therefore, proposing that standard 

for modified units. We are requesting 

comment on these standards and are 

considering a range of 130 to 180 

ng/J (1.0 to 1.4 lb/MWh) for new and 

reconstructed units and of 180 to 230 

ng/J (1.4 to 1.8 lb/MWh) for modified 

units. 

Another potential GHG benefit, 

beyond boiler efficiency, of a combined 

NOX + CO standard is the flexibility to 

minimize nitrous oxide (N2O) 

emissions. Formation of N2O during the 

combustion process results from a 

complex series of reactions and is 

dependent upon many factors. 

Operating factors impacting N2O 

formation include combustion 

temperature, excess air, and sorbent 

feed rate. The N2O formation resulting 

from SNCR depends upon the reagent 

used, the amount of reagent injected, 

and the injection temperature. Adjusting 

any of these factors can impact CO and/ 

or NOX emissions, and a combined 

standard provides an owner/operator 

the maximum flexibility to reduce 

overall criteria and GHG emissions. 

Pulverized coal boilers tend to operate 

at sufficiently high temperatures so as to 

not generally have significant N2O 

emissions. On the other hand, fluidized 

bed boilers operate at lower 

temperatures and can have measurable 

N2O emissions. However, the fuel 

flexibility benefit (i.e., the ability to 

burn coal refuse and biomass) of 

fluidized bed boilers can help to offset 

the increase in N2O emissions. 

4. Commercial Demonstration Permit 

The commercial demonstration 

permit section of the EGU NSPS was 

included in the original rulemaking in 

1979 (44 FR 33580) to assure that the 

NSPS did not discourage the 

development of new and promising 

technologies. In the 1979 rule, the 

Administrator recognized that the 

innovative technology waiver 

provisions under CAA section 111(j) are 

not adequate to encourage certain 

capital intensive technologies. (44 FR 

33580.) Under the innovative 

technology provisions, the 

Administrator may grant waivers for a 

period of up to 7 years from the date of 

issuance of a waiver or up to 4 years 

from the start of operation of a facility, 

whichever is less. The Administrator 

recognized that this time frame is not 

sufficient for amortization of highcapital-cost technologies. The 

commercial demonstration permit 

section established less stringent 

requirements for initial full-scale 

demonstration plants that received a 

permit in order to mitigate the potential 

impact of the rule on emerging 

technologies and insure that standards 

did not preclude the development of 

such technologies. 

The authority to issue these permits 

was predicated on the DC Circuit 

Court’s opinion in Essex Chemical Corp. 

v. Ruckelshaus, 486 F. 2d 42 (DC Cir. 

1973); NSPS should be set to avoid 

unreasonable costs or other impacts. 

Standards requiring a high level of 

performance, such as the proposed 

standards for PM, SO2, and NOX, might 

discourage the continued development 

of some new technologies. Owners/ 

operators may view it as too risky to use 

new and untried or unproven 

technologies that have the potential to 

achieve greater continuous emission 

reductions than those required to be 

achieved under the new standards or 

achieve those reductions at a reduced 

cost. Thus, to encourage the continued 

development of new technologies that 


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show promise in achieving levels of 

performance comparable to those of 

existing technologies, but at lower cost 

or with other offsetting environmental 

or energy benefits, special provisions 

are needed which encourage the 

development and use of new 

technologies, while ensuring that 

emissions will be minimized. 

To mitigate the potential impact on 

emerging technologies, EPA is 

proposing to maintain similar standards 

to those finalized in 2006 for 

demonstration plants using innovative 

technologies. This should insure that 

the amended standards do not preclude 

the development of new technologies 

and should compensate for problems 

that may arise when applying them to 

commercial-scale units. Under the 

proposal, the Administrator (in 

consultation with DOE) would issue 

commercial demonstration permits for 

the first 1,000 MW of full-scale 

demonstration units of pressurized 

fluidized bed technology and EGUs 

using a multi-pollutant pollution 

control technology. Owners/operators of 

these units that are granted a 

commercial demonstration permit 

would be exempt from the amended 

standards and would instead be subject 

to less stringent emission standards. The 

proposed commercial demonstration 

permit standards for SO2 and NOX are 

similar to those finalized in 2006 and 

would avoid weakening existing 

standards while providing flexibility for 

innovative and emerging technologies. 

As discussed earlier, the proposed total 

PM standard of 0.034 lb/MMBtu 

approximates an equivalent stringency 

as the 2006 filterable PM standard of 

0.015 lb/MMBtu. In addition, the first 

1,000 MW of equivalent electrical 

capacity using advanced combustion 

controls to reduce NOX emissions 

would be subject to an emissions 

standard of 1.0 lb/MWh (or 1.4 (lb NOX

+ CO)/MWh). 

The reason we selected these 

particular technologies is as follows. 

Multi-pollutant controls (e.g., the 

Airborne Process TM, the CEFCO 

process, Eco Power’s COMPLY 2000, 

Powerspan’s ECO®, ReACTTM, 

Skyonic’s SkyMine®, TOPS;E 

SNOX TM, and the Pahlman process 

technology developed by Enviroscrub) 

offer the potential of reduced 

compliance costs and improved overall 

environmental performance. In 

addition, for boilers with exhaust 

temperatures that are too low for SCR 

(i.e., fluidized bed boilers) multipollutant controls are an alternative to 

SNCR. As discussed above, the use of 

SNCR can increase N2O emissions. 

Since multi-pollutant controls use a 

different mechanism to reduce NOX

emissions, they do not necessarily result 

in additional N2O formation. However, 

guaranteeing that the technologies could 

achieve the proposed standards on a 

continuous basis might discourage the 

deployment and demonstration of these 

technologies at EGUs. Pressurized 

fluidized bed technology has the 

potential to improve the efficiency and 

reduce the environmental impact of 

using coal to generate electricity. 

However, it is still a relatively 

undeveloped technology and has only 

been deployed on a limited basis 

worldwide. Allowing new pressurized 

beds to demonstrate compliance with 

slightly less stringent standards will 

help assure the NSPS does not 

discourage the development of this 

technology. Advanced combustion 

controls allow for the possibility of 

developing EGUs with low NOX

emissions while minimizing the need to 

install and operate SNCR or SCR. 

Advanced combustion controls reduce 

compliance costs, parasitic energy 

requirements, and ammonia emissions. 

Allowing the Administrator to approve 

commercial demonstration permits 

would limit regulatory impediments to 

improvements in combustion controls. 

If the Administrator subsequently finds 

that a given emerging technology (taking 

into consideration all areas of 

environmental impact, including air, 

water, solid waste, toxics, and land use) 

offers superior overall environmental 

performance, alternative standards 

could then be established by the 

Administrator. Technologies considered 

as nothing more than modified versions 

of existing demonstrated technologies 

will not be viewed as emerging 

technologies and will not be approved 

for a commercial demonstration permit. 

We are requesting comment on 

additional technologies that should be 

considered and the maximum 

magnitude of the demonstration 

permits. 

5. Other Exemptions 

Because filterable PM emissions are 

generally negligible for boilers burning 

natural gas or low sulfur oil, eliminating 

the PM standard for owners/operators of 

natural gas and low sulfur oil-fired 

EGUs would both help harmonize the 

various steam generating unit NSPS and 

lower the compliance burden without 

increasing emissions. Similarly, 

eliminating the opacity standard for 

owners/operators of natural gas-fired 

EGUs would reduce testing and 

monitoring requirements that do not 

result in any emissions benefit. 

As municipal solid waste (MSW) 

combustors and CISWI units increase in 

size it is possible that they could 

generate sufficient electricity to become 

subject to the EGU NSPS. We have 

concluded that it is more appropriate to 

regulate these units under the CAA 

section 129 regulations and are, 

therefore, proposing to exempt owners/ 

operators of affected facilities subject to 

the standards of performance for large 

MSW combustors (40 CFR part 60, 

subpart Eb) and CISWI (40 CFR part 60, 

subpart CCCC) from complying with the 

otherwise applicable standards for 

pollutants that those subparts address. 

The PM, SO2, and NOX standards in 40 

CFR part 60, subpart Eb, are averaged 

over a daily basis and the PM, SO2, and 

NOX standards in 40 CFR part 60, 

subpart CCCC, do not require CEMS and 

are based on performance test data. The 

standards are either approximately 

equivalent to or more stringent than the 

present standards in 40 CFR part 60, 

subpart Da, so this proposed 

amendment would simplify compliance 

for owner/operators of MSW combustors 

and CISWI without an increase in 

emissions. 

Similarly, in the final 2007 steam 

generating unit amendments (72 FR 

32,710) we inadvertently expanded the 

applicability of 40 CFR part 60, subpart 

Db, to include industrial boilers 

combusting black liquor and distillate 

oil at Kraft pulp mills. Even though the 

distillate oil is generally low sulfur and 

would otherwise be exempt from the 

PM standards in 40 CFR part 60, subpart 

Db, the boilers use ESPs and the 

addition of ‘‘not using a postcombustion technology (except a wet 

scrubber) to reduce SO2 or PM 

emissions’’ to the oil-fired exemption 

inadvertently expanded the 

applicability to owners/operators of 

boilers currently subject to the 

standards of performance for Kraft pulp 

mills (40 CFR part 60, subpart BB). 

Because 40 CFR part 60, subpart BB, 

includes a PM standard, we have 

concluded it is more appropriate to only 

regulate PM emissions from these units 

under 40 CFR part 60, subpart BB, and 

are, therefore, proposing to exempt 

these units from the PM standard under 

40 CFR part 60, subpart Db. The PM 

standard in 40 CFR part 60, subpart BB, 

is approximately equivalent in 

stringency to the one in 40 CFR part 60, 

subpart Db, prior to the recent 

amendments, so this proposed 

amendment would simplify compliance 

for owner/operators of Kraft pulp mills 

without an increase in emissions. 

We are also proposing to exempt 

owners/operators of IBs that meet the 

applicability requirements and that are 

complying with the SO2 standard in 40 

CFR part 60, subpart Ja (standards of 


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performance for petroleum refineries) 

from complying with the otherwise 

applicable SO2 limit in 40 CFR part 60, 

subpart Db. The SO2 standard in 40 CFR 

part 60, subpart Ja, is more stringent 

than in 40 CFR part 60, subpart Db, so 

this proposed amendment would 

simplify compliance for owner/ 

operators of petroleum refineries 

without an increase in pollutant 

emissions. 

C. Changes to the Affected Facility 

The present definition of a steam 

generating unit under 40 CFR part 60, 

subpart Da, starts at the coal bunkers 

and ends at the stack breeching. It 

includes the fuel combustion system 

(including bunker, coal pulverizer, 

crusher, stoker, and fuel burners, as 

applicable), the combustion air system, 

the steam generating system (firebox, 

boiler tubes, etc.), and the draft system 

(excluding the stack). This definition 

works well for traditional coal-fired 

EGUs, but does not account for potential 

efficiency improvements that have 

become available since 40 CFR part 60, 

subpart Da, was originally promulgated 

and are recognized through the use of 

output-based standards. 

The proposed rule revision to include 

integrated CTs and/or fuel cells in the 

definition of a steam generating unit 

would increase compliance flexibility 

and decrease costs. Although we are not 

aware of any EGUs that have presently 

integrated either device, using exhaust 

heat for reheating or preheating boiler 

feedwater, preheating combustion air, or 

using the exhaust directly in the boiler 

to generate steam has high theoretical 

incremental efficiencies. In addition, 

using exhaust heat to reheat boiler 

feedwater would minimize the steam 

otherwise extracted from the steam 

turbine used for the reheating process 

and increase the theoretical electric 

output for an equivalent sized boiler. 

Because the exhaust from either an 

integrated CT or fuel cell would likely 

not be exhausted through the primary 

boiler stack, we are requesting comment 

on the appropriate emissions 

monitoring for these separate stacks. 

Because these emissions would likely be 

relatively small compared to the boiler, 

we are considering allowing emissions 

to be estimated using procedures that 

are similar to those used in the acid rain 

trading programs as an alternative to an 

NOX CEMS. The CT or fuel cell 

emissions and electric output would be 

added to the boiler/steam turbine 

outputs. 

D. Additional Proposed Amendments 

Petroleum Coke. Petroleum coke, a 

carbonaceous material, is a by-product 

residual from the thermal cracking of 

heavy residual oil during the petroleum 

refining process and is a potentially 

useful boiler fuel. It has a superior 

heating value and lower ash content 

than coal and has historically been 

priced at a discount compared to coal. 

However, depending on the original 

crude feedstock, it may contain greater 

concentrations of sulfur and metals. At 

the time 40 CFR part 60, subpart Da, 

was originally promulgated, petroleum 

coke was not considered to be ‘‘created 

for the purpose of creating useful heat’’ 

and, hence, was not considered a ‘‘fossil 

fuel.’’ However, we have concluded that 

because petroleum coke has similar 

physical characteristics to coal, owners/ 

operators of EGUs burning petroleum 

coke can cost effectively achieve the 

proposed standards. Due to the 

increased use of heavier crudes and 

more efficient processing of refinery 

residuals, U.S. and worldwide 

production of petroleum coke is 

increasing and is expected to continue 

to grow. Therefore, we expect owners/ 

operators of EGUs to increase their use 

of petroleum coke in the future. 

Consistent with the EGU NESHAP, we 

are proposing to add petroleum coke to 

the definition of petroleum. 

We are requesting comment on 

whether petroleum coke should be 

added to the definition of coal instead 

of petroleum. Both 40 CFR part 60, 

subparts Db and Dc, the large and small 

IB NSPS, include petroleum coke under 

the definition of coal. Including 

petroleum coke under coal would be 

consistent with the IB NSPS. However, 

the proposed emission standards are 

fuel neutral and because the revised 

definition would only apply to affected 

facilities that begin construction, 

modification, or reconstruction after the 

proposal date the impact on the 

regulated community would be the 

same if we added petroleum coke to the 

definition of coal as it would if we 

added it to the definition of petroleum. 

Continuous Opacity Monitoring 

Systems (COMS). We have concluded 

that a BLDS and an ESP predictive 

model provide sufficient assurance that 

the filterable PM control device is 

operating properly such that a COMS is 

no longer necessary. Allowing this 

flexibility across the various steam 

generating unit NSPS would increase 

flexibility and decrease compliance 

costs without reducing environmental 

protection. 

Titles of 40 CFR part 60, subparts D 

and Da. We are proposing to simplify 

the titles, but not amending the 

applicability, of 40 CFR part 60, 

subparts D and Da. The end of the titles 

‘‘for Which Construction Is Commenced 

After August 17, 1971’’ and ‘‘for Which 

Construction is Commenced After 

September 18, 1978’’ respectively are 

unnecessary and potentially confusing. 

E. Request for Comments on the 

Proposed NSPS Amendments 

We request comments on all aspects 

of the proposed amendments. All 

significant comments received will be 

considered in the development and 

selection of the final amendments. We 

specifically solicit comments on 

additional amendments that are under 

consideration. These potential 

amendments are described below. 

Net Output. The current output-based 

emission limit for PM, SO2, and NOX

uses gross output, and the proposal 

includes standards that are based on 

gross energy output. In general, about 5 

percent of station power is used 

internally by parasitic energy demands, 

but these parasitic loads vary on a 

source-by-source basis. To provide a 

greater incentive for achieving overall 

energy efficiency and minimizing 

parasitic loads, we would prefer to base 

output-based standards on net-energy 

output. However, it is our 

understanding that requiring a net 

output approach could result in 

monitoring difficulties and 

unreasonable monitoring costs at 

modified units. Demonstrating 

compliance with net-output based 

standards could be particularly 

problematic at existing units with both 

affected and unaffected facilities and 

units with common controls and/or 

stacks. Monitoring net output for new 

and reconstructed units can, on the 

other hand, be designed into the facility 

at low costs. To recognize the 

environmental benefit of overall 

environmental performance, we are 

considering establishing a net outputbased emission standards for new and 

reconstructed units in the final rule in 

lieu of gross output-based standards. 

In addition to recognizing the 

environmental benefit of minimizing the 

internal parasitic energy demand 

generally, net output based standards 

would serve to further recognize the 

environmental benefits of the use of 

supercritical steam conditions because 

parasitic loads tend to be lower for units 

using supercritical steam conditions 

compared to subcritical steam 

conditions. Furthermore, although the 

gross efficiencies of IGCC units are 

projected to be several percentage points 

higher than a comparable PC facility 

using supercritical steam conditions, the 

parasitic energy demands at IGCC units 

are expected to be much higher at 

approximately 15 percent. 

Consequently, on a net output basis, the 


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efficiencies are comparable. Because we 

do not have continuous net output data 

available, we are considering assuming 

5 percent parasitic losses to convert the 

gross output values to net output. We 

are requesting comments on the 

appropriate conversion factor. 

Combined Heat and Power. We are 

requesting comment on whether it is 

appropriate to recognize the 

environmental benefit of electricity 

generated by CHP units by accounting 

for the benefit of on-site generation 

which avoids losses from the 

transmission and distribution of the 

electricity. Actual line losses vary from 

location to location, but if we adopt this 

provision in the final rule, we are 

considering a benefit of 5 percent 

avoided transmission and distribution 

losses when determining the electric 

output for CHP units. To assure that 

only well balanced units would be 

eligible; this provision would be 

restricted to units where the useful 

thermal output is at least 20 percent of 

the total output. 

Opacity. We are requesting comment 

on the appropriate opacity monitoring 

procedures for owners/operators of 

affected facilities that are subject to an 

opacity standard but are not required to 

install a COMS. The present monitoring 

requirements as amended on January 20, 

2011 (76 FR 3,517) require Method 9 

performance testing every 12 months for 

owners/operators of affected facilities 

with no visible emissions, performance 

testing every 6 months for owners/ 

operators of affected facilities with 

maximum opacity readings of 5 percent 

of less, performance testing every 3 

months for owners/operators of affected 

facilities with maximum opacity 

readings of between 5 to 10 percent, and 

performance testing every 45 days for 

owners/operators of affected facilities 

with maximum opacity readings of 

greater than 10 percent. We are 

requesting comment on revising the 

schedule to require owners/operators of 

affected facilities with maximum 

opacity readings of 5 percent or less to 

conduct annual performance testing. To 

further reduce the compliance burden 

for owners/operators of affected 

facilities that intermittently use backup 

fuels with opacity of 5 percent or less 

(i.e., natural gas with distillate oil 

backup), we are requesting comment on 

allowing Method 9 performance testing 

to be delayed until 45 days after the 

next day that a fuel with an opacity 

standard is combusted. The required 

performance testing for owners/ 

operators of affected facilities with 

maximum opacity readings between 5 to 

10 percent would be required to be 

performed within 6 months. The 

required performance testing for 

owners/operators of affected facilities 

with maximum opacity readings greater 

than 10 percent would be required to be 

performed within 3 months. In addition, 

the alternate Method 22 visible 

observation approach requires 30 

operating days of no visible emissions to 

qualify for the reduced monitoring 

procedures. We are requesting comment 

on only requiring either 5 or 10 days of 

observation with no visible emissions to 

qualify for the reduced periodic 

monitoring. 

In general, the level of filterable PM 

emissions and the resultant opacity 

from oil-fired steam generating units is 

a function of the completeness of fuel 

combustion as well as the ash content 

in the oil. Distillate oil contains 

negligible ash content, so the filterable 

PM emissions and opacity from 

distillate oil-fired steam generating units 

are primarily comprised of carbon 

particles resulting from incomplete 

combustion of the oil. Naturally low 

sulfur crude oil and desulfurized oils 

are higher quality fuels and exhibit 

lower viscosity and reduced asphaltene, 

ash, and sulfur content, which result in 

better atomization and improved overall 

combustion properties. To provide 

additional flexibility and decrease the 

compliance burden on affected 

facilities, we are requesting comment on 

whether the opacity standard should be 

eliminated for owners/operators of 

affected facilities burning ultra low 

sulfur (i.e., 15 ppm sulfur) distillate oil. 

We are also requesting comment on 

amending the opacity requirements for 

owners/operators of affected facilities 

using PM CEMS, but not complying 

with the PM standard under 40 CFR part 

60, subpart Da. Owners/operators of 

these facilities are subject to an opacity 

standard and are required to 

periodically monitor opacity. We are 

requesting comment on the 

appropriateness of waiving all opacity 

monitoring for owners/operators of 

these affected facilities. In addition, we 

are also requesting comment on 

allowing owners/operators of 40 CFR 

part 60, subpart D, affected facilities that 

opt to comply with the 40 CFR part 60, 

subpart Da, PM standard and qualify for 

the corresponding opacity exemption to 

opt back out. (Under the existing rule, 

once a 40 CFR part 60, subpart D, 

affected facility opts to comply with the 

40 CFR part 60, subpart Da, PM 

standard in order to qualify for the 

corresponding opacity exemption, it 

cannot subsequently opt to go back to 

complying with the 40 CFR part 60, 

subpart D, PM standard.) Finally, we are 

requesting comment on the 

appropriateness of eliminating the 

opacity standard for owners/operators of 

40 CFR part 60, subpart D, affected 

facilities using PM CEMS even if they 

are not complying with the 40 CFR part 

60, subpart Da, PM standard. Consistent 

with paragraph 40 CFR 60.11(e), as long 

as these facilities demonstrate 

continuous compliance with the 

applicable PM standard on a 3-hour 

average, the opacity standard would not 

apply. 

In addition, we are requesting 

comment on eliminating the opacity 

standard for owners/operators of 

affected facilities complying with a total 

PM standard of 15 ng/J (0.034 lb/ 

MMBtu) or less that use control 

equipment parameter monitoring or 

some other continuous monitoring 

approach to demonstrate compliance 

with that standard. Based on the PM 

performance test data collected as part 

of the 2010 ICR, at this total PM 

emissions rate the filterable portion is 

expected to be significantly lower than 

the original 40 CFR part 60, subpart Da, 

filterable PM standard, 0.030 lb/MMBtu. 

As described in the 2006 NSPS 

amendments, at filterable PM emissions 

at this level, opacity is less useful and 

eliminating the standards would 

simplify compliance without decreasing 

environmental protection. 

IGCC Units. We are requesting 

comment on whether an IGCC unit that 

co-produces hydrocarbons or hydrogen 

should be subject to the CT NSPS 

instead of the EGU NSPS. The original 

rationale for including IGCC units in the 

EGU NSPS is that it is simply another 

process for converting coal to electricity. 

However, an IGCC that co-produces 

hydrocarbons or hydrogen would 

convert a substantial portion of the 

original energy in the coal to useful 

chemicals instead of to measurable 

useful electric and thermal output. 

Using net-output based standards in this 

situation would be difficult because a 

portion of the parasitic load would be 

attributed to the production of the 

useful chemicals and it would not be 

possible to apportion this easily. To 

avoid owners/operators from producing 

a small amount of hydrocarbons/ 

hydrogen to avoid being subject to 40 

CFR part 60, subpart Da, we are 

requesting comment on the percentage 

of coal that must be converted to useful 

chemical products to quality for 

regulation under the stationary CT 

NSPS. We are presently considering 

between 10 to 20 percent. We are also 

requesting comment on whether there is 

a way to effectively account for the 

parasitic losses such attributable to 

production of the useful chemicals. 

Elimination of Existing References. To 

simplify compliance and improve the 


jlentini on DSKJ8SOYB1PROD with PROPOSALS2
25072 Federal Register / Vol. 76, No. 85 / Tuesday, May 3, 2011 / Proposed Rules 

readability of 40 CFR part 60, subpart 

Da, we are requesting comment on 

deleting the ‘‘emergency condition’’ 

requirement for the SO2 standard 

exemption, references to percent 

reductions for NOX and PM, references 

to solvent refined coal, and the existing 

commercial demonstration permit 

references. The emergency condition 

requirement was originally included in 

40 CFR part 60, subpart Da, as an 

alternative to excluding periods of 

malfunction. The provision was 

intended to avoid power supply 

disruptions while also minimizing 

operation of affected facilities without 

operation of SO2 controls. However, the 

reliability of FGD technology has been 

demonstrated since 40 CFR part 60, 

subpart Da, was originally promulgated 

and malfunctions are uncommon 

events. Furthermore, the Transport Rule 

provides a financial incentive to operate 

SO2 control equipment at all times. 

Therefore, we would delete references 

to the emergency condition requirement 

and simply exclude periods of 

malfunction from the SO2 standard for 

owners/operators of affected facilities 

presently subject to 40 CFR part 60, 

subpart Da. 

The 1990 CAA amendments removed 

the requirement that standards be based 

on a percent reduction. The percent 

reduction requirements for NOX and PM 

have been superseded by the numerical 

limits for owners/operators of existing 

units and deleting these references 

would improve the readability of the 

subpart. Similarly, we are not aware of 

any affected facility burning solvent 

refined coal or operating under the 

existing commercial demonstration 

permit. Because these provisions have 

been superseded, deleting these 

references would improve the 

readability of the subpart. 

The IB NSPS currently does not credit 

fuel pretreatment toward compliance 

with the SO2 percent reduction standard 

unless the fuel pretreatment results in a 

50 percent or greater reduction in the 

potential SO2 emissions rate and results 

in an uncontrolled SO2 emissions rate of 

equal to less than 0.60 lb/MMBtu. We 

are requesting comment on whether 

these restrictions discourage the 

development and use of cost-effective 

fuel pretreatment technologies and 

increase costs to the regulated 

community. To the extent that this 

restriction could be eliminated without 

adversely impacting protection of the 

environment, we are considering 

eliminating this restriction. We are also 

requesting comment on other provisions 

in the steam generating unit NSPS that 

could be eliminated to reduce regulatory 

burden without decreasing 

environmental protection. 

The large IB NSPS (40 CFR part 60, 

subpart Db) currently includes 

regulatory language for standards for 

boilers burning MSW. This language 

was included to assure the broad 

applicability of 40 CFR part 60, subpart 

Db. However, subsequent to the original 

promulgation of 40 CFR part 60, subpart 

Db, EPA promulgated specific standards 

for MWCs and exempted owners/ 

operators of MWCs from 40 CFR part 60, 

subpart Db. We are requesting comment 

on deleting all references to MSW in 40 

CFR part 60, subpart Db. This would 

simplify compliance and readability of 

the rule without increasing emissions to 

the environment. Owners/operators of 

these units would still be subject to 

emission standards under 40 CFR part 

60, subpart Db, if they stop burning 

MSW. 

Coal Refuse. The high ash and 

corresponding low Btu content of coal 

refuse results in lower efficiencies than 

comparable coal-fired EGUs. Therefore, 

we are requesting comment on the 

environmental impact of 

subcategorizing coal refuse-fired EGUs 

and maintaining the existing NOX

standard of 1.0 lb/MWh (or 1.4 lb [NOX

+ CO]/MWh) for owners/operators of 

these units. 

Temporary Boilers. On occasion, 

owners/operators of industrial facilities 

need to bring in temporary boilers for 

steam production for short-term use 

while the primary steam boilers are not 

available. The existing testing and 

monitoring requirements for IB may not 

be appropriate for temporary boilers 

used for less than 30 days. We intend 

to establish alternate testing and 

monitoring requirements for owners/ 

operators of temporary IBs and are 

requesting comment on the appropriate 

requirements. 

IX. Summary of Cost, Environmental, 

Energy, and Economic Impacts of This 

Proposed NSPS 

In setting the standards, the CAA 

requires us to consider alternative 

emission control approaches, taking into 

account the estimated costs and 

benefits, as well as the energy, solid 

waste and other effects. EPA requests 

comment on whether it has identified 

the appropriate alternatives and 

whether the proposed standards 

adequately take into consideration the 

incremental effects in terms of emission 

reductions, energy and other effects of 

these alternatives. EPA will consider the 

available information in developing the 

final rule. 

The costs, environmental, energy, and 

economic impacts are typically 

expressed as incremental differences 

between the impacts on owners/ 

operators of units complying with the 

proposed amendments relative to 

complying with the current NSPS 

emission standards (i.e., baseline). 

However, for EGUs this would not 

accurately represent actual costs and 

benefits of the proposed amendments. 

Requirements of the NSR program often 

result in new EGUs installing controls 

beyond what is required by the existing 

NSPS. In addition, owners/operators of 

new EGUs subject to the requirements of 

the Transport Rule will likely elect to 

minimize operating costs by operating at 

SO2 and NOX emission rates lower than 

what is required by the existing NSPS. 

Finally, the proposed EGU NESHAP PM 

and SO2 standards for new EGUs are as 

stringent as or more stringent than the 

proposed NSPS amendments, and we 

have concluded that there are no costs 

or benefits associated with these 

amendments. We are requesting 

comment on this conclusion. 

To establish the regulatory baseline 

for NOX emissions, we reviewed annual 

NOX emission rates for units operating 

at levels below the existing NSPS NOX

standard that commenced operation 

between 2005 and 2008 and that 

reported both NOX emissions and gross 

electric output data to CAMD. The 2009 

average annual NOX emissions rate for 

these units was 0.61 lb/MWh. To 

account for the variability in 

performance of presently used NOX

controls, we concluded that 30-day 

averages are typically 1⁄4 to 1⁄3 higher 

than annual average emission rates and 

used 0.80 lb/MWh as the baseline. This 

represents an approximate 12 percent 

reduction in the growth of NOX

emissions from new units that would be 

subject to the proposed standards. We 

have concluded that a combined NOX/ 

CO standard would have similar 

impacts because CO controls are based 

on readily available combustion 

controls. The additional monitoring 

costs for a combined standard would 

include additional CEMS certification 

because many facilities currently have 

CO CEMS for operational control. 

Although multiple coal-fired EGUs 

have recently commenced operation and 

several are currently under 

construction, no new coal-fired EGUs 

have commenced construction in either 

2009 or 2010. In addition, forecasts of 

new generation capacity from both the 

EIA and the Edison Electric Institute do 

not project any new coal-fired EGUs 

being constructed in the short term. 

This is an indication that, in the near 

term, few new coal-fired EGUs will be 

subject to the NSPS amendments. 

Because the use of natural gas in boiler/ 


jlentini on DSKJ8SOYB1PROD with PROPOSALS2
Federal Register / Vol. 76, No. 85 / Tuesday, May 3, 2011 / Proposed Rules 25073 

179The Shifting Landscape of Ratepayer Funded 

Energy Efficiency in the U.S., Galen Barbose et al., 

October 2009, Lawrence Berkeley National 

Laboratory, LBNL–2258E. 

steam turbine-based EGUs is an 

inefficient use of natural gas to generate 

electricity, all new natural gas-fired 

EGUs built in the foreseeable future will 

most likely be combined cycle units or 

CT peaking units and, thus, not subject 

to 40 CFR part 60, subpart Da, but 

instead subject to the NSPS for 

stationary CTs (40 CFR part 60, subpart 

KKKK). Furthermore, because of fuel 

supply availability and cost 

considerations, we assumed that no new 

oil-fired EGUs will be built during the 

next 5 years. 

Therefore, we are not projecting that 

any new, reconstructed, or modified 

steam generating units would become 

subject to the proposed amendments 

over the next 5 years. Even though we 

are not projecting any impacts from the 

proposed amendments, in the event a 

new steam generating units does 

become subject the proposed 

amendments we have concluded that 

the proposed amendments would be 

appropriate. For more information on 

these impacts, please refer to the 

economic impact analysis and technical 

support documents in the public docket. 

X. Impacts of These Proposed Rules 

A. What are the air impacts? 

Under the proposed Toxics Rule, EPA 

projects annual HCl emissions 

reductions of 91 percent in 2015, Hg 

emissions reductions of 79 percent in 

2015, and PM2.5 emissions reductions of 

29 percent in 2015. In addition, EPA 

projects SO2 emission reductions of 53 

percent, annual NOX emissions 

reductions of 7 percent, and annual CO2

reductions of 1 percent from the power 

sector by 2015, relative to the base case. 

See Table 21. 

TABLE 21—SUMMARY OF POWER SECTOR EMISSIONS REDUCTIONS (TPY) 

SO2

(million tons) 

NOX

(million tons) 

Mercury 

(tons) 

HCl 

(thousand 

tons) 

PM2.5

(thousand 

tons) 

CO2 (million 

metric tonnes) 

Base Case ............................................... 3.9 2.0 29 78 286 2,243 

Proposed Toxics Rule .............................. 1.8 1.9 6 10 202 2,219 

Change ..................................................... ¥2.1 ¥0.1 ¥23.0 ¥68 ¥83.2 ¥24.2 

B. What are the energy impacts? 

Under the provisions of this proposed 

rule, EPA projects that approximately 

9.9 GW of coal-fired generation (roughly 

3 percent of all coal-fired capacity and 

1% of total generation capacity in 2015) 

may be removed from operation by 

2015. These units are predominantly 

smaller and less frequently used 

generating units dispersed throughout 

the area affected by the rule. 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 keep these units 

operational. 

EPA also projects fuel price increases 

resulting from the proposed Toxics 

Rule. Average retail electricity prices are 

shown to increase in the continental 

U.S. by 3.7 percent in 2015. This is 

generally less of an increase than often 

occurs with fluctuating fuel prices and 

other market factors. Related to this, the 

average delivered coal price increases 

by less than 1 percent in 2015 as a result 

of shifts within and across coal types. 

EPA also projects that electric power 

sector-delivered natural gas prices will 

increase by about 1 percent over the 

2015–2030 timeframe and that natural 

gas use for electricity generation will 

increase by about less than 300 billion 

cubic feet (BCF) over that horizon. 

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 20 million 

tons in 2015 from base case levels, 

which is less than 2 percent of total coal 

produced for the electric power sector 

in that year. 

C. What are the compliance costs? 

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 proposed Toxics Rule HAP emission 

standards. In simple terms, these costs 

are the resource costs of what the power 

industry will directly expend to comply 

with EPA’s requirements. 

EPA projects that the annual 

incremental compliance cost of the 

proposed Toxics Rule is $10.9 billion in 

2015 ($2007). The annualized 

incremental cost is the projected 

additional cost of complying with the 

proposed 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. 

End-use energy efficiency can be an 

important part of a compliance strategy 

for this regulation. It can reduce the cost 

of compliance, lower consumer costs, 

reduce emissions, and help to ensure 

reliability of the U.S. power system. 

Policies to promote end-use energy 

efficiency are largely outside of EPA’s 

direct control. However this rule can 

provide an incentive for action to 

promote energy efficiency. To examine 

the potential impacts of Federal and 

state energy efficiency policies, EPA 

used the Integrated Planning Model 

(IPM). 

An illustrative Energy Efficiency 

Scenario was developed and run as a 

sensitivity for both the Base Case and 

the Toxics Rule Case. The illustrative 

Energy Efficiency Case assumed 

adoption of two key energy efficiency 

policies. First, it assumed that states 

adopted rate-payer funded energy 

efficiency programs, such as energy 

efficiency resource standards, integrated 

resource planning and demand side 

management plans. Examples of energy 

efficiency programs that might be driven 

by these policies include rebate 

programs for efficient products and state 

programs to provide technical assistance 

and information for energy efficient 

home retrofits. The electricity demand 

reduction that could be gained from 

these programs was taken from work 

done by Lawrence Berkley National 

Laboratory (LBNL).179 Second, the 

Department of Energy (DOE) provided 

estimates of the demand reductions that 

could be achieved from implementation 

of appliance efficiency standards 

mandated by existing statutes but not 

yet implemented (appliance standards 

that have been implemented are in the 

base case.) EPA assumed that these 

policies are used beyond the timeframe 

of the DOE and LBNL estimates (2035 


jlentini on DSKJ8SOYB1PROD with PROPOSALS2
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180Source: EPA’s Retail Electricity Price Model. 

and 2020 respectively) so that their 

impacts continue through 2050. Table 

22 below gives the electricity demand 

reductions that these two policies 

would yield. 

TABLE 22—ENERGY EFFICIENCY SENSITIVITY RESULTS: ELECTRICITY DEMAND REDUCTIONS

(all in TWh) 2009 2012 2015 2020 2030 2040 2050 

Ratepayer-funded EE Programs .............. .................... 59 110 174 198 198 198 

% of U.S. Demand ................................... .................... 1.5% 2.7% 4.1% 4.2% 3.9% 3.6% 

Federal Appliance Standards .................. .................... 0 6 52 112 114 124 

% of U.S. Demand ................................... .................... 0.0% 0.2% 1.2% 2.4% 2.2% 2.2% 

Total EE Demand Reductions ................. .................... 59 117 226 310 312 322 

% of U.S. Demand ................................... .................... 1.5% 2.9% 5.3% 6.6% 6.1% 5.8% 

U.S. Electricity Demand (EPA Reference) ................................................. 3,838 4,043 4,086 4,302 4,703 5,113 5,568 

Average Annual Growth Rate (2009 to 

20xx) ..................................................... .................... .................... 1.05% 1.04% 0.97% 0.93% 0.91%

Net Demand after EE .............................. 3,838 3,984 3,969 4,076 4,392 4,801 5,246 

Average Annual Growth Rate (2009 to 

20xx) ..................................................... .................... .................... 0.56% 0.55% 0.64% 0.73% 0.77%

As shown, these policies are 

estimated to result in a moderate 

reduction in U.S. electricity demand 

climbing to over five percent by 2020 

and averaging over five percent from 

2020 to 2050. These reductions lower 

annual average electricity demand 

growth (from 2009 historic data) 

through 2020 relative to the reference 

forecast from 1.04 percent to 0.55 

percent. 

The effects of the Energy Efficiency 

Scenario on the projected total 

electricity generating costs of the power 

sector are shown below in Table 23. In 

this table we see the projected costs in 

the Base and Toxics Rule Cases with 

and without energy efficiency. 

TABLE 23—EFFECT OF ENERGY EFFICIENCY POLICY ON GENERATION SYSTEM COSTS

Total costs (billion 2007$)—IPM + Total EE 2015 2020 2030 

Base ............................................................................................................................................. 144 155 200 

Base + EE .................................................................................................................................... 142 150 190 

Toxics Rule .................................................................................................................................. 155 165 210 

Toxics Rule + EE ......................................................................................................................... 153 159 199 

1. Increment (Base to Base + EE) .............................................................................................. ¥2 ¥5 ¥11 

2. Increment (Toxics Rule to Toxics Rule + EE) ......................................................................... ¥2 ¥6 ¥11 

3. Increment (Base to Toxics Rule) ............................................................................................. 11 10 10 

4. Increment (Base + EE to Toxics Rule + EE) .......................................................................... 11 9 9 

5. Increment (Base to Toxics Rule) to (Base + EE to Toxics Rule + EE) .................................. 0 ¥1 ¥1 

6. Increment (Base to Toxics Rule + EE) ................................................................................... 9 4 ¥1 

In this analysis, the costs of the 

energy efficiency policies are treated as 

a component of the cost of generating 

electricity and are imbedded in the costs 

seen in Table 23. The modeling 

estimated that these energy efficiency 

policies would reduce the total cost of 

implementing the rule by billions of 

dollars. EPA looked at a case in which 

these energy efficiency policies were in 

place with and without the Toxics Rule. 

As Table 23 shows, with or without the 

Toxics Rule, energy efficiency policies 

reduce the overall costs to generate 

electricity. The cost reductions increase 

over time. When comparing the Toxics 

Rule Case without energy efficiency to 

the Toxics Rule Case with energy 

efficiency, the analysis shows that these 

energy efficiency policies could reduce 

overall system costs by $2 billion in 

2015, $6 billion in 2020, and $11 billion 

in 2030. 

The energy savings driven by these 

energy efficiency policies, and 

corresponding lower levels of demand, 

translate into reductions in electricity 

prices. EPA’s modeling shows that the 

Toxics Rule increases retail prices by 

3.7 percent, 2.6 percent and 1.9 percent 

in 2015, 2020 and 2030, respectively, 

relative to the base case. If energy 

efficiency policies are implemented, the 

price increase would be smaller in 2015 

when retail prices would increase by 3.3 

percent. In 2020 and 2030 the reduced 

demand for electricity is sufficient to 

reduce the retail price of electricity 

relative to the Base Case even with the 

Toxics Rule. If the Toxics Rule is 

implemented with energy efficiency, 

retail electricity prices decrease by 

about 1.6 percent in 2020 and by about 

2.3 percent in 2030 relative to the 

Base.180 The effect on average electricity 

bills, however, may fall more than these 

percentages as energy efficiency means 

that less electricity will be used by 

consumers of electricity. 

In the Energy Efficiency Cases, IPM 

projects considerably more plant 

retirements than in the Base and Policy 

Cases. The Base Case with Energy 

Efficiency in 2020 shows twice as much 

capacity retiring, and more than double 

the capacity of coal plant retirements as 

the Base Case without energy efficiency. 

The Toxics Rule would increase the 

amount of capacity retired over the Base 

Case by 8 GW. If the energy efficiency 

policies were imposed as the power 

sector was taking action to come into 

compliance, the effect of the Toxics 

Rule on plant retirements would be 

greater with an additional 25 GW of 


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retirements in 2020. These results are 

shown in Table 24 below. 

TABLE 24—EFFECT OF ENERGY EFFICIENCY ON RETIREMENTS

Retirements Grand Total & (Coal) (GW) 2015 2020 2030 

Base ............................................................................................................................................. 27 (5) 27 (5) 27 (5) 

Base + EE .................................................................................................................................... 38 (12) 54 (12) 53 (12) 

Toxics Rule .................................................................................................................................. 35 (15) 35 (14) 35 (14) 

Toxics Rule + EE ......................................................................................................................... 47 (25) 60 (24) 60 (24) 

1. Increment (Base to Base + EE) .............................................................................................. 11 (7) 27 (7) 26 (7) 

2. Increment (Toxics Rule to Toxics Rule + EE) ......................................................................... 11 (10) 25 (10) 24 (10) 

3. Increment (Base to Toxics Rule) ............................................................................................. 9 (10) 8 (9) 8 (9) 

4. Increment (Base + EE to Toxics Rule + EE) .......................................................................... 9 (13) 6 (12) 6 (12) 

5. Increment (Base to Toxics Rule) to (Base + EE to Toxics Rule + EE) .................................. 0 (3.0) ¥2 (3) ¥2 (3) 

6. Increment (Base to Toxics Rule + EE) ................................................................................... 20 (20) 33 (19) 32 (19) 

In effect, the timely adoption and 

implementation of energy efficiency 

policies would augment currently 

projected reserve capacities that are 

instrumental to assuring system 

reliability. 

The addition of energy efficiency 

policies during and beyond the Toxics 

Rule compliance period can result in 

very modest reductions in air emissions. 

This is largely due to lower levels of 

electricity generation. As a result, with 

energy efficiency policies the Toxics 

Rule would achieve reductions of 

approximately an additional 520 

pounds of Hg emissions, an additional 

80,000 tons of SO2, and an additional 

110,000 tons of NOX in 2020. 

Although EPA cannot mandate energy 

efficiency policies, the positive effects 

of these policies on the cost of rule to 

industry and consumers could be a 

strong incentive to undertake them as a 

part of an overall compliance strategy. 

Table 25 presents estimated breakouts 

of the cost of reducing certain key 

pollutants under the Toxics Rule. 

Because many of the strategies to reduce 

pollutants are multi-pollutant in nature, 

it is not possible to create a technologyspecific breakout of costs (e.g. a 

baghouse reduces PM2.5 as well as Hg, 

it also reduces the cost of using 

additional sorbents to reduce acid gases 

or further reduce Hg). Costs were first 

calculated by using representative unit 

costs for each control option. These 

costs were then multiplied by the 

amount of capacity that employed the 

given control option. Costs were then 

pro-rated amongst the pollutants that a 

given technology reduced. This proration was based on rough estimates of 

the percentage reduction expected for a 

given pollutant (e.g. because a baghouse 

alone removes significant amounts of 

PM2.5 and has a much smaller Hg 

reduction, most of the baghouse cost 

was assigned to PM2.5, in the case of ACI 

(which often includes a baghouse) 

reductions of Hg and fine PM were 

similar, therefore costs were pro-rated 

more equally). Since total costs from the 

bottom up calculation did not exactly 

match our total modeled costs, the 

pollutant by pollutant costs were then 

pro-rated to equal the total model costs. 

TABLE 25—BREAKOUTS OF COSTS BY CONTROL MEASURE AND POLLUTANT FOR THE PROPOSED TOXICS RULE

Dry FGD + 

FF DSI FF ACI Scrubber upgrade 

Waste coal 

FGD Total 

Total (2007 $MM) ........................ Capital ............................ 1,421 428 1,092 1,498 669 94 5,201 

FOM ................................ 252 71 41 45 0 20 431 

VOM 377 1,241 105 627 0 66 2,416 

2015 Annual Capital + 

FOM + VOM.

2,050 1,740 1,238 2,173 669 179 8,048 

Cost Share ................................... HCl .................................. 29% 56% 0% 0% 52% 29% ....................

Hg ................................... 10% 0% 10% 51% 0% 10% ....................

PM2.5 ............................... 32% 0% 90% 49% 0% 32% ....................

SO2 ................................. 29% 44% 0% 0% 48% 29% ....................

Total Annual Costs, 2015 (2007 

$MM).

HCL ................................ 588 979 0 0 347 51 1,965 

Hg ................................... 205 0 124 1,106 0 18 1,453 

PM2.5 ............................... 654 0 1,114 1,067 0 57 2,892 

SO2 ................................. 603 761 0 0 322 53 1,739 

TOTAL ........................ 2,050 1,740 1,238 2,173 669 179 8,048 

Capital + FOM + VOM 

Costs Fuel cost Total cost Share of total cost 

Capital 

share 

Tons 

reduced 

$/ton 

($/lb for Hg) 

General 

range of 

costs from 

other MACT 

rules 

Acid Gasses (HCl + HCN + HF) .. 1,965 ............................... 1,064 3,029 24% 37% 106,038 $18,529 $2,500– 

$55,000 

Hg ................................................. 1,453 ............................... 825 2,277 18% 49% 18 $40,428 $1,250– 

$55,200 

PM2.5 ............................................ 2,892 ............................... 357 3,249 36% 74% 83,246 $34,742 $1,600– 

$55,000 

SO2 ............................................... 1,739 ............................... 645 2,384 22% 44% 2,050,871 $848 $540– 

$5,100 

Total ...................................... 8,048 ............................... 2,892 10,940 100% .................... .................... .................... ....................


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181Numbers 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. 

182For alternative views in economic journals, 

see Henderson (1996) and Greenstone (2002). 

D. What are the economic impacts? 

For this proposed rule, EPA analyzed 

the costs using IPM. IPM is a dynamic 

linear programming model that can be 

used to examine the economic impacts 

of air pollution control policies for a 

variety of HAP and other pollutants 

throughout the contiguous U.S. for the 

entire power system. 

Documentation for IPM can be found 

in the docket for this rulemaking or at 

http://www.epa.gov/airmarkets/

progsregs/epa-ipm/index.html. 

EPA also included an analysis of 

impacts of the proposed rule to 

industries outside of the electric power 

sector by using the Multi-Market Model. 

This model is a partial equilibrium 

model that includes 100 sectors that 

cover energy, manufacturing, and 

service applications and is designed to 

capture the short-run effects associated 

with an environmental regulation. It 

was used to estimate economic impacts 

for the recently promulgated Industrial 

Boiler major and area source standards 

and CISWI standard. 

We use the Multi-Market model to 

estimate the social cost of the proposed 

rule. Using this model, we estimate the 

social costs of the proposal to be $10.9 

billion (2007$), which is almost 

identical to the compliance costs. The 

usefulness of a Multi-Market model in 

predicting the estimated effects is 

limited because the electric power 

sector affects all sectors of the economy. 

For the final rule, we will be refining 

the social cost estimates with general 

equilibrium models, including an 

assessment with our upgraded CGE 

model, EMPAX. Commenters are 

encouraged to provide other general 

equilibrium model platforms and to 

provide other information to refine the 

social cost assessments for the final rule. 

EPA also performed a screening 

analysis for impacts on small entities by 

comparing compliance costs to sales/ 

revenues (e.g., sales and revenue tests). 

EPA’s analysis found the tests were 

typically higher than 1 percent for small 

entities included in the screening 

analysis. EPA has prepared an Initial 

Regulatory Flexibility Analysis (IRFA) 

that discusses alternative regulatory or 

policy options that minimize the rule’s 

small entity impacts. It includes key 

information about key results from the 

SBAR panel. 

Although a stand-alone analysis of 

employment impacts is not included in 

a standard cost-benefit analysis, the 

current economic climate has led to 

heightened concerns about potential job 

impacts. Such an analysis is of 

particular concern in the current 

economic climate as sustained periods 

of excess unemployment may introduce 

a wedge between observed (market) 

wages and the social cost of labor. In 

such conditions, the opportunity cost of 

labor required by regulated sectors to 

bring their facilities into compliance 

with an environmental regulation may 

be lower than it would be during a 

period of full employment (particularly 

if regulated industries employ otherwise 

idled labor to design, fabricate, or install 

the pollution control equipment 

required under this proposed rule). For 

that reason, EPA also includes estimates 

of job impacts associated with the 

proposed rule. EPA presents an estimate 

of short-term employment opportunities 

as a result of increased demand for 

pollution control equipment. Overall, 

the results suggest that the proposed 

rule could support a net of roughly 

31,000 job-years 181 in direct 

employment impacts in 2015. 

The basic approach to estimate these 

employment impacts involved using 

projections from IPM from the proposed 

rule analysis such as the amount of 

capacity that will be retrofit with 

control technologies, for various energy 

market implications, along with data on 

labor and resource needs of new 

pollution controls and labor 

productivity from secondary sources, to 

estimate employment impacts for 2015. 

For more information, please refer to the 

TSD for this analysis, ‘‘Employment 

Estimates of Direct Labor in Response to 

the Proposed Toxics Rule in 2015.’’ 

EPA relied to Morgenstern, et al. 

(2002), identify three economic 

mechanisms by which pollution 

abatement activities can indirectly 

influence jobs: 

Higher production costs raise market 

prices, higher prices reduce 

consumption, and employment within 

an industry falls (‘‘demand effect’’); 

Pollution abatement activities require 

additional labor services to produce the 

same level of output (‘‘cost effect’’); and 

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, 

Morgenstern, et al., estimate the size of 

each effect for four polluting and 

regulated industries (petroleum, plastic 

material, pulp and paper, and steel). On 

average across the four industries, each 

additional $1 million spending on 

pollution abatement results in an small 

net increase of 1.6 jobs; the estimated 

effect is not statistically significant 

different from zero. As a result, the 

authors conclude that increases in 

pollution abatement expenditures do 

not necessarily cause economically 

significant employment changes. The 

conclusion is similar to Berman and Bui 

(2001) who found that increased air 

quality regulation in Los Angeles did 

not cause large employment changes.182

For more information, please refer to the 

RIA for this proposed rule. 

The ranges of job effects calculated 

using the Morgenstern, et al., approach 

are listed in Table 26. 

TABLE 26—RANGE OF JOB EFFECTS FOR THE ELECTRICITY SECTOR

Estimates using Morgenstern, et al. (2001) 

Factor shift effect 

Demand effect Cost effect 

Change in Full-Time Jobs per Million Dollars of Environmental Expenditure a.¥3.56 ................................ 2.42 .................................... 2.68. 

Standard Error ................................................................. 2.03 .................................... 1.35 .................................... 0.83. 

EPA estimate for Proposed Rule b .................................. ¥45,000 to +2,500 ........... +4,700 to 24,000 ............... +200 to 32,000. 

aExpressed in 1987 dollars. See footnote a from Table 9–3 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. 


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183Roman 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. 184Fann, 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. 

185Pope 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. 186Laden et al., 2006. ‘‘Reduction in Fine 

Particulate Air Pollution and Mortality.’’ American 

Journal of Respiratory and Critical Care Medicine. 

173: 667–672. 

187U.S. Environmental Protection Agency, 2006. 

Final Regulatory Impact Analysis: PM2.5 NAAQS. 

Prepared by Office of Air and Radiation. October. 

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

ecas/ria.html. 

EPA recognizes there may be other job 

effects which are not considered in the 

Morgenstern, et al., study. Although 

EPA has considered some economywide changes in industry output as 

shown earlier with the Multi-Market 

model, we do not have sufficient 

information to quantify other associated 

job effects associated with this rule. EPA 

solicits comments on information (e.g., 

peer-reviewed journal articles) and data 

to assess job effects that may be 

attributable to this rule. 

E. What are the benefits of this proposed 

rule? 

We estimate the monetized benefits of 

this proposed regulatory action to be 

$59 billion to $140 billion (2007$, 3 

percent discount rate) in 2016. The 

monetized benefits of the proposed 

regulatory action at a 7 percent discount 

rate are $53 billion to $130 billion 

(2007$). These estimates reflect the 

economic value of the Hg benefits as 

well as the PM2.5 and CO2-related cobenefits. 

Using alternate relationships between 

PM2.5 and premature mortality supplied 

by experts, higher and lower benefits 

estimates are plausible, but most of the 

expert-based estimates fall between 

these two estimates.183 A summary of 

the monetized benefits estimates at 

discount rates of 3 percent and 7 

percent is in Table 27 of this preamble. 

TABLE 27—SUMMARY OF THE PM2.5 MONETIZED CO-BENEFITS ESTIMATES FOR THE PROPOSED TOXICS RULE IN 2016 

[Billions of 2007$] a

Estimated emission reductions (million tons per year) Monetized PM2.5 co-benefits (3% discount rate) Monetized PM2.5 co-benefits (7% discount rate) 

PM2.5 Precursors 

SO2 .................................................................................. 2.1 ...................................... $58 to $140 ....................... $53 to $130. 

Total .......................................................................... ............................................ $58 to $140 ....................... $53 to $130. 

aAll estimates are for the implementation year (2016), and are rounded to two significant figures. All fine particles are assumed to have equivalent health effects, but the benefit-per-ton estimates vary between precursors because each ton of precursor reduced has a different propensity 

to form PM2.5. Benefits from reducing HAP are not included. 

These benefits estimates represent the 

total monetized human health benefits 

for populations exposed to less PM2.5 in 

2016 from controls installed to reduce 

air pollutants in order to meet these 

standards. These estimates are 

calculated as the sum of the monetized 

value of avoided premature mortality 

and morbidity associated with reducing 

a ton of PM2.5 and PM2.5 precursor 

emissions. To estimate human health 

benefits derived from reducing PM2.5

and PM2.5 precursor emissions, we used 

the general approach and methodology 

laid out in Fann, et al. (2009).184

To generate the benefit-per-ton 

estimates, we used a model to convert 

emissions of PM2.5 precursors into 

changes in ambient PM2.5 levels and 

another model to estimate the changes 

in human health associated with that 

change in air quality. Finally, the 

monetized health benefits were divided 

by the emission reductions to create the 

benefit-per-ton estimates. Even though 

we assume that all fine particles have 

equivalent health effects, the benefitper-ton estimates vary between 

precursors because each ton of 

precursor reduced has a different 

propensity to form PM2.5. For example, 

SOX has a lower benefit-per-ton estimate 

than direct PM2.5 because it does not 

form as much PM2.5, thus the exposure 

would be lower, and the monetized 

health benefits would be lower. 

For context, it is important to note 

that the magnitude of the PM benefits is 

largely driven by the concentration 

response function for premature 

mortality. Experts have advised EPA to 

consider a variety of assumptions, 

including estimates based both on 

empirical (epidemiological) studies and 

judgments elicited from scientific 

experts, to characterize the uncertainty 

in the relationship between PM2.5

concentrations and premature mortality. 

For this proposed rule we cite two key 

empirical studies, one based on the 

American Cancer Society cohort 

study 185 and the extended Six Cities 

cohort study.186 In the Regulatory 

Impacts Analysis (RIA) for this 

proposed rule, which is available in the 

docket, we also include benefits 

estimates derived from expert 

judgments and other assumptions. 

This analysis does not include the 

type of detailed uncertainty assessment 

found in the 2006 PM2.5 NAAQS RIA 

because we lack the necessary air 

quality input and monitoring data to run 

the benefits model. However, the 2006 

PM2.5 NAAQS benefits analysis 187

provides an indication of the sensitivity 

of our results to various assumptions. 

It should be emphasized that the 

monetized benefits estimates provided 

above do not include benefits from 

several important benefit categories, 

including reducing other air pollutants, 

ecosystem effects, and visibility 

impairment. The benefits from reducing 

various HAP have not been monetized 

in this analysis, including reducing 

68,000 tons of HCl, and 3,200 tons of 

other metals each year. Although we do 

not have sufficient information or 

modeling available to provide 

monetized estimates for this 

rulemaking, we include a qualitative 

assessment of the health effects of these 

air pollutants in the RIA for this 

proposed rule, which is available in the 

docket. 


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TABLE 28—SUMMARY OF THE MONETIZED BENEFITS, SOCIAL COSTS, AND NET BENEFITS FOR THE PROPOSED RULE IN

2016 

[Millions of 2006$] a

3% Discount rate 7% Discount rate 

Total Monetized Benefits b ...................................................................... $59,000 to $140,000 ..................... $53,000 to $130,000. 

Hg-related Benefits c ................................................................................ $4.1 to $5.9 ................................... $0.45 to $0.89. 

CO2-related Benefits ............................................................................... $570 ............................................... $570. 

PM2.5-related Co-benefits d ...................................................................... $59,000 to $140,000 ..................... $53,000 to $120,000. 

Total Social Costs e ................................................................................. $10,900 .......................................... $10,900. 

Net Benefits ............................................................................................. $48,000 to $130,000 ..................... $42,000 to $130,000. 

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

Cardiovascular effects of Hg exposure. 

Other health effects of Hg exposure. 

Ecosystem effects. 

Commercial and non-freshwater fish consumption. 

aAll estimates are for 2016, and are rounded to two significant figures. The net present value of reduced CO2 emissions are calculated differently than other benefits. The same discount rate used to discount the value of damages from future emissions (SCC at 5, 3, 2.5 percent) is 

used to calculate net present value of SCC for internal consistency. This table shows monetized CO2 co-benefits at discount rates at 3 and 7 

percent that were calculated using the global average SCC estimate at a 3 percent discount rate because the interagency workgroup on this 

topic deemed this marginal value to be the central value. In section 6.6 of the RIA we also report the monetized CO2 co-benefits using discount 

rates of 5 percent (average), 2.5 percent (average), and 3 percent (95th percentile). bThe total monetized benefits reflect the human health benefits associated with reducing exposure to MeHg, PM2.5, and ozone. cBased on an analysis of health effects due to recreational freshwater fish consumption. 

dThe reduction in premature mortalities account for over 90 percent of total monetized PM2.5 benefits. eSocial costs are estimated using the MultiMarket model, in order to estimate economic impacts of the proposal to industries outside the electric power sector. Details on the social cost estimates can be found in Chapter 9 and Appendix E of the RIA. 

For more information on the benefits 

and cost analysis, please refer to the RIA 

for this rulemaking, which is available 

in the docket. 

XI. Public Participation and Request for 

Comment 

We request comment on all aspects of 

this proposed rule. 

During this rulemaking, we conducted 

outreach to small entities and convened 

a SBAR Panel to obtain advice and 

recommendation of representatives of 

the small entities that potentially would 

be subject to the requirements of this 

proposed rule. As part of the SBAR 

Panel process we conducted outreach 

with representatives from various small 

entities that would be affected by this 

proposed rule. We met with these SERs 

to discuss the potential rulemaking 

approaches and potential options to 

decrease the impact of the rulemaking 

on their industries/sectors. We 

distributed outreach materials to the 

SERs; these materials included 

background, project history, CAA 

section 112 overview, constraints on 

rulemaking, affected facilities, data, 

rulemaking options under 

consideration, potential control 

technologies and estimated costs, 

applicable small entity definitions, 

small entities potentially subject to 

regulation, and questions for SERs. We 

met with SERs that will be impacted 

directly by this proposed rule to discuss 

the outreach materials and receive 

feedback on the approaches and 

alternatives detailed in the outreach 

packet. The Panel received written 

comments from the SERs following the 

meeting in response to discussions at 

the meeting and the questions posed to 

the SERs by the Agency. The SERs were 

specifically asked to provide comment 

on regulatory alternatives that could 

help to minimize the rule’s impact on 

small businesses. (See elsewhere in this 

preamble for further information 

regarding the SBAR process.) 

EPA consulted with state and local 

officials in the process of developing the 

proposed action to permit them to have 

meaningful and timely input into its 

development. EPA met with 10 national 

organizations representing state and 

local elected officials to provide general 

background on the proposal, answer 

questions, and solicit input from state/ 

local governments. EPA also consulted 

with tribal officials early in the process 

of developing this proposed rule to 

permit them to have meaningful and 

timely input into its development. 

Consultation letters were sent to 584 

tribal leaders. The letters provided 

information regarding EPA’s 

development of NESHAP for EGUs and 

offered consultation. Three consultation 

meetings were requested and held. The 

Unfunded Mandates Reform Act 

(UMRA) discussion in this preamble 

includes a description of the 

consultation. (See elsewhere in this 

preamble for further information 

regarding these consultations with state, 

local, and tribal officials.) 

XII. 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, EPA submitted this 

action to the OMB for review under EO 

12866 and any changes in response to 

OMB recommendations have been 

documented in the docket for this 

action. For more information on the 

costs and benefits for this rule, please 

refer to Table 28 of this preamble. 

When estimating the human health 

benefits and compliance costs in Table 

28 of this preamble, EPA applied 

methods and assumptions consistent 

with the state-of-the-science for human 

health impact assessment, economics 

and air quality analysis. 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 


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basis for EPA’s assumptions and 

characterizes the various sources of 

uncertainties affecting the estimates 

below. In doing what is laid out above 

in this paragraph, 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 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 section 

316(b) of the CWA. They will also soon 

be the subject of a rulemaking under 

CAA section 111 concerning emissions 

of GHG. In developing today’s proposed 

rule, EPA recognizes that it needs to 

endeavor to approach these rulemakings 

in ways that allow the industry to make 

practical investment decisions that 

minimize costs in complying with all of 

the final rules, while still achieving the 

fundamentally important environmental 

and public health benefits that underlie 

the rulemakings. 

1. Human Health and Environmental 

Effects Due to Exposure to MeHg 

In this section, we provide a 

qualitative description of human health 

and environmental effects due to 

exposure to MeHg. In 2000, the NAS 

Study was issued which provides a 

thorough review of the effects of MeHg 

on human health (NRC, 2000). Many of 

the peer-reviewed articles cited in this 

section are publications originally cited 

in the MeHg Study. In addition, EPA 

has conducted literature searches to 

obtain other related and more recent 

publications to complement the material 

summarized by the NRC in 2000. 

2. Reference and Benchmark Doses 

In 1995, EPA set a health-based 

ingestion rate for chronic oral exposure 

to MeHg, termed an oral RfD, at 0.0001 

mg/kg-day. The RfD was based on 

effects reported to children exposed in 

utero during the Iraqi poisoning episode 

(Marsh, et al., 1987). Subsequent 

research from large epidemiological 

studies in the Seychelles, Faroe Islands, 

and New Zealand added substantially to 

the body of knowledge on neurological 

effects from MeHg exposure. Per 

Congressional direction via the House 

Appropriations Report for Fiscal Year 

1999, the NRC was contracted by EPA 

to examine these data and, if 

appropriate, make recommendations for 

deriving a revised RfD. The NRC’s 

analysis concluded that the Iraqi study 

on children exposed in utero should no 

longer be considered the critical study 

for the derivation of the RfD. NRC also 

provided specific recommendations to 

EPA for a MeHg RfD based on analyses 

of the three large epidemiological 

studies (NRC, 2000). Although derived 

from a more complete data set and with 

a somewhat different methodology, the 

current RfD is numerically the same as 

the previous (1995) RfD (0.0001 mg/kgday). 

The RfD is an estimate (with 

uncertainty spanning perhaps an order 

of magnitude) of a daily exposure to the 

human population (including sensitive 

subgroups) that is likely to be without 

an appreciable risk of deleterious effects 

during a lifetime (EPA, 2002). Data 

published since 2001, development of 

risk assessment methods, and continued 

examination of the concepts underlying 

benchmark doses and RfDs based on 

them add to EPA’s interpretation of the 

2001 MeHg RfD in the current 

rulemaking. Additional information on 

EPA’s interpretation can be found in 

Section X of the Appropriate & 

Necessary TSD. 

3. Neurologic Effects of Exposure to 

MeHg 

In their review of the literature, the 

NRC found neurodevelopmental effects 

to be the most sensitive endpoints and 

appropriate for establishing an RfD 

(NRC, 2000). Studies involving animals 

found sensory effects and support the 

conclusions reached by studies 

involving human subjects, with a 

similar range of neurodevelopmental 

effects reported (NRC, 2000). As noted 

by the NRC, the clinical significance of 

some of the more subtle endpoints 

included in the human low-dose studies 

is difficult to gauge due to the quantal 

nature of the effects observed (i.e., 

subjects either display the abnormality 

or do not) and the rather low occurrence 

rate of these effects. 

Little is known about the effects of 

low-level chronic MeHg exposure in 

children that can be linked to exposures 

after birth. The difficulty in identifying 

a cohort exposed after birth but not 

prenatally, or separating prenatal from 

postnatal effects, makes research on the 

topic complicated. These challenges 

were present in the three large 

epidemiologic studies used to derive the 

RfD, as in all three studies there was 

postnatal exposure as well. 

Several studies have shown 

neurological effects including delayed 

peak latencies in brainstem auditory 

evoked potentials are associated with 

prenatal or recent MeHg exposures 

(Debes, et al., 2006; Grandjean, et al., 

1997; Murata, et al., 2004). A recent case 

control study of Chinese children in 

Hong Kong (Cheuk and Wong, 2006) 

paired 59 normal controls with 52 

children (younger than 18 years) 

diagnosed with attention deficit/ 

hyperactivity disorder (ADHD). The 

authors reported a significant difference 

in blood Hg levels between cases and 

controls (geometric mean 18.2 nmol/L 

(95 percent confidence interval, CI, 

15.4–21.5 nmol/L] vs. 11.6 nmol/L [95 

percent CI 9.9–13.7 nmol/L], p < 0.001), 

which persisted after they adjusted for 

age, gender and parental occupational 

status (p less than 0.001). 

Several studies have also examined 

the effects of chronic low-dose MeHg 

exposures on adult neurological and 

sensory functions (e.g., Lebel, et al., 

1996; Lebel, et al., 1998; Beuter and 

Edwards, 1998). Research results 

suggest that elevated hair MeHg 

concentrations in individuals are 

associated with visual deficits, 

including loss of peripheral vision and 

chromatic and contrast sensitivity. 

These concentrations range between a 

high of 50 ppm, and possibly as low as 

20 ppm, although a no observed adverse 

effect level (NOAEL) was not clearly 

estimated). These individuals also 

exhibited a loss of manual dexterity, 

hand-eye coordination, and grip 

strength; difficulty performing complex 

sequences of movement; and (at the 

higher doses) tremors, although 

expression of some effects was sexspecific. Although additional data 

would be needed to quantify a doseresponse relationship for these effects, it 

is noteworthy that the effects occurred 

at doses lower than the Japanese and 

Iranian poisoning episodes, via 

consumption of Hg-laden fish in 

riverine Brazilian communities. These 

are areas where extensive Hg 

contamination has resulted from smallscale gold mining activities begun in the 

1980s. Note that these doses are above 

the EPA’s RfD equivalent level for hair 

Hg. In regard to the Lebel, et al. (1998) 

study, the NRC states that ‘‘the mercury 

exposure of the cohort is presumed to 

have resulted from fish-consumption 


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patterns that are stable and thus relevant 

to estimating the risk associated with 

chronic, low-dose MeHg exposure’’ 

(NRC, 2000). The NRC noted, however, 

‘‘that the possibility cannot be excluded 

that the neurobehavioral deficits of the 

adult subjects were due to increased 

prenatal, rather than ongoing, MeHg 

exposure.’’ More recent studies in the 

Brazilian communities provide some 

evidence that the adverse 

neurobehavioral effects may in fact 

result from postnatal exposures (e.g., 

Yokoo, et al., 2003); however, additional 

longitudinal study of these and other 

populations is required to resolve 

questions regarding exposure timing 

and fully characterize the potential 

neurological impacts of MeHg exposure 

in adults. 

4. Cardiovascular Impacts of Exposure 

to MeHg 

A number of epidemiological and 

toxicological studies have evaluated the 

relationship between MeHg exposures 

and various cardiovascular effects 

including acute myocardial infarction 

(AMI), oxidative stress, atherosclerosis, 

decreased heart rate variability (HRV), 

and hypertension. An AMI (i.e., heart 

attack) is clearly an adverse health 

effect. The other four effects are 

considered ‘‘intermediary’’ effects and 

risk factors for development of AMI or 

coronary heart disease. Hypertension is 

a commonly measured clinical outcome 

that is also considered a risk factor for 

other adverse effects (such as stroke). 

These epidemiological studies 

evaluated Hg exposures using various 

measures (including Hg or MeHg in 

blood, cord blood, hair and toenails) 

and the associations of these exposures 

with various effects. The overall results 

of the available studies (published 

before and after NRC 2000) are 

summarized in the following 

paragraphs. 

Studies in two cohorts (the Kuopio 

Ischemic Heart Disease Risk Factor 

study, or KIHD study; and the European 

Community Multicenter Study on 

Antioxidants, Myocardial Infarction and 

Breast Cancer, or EURAMIC study), 

report statistically significant positive 

associations between MeHg exposure 

and AMI. A third study (U.S. Health 

Professionals Study, USHPS) also 

reported a positive association between 

Hg exposure and AMI but only after 

excluding individuals who may have 

been occupationally exposed to 

inorganic Hg. However, a fourth study 

(the Northern Sweden Health and 

Disease Study, or NSHDS) reported an 

inverse relationship between MeHg 

exposure and AMI, and another study 

(Minamata Cohort) identified no 

increase in fatal heart attacks following 

a MeHg poisoning epidemic. 

Although each of these AMI studies 

had strengths and limitations, the 

EURAMIC and KIHD studies appear to 

be most robust. Strengths of these two 

studies include their large sample sizes 

and control for key potential 

confounders (such as exposure to 

omega-3 fatty acid, which are related to 

decreases in cardiovascular effects). The 

KIHD study was well-designed and 

included a population-based 

recruitment and limited loss to followup. Additional strengths of the 

EURAMIC study include exposure data 

that were collected shortly after the 

AMI. In addition, recruitment of 

participants across nine countries likely 

resulted in a wide range of MeHg and 

fish fatty acid intakes. Although the 

USHPS study was well-conducted, the 

Hg exposure measure used was 

potentially confounded by possible 

inorganic Hg exposures in roughly half 

of the study population. When these 

subjects were excluded from the 

analyses, the power of the study to 

detect an effect was reduced. 

Limitations of the NSHDS study 

included its relatively small sample size 

and narrow MeHg exposure range. The 

Minamata study also had important 

limitations, primarily that the effects of 

the very high exposures in this 

population may differ substantially from 

effects of lower exposures expected at 

typical environmental levels; also the 

death certificates were collected starting 

10 years after the initial cases of MeHg 

poisoning. 

In summary, the most robust available 

studies (i.e., the EURAMIC and KIHD), 

report statistically significant positive 

relationships between MeHg exposure 

and the incidence of AMI. Further, both 

studies report statistically significantly 

positive trend tests for the relationship 

between MeHg and AMI. The USHPS 

provides some additional evidence of a 

positive association. The NSHDS and 

the Minamata Cohort studies are less 

robust; however, the results from those 

two studies showed no adverse effect, 

and, therefore, reduce the overall 

confidence in the association of MeHg 

with AMIs. 

The studies that evaluated 

intermediary effects generally provide 

some additional evidence of the 

potential adverse effects of Hg or MeHg 

to the cardiovascular system. However, 

results are somewhat inconsistent. For 

example, two epidemiological studies 

(the KIHD and the Tapajo ́ s River Basin 

studies) reported positive associations 

between MeHg exposures and oxidative 

stress, but one short-term study (the 

Quebec Sport Fisherman Study) 

reported a negative association. For 

atherosclerosis, the results across 

epidemiological studies are more 

consistent. Three studies (the KIHD, 

Faroese Whaler Cohort Study, and 

Nunavik Inuit Cohort in Quebec) 

reported a positive association between 

MeHg exposure and atherosclerosis. 

Moreover, animal studies and in vitro 

studies (cell studies) provide additional 

evidence that MeHg may cause 

oxidative stress and increased risk of 

atherosclerosis. 

Another intermediary effect, 

decreases in heart rate variability (HRV), 

can be indicative of cardiovascular 

disease, particularly in the elderly. 

Associations of decreased HRV with 

increased MeHg exposures have been 

reported in four of five studies of adults 

and three studies of children; however, 

the clinical significance of decreased 

HRV in children is not known. 

The existing epidemiological studies 

are inconsistent in showing an 

association between MeHg and 

hypertension. A prospective study of 

the Faroe Islands birth cohort reported 

statistically significant associations 

between elevated cord blood Hg levels 

or maternal hair Hg levels and increased 

diastolic and systolic blood pressures 

for 7-year-old children; this association 

was no longer seen in the children 

tested at 14 years. Other studies suggest 

that these are not correlated. 

In January 2010, EPA sponsored a 

workshop in which a group of experts 

were asked to assess the plausibility of 

a causal relationship between MeHg 

exposure and cardiovascular health 

effects, and to advise EPA on 

methodologies for estimating 

population-level cardiovascular health 

impacts of reduced MeHg exposure. The 

final workshop report was published in 

January, 2011, and includes as its key 

recommendation the development of a 

dose-response function relating MeHg 

exposure and AMI incidence for use in 

regulatory benefits analyses that target 

Hg air emissions. 

The experts identified both 

intermediary and clinical effects in the 

published literature. The panelists 

assessed the strength of evidence 

associated with three intermediary 

effects (i.e., oxidative stress, 

atherosclerosis, and HRV), and with two 

main clinical effects (i.e., hypertension 

and AMI). The panel concluded there 

was at least moderate evidence of an 

association between MeHg exposure and 

all of these effects in the 

epidemiological literature. The evidence 

for an association with hypertension 

was considered the weakest. 

The workshop panel concluded that 

‘‘a causal link between MeHg and AMI 


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188Crump, KL, and Trudeau, VL. Mercuryinduced reproductive impairment in fish. 

Environmental Toxicology and Chemistry. Vol. 28, 

No. 5, 2009. 

is plausible, given the range of 

intermediary effects for which some 

positive evidence exists and the strength 

and consistency across the 

epidemiological studies for AMI.’’ 

During the workshop, the individual 

experts provided quantitative estimates 

of the likelihood of a true causal 

relationship between MeHg and AMI, 

ranging from 0.45 to 0.80, and 

characterized by the panel as ‘‘moderate 

to strong.’’ A recently published health 

benefits analysis of reduced MeHg 

exposures analyzed the epidemiology 

literature and assessed the ‘‘plausibility 

of causal interpretation of 

cardiovascular risk’’ as about 1⁄3 as a 

separate parameter in their analysis. 

EPA did not develop a quantitative 

dose-response assessment or quantified 

estimates of benefits for cardiovascular 

effects associated with MeHg exposures, 

as there is no consensus among 

scientists on the dose-response 

functions for these effects. In addition, 

there is inconsistency among available 

studies as to the association between 

MeHg exposure and various 

cardiovascular system effects. The 

pharmacokinetics of some of the 

exposure measures (such as toenail Hg 

levels) are not well understood. The 

studies have not yet received the review 

and scrutiny of the more wellestablished neurotoxicity data base. 

5. 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 

NRC concluded that evidence that 

human exposure to MeHg caused 

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 (Amorim, et al., 2000) reported 

a direct relationship between MeHg 

concentration in hair and DNA damage 

in lymphocytes,; polyploidal aberrations 

and chromatid breaks observed at Hg 

hair levels around 7.25 ppm and 10 

ppm, respectively. Long-term MeHg 

exposures in this population were 

believed to occur through consumption 

of fish, suggesting that genotoxic effects 

(largely chromosomal aberrations) may 

result from dietary, chronic MeHg 

exposures similar to and above those 

seen in the Faroes and Seychelles 

populations. 

6. 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). Some persistent 

immunotoxic effects have been observed 

in mice treated with MeHg in drinking 

water at relatively high levels of 

exposure (Havarinasab, et al., 2007). A 

recent study of fish-consuming 

communities in Amazonian Brazil has 

identified a possible association 

between MeHg exposure and 

immunotoxic effects reflective of 

autoimmune dysfunction. The authors 

noted that this may reflect interactions 

with infectious disease and other factors 

(Silva, et al., 2004). Exposures to these 

communities occurred via fish 

consumption (some community 

members were also exposed to inorganic 

Hg through gold mining activities). The 

researchers assessed levels of specific 

antibodies that are markers of Hginduced autoimmunity. They found that 

both prevalence and levels of these 

antibodies were higher in a population 

exposed to MeHg via fish consumption 

compared to a reference (unexposed) 

population. Median hair Hg 

concentration was 8 ppm in the more 

exposed population (range 0.29 to 58.47 

ppm) and 5.57 ppm in the less exposed 

reference population (range 1.19 to 

16.96 ppm). The ranges of Hg hair 

concentrations reported in this study are 

within an order of magnitude of the 

concentration corresponding to the 

MeHg RfD. Overall, there is a relatively 

small body of evidence from human 

studies that suggests exposure to MeHg 

can result in immunotoxic effects. 

7. Other Hg-Related Human Toxicity 

Data 

Based on limited human and animal 

data, MeHg is classified as a ‘‘possible’’ 

human carcinogen by the IARC (1994) 

and in the IRIS (EPA, 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; NRC, 

2000). The Mercury Study observed that 

‘‘MeHg is not likely to be a human 

carcinogen under conditions of 

exposure generally encountered in the 

environment’’ (p 6–16, Vol. V). This was 

based on observation that tumors were 

noted in one species only at doses 

causing severe toxicity to the target 

organ. Although some of the human and 

animal research suggests that a link 

between MeHg and cancer may 

plausibly exist, more research is needed. 

There is also some evidence of 

reproductive and renal toxicity in 

humans from MeHg exposure. For 

example, a smaller than expected 

number of pregnancies were observed 

among women exposed via 

contaminated wheat in the Iraqi 

poisoning episode of 1956 (Bakir, et al., 

1973); other victims of that same 

poisoning event exhibited signs of renal 

damage (Jalili and Abbasi, 1961); and an 

increased incidence of deaths due to 

kidney disease was observed in women 

exposed in Minamata Bay via 

contaminated fish (Tamashiro, et al., 

1986). Other data from animal studies 

suggest a link between MeHg exposure 

and similar reproductive and renal 

effects, as well as hematological toxicity 

(NRC, 2000). Overall, human data 

regarding reproductive, renal, and 

hematological toxicity from MeHg are 

very limited and are based on either 

studies of the two high-dose poisoning 

episodes in Iraq and Japan or animal 

data, rather than epidemiological 

studies of chronic exposures at the 

levels of interest in this analysis. Note 

that the Mercury Study provides an 

assessment of MeHg cancer risk using 

the 1993 version of the Revised Cancer 

Guidelines. 

8. 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. In the 

sections that follow, numerous adverse 

effects have been identified. Further 

reducing the presence of Hg in the 

environment may help to alleviate the 

potential for adverse ecological health 

outcomes. 

A review of the literature on effects of 

Hg on fish 188 reports results for 

numerous species including trout, bass 

(large and smallmouth), northern pike, 

carp, walleye, salmon, and others from 


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189U.S. Environmental Protection Agency (EPA). 

1997. Mercury Study Report to Congress. Volume 

V: Health Effects of Mercury and Mercury 

Compounds. EPA–452/R–97–007. U.S. EPA Office 

of Air Quality Planning and Standards, and Office 

of Research and Development; U.S. Environmental 

Protection Agency (U.S. EPA). 2005. Regulatory 

Impact Analysis of the Final Clean Air Mercury 

Rule. Office of Air Quality Planning and Standards, 

Research Triangle Park, NC., March; EPA report no. 

EPA–452/R–05–003. Available on the Internet at 

http://www.epa.gov/ttn/ecas/regdata/RIAs/ 

mercury_ria_final.pdf. 

190McIntyre, JW, Barr, JF. 1997. Common Loon 

(Gavia immer) in: Pool A, Gill F (eds) The Birds of 

North America. Academy of Natural Sciences, 

Philadelphia, PA, 313. 

191McIntrye, JW, and Evers, DC, (eds) 2000. 

Loons: old history and new finding. Proceedings of 

a Symposium from the 1997 meeting, American 

Ornithologists’ Union. North American Loon Fund, 

15 August 1997, Holderness, NH, USA; Evers, DC, 

2006. Status assessment and conservation plan for 

the common loon (Gavia immer) in North America. 

U.S. Fish and Wildlife Service, Hadley, MA, USA. 

192Evers, 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. 

193Adams, 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. 

194Frederick, 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. 

195Sepulveda, 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. 

196Hoffman, 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. 

197Brasso, RL, and Cristol, DA. Effects of mercury 

exposure in the reproductive success of tree 

swallows (Tachycineta bicolor). Ecotoxicology. 

17:133–141, 2008. 

198Hallinger, 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. 

199Hawley, DM, Hallinger, KK, Cristol, DA. 

Compromised immune competence in free-living 

tree swallows exposed to mercury. Ecotoxicology. 

18:499–503, 2009. 

200 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. 

201 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. 

202Scheuhammer, 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. 

laboratory and field studies. The studies 

were conducted in areas from New York 

to Washington and the effects studied 

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. Lower fish populations 

would conceivably impact the 

ecosystem services like recreational 

fishing derived from having healthy 

aquatic ecosystems. 

Mercury also affects avian species. In 

previous reports 189 much of the focus 

has been on large piscivorous species in 

particular the common loon. The loon is 

most visible to the public during the 

summer breeding season on northern 

lakes and they have become an 

important symbol of wilderness in these 

areas.190 A multitude of loon watch, 

preservation, and protection groups 

have formed over the past few decades 

and have been instrumental in 

promoting conservation, education, 

monitoring, and research of breeding 

loons.191 Significant adverse effects on 

breeding loons from Hg have been found 

to occur including behavioral (reduced 

nest-sitting), physiological (flight feather 

asymmetry) and reproductive (chicks 

fledged/territorial pair) effects and 

reduced survival.192 Additionally, 

Evers, et al. (see footnote 5), report that 

they 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. Although 

considered to be fish-eating generally, 

these wading birds have a very wide 

diet including crayfish, crabs, snails, 

insects and frogs. These species are 

experiencing a range of adverse effects 

due to exposure to Hg. The white ibis 

has been observed to have decreased 

foraging efficiency.193 Additionally 

ibises have been shown to exhibit 

decreased reproductive success and 

altered pair behavior.194 These effects 

include significantly more unproductive 

nests, male/male pairing, reduced 

courtship behavior and lower nestling 

production by exposed males. In this 

study, a worst-case scenario suggested 

by the results could involve up to a 50 

percent reduction in fledglings due to 

MeHg in diet. In egrets, Hg has been 

implicated in the decline of the species 

in south Florida 195 and Hoffman 196 has 

shown that egrets show liver and 

possibly kidney effects. Although ibises 

and egrets are most abundant in coastal 

areas and these studies were conducted 

in south Florida and Nevada the ranges 

of ibises and egrets extend to a large 

portion of the U.S. 

Insectivorous birds have also been 

shown to suffer adverse effects due to 

Hg exposure. These songbirds such as 

Bicknell’s thrush, tree swallows, and the 

great tit have shown reduced 

reproduction, survival, and changes in 

singing behavior. Exposed tree swallows 

produced fewer fledglings,197 lower 

survival,198 and had compromised 

immune competence.199 The great tit 

has exhibited reduced singing behavior 

and smaller song repertoire in areas of 

high contamination.200 These effects 

may result in population reductions 

sufficient to affect people’s enjoyment of 

these birds. 

In mammals adverse effects have been 

observed in mink and river otter, both 

fish eating species. For otter from Maine 

and Vermont, maximum concentrations 

on Hg in fur nearly equal or exceed a 

concentration associated with mortality 

and concentration in liver for mink in 

Massachusetts/Connecticut and the 

levels in fur from mink in Maine exceed 

concentrations associated with acute 

mortality.201 Adverse sublethal effects 

may be associated with lower Hg 

concentrations and consequently be 

more widespread than potential acute 

effects. These effects may include 

increased activity, poorer maze 

performance, abnormal startle reflex, 

and impaired escape and avoidance 

behavior.202 Although we do not have 

data to show population level effects 

that would impact wildlife viewing and 

enjoyment these are ecosystem services 

potentially affected by impacts on these 

species. 

The proposed rule will also reduce 

emissions of directly emitted PM and 

ozone precursors and estimates of the 

PM2.5-related co-benefits of these air 

quality improvements may be found in 

Table 28 of this preamble. When 

characterizing uncertainty in the PMmortality relationship, 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, 

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 


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out impacts predicted to be associated 

levels above and below a ‘‘bright line’’ 

threshold, 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 PM2.5-related 

premature mortality diminishes as 

baseline concentrations of PM2.5 are 

lowered. Using the Pope, et al. (2002) 

study, 86 percent of the population is 

exposed at or above the LML of 7.5 μg/ 

m3. Using the Laden, et al. (2006) study, 

30 percent of the population is exposed 

at or above the LML of 10 μg/m3. 

Although the LML analysis provides 

some insight into the level of 

uncertainty in the estimated PM 

mortality benefits, EPA does not view 

the LML as a threshold and continues to 

quantify PM-related mortality impacts 

using a full range of modeled air quality 

concentrations. It is important to note 

that the monetized benefits include 

many but not all health effects 

associated with PM2.5 exposure. Benefits 

are shown as a range from Pope, et al., 

(2002) to Laden, et al., (2006). These 

models assume that all fine particles, 

regardless of their chemical 

composition, are equally potent in 

causing premature mortality because 

there is no clear scientific evidence that 

would support the development of 

differential effects estimates by particle 

type. 

The cost analysis is also subject to 

uncertainties. Estimating the cost 

conversion from one process to another 

is more difficult than estimating the cost 

of adding control equipment because it 

is more dependent on plant specific 

information. More information on the 

cost uncertainties can be found in the 

RIA. 

A summary of the monetized benefits 

and net benefits for the proposed rule at 

discount rates of 3 percent and 7 

percent is in Table 28 of this preamble. 

For more information on the benefits 

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 proposed rule will 

be submitted for approval to the OMB 

under the PRA, 44 U.S.C. 3501 et seq. 

An ICR document has been prepared by 

EPA (ICR No. 2137.05). 

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 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 proposed rule would require 

maintenance inspections of the control 

devices but would not require any 

notifications or reports beyond those 

required by the General Provisions. The 

recordkeeping requirements require 

only the specific information needed to 

determine compliance. 

The annual monitoring, reporting, and 

recordkeeping burden for this collection 

(averaged over the first 3 years after the 

effective date of the standards) is 

estimated to be $49.1 million. This 

includes 329,605 labor hours per year at 

a total labor cost of $27.0 million per 

year, and total non-labor capital costs of 

$22.1 million per year. This estimate 

includes initial and annual performance 

test, conducting and documenting a 

tune-up, semiannual excess emission 

reports, maintenance inspections, 

developing a monitoring plan, 

notifications, and recordkeeping. The 

total burden for the Federal government 

(averaged over the first 3 years after the 

effective date of the standard) is 

estimated to be 18,039 hours per year at 

a total labor cost of $877 million per 

year. 

Burden means the total time, effort, or 

financial resources expended by persons 

to generate, maintain, retain, or disclose 

or provide information to or for a 

Federal agency. This includes the time 

needed to review instructions; develop, 

acquire, install, and utilize technology 

and systems for the purposes of 

collecting, validating, and verifying 

information, processing and 

maintaining information, and disclosing 

and providing information; adjust the 

existing ways to comply with any 

previously applicable instructions and 

requirements; train personnel to be able 

to respond to a collection of 

information; search data sources; 

complete and review the collection of 

information; and transmit or otherwise 

disclose the information. 

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 and 48 CFR chapter 15. 

To comment on EPA’s need for this 

information, the accuracy of the 

provided burden estimates, and any 

suggested methods for minimizing 

respondent burden, including the use of 

automated collection techniques, EPA 

has established a public docket for this 

proposed rule, which includes this ICR, 

under Docket ID number EPA–HQ– 

OAR–2009–0234. Submit any comments 

related to the ICR to EPA and OMB. See 

ADDRESSES section at the beginning of 

this preamble for where to submit 

comments to EPA. Send comments to 

OMB at the Office of Information and 

Regulatory Affairs, Office of 

Management and Budget, 725 17th 

Street, NW., Washington, DC 20503, 

Attention: Desk Office for EPA. Because 

OMB is required to make a decision 

concerning the ICR between 30 and 60 

days after May 3, 2011, a comment to 

OMB is best assured of having its full 

effect if OMB receives it by June 2, 2011. 

The final rule will respond to any OMB 

or public comments on the information 

collection requirements contained in 

this proposal. 

C. Regulatory Flexibility Act (RFA), as 

Amended by the Small Business 

Regulatory Enforcement Fairness Act of 

1996 (SBREFA), 5 U.S.C. 601 et seq. 

The 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 proposed rule on small 

entities, small entity is defined as (as 

defined by the Small Business 

Administration’s (SBA) regulations at 13 

CFR 121.201): (1) A small business 

according to SBA size standards by the 

North American Industry Classification 

System category of the owning entity 

(for NAICS 221112 and 221122, the 

range of small business size standards 

for electric utilities is 4 million 


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megawatt hours of production or less); 

(2) a small governmental jurisdiction 

that is a government of a city, county, 

town, township, village, 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. 

After considering the economic 

impacts of this proposed rule on small 

entities, EPA cannot certify that this 

action will not have a significant 

economic impact on a substantial 

number of small entities. This 

determination, which is included in the 

Initial Regulatory Flexibility Analysis 

(IRFA) found in Chapter 10 of the RIA 

for this proposed rule, is based on the 

economic impact of this proposed rule 

to all affected small entities across the 

electric power sector. 

The summary of the IRFA is as 

follows. EPA has assessed the potential 

impact of this action on small entities 

and found that approximately 102 of the 

estimated 1,400 EGUs potentially 

affected by today’s proposed rule are 

owned by the 83 potentially affected 

small entities identified by EPA’s 

analysis. EPA estimates that 59 of the 83 

identified small entities will have 

annualized costs greater than 1 percent 

of their revenues. 

Because the potential existed for a 

likely significant impact for substantial 

number of small entities, 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 this 

rule. 

1. Panel Process and Panel Outreach 

As required by RFA section 609(b), as 

amended by SBREFA, EPA has 

conducted outreach to small entities 

and on October 27, 2010, EPA’s Small 

Business Advocacy Chairperson 

convened a Panel under RFA section 

609(b). In addition to the Chair, the 

Panel consisted of the Director of the 

Sector Policies and Programs Division 

within EPA’s Office of Air and 

Radiation, the Chief Counsel for 

Advocacy of SBA, and the 

Administrator of the Office of 

Information and Regulatory Affairs 

within OMB. 

As part of the SBAR Panel process we 

conducted outreach with 

representatives from 18 various small 

entities that potentially would be 

affected by this rule. The SERs included 

representatives of EGUs owned by 

municipalities, cooperatives, and 

private investors. We distributed 

outreach materials to the SERs; these 

materials included background and 

project history, CAA section 112 

overview, constraints on the 

rulemaking, rulemaking options under 

consideration, and potential control 

technologies and estimated cost. We met 

with 14 of the SERs, as well as five nonSER participants from organizations 

representing power producers, on 

December 2, 2010, to discuss the 

outreach materials, potential 

requirements of the rule, and regulatory 

areas where EPA has discretion and 

could potentially provide flexibility. 

The Panel received written comments 

from, or on behalf of, 10 SERs following 

the meeting in response to discussions 

at the meeting and the questions posed 

to the SERs by the Agency. The SERs 

were specifically asked to provide 

comment on regulatory approaches that 

could help to minimize the rule’s 

impact on small businesses. 

2. Panel Recommendations for Small 

Business Flexibilities 

Consistent with the RFA/SBREFA 

requirements, the Panel evaluated the 

assembled materials and small-entity 

comments on issues related to elements 

of the IRFA. A copy of the Final Panel 

Report (including all comments 

received from SERs in response to the 

Panel’s outreach meeting) is included in 

the docket for this proposed rule. In 

general, the Panel recommended that 

EPA consider its various flexibilities to 

the maximum extent possible consistent 

with CAA requirements to mitigate the 

impacts of the rulemaking on small 

businesses and to seek comment on 

potential adverse economic impacts of 

the proposed rule on affected small 

entities and recommendations to 

mitigate such impacts. With respect to 

specific issues and options, however, 

there were varying recommendations 

from panel members. Issues and options 

discussed among the panel members 

included: (1) MACT floor 

determinations and variability 

assessment; (2) monitoring, reporting, 

and recordkeeping requirements; (3) 

subcategorization; (4) area source 

standards; (5) work practice standards; 

(6) health based emission limits; (7) 

related Federal rules; (8) potential 

adverse economic impacts; and (9) 

concerns with the SBAR process. Panel 

member recommendations regarding 

each of these issues and options are 

presented in Chapter 9 of the Final 

Panel Report. As noted elsewhere in this 

preamble, this proposal is based on a 

regulatory alternative that includes 

subcategorization, MACT floor-based 

numerical emission limitations, work 

practice standards, alternative 

standards, alternative compliance 

options, and emissions averaging. 

We invite comments on all aspects of 

the proposal and its impacts, including 

potential adverse impacts, on small 

entities. 

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 

proposed 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 for the 

Proposed Toxics Rule’’ under UMRA 

section 202 that is within the RIA and 

which is summarized below. 


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1. Statutory Authority 

As discussed elsewhere in this 

preamble, the statutory authority for this 

proposed 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 MACT 

based 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 is 

presented in the RIA for this rulemaking 

and in the docket. The regulatory 

alternative upon which this proposed 

rule is based represents the MACT floor 

for all regulated pollutants for four of 

the five subcategories of EGUs and for 

all but one regulated pollutant for the 

fifth subcategory. These proposed 

MACT floor-based standards represent 

the least costly and least burdensome 

alternative. Beyond-the-floor emission 

limits for Hg are proposed for existing 

and new EGUs designed to burn coal 

having a calorific value less than 8,300 

Btu/lb. 

2. Social Costs and Benefits 

The RIA prepared for this proposed 

rule including the Agency’s assessment 

of costs and benefits and is in the 

docket. 

It is estimated that 3 years after 

implementation of this proposed rule, 

HAP would be reduced by thousands of 

tons, including reductions in HCl, HF, 

metallic HAP (including Hg), and 

several other organic HAP from EGUs. 

Studies have determined a relationship 

between exposure to 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, there are significant 

reductions in PM2.5 and in SO2 that 

would occur, including approximately 

84 thousand tons of PM2.5 and over 2 

million tons of SO2. These reductions 

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, 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 proposed 

alternative range from $59 billion (2007 

dollars) to $140 billion (2007 dollars) 

when using a 3 percent discount rate (or 

from $53 billion (2007 dollars) to $130 

billion (2007 dollars) when using a 7 

percent discount rate). Our estimate of 

social costs is $10.9 billion (2007 

dollars). For more detailed information 

on the benefits and costs estimated for 

this proposed rulemaking, refer to the 

RIA in the docket. 

3. Future and Disproportionate Costs 

UMRA requires that we estimate, 

where accurate estimation is reasonably 

feasible, future compliance costs 

imposed by this proposed rule and any 

disproportionate budgetary effects. Our 

estimates of the future compliance costs 

of this proposed rule are discussed 

previously in this preamble. 

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. EPA projects that 55 

government entities will have 

compliance costs greater than 1 percent 

of base generation revenue in 2016, and 

37 may experience compliance costs 

greater than 3 percent of base revenues. 

Also, one government entity is 

estimated to have all of its affected units 

retire. Overall, 17 units owned by 

government entities retire. It is also 

worth noting that two-thirds of the net 

compliance costs shown above are due 

to lost profits from retirements. More 

than half of those lost profits arise from 

retiring two large units, according to 

EPA modeling. For more details on 

these results and the methodology 

behind their estimation, see the results 

included in the RIA and which are 

discussed previously in this preamble. 

4. Effects on the National Economy 

UMRA requires that we estimate the 

effect of this proposed 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 proposed rule is presented in the 

RIA in the docket. This analysis 

provides estimates of the effect of this 

proposed 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 there 

will be a less than 4 percent increase in 

electricity price on average nationwide 

in 2016, and a less than 7 percent 

increase in natural gas price nationwide 

in 2016. Power generation from coalfired plants will fall by about 1 percent 

nationwide in 2016. 

5. Consultation With Government 

UMRA requires that we describe the 

extent of the Agency’s prior 

consultation with affected State, local, 

and tribal officials, summarize the 

officials’ comments or concerns, and 

summarize our response to those 

comments or concerns. In addition, 

UMRA section 203 requires that we 

develop a plan for informing and 

advising small governments that may be 

significantly or uniquely impacted by a 

proposal. Consistent with the 

intergovernmental consultation 

provisions of UMRA section 204, EPA 

has initiated consultations with 

governmental entities affected by this 

proposed rule. 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 

EPA as the ‘‘Big 10’’ organizations 

appropriate to contact for purpose of 

consultation with elected officials. The 

purposes of the consultation were to 


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provide general background on the 

proposal, 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 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 EPA provided, addresses 

associated with the 112 state and local 

governments estimated to be potentially 

impacted by the proposed rule. EPA has 

not received additional questions or 

requests from state or local officials. 

Consistent with UMRA section 205, 

EPA has identified and considered a 

reasonable number of regulatory 

alternatives. Because the potential 

existed for a likely significant impact for 

substantial number of small entities, 

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, EPA considered several 

options. 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 proposed provisions 

regarding a number of the 

recommendations resulting from the 

SBAR Panel process as described below 

(see elsewhere in this preamble for more 

detail). 

EPA determined that there is a 

distinguishable difference in emissions 

characteristics associated with five EGU 

design types and that these 

characteristics may affect the feasibility 

and/or effectiveness of emission control. 

Thus, the five types of units are 

proposed to be regulated separately (i.e., 

subcategorized) to account for the 

difference in emissions and applicable 

controls. The proposal establishes three 

subcategories for coal-fired EGUs and 

two subcategories for oil-fired EGUs: (1) 

Coal-fired units designed to burn coal 

having a calorific value of 8,300 Btu/lb 

or greater, (2) coal-fired units designed 

to burn virgin coal having a calorific 

value less than 8,300 Btu/lb, (3) IGCC 

units (for Hg emissions only), (4) liquid 

oil units, and (5) solid oil-derived units. 

The regulatory alternative upon 

which the proposed standards for coalfired EGUs are based includes: (1) 

MACT floor-based numerical emission 

limitations for HCl (a HAP as well as a 

surrogate for all other acid gas HAP) and 

for PM (a surrogate for non-Hg metallic 

HAP) for existing and new EGUs in all 

three subcategories; (2) MACT floorbased numerical emission limitations 

for Hg for existing and new coal-fired 

units designed to burn coal having a 

calorific value of 8,300 Btu/lb or greater 

and IGCC units; (3) beyond-the-floor 

numerical emission limitations for Hg 

for existing and new coal-fired units 

designed to burn virgin coal having a 

calorific value less than 8,300 Btu/lb; 

and (4) work practices to limit 

emissions of dioxin/furan organic HAP 

and non-dioxin/furan organic HAP for 

existing and new EGUs in all three 

subcategories. The regulatory alternative 

upon which the proposed standards for 

oil-fired EGUs are based includes: (1) 

MACT floor-based numerical emission 

limitations for Hg, total non-Hg metallic 

HAP, HCl, and HF for existing and new 

EGUs in both subcategories; and (2) 

work practices to limit emissions of 

dioxin/furan organic HAP and nondioxin/furan organic HAP for existing 

and new EGUs in both subcategories. 

The proposed use of surrogate 

pollutants would result in reduced 

compliance costs because testing would 

only be required for the surrogate 

pollutants (i.e., HCl and PM) versus for 

the HAP (i.e., acid gases and non-Hg 

metals). 

EPA also is proposing three 

alternative standards for certain 

subcategories: (1) SO2 (as an alternate to 

HCl for all subcategories with add-on 

FGD systems except IGCC units and 

liquid oil-fired units); (2) individual 

non-Hg metallic HAP (as an alternate to 

PM for all subcategories except liquid 

oil-fired units, and as an alternative to 

total non-Hg metallic HAP for the liquid 

oil-fired units subcategory); and (3) total 

non-Hg metallic HAP (as an alternate to 

PM for all subcategories except liquid 

oil-fired units). In addition, liquid oilfired EGUs may choose to demonstrate 

compliance with the Hg, non-Hg 

metallic HAP, HCl, and HF emission 

limits on the basis of fuel analysis. 

Maximum fuel inlet values for Hg, nonHg metals, chlorine, and fluorine would 

be established based on the inlet fuel 

values measured during the 

performance test indicating compliance 

with the emission limits. We also are 

proposing that owners and operators of 

existing affected sources may 

demonstrate compliance by emissions 

averaging for units at the affected source 

that are within a single subcategory. 

Alternative standards, alternative 

compliance options, and emissions 

averaging can provide sources the 

flexibility to comply in the least costly 

manner. 

The proposed work practice standard, 

which requires implementation of an 

annual performance (compliance) test 

program includes requirements to 

inspect the burner, flame pattern, and 

the system controlling the air-to-fuel 

ratio, and make any necessary 

adjustments and/or conduct any 

required maintenance and repairs; 

minimize CO emissions consistent with 

the manufacturer’s specifications; 

measure the concentration of CO in the 

effluent stream before and after any 

adjustments are made; and submit an 

annual report containing the 

concentrations of CO and O2 measured 

before and after adjustments, a 

description of any corrective actions 

taken as a part of the combustion 

adjustment, and the type and amount of 

fuel used over the 12 months prior to 

the annual adjustment. 

E. Executive Order 13132, Federalism 

Under EO 13132, 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 EPA consults with state 

and local officials early in the process 

of developing the proposed action. 

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, EPA provides the 

following federalism summary impact 

statement as required by section 6(b) of 

EO 13132. 

Based on the estimates in EPA’s RIA 

for today’s proposed rule, the proposed 

regulatory option, if promulgated, may 

have federalism implications because 

the option may impose approximately 

$666.3 million in annual direct 

compliance costs on an estimated 97 

state or local governments. Specifically, 

we estimate that there are 81 

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 


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energy) that may be directly impacted 

by today’s proposed rule. Responses to 

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.’’ 

EPA consulted with state and local 

officials in the process of developing the 

proposed rule to permit them to have 

meaningful and timely input into its 

development. EPA met with 10 national 

organizations representing state and 

local elected officials to provide general 

background on the proposal, answer 

questions, and solicit input from state/ 

local governments. The UMRA 

discussion in this preamble includes a 

description of the consultation. 

In the spirit of EO 13132, and 

consistent with EPA policy to promote 

communications between EPA and state 

and local governments, EPA specifically 

solicits comment on this proposed 

action from state and local officials. 

F. Executive Order 13175, Consultation 

and Coordination With Indian Tribal 

Governments 

Subject to EO 13175 (65 FR 67249, 

November 9, 2000) 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 

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 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.’’ 

EPA has concluded that this action 

may have tribal implications. However, 

it will neither impose substantial direct 

compliance costs on tribal governments, 

nor preempt tribal law. This proposed 

rule would impose requirements on 

owners and operators of EGUs. EPA is 

aware of three coal-fired EGUs located 

in Indian Country but is not aware of 

any EGUs owned or operated by tribal 

entities. 

EPA offered consultation with tribal 

officials early in the process of 

developing this proposed regulation to 

permit them to have meaningful and 

timely input into its development. 

Consultation letters were sent to 584 

tribal leaders. The letters provided 

information regarding EPA’s 

development of NESHAP for EGUs and 

offered consultation. Three consultation 

meetings were held on December 7, 

2010, with the Upper Sioux Community 

of Minnesota; on December 13 with 

Moapa Band of Paiutes, Forest County 

Potawatomi, Standing Rock Sioux Tribal 

Council, Fond du Lac Band of 

Chippewa; and on January 5, 2011 with 

the Forest County Potawatomi, and a 

representative from the National Tribal 

Air Association (NTAA). In these 

meetings, EPA presented the authority 

under the CAA used to develop these 

rules, and an overview of the industry 

and the industrial processes that have 

the potential for regulation. Tribes 

expressed concerns about the impact of 

EGUs on the reservations. Particularly, 

they were concerned about potential Hg 

deposition and the impact on the water 

resources of the Tribes, with particular 

concern about the impact on subsistence 

lifestyles for fishing communities, the 

cultural impact of impaired water 

quality for ceremonial purposes, and the 

economic impact on tourism. In light of 

these concerns, the tribes expressed 

interest in an expedited implementation 

of the rule, they expressed concerns 

about how the Agency would consider 

variability in setting the standards and 

use 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 they asked the Agency to consider 

going beyond-the-floor to offer more 

protection for the tribal communities. A 

more specific list of comments can be 

found in the Docket. 

In addition to these consultations, 

EPA also conducted outreach on this 

rule through presentations at the 

National Tribal Forum in Milwaukee, 

WI, and on NTAA calls. EPA 

specifically requested tribal data that 

could support the appropriate and 

necessary analysis and the RIA for this 

rule. We will also hold additional 

meetings with tribal environmental staff 

to inform them of the content of this 

proposal as well as provide additional 

consultation with tribal elected officials 

where it is appropriate. 

EPA specifically solicits additional 

comment on this proposed rule from 

tribal officials. 

G. Executive Order 13045, Protection of 

Children From Environmental Health 

Risks and Safety Risks 

Executive Order 13045 (62 FR 19,885, 

April 23, 1997) applies to any rule that: 

(1) Is determined to be ‘‘economically 

significant’’ as defined under EO 12866, 

and (2) concerns an environmental 

health or safety risk that EPA has reason 

to believe may have a disproportionate 

effect on children. If the regulatory 

action meets both criteria, the Agency 

must evaluate the environmental health 

or safety effects of this planned rule on 

children, and explain why this planned 

regulation is preferable to other 

potentially effective and reasonably 

feasible alternatives considered by the 

Agency. 

This proposed rule is subject to EO 

13045 because it is an economically 

significant regulatory action as defined 

by EO 12866, and we believe that the 

action concerns an environmental 

health risk which may have a 

disproportionate impact on children. 

Although this proposed rule is based on 

technology performance, the statute is 

designed to require standards that are 

likely to protect against hazards to 

public health with an adequate margin 

of safety as described elsewhere in this 

document. The protection offered by 

this proposed rule is especially 

important for children, especially the 

developing fetus. As referenced in the 

section entitled, ‘‘Consideration of 

Health Risks to Children and 

Environmental Justice Communities’’ 

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 

elsewhere in this document. 

The public is invited to submit 

comments or identify peer-reviewed 

studies and data that assess effects of 

early life exposure to this proposed rule. 

H. Executive Order 13211, Actions 

Concerning Regulations That 

Significantly Affect Energy Supply, 

Distribution, or Use 

Executive Order 13211, (66 FR 28355, 

May 22, 2001), provides that agencies 

shall prepare and submit to the 

Administrator of the Office of 

Information and Regulatory Affairs, 

OMB, a Statement of Energy Effects for 

certain actions identified as significant 

energy actions. Section 4(b) of EO 13211 

defines ‘‘significant energy actions’’ as 

‘‘any action by an agency (normally 

published in the Federal Register) that 

promulgates or is expected to lead to the 

promulgation of a final rule or 

regulation, including notices of inquiry, 

advance notices of proposed 

rulemaking, and notices of proposed 

rulemaking: (1)(i) That is a significant 

regulatory action under EO 12866 or any 

successor order, and (ii) is likely to have 

a significant adverse effect on the 


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supply, distribution, or use of energy; or 

(2) that is designated by the 

Administrator of the Office of 

Information and Regulatory Affairs as a 

significant energy action.’’ This 

proposed rule is a ‘‘significant regulatory 

action’’ because it may likely have a 

significant adverse effect on the supply, 

distribution, or use of energy. The basis 

for the determination is as follows. 

We estimate a less than 4 percent 

price increase for electricity nationwide 

in 2016 and a 1 percent percentage fall 

in coal-fired power production. EPA 

projects that delivered natural gas prices 

will increase by about 1 percent over the 

2015 to 2030 timeframe. For more 

information on the estimated energy 

effects, please refer to the economic 

impact analysis for this proposed rule. 

The analysis is available in the RIA, 

which is in the public docket. 

Therefore, we conclude that this 

proposed rule when implemented is 

likely to have a significant adverse effect 

on the supply, distribution, or use of 

energy. 

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 EPA to use 

voluntary consensus standards (VCS) in 

their regulatory and procurement 

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) developed or 

adopted by one or more voluntary 

consensus bodies. The NTTAA directs 

EPA to provide Congress, through 

annual reports to OMB, with 

explanations when an agency does not 

use available and applicable voluntary 

consensus standards. 

This rulemaking involves technical 

standards. EPA cites the following 

standards in this proposed rule: EPA 

Methods 1, 2, 2F, 2G, 3A, 3B, 4, 5, 5D, 

6, 6C, 9, 19, 26, 26A, 29, 30A, 30B, and 

202 of 40 CFR part 60. Consistent with 

the NTTAA, EPA conducted searches to 

identify VCS in addition to these EPA 

methods. No applicable voluntary 

standards were identified for EPA 

Methods 2F, 2G, 8, 19, 201A, and 202. 

The search and review results have been 

documented and are placed in the 

docket for this proposed rule. 

EPA has decided to use American 

National Standards Institute (ANSI)/ 

ASME PTC 19–10–1981 Part 10, ‘‘Flue 

and Exhaust Gas Analyses,’’ acceptable 

as an alternative to Methods 3B (for 

CO2, CO, and O2), 6 (for SO2), 6A and 

6B (for CO2 and SO2). This standard is 

available from the ASME, Three Park 

Avenue, New York, NY 10016–5990. 

Another VCS, ASTM D6735–01, 

‘‘Standard Test Method for Measurement 

of Gaseous Chlorides and Fluorides 

from Mineral Calcining Exhaust Sources 

Impinger Method,’’ is an acceptable 

alternative to EPA Methods 26 and 26A. 

An additional VCS, ASTM D6784–02 

(2008)—Standard Test Method for 

Elemental, Oxidized, Particle-Bound 

and Total Mercury Gas Generated from 

Coal-Fired Stationary Sources (Ontario 

Hydro Method) is acceptable as an 

alternative to Method 29 for Hg, but 

only if the standard falls within the 

applicable concentration range of 0.5 to 

100 μg/Nm3. 

During the search, if the title or 

abstract (if provided) of the VCS 

described technical sampling and 

analytical procedures that are similar to 

EPA’s reference method, EPA ordered a 

copy of the standard and reviewed it as 

a potential equivalent method. All 

potential standards were reviewed to 

determine the practicality of the VCS for 

this rule. This review requires 

significant method validation data 

which meets the requirements of EPA 

Method 301 for accepting alternative 

methods or scientific, engineering and 

policy equivalence to procedures in 

EPA reference methods. EPA may 

reconsider determinations of 

impracticality when additional 

information is available for particular 

VCS. 

The search identified 22 other VCS 

that were potentially applicable for this 

rule in lieu of EPA reference methods. 

After reviewing the available standards, 

EPA determined that 22 candidate VCS 

(ASTM D3154–00 (2006), ASME 

B133.9–1994 (2001), ANSI/ASME PTC 

19–10–1981 Part 10, ASTM D5835–95 

(2007), International Organization for 

Standards (ISO) 10396:1993 (2007), ISO 

12039:2001, ASTM D6522–00 (2005), 

Canadian Standards Association (CAN/ 

CSA) Z223.2–M86 (1999), ISO 

9096:1992 (2003), ANSI/ASME PTC– 

38–1980 (1985), ASTM D3685/D3685M– 

98 (2005), ISO 7934:1998, ISO 

11632:1998, ASTM D3464–96 (2007), 

ASTM D3796–90 (2004), ISO 

10780:1994, CAN/CSA Z223.21–M1978, 

ASTM D3162–94 (2005), CAN/CSA 

Z223.1–M1977, EN 1911–1,2,3 (1998), 

EN 13211:2001, CAN/CSA Z223.26– 

M1987) identified for measuring 

emissions of pollutants or their 

surrogates subject to emission standards 

in the proposed rule would not be 

practical due to lack of equivalency, 

documentation, validation data, and 

other important technical and policy 

considerations. These 22 methods are 

listed Attachment 1 to the 

documentation memo, along with the 

EPA review comments, which may be 

found in the docket. 

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 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, lowincome, and tribal populations in the 

U.S. 

This proposed rule establishes 

national emission standards for new and 

existing EGUs that combust coal and oil. 

EPA estimates that there are 

approximately 1,400 units located at 

550 facilities covered by this proposed 

rule. 

This proposed 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 proposed 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; some of the 

directly-emitted PM is in the form of 

PM2.5. Reducing emissions of PM 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 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 

proposed rule will also have a small 

effect on electricity and natural gas 


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prices and has the potential to affect the 

cost structure of the utility industry and 

could lead to shifts in how and where 

electricity is generated. Although energy 

prices are estimated to increase, we can 

only estimate national impacts. We are 

unable to determine impacts other than 

at the national level at this time. 

Pursuant to EO 12898 and the 

‘‘Interim Guidance on Considering 

Environmental Justice During the 

Development of an Action’’ (July 2010), 

during development of a rule EPA 

considers whether there are positive or 

negative impacts of the action that 

appear to affect low-income, minority, 

or tribal communities 

disproportionately. Regardless of 

whether a disproportionate effect exists, 

EPA also considers whether there is a 

chance for these communities to 

meaningfully participate in the 

rulemaking process. 

Today’s proposed rule is one of a 

group of regulatory actions that EPA 

will take over the next several years to 

respond to statutory and judicial 

mandates that will reduce exposure to 

HAP and PM2.5, as well as to other 

pollutants, from EGUs and other 

sources. In addition, 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 proposed 

rule will place a limit on the rates of Hg 

and other HAP emitted from each 

affected EGU. As a result, emissions of 

Hg and other HAP such as HCl will be 

substantially reduced in the vast 

majority of states. In some states, 

however, there may be small increases 

in Hg emissions due to shifts in 

electricity generation from EGUs with 

higher emission rates to EGUs with 

already low emission rates. Hydrogen 

chloride emissions are projected to 

increase at a small number of sources 

but that does not lead to any increased 

emissions at the state level. 

The primary risk analysis to support 

the finding that this proposed 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 was collected. For 

example, while the Vietnamese and 

Laotian survey data were collected in 

California, given the ethnic (heritage) 

nature of these high fish consumption 

rates, we assumed that they could also 

be associated with members of these 

ethnic groups living elsewhere in the 

U.S. Therefore, the high-end 

consumption rates referenced in the 

California study for these ethnic groups 

were used to model risk at watersheds 

elsewhere in the U.S. As a result of this 

approach, the specific fish consumption 

patterns of several different EJ groups 

are fundamental to EPA’s assessment of 

both the underlying risks that make this 

proposed rule appropriate and 

necessary, and of the analysis of the 

benefits of reducing exposure to Hg and 

the other hazardous air pollutants. 

EPA’s full analysis of risks from 

consumption of Hg-contaminated fish 

are contained in the preamble for this 

rule. The effects of this proposed rule on 

the health risks from Hg and other HAP 

are presented in the preamble and in the 

RIA for this rule. This information can 

be accessed through docket EPA–HQ– 

OAR–2009–0234 and from the main 

EPA webpage for the rule http:// 

www.epa.gov/ttn/atw/utility/ 

utilitypg.html. 

2. Potential Environmental and Public 

Health Impacts to Vulnerable 

Populations 

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 

proposed rule (so-called ‘‘co-benefits’’). 

a. Socio-Economic Distribution. As 

part of the analysis for this proposed 

rule, EPA reviewed the aggregate 

demographic makeup of the 

communities near EGUs covered by this 

proposed 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. 

EGUs usually have very tall emission 

stacks; this tends to disperse the 

pollutants emitted from these stacks 

fairly far from the source. In addition, 

several of the pollutants emitted by 

these sources, such as Hg and SO2, are 

known to travel long distances and 

harm both the environment and human 

health hundreds or even thousands of 

miles from where they were emitted. 

This proximity-to-the-source review is 

included in the analysis for this 

proposed rule because some EGUs emit 

enough Ni or Cr to cause elevated 

lifetime cancer risks greater than 1 in a 

million in nearby communities. In 

addition, EPA’s analysis indicates that 

there are localized areas with elevated 

levels of Hg deposition around most 

U.S. EGUs. 

The review identified those census 

blocks within two circular distances (5 

km and 50 km) of coal-fired EGUs and 

determined their demographic and 

socio-economic composition (e.g., race, 

income, education, etc.). The radius of 

5 km (or approximately 3 miles) was 

chosen because it has been used in other 

demographic analyses focused on areas 

around potential sources. The radius of 

50 km (or approximately 31 miles) was 

used to approximate the distance from 

the source where elevated levels of Hg 

deposition might occur and may also be 

indicative of the area where risks from 

non-Hg HAP are most likely to occur. 

The results of EPA’s demographic 

analysis for coal fired EGUs are shown 

in the following table: 


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TABLE 30—COMPARATIVE SUMMARY OF THE DEMOGRAPHICS WITHIN 5 KM (3 MILES) AND 50 KM (31 MILES) OF THE

AFFECTED SOURCES

White 

(%) 

African 

American 

(%) 

Native 

American 

(%) 

Other and 

multiracial 

(%) 

Hispanic 

(%) 

Minority 

(%) 

Below poverty line (%) 

5 km (3-mile) Buffer ................................. 70.8 15.8 0.7 12.7 15.5 35.5 15.6 

50 km (31.1 miles) Buffer ........................ 74.5 15.2 0.5 9.7 9.9 29.7 11.6 

National Average ..................................... 75.1 12.3 0.9 11.7 13.7 31.6 13.1 

The data indicate that coal-fired EGUs 

are located in areas where minority 

share of the population living within a 

3-mile buffer is higher than the national 

average. For these same areas, the 

percent of the population below the 

poverty line is also higher than the 

national average. At 50 km from the 

source, however, the demographics are 

different. Although the percent African 

American remain above the national 

average, the percent of minority 

(including Native Americans) and the 

percent of the population living below 

the poverty line decrease below their 

respective national averages. 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 take to reduce their emissions of 

air toxics as required by this proposed 

rule will also reduce emissions of PM 

and SO2. As a result, this proposed rule 

will reduce concentrations of PM2.5 in 

the atmosphere. Exposure to PM2.5 can 

cause or contribute to adverse health 

effects, such as asthma and heart 

disease, that significantly affect many 

minority, low-income, and tribal 

individuals and their communities. Fine 

PM (PM2.5) is particularly (but not 

exclusively) harmful to children, the 

elderly, and people with existing heart 

and lung diseases, including asthma. 

Exposure can cause premature death 

and trigger heart attacks, asthma attacks 

in children and adults with asthma, 

chronic and acute bronchitis, and 

emergency room visits and 

hospitalizations, as well as milder 

illnesses that keep children home from 

school and adults home from work. 

Missing work due to illness or the 

illness of a child is a particular problem 

for people who work jobs that do not 

provide paid sick days. Many low-wage 

employees also risk losing their jobs if 

they are absent too often, even if it is 

due to their own illness or the illness of 

a child or other relative. Finally, many 

individuals in these communities also 

lack access to high quality health care 

to treat these types of illnesses. Due to 

all these factors, many minority and 

low-income communities are 

particularly susceptible to the health 

effects of PM2.5 and receive many 

benefits from reducing it. 

We estimate that in 2016 the PMrelated annual benefits of the proposed 

rule for adults include approximately 

6600 to 17,000 fewer premature 

mortalities, 4,300 fewer cases of chronic 

bronchitis, 10,000 fewer non-fatal heart 

attacks, 12,000 fewer hospitalizations 

(for respiratory and cardiovascular 

disease combined), 4.9 million fewer 

days of restricted activity due to 

respiratory illness and approximately 

830,000 fewer lost work days. We also 

estimate substantial health 

improvements for children in the form 

of 110,000 fewer asthma attacks, 6,700 

fewer hospital admissions due to 

asthma, 10,000 fewer cases of acute 

bronchitis, and approximately 210,000 

fewer cases of upper and lower 

respiratory illness. 

We also examined the PM2.5 mortality 

risks according to race, income, and 

educational attainment. We then 

estimated the change in PM2.5 mortality 

risk as a result of this proposed 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 highestrisk counties and in the poorest counties 

have substantially higher risks of PM2.5- 

related death than people living in the 

other 95 percent of counties. This was 

true regardless of race; the difference 

between the groups of counties for each 

race is large while the differences 

among races in both groups of counties 

is very small. In contrast, the analysis 

found that people with less than high 

school education have significantly 

greater risks from PM2.5 mortality than 

people with a greater than high school 

education. This was true both for the 

highest-risk counties and for the other 

counties. In summary, the analysis 

indicates that in 2005, educational 

status, living in one of the poorest 

counties, and living in a high-risk 

county are associated with higher PM2.5

mortality risk while race is not. 

Our analysis finds that this proposed 

rule will significantly reduce the PM2.5

mortality among all populations of 

different races living throughout the 

U.S. compared to both 2005 and 2016 

pre-rule (i.e., base case) levels. The 

analysis indicates that people living in 

counties with the highest rates (top 5 

percent) of PM2.5 mortality risk in 2005 

receive the largest reduction in 

mortality risk after this rule takes effect. 

We also find that people living in the 

poorest 5 percent of the counties receive 

a larger reduction in PM2.5 mortality risk 

than all other counties. More 

information can be found in Appendix 

C of the RIA. 

EPA estimates that the benefits of the 

proposed rule are distributed among 

these populations fairly evenly. 

Therefore, there is no indication that 

people of particular race, income, or 

level of education receive a greater 

benefit (or smaller benefit) than others. 

However, the analysis does indicate that 

this proposed rule in conjunction with 

the implementation of existing or 

proposed rules (e.g., the Transport Rule) 

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 proposed rule and other rules 

will, together, reduce risks in the 

highest-risk counties to the approximate 

level of risk for the rest on the counties 

before implementation. 

These results are presented in more 

detail in the ‘‘Benefits Appendix’’ to this 

rule, a copy of which is available in the 

docket. 

3. Meaningful Public Participation 

EPA defines ‘‘Environmental Justice’’ 

to include meaningful involvement of 

all people regardless of race, color, 

national origin, or income with respect 

to the development, implementation, 

and enforcement of environmental laws, 

regulations, and polices. To promote 

meaningful involvement, EPA has 

developed a communication and 

outreach strategy to ensure that 

interested communities have access to 


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this proposed rule, are aware of its 

content, and have an opportunity to 

comment during the comment period. 

During the comment period, EPA will 

publicize the rulemaking via 

newsletters, EJ listserves, webinars and 

the internet, including the Office of 

Policy’s (OP) Rulemaking Gateway Web 

site (http://yosemite.epa.gov/opei/ 

RuleGate.nsf/). EPA will also provide 

general rulemaking fact sheets (e.g., why 

is this important for my community) for 

EJ community groups and conduct 

conference calls with interested 

communities. 

Once this rule is finalized and 

implemented, affected EGUs will need 

to update their operating (Title V) 

permits to reflect their new emissions 

limits and any other applicable 

requirements (i.e., monitoring and 

recordkeeping) from this rule. The Title 

V permitting process provides that most 

permit actions must include an 

opportunity for public review and 

comments. In addition, after the public 

review process, EPA has an opportunity 

to review the proposed permit and 

object to its issuance if it does not meet 

CAA requirements. This process gives 

members of affected communities the 

opportunity to comment on the permit 

conditions for specific sources affected 

by this rulemaking. 

4. Summary 

This proposed rule strictly limits the 

emissions rate of Hg and other HAP 

from every affected EGU in the U.S. 

EPA’s analysis indicates substantial 

health benefits, including for vulnerable 

populations, from reductions in PM2.5. 

EPA’s analysis also indicates reductions 

in risks for individuals, including for 

members of many minority populations, 

who eat fish frequently from U.S. lakes 

and rivers and who live near affected 

sources. Based on all the available 

information, EPA has determined that 

this proposed rule will not have 

disproportionately high and adverse 

human health or environmental effects 

on minority, low-income, or tribal 

populations. EPA is providing multiple 

opportunities for EJ communities to 

both learn about and comment on this 

rule and welcomes their participation. 

List of Subjects in 40 CFR Parts 60 and 

63 

Environmental protection, 

Administrative practice and procedure, 

Air pollution control, Hazardous 

substances, Intergovernmental relations, 

Reporting and recordkeeping 

requirements. 

Dated: March 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 proposed 

to be amended as follows: 

PART 60—[AMENDED] 

1. The authority citation for part 60 

continues to read as follows: 

Authority: 42 U.S.C. 7401, et seq. 

Subpart A-—[Amended] 

2. Section 60.17 is amended: 

a. By redesignating paragraphs (a)(91) 

and (a)(92) as paragraphs (a)(94) and 

(a)(95); 

b. By redesignating paragraphs (a)(89) 

and (a)(90) as paragraphs (a)(91) and 

(a)(92); 

c. By redesignating paragraphs (a)(54) 

through (a)(88) as paragraphs (a)(55) 

through (a)(89); 

d. By adding paragraph (a)(54); 

e. By adding paragraph (a)(90); and 

f. By adding paragraph (a)(93) to read 

as follows: 

§ 60.17 Incorporations by Reference. 

* * * * * 

(54) ASTM D3699—08, Standard 

Specification for Kerosine, IBR 

approved for §§ 60.41b of subpart Db of 

this part and 60.41c of subpart Dc of this 

part. 

* * * * * 

(90) ASTM D6751–11, Standard 

Specification for Biodiesel Fuel Blend 

Stock (B100) for Middle Distillate Fuels, 

IBR approved for §§ 60.41b of subpart 

Db of this part and 60.41c of subpart Dc 

of this part. 

* * * * * 

(94) ASTM D7467–10, Standard 

Specification for Diesel Fuel Oil, 

Biodiesel Blend (B6 to B20), IBR 

approved for §§ 60.41b of subpart Db of 

this part and 60.41c of subpart Dc of this 

part. 

* * * * * 

Subpart D—[Amended] 

3. The heading to Subpart D is revised 

to read as follows: 

Subpart D—Standards of Performance 

for Fossil-Fuel-Fired Steam Generators 

4. Section 60.40 is amended by 

revising paragraph (e) to read as follows: 

§ 60.40 Applicability and designation of 

affected facility. 

* * * * * 

(e) Any facility covered under either 

subpart Da or KKKK is not covered 

under this subpart. 

5. Section 60.41 is amended by 

adding the definitions of ‘‘natural gas’’ to 

read as follows: 

§ 60.41 Definitions. 

* * * * * 

Natural gas means: 

(1) A naturally occurring mixture of 

hydrocarbon and nonhydrocarbon gases 

found in geologic formations beneath 

the earth’s surface, of which the 

principal constituent is methane; or 

(2) Liquid petroleum gas, as defined 

by the American Society of Testing and 

Materials in ASTM D1835 (incorporated 

by reference, see § 60.17); or 

(3) A mixture of hydrocarbons that 

maintains a gaseous state at ISO 

conditions. Additionally, natural gas 

must either be composed of at least 70 

percent methane by volume or have a 

gross calorific value between 34 and 43 

megajoules (MJ) per dry standard cubic 

meter (910 and 1,150 Btu per dry 

standard cubic foot). 

* * * * * 

6. Section 60.42 is amended as 

follows: 

a. By revising paragraph (a) 

introductory text. 

b. By adding paragraph (d). 

c. By adding 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 and operator of an 

affected facility that combusts only 

natural gas and that is subject to a 

federally enforceable permit limiting 

fuel use to natural gas is exempt from 

the PM and opacity standards specified 

in paragraph a of this section. 

(e) An owner or operator of an 

affected facility that combusts only 

gaseous or liquid fossil fuel (excluding 

residual oil) with potential SO2

emissions rates of 26 ng/J (0.060 lb/ 

MMBtu) or less and that does not use 

post-combustion technology to reduce 

emissions of SO2 or PM is exempt from 

the PM standards specified in paragraph 

a of this section. 

7. Section 60.45 is amended as 

follows: 

a. By revising paragraph (a). 

b. By revising paragraphs (b) 

introductory text and (b)(1) through 

(b)(5). 

c. By revising paragraph (b)(6) 

introductory text. 


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§ 60.45 Emissions and Fuel Monitoring. 

(a) Each owner or operator of an 

affected facility subject to the applicable 

emissions standard shall install, 

calibrate, maintain, and operate 

continuous opacity monitoring system 

(COMS) for measuring opacity and a 

continuous emissions monitoring 

system (CEMS) for measuring SO2

emissions, NOX emissions, and either 

oxygen (O2) or carbon dioxide (CO2) 

except as provided in paragraph (b) of 

this section. 

(b) Certain of the CEMS and COMS 

requirements under paragraph (a) of this 

section do not apply to owners or 

operators under the following 

conditions: 

(1) For a fossil-fuel-fired steam 

generator that combusts only gaseous or 

liquid fossil fuel (excluding residual oil) 

with potential SO2 emissions rates of 26 

ng/J (0.060 lb/MMBtu) or less and that 

does not use post-combustion 

technology to reduce emissions of SO2

or PM, COMS for measuring the opacity 

of emissions and CEMS for measuring 

SO2 emissions are not required if the 

owner or operator monitors SO2

emissions by fuel sampling 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 SO2 and NOX, a CEMS for 

measuring either O2 or CO2 is not 

required. 

(5) For affected facilities using a PM 

CEMS, a bag leak detection system to 

monitor the performance of a fabric 

filter (baghouse) according to the most 

current requirements in section 

§ 60.48Da of this part, or an ESP 

predictive model to monitor the 

performance of the ESP developed in 

accordance and operated according to 

the most current requirements in section 

§ 60.48Da of this part a COMS is not 

required. 

(6) A COMS for measuring the opacity 

of emissions is not required for an 

affected facility that does not use postcombustion technology (except a wet 

scrubber) for reducing PM, SO2, or 

carbon monoxide (CO) emissions, burns 

only gaseous fuels or fuel oils that 

contain less than or equal to 0.30 weight 

percent sulfur, and is operated such that 

emissions of CO to the atmosphere from 

the affected source are maintained at 

levels less than or equal to 0.15 lb/ 

MMBtu on a boiler operating day 

average basis. Owners and operators of 

affected sources electing to comply with 

this paragraph must demonstrate 

compliance according to the procedures 

specified in paragraphs (b)(6)(i) through 

(iv) of this section. 

* * * * * 

Subpart Da—[Amended] 

8. The heading to Subpart Da is 

revised to read as follows: 

Subpart Da—Standards of 

Performance for Electric Utility Steam 

Generating Units 

9. Section 60.40Da is amended by 

revising paragraph (e) and by adding 

paragraph (f) to read as follows: 

§ 60.40Da Applicability and designation of 

affected facility. 

* * * * * 

(e) Applicability of the requirement of 

this subpart to an electric utility 

combined cycle gas turbine other than 

an IGCC electric utility steam generating 

unit is as specified in paragraphs (e)(1) 

through (e)(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/hr) heat input of fossil 

fuel are subject to this subpart except in 

cases when the affected facility (i.e. heat 

recovery steam generator) meets the 

applicability requirements and is 

subject to subpart KKKK of this part. 

(2) For heat recovery steam generators 

used with duct burners subject to this 

subpart, only emissions resulting from 

the combustion of fuels in the steam 

generating unit (i.e. duct burners) are 

subject to the standards under this 

subpart. (The emissions resulting from 

the combustion of fuels in the stationary 

combustion turbine engine are subject to 

subpart GG or KKKK, as applicable, of 

this part). 

(3) Any affected facility that meets the 

applicability requirements and is 

subject to subpart Eb or subpart CCCC 

of this part is not subject to the emission 

standards under subpart Da. 

(f) General Duty to minimize 

emissions. At all times, the owner or 

operator must operate and maintain any 

affected source, including associated air 

pollution control equipment and 

monitoring equipment, in a manner 

consistent with safety and good air 

pollution control practices for 

minimizing emissions. Determination of 

whether such operation and 

maintenance procedures are being used 

will be based on information available 

to the Administrator which may 

include, but is not limited to, 

monitoring results, review of operation 

and maintenance procedures, review of 

operation and maintenance records, and 

inspection of the source. 

10. Section 60.41Da is amended by 

revising the definitions of ‘‘gaseous 

fuel,’’ ‘‘integrated gasification combined 

cycle electric utility steam generating 

unit,’’ ‘‘petroleum’’ and ‘‘steam 

generating unit,’’ adding the definitions 

of ‘‘affirmative defense’’ and ‘‘petroleum 

coke,’’ and deleting the definitions of 

‘‘dry flue gas desulfurization 

technology,’’ ‘‘emission rate period,’’ and 

‘‘responsible official’’ to read as follows: 

§ 61.41Da Definitions. 

* * * * * 

Affirmative defense means, in the 

context of an enforcement proceeding, a 

response or defense put forward by a 

defendant, regarding which the 

defendant has the burden of proof, and 

the merits of which are independently 

and objectively evaluated in a judicial 

or administrative proceeding. 

* * * * * 

Gaseous fuel means any fuel that is 

present as a gas at standard conditions 

and includes, but is not limited to, 

natural gas, refinery fuel gas, process 

gas, coke-oven gas, synthetic gas, and 

gasified coal. 

* * * * * 

Integrated gasification combined 

cycle electric utility steam generating 

unit or IGCC electric utility steam 

generating unit means an electric utility 

combined cycle gas turbine that is 

designed to burn fuels containing 50 

percent (by heat input) or more 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. 

* * * * * 


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Petroleum for facilities constructed, 

reconstructed, or modified before May 4, 

2011, means crude oil or a fuel derived 

from crude oil, including, but not 

limited to, distillate oil, and residual oil. 

For units constructed, reconstructed, or 

modified after May 3, 2011, Petroleum 

means crude oil or a fuel derived from 

crude oil, including, but not limited to, 

distillate oil, residual oil, and petroleum 

coke. 

* * * * * 

Petroleum Coke, also known as 

petcoke, means a carbonization product 

of high-boiling hydrocarbon fractions 

obtained in petroleum processing 

(heavy residues). Petroleum coke is 

typically derived from oil refinery coker 

units or other cracking processes. 

* * * * * 

Steam generating unit for facilities 

constructed, reconstructed, or modified 

before May 4, 2011, means any furnace, 

boiler, or other device used for 

combusting fuel for the purpose of 

producing steam (including fossil-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. 

* * * * * 

11. Revise § 60.42Da to read as 

follows: 

§ 60.42Da Standard for particulate matter 

(PM). 

(a) Except as provided in paragraph 

(a)(4) of this section, on and after the 

date on which the initial performance 

test is completed or required to be 

completed under § 60.8, whichever date 

comes first, an owner or operator of an 

affected facility shall not cause to be 

discharged into the atmosphere from 

any affected facility for which 

construction, reconstruction, or 

modification commenced before March 

1, 2005, any gases that contain filterable 

PM in excess of: 

(1) 13 ng/J (0.03 lb/MMBtu) heat 

input; 

(2) 1 percent of the potential 

combustion concentration (99 percent 

reduction) when combusting solid fuel; 

and 

(3) 30 percent of potential combustion 

concentration (70 percent reduction) 

when combusting liquid fuel. 

(4) An owner or operator of an 

affected facility that combusts only 

gaseous or liquid fuels (excluding 

residual oil) with potential SO2

emissions rates of 26 ng/J (0.060 lb/ 

MMBtu) or less, and does not use a postcombustion technology to reduce 

emissions of SO2 or PM is exempt from 

the PM standard specified in paragraphs 

(a)(1), (a)(2), and (a)(3) of this section: 

(b) Except as provided in paragraphs 

(b)(1) and (b)(2) of this section, on and 

after the date the initial PM performance 

test is completed or required to be 

completed under § 60.8, whichever date 

comes first, an owner or operator of an 

affected facility shall not cause to be 

discharged into the atmosphere any 

gases which exhibit greater than 20 

percent opacity (6-minute average), 

except for one 6-minute period per hour 

of not more than 27 percent opacity. 

(1) Owners and operators of an 

affected facility that elect to install, 

calibrate, maintain, and operate a 

continuous emissions monitoring 

system (CEMS) for measuring PM 

emissions according to the requirements 

of this subpart are exempt from the 

opacity standard specified in this 

paragraph (b) of this section. 

(2) An owner or operator of an 

affected facility that combusts only 

natural gas is exempt from the opacity 

standard specified in paragraph (b) of 

this section. 

(c) Except as provided in paragraphs 

(d) and (e) of this section, on and after 

the date on which the initial 

performance test is completed or 

required to be completed under § 60.8, 

whichever date comes first, no owner or 

operator of an affected facility that 

commenced construction, 

reconstruction, or modification after 

February 28, 2005, but before May 4, 

2011, shall cause to be discharged into 

the atmosphere from that affected 

facility any gases that contain filterable 

PM in excess of either: 

(1) 18 ng/J (0.14 lb/MWh) gross energy 

output; or 

(2) 6.4 ng/J (0.015 lb/MMBtu) heat 

input. 

(d) As an alternative to meeting the 

requirements of paragraph (c) of this 

section, the owner or operator of an 

affected facility for which construction, 

reconstruction, or modification 

commenced after February 28, 2005, but 

before May 4, 2011, may elect to meet 

the requirements of this paragraph. For 

an affected facility that commenced 

construction, reconstruction, or 

modification, on and after the date on 

which the initial performance test is 

completed or required to be completed 

under § 60.8, whichever date comes 

first, no owner or operator shall cause 

to be discharged into the atmosphere 

from that affected facility any gases that 

contain filterable PM in excess of: 

(1) 13 ng/J (0.030 lb/MMBtu) heat 

input, and 

(2) For an affected facility that 

commenced construction or 

reconstruction, 0.1 percent of the 

combustion concentration determined 

according to the procedure in 

§ 60.48Da(o)(5) (99.9 percent reduction) 

when combusting solid, liquid, or 

gaseous fuel, or 

(3) For an affected facility that 

commenced modification, 0.2 percent of 

the combustion concentration 

determined according to the procedure 

in § 60.48Da(o)(5) (99.8 percent 

reduction) when combusting solid, 

liquid, or gaseous fuel. 

(e) An owner or operator of an 

affected facility than combusts only 

gaseous or liquid fuels (excluding 

residual oil) with potential SO2

emissions rates of 26 ng/J (0.060 lb/ 

MMBtu) or less, and that does not use 

a post-combustion technology to reduce 

emissions of SO2 or PM is exempt from 

the PM standard specified in paragraphs 

(c) of this section. 

(f) Except as provided in paragraph (g) 

of this section, on and after the date on 

which the initial performance test is 

completed or required to be completed 

under § 60.8, whichever date comes 

first, no owner or operator of an affected 

facility that commenced construction, 

modification, or reconstruction after 

May 3, 2011, shall cause to be 

discharged into the atmosphere from 

that affected facility any gases that 

contain total PM in excess of either: 

(1) For an affected facility that 

commenced construction or 

reconstruction 7.0 ng/J (0.055 lb/MWh) 

gross energy output; or 

(2) For an affected facility that 

commenced modification, 15 ng/J (0.034 

lb/MMBtu) heat input. 

(g) An owner or operator of an 

affected facility that combusts only 

natural gas is exempt from the total PM 

standard specified in paragraph (f) of 

this section. 

(h) The PM emission standards under 

this section do not apply to an owner or 

operator of any affected facility that is 

operated under a PM commercial 

demonstration permit issued by the 

Administrator in accordance with the 

provisions of § 60.47Da. 

12. Section 60.43Da is amended as 

follows: 

a. By revising paragraphs (a)(1) 

through (a)(3). 

b. By revising paragraph (f). 

c. By revising paragraph (i). 

d. By revising paragraph (j). 

e. By revising paragraph (k). 


jlentini on DSKJ8SOYB1PROD with PROPOSALS2
25094 Federal Register / Vol. 76, No. 85 / Tuesday, May 3, 2011 / Proposed Rules 

f. By adding paragraph (a)(4). 

g. By adding paragraph (l). 

h. By adding paragraph (m). 

i. By adding paragraph (n). 

§ 60.43Da Standard for sulfur dioxide 

(SO2). 

(a) * * * 

(1) 520 ng/J (1.20 lb/MMBtu) heat 

input and 10 percent of the potential 

combustion concentration (90 percent 

reduction); 

(2) 30 percent of the potential 

combustion concentration (70 percent 

reduction), when emissions are less 

than 260 ng/J (0.60 lb/MMBtu) heat 

input; 

(3) 180 ng/J (1.4 lb/MWh) gross energy 

output; or 

(4) 65 ng/J (0.15 lb/MMBtu) heat 

input. 

* * * * * 

(f) The SO2 standards under this 

section do not apply to an owner or 

operator of an affected facility that is 

operated under an SO2 commercial 

demonstration permit issued by the 

Administrator in accordance with the 

provisions of § 60.47Da. 

* * * * * 

(i) Except as provided in paragraphs 

(j) and (k) of this section, on and after 

the date on which the initial 

performance test is completed or 

required to be completed under § 60.8, 

whichever date comes first, no owner or 

operator of an affected facility that 

commenced construction, 

reconstruction, or modification 

commenced after February 28, 2005, but 

before May 4, 2011, shall cause to be 

discharged into the atmosphere from 

that affected facility, any gases that 

contain SO2 in excess of the applicable 

emission limitation specified in 

paragraphs (i)(1) through (3) of this 

section. 

(1) For an affected facility which 

commenced construction, any gases that 

contain SO2 in excess of either: 

(i) 180 ng/J (1.4 lb/MWh) gross energy 

output; or 

(ii) 5 percent of the potential 

combustion concentration (95 percent 

reduction). 

(2) For an affected facility which 

commenced reconstruction, any gases 

that contain SO2 in excess of either: 

(i) 180 ng/J (1.4 lb/MWh) gross energy 

output; 

(ii) 65 ng/J (0.15 lb/MMBtu) heat 

input; or 

(iii) 5 percent of the potential 

combustion concentration (95 percent 

reduction). 

(3) For an affected facility which 

commenced modification, any gases that 

contain SO2 in excess of either: 

(i) 180 ng/J (1.4 lb/MWh) gross energy 

output; 

(ii) 65 ng/J (0.15 lb/MMBtu) heat 

input; or 

(iii) 10 percent of the potential 

combustion concentration (90 percent 

reduction). 

(j) On and after the date on which the 

initial performance test is completed or 

required to be completed under § 60.8, 

whichever date comes first, no owner or 

operator of an affected facility that 

commenced construction, 

reconstruction, or modification 

commenced after February 28, 2005, but 

before May 4, 2011, and that burns 75 

percent or more (by heat input) coal 

refuse on a 12-month rolling average 

basis, shall cause to be discharged into 

the atmosphere from that affected 

facility any gases that contain SO2 in 

excess of the applicable emission 

limitation specified in paragraphs (j)(1) 

through (3) of this section. 

(1) For an affected facility which 

commenced construction, any gases that 

contain SO2 in excess of either: 

(i) 180 ng/J (1.4 lb/MWh) gross energy 

output; or 

(ii) 6 percent of the potential 

combustion concentration (94 percent 

reduction). 

(2) For an affected facility which 

commenced reconstruction, any gases 

that contain SO2 in excess of either: 

(i) 180 ng/J (1.4 lb/MWh) gross energy 

output; 

(ii) 65 ng/J (0.15 lb/MMBtu) heat 

input; or 

(iii) 6 percent of the potential 

combustion concentration (94 percent 

reduction). 

(3) For an affected facility which 

commenced modification, any gases that 

contain SO2 in excess of either: 

(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 that commenced 

construction, reconstruction, or 

modification commenced after February 

28, 2005, but before May 4, 2011, shall 

cause to be discharged into the 

atmosphere from that affected facility 

any gases that contain SO2 in excess of 

the applicable emission limitation 

specified in paragraphs (k)(1) and (2) of 

this section. 

(1) For an affected facility that burns 

solid or solid-derived fuel, the owner or 

operator shall not cause to be 

discharged into the atmosphere any 

gases that contain SO2 in excess of 520 

ng/J (1.2 lb/MMBtu) heat input. 

(2) For an affected facility that burns 

other than solid or solid-derived fuel, 

the owner or operator shall not cause to 

be discharged into the atmosphere any 

gases that contain SO2 in excess of 230 

ng/J (0.54 lb/MMBtu) heat input. 

(l) Except as provided in paragraphs 

(m) and (n) of this section, on and after 

the date on which the initial 

performance test is completed or 

required to be completed under § 60.8, 

whichever date comes first, no owner or 

operator of an affected facility that 

commenced construction, 

reconstruction, or modification 

commenced after May 3, 2011, shall 

cause to be discharged into the 

atmosphere from that affected facility, 

any gases that contain SO2 in excess of 

the applicable emission limitation 

specified in paragraphs (l)(1) or (2) of 

this section. 

(1) For an affected facility which 

commenced construction or 

reconstruction, any gases that contain 

SO2 in excess of either: 

(i) 130 ng/J (1.0 lb/MWh) gross energy 

output; or 

(ii) 3 percent of the potential 

combustion concentration (97 percent 

reduction). 

(2) For an affected facility which 

commenced modification, any gases that 

contain SO2 in excess of either: 

(i) 180 ng/J (1.4 lb/MWh) gross energy 

output; or 

(ii) 10 percent of the potential 

combustion concentration (90 percent 

reduction). 

(m) On and after the date on which 

the initial performance test is completed 

or required to be completed under 

§ 60.8, whichever date comes first, no 

owner or operator of an affected facility 

that commenced construction, 

reconstruction, or modification 

commenced after May 3, 2011, and that 

burns 75 percent or more (by heat input) 

coal refuse on a 12-month rolling 

average basis, shall caused to be 

discharged into the atmosphere from 

that affected facility any gases that 

contain SO2 in excess of the applicable 

emission limitation specified in 

paragraphs (m)(1) or (2) of this section. 

(1) For an affected facility which 

commenced construction or 

reconstruction, any gases that contain 

SO2 in excess of either: 

(i) 180 ng/J (1.4 lb/MWh) gross energy 

output; or 

(ii) 6 percent of the potential 

combustion concentration (94 percent 

reduction). 

(2) For an affected facility which 

commenced modification, any gases that 

contain SO2 in excess of either: 


jlentini on DSKJ8SOYB1PROD with PROPOSALS2
Federal Register / Vol. 76, No. 85 / Tuesday, May 3, 2011 / Proposed Rules 25095 

(i) 180 ng/J (1.4 lb/MWh) gross energy 

output; or 

(ii) 10 percent of the potential 

combustion concentration (90 percent 

reduction). 

(n) On and after the date on which the 

initial performance test is completed or 

required to be completed under § 60.8, 

whichever date comes first, no owner or 

operator of an affected facility located in 

a noncontinental area that commenced 

construction, reconstruction, or 

modification commenced after May 3, 

2011, shall cause to be discharged into 

the atmosphere from that affected 

facility any gases that contain SO2 in 

excess of the applicable emission 

limitation specified in paragraphs (n)(1) 

and (2) of this section. 

(1) For an affected facility that burns 

solid or solid-derived fuel, the owner or 

operator shall not cause to be 

discharged into the atmosphere any 

gases that contain SO2 in excess of 520 

ng/J (1.2 lb/MMBtu) heat input. 

(2) For an affected facility that burns 

other than solid or solid-derived fuel, 

the owner or operator shall not cause to 

be discharged into the atmosphere any 

gases that contain SO2 in excess of 230 

ng/J (0.54 lb/MMBtu) heat input. 

13. Section 60.44Da is amended: 

a. By revising paragraph (a) 

introductory text. 

b. By revising paragraph (b). 

c. By revising paragraph (d). 

d. By revising paragraph (e). 

e. By revising paragraph (f). 

f. By adding paragraph (g). 

g. By adding paragraph (h). 

§ 60.44Da Standard for nitrogen oxides 

(NO). 

(a) On and after the date on which the 

initial performance test is completed or 

required to be completed under § 60.8, 

whichever date comes first, no owner or 

operator subject to the provisions of this 

subpart shall cause to be discharged into 

the atmosphere from any affected 

facility, except as provided under 

paragraphs (b), (d), (e), and (f) of this 

section, any gases that contain NOX

(expressed as NO2) in excess of the 

following emission limits: 

* * * * * 

(b) The NOX emission limitations 

under this section do not apply to an 

owner or operator of an affected facility 

which is operating under a commercial 

demonstration permit issued by the 

Administrator in accordance with the 

provisions of § 60.47Da. 

(d)(1) On and after the date on which 

the initial performance test is completed 

or required to be completed under 

§ 60.8, whichever date comes first, no 

owner or operator of an affected facility 

that commenced construction after July 

9, 1997, but before March 1, 2005 shall 

cause to be discharged into the 

atmosphere any gases that contain NOX

(expressed as NO2) in excess of 200 ng/ 

J (1.6 lb/MWh) gross energy output, 

except as provided under § 60.48Da(k). 

(2) On and after the date on which the 

initial performance test is completed or 

required to be completed under § 60.8, 

whichever date comes first, no owner or 

operator of affected facility for which 

reconstruction commenced after July 9, 

1997, but before March 1, 2005 shall 

cause to be discharged into the 

atmosphere any gases that contain NOX

(expressed as NO2) in excess of 65 ng/ 

J (0.15 lb/MMBtu) heat input. 

(e) Except as provided in paragraph (f) 

of this section, on and after the date on 

which the initial performance test is 

completed or required to be completed 

under § 60.8, whichever date comes 

first, no owner or operator of an affected 

facility that commenced construction, 

reconstruction, or modification after 

February 28, 2005 but before May 4, 

2011, shall cause to be discharged into 

the atmosphere from that affected 

facility any gases that contain NOX

(expressed as NO2) in excess of the 

applicable emission limitation specified 

in paragraphs (e)(1) through (3) of this 

section. 

(1) For an affected facility which 

commenced construction, any gases that 

contain NOX (expressed as NO2) in 

excess of 130 ng/J (1.0 lb/MWh) gross 

energy output, except as provided under 

§ 60.48Da(k). 

(2) For an affected facility which 

commenced reconstruction, any gases 

that contain NOX (expressed as NO2) in 

excess of either: 

(i) 130 ng/J (1.0 lb/MWh) gross energy 

output; or 

(ii) 47 ng/J (0.11 lb/MMBtu) heat 

input. 

(3) For an affected facility which 

commenced modification, any gases that 

contain NOX (expressed as NO2) in 

excess of either: 

(i) 180 ng/J (1.4 lb/MWh) gross energy 

output; or 

(ii) 65 ng/J (0.15 lb/MMBtu) heat 

input. 

(f) On and after the date on which the 

initial performance test is completed or 

required to be completed under § 60.8, 

whichever date comes first, the owner 

or operator of an IGCC electric utility 

steam generating unit subject to the 

provisions of this subpart and for which 

construction, reconstruction, or 

modification commenced after February 

28, 2005 but before May 4, 2011, shall 

meet the requirements specified in 

paragraphs (f)(1) through (3) of this 

section. 

(1) Except as provided for in 

paragraphs (f)(2) and (3) of this section, 

the owner or operator shall not cause to 

be discharged into the atmosphere any 

gases that contain NOX (expressed as 

NO2) in excess of 130 ng/J (1.0 lb/MWh) 

gross energy output. 

(2) When burning liquid fuel 

exclusively or in combination with 

solid-derived fuel such that the liquid 

fuel contributes 50 percent or more of 

the total heat input to the combined 

cycle combustion turbine, the owner or 

operator shall not cause to be 

discharged into the atmosphere any 

gases that contain NOX (expressed as 

NO2) in excess of 190 ng/J (1.5 lb/MWh) 

gross energy output. 

(3) In cases when during a 30 boiler 

operating day rolling average 

compliance period liquid fuel is burned 

in such a manner to meet the conditions 

in paragraph (f)(2) of this section for 

only a portion of the clock hours in the 

30-day period, the owner or operator 

shall not cause to be discharged into the 

atmosphere any gases that contain NOX

(expressed as NO2) in excess of the 

computed weighted-average emissions 

limit based on the proportion of gross 

energy output (in MWh) generated 

during the compliance period for each 

of emissions limits in paragraphs (f)(1) 

and (2) of this section. 

(g) Compliance with the emission 

limitations under this section are 

determined on a 30-boiler operating day 

rolling average basis, except as provided 

under § 60.48Da(j)(1). 

(h) On and after the date on which the 

initial performance test is completed or 

required to be completed under § 60.8, 

whichever date comes first, no owner or 

operator of an affected facility that 

commenced construction, 

reconstruction, or modification after 

May 3, 2011, shall cause to be 

discharged into the atmosphere from 

that affected facility any gases that 

contain NOX (expressed as NO2) in 

excess of 88 ng/J (0.70 lb/MWh) gross 

energy output. 

§ 60.45Da [Removed and Reserved] 

14. Remove and reserve § 60.45Da. 

15. Section 60.47Da is amended as 

follows: 

a. By adding paragraph (f). 

b. By adding paragraph (g). 

c. By adding paragraph (h). 

d. By adding paragraph (i). 

Section 60.47Da Commercial 

demonstration permit. 

* * * * * 

(f) An owner or operator of an affected 

facility that uses a pressurized fluidized 

bed or a multi-pollutant emissions 

controls system who is issued a 


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commercial demonstration permit by 

the Administrator is not subject to the 

total PM emission reduction 

requirements under § 60.42Da but must, 

as a minimum, reduce PM emissions to 

less than 15 ng/J (0.034 lb/MMBtu) heat 

input. 

(g) An owner or operator of an 

affected facility that uses a pressurized 

fluidized bed or a multi-pollutant 

emissions controls system who is issued 

a commercial demonstration permit by 

the Administrator is not subject to the 

SO2 standards or emission reduction 

requirements under § 60.43Da but must, 

as a minimum, reduce SO2 emissions to 

5 percent of the potential combustion 

concentration (95 percent reduction) or 

to less than 180 ng/J (1.4 lb/MWh) gross 

output on a 30 boiler operating day 

rolling average basis. 

(h) An owner or operator of an 

affected facility that uses a pressurized 

fluidized bed or a multi-pollutant 

emissions controls system or advanced 

combustion controls who is issued a 

commercial demonstration permit by 

the Administrator is not subject to the 

NOX standards or emission reduction 

requirements under § 60.44Da but must, 

as a minimum, reduce NOX emissions to 

less than 130 ng/J (1.0 lb/MWh) gross 

output on a 30 boiler operating day 

rolling average basis. 

(i) Commercial demonstration permits 

may not exceed the following equivalent 

MW electrical generation capacity for 

any one technology category. 

Technology Pollutant 

Equivalent electrical capacity 

(MW electrical 

output) 

Multi-pollutant Emission Control ................................................................................................................... SO2 ....................... 1,000 

Multi-pollutant Emission Control ................................................................................................................... NOX ....................... 1,000 

Multi-pollutant Emission Control ................................................................................................................... PM ......................... 1,000 

Pressurized Fluidized Bed Combustion ....................................................................................................... SO2 ....................... 1,000 

Pressurized Fluidized Bed Combustion ....................................................................................................... NOX ....................... 1,000 

Pressurized Fluidized Bed Combustion ....................................................................................................... PM ......................... 1,000 

Advanced Combustion Controls ................................................................................................................... NOX ....................... 1,000 

16. Section 60.48Da is amended as 

follows: 

a. By revising paragraph (c). 

b. By revising paragraph (g). 

c. By revising paragraph (k)(1)(i). 

d. By revising paragraph (k)(1)(ii). 

e. By revising paragraph (k)(2)(i). 

f. By revising paragraph (k)(2)(iv). 

g. By removing and reserving 

paragraph (l). 

h. By revising paragraph (n). 

i. By revising paragraphs (p)(5), (p)(7), 

and (p)(8). 

j. By adding paragraph (r). 

Section 60.48a Compliance provisions. 

* * * * * 

(c) For affected facilities that 

commenced construction, modification, 

or reconstruction before May 4, 2011, 

the PM emission standards under 

§ 60.42Da, and the NOX emission 

standards under § 60.44Da apply at all 

times except during periods of startup, 

shutdown, or malfunction. The sulfur 

dioxide emission standards under 

§ 60.43Da apply at all times except 

during periods of startup, shutdown, or 

when both emergency conditions exist 

and the procedures under paragraph (d) 

of this section are implemented. For 

affected facilities that commence 

construction, modification, or 

reconstruction after May 3, 2011, the 

PM emission standards under § 60.42Da, 

the NOX emission standards under 

§ 60.44Da, and the sulfur dioxide 

emission standards under § 60.43Da 

apply at all times. 

* * * * * 

(g) The owner or operator of an 

affected facility subject to emission 

limitations in this subpart shall 

determine compliance as follows: 

(1) For affected facilities that 

commenced construction, modification, 

or reconstruction before May 4, 2011, 

compliance with applicable 30 boiler 

operating day rolling average SO2 and 

NOX emission limitations is determined 

by calculating the arithmetic average of 

all hourly emission rates for SO2 and 

NOX for the 30 successive boiler 

operating days, except for data obtained 

during startup, shutdown, malfunction 

(NOX only), or emergency conditions 

(SO2 only). For affected facilities that 

commence construction, modification, 

or reconstruction after May 3, 2011, 

compliance with applicable 30 boiler 

operating day rolling average SO2 and 

NOX emission limitations is determined 

by dividing the sum of all the SO2 and 

NOX emissions for the 30 successive 

boiler operating days divided by the 

sum of all the gross useful output for the 

30 successive boiler operating days. 

(2) For affected facilities that 

commenced construction, modification, 

or reconstruction before May 4, 2011, 

compliance with applicable SO2

percentage reduction requirements is 

determined based on the average inlet 

and outlet SO2 emission rates for the 30 

successive boiler operating days. For 

affected facilities that commence 

construction, modification, or 

reconstruction after May 3, 2011, 

compliance with applicable SO2

percentage reduction requirements is 

determined based on the ‘‘as fired’’ total 

potential emissions and the total outlet 

SO2 emissions for the 30 successive 

boiler operating days. 

(3) For affected facilities that 

commenced construction, modification, 

or reconstruction before May 4, 2011 

compliance with applicable daily 

average PM emission limitations is 

determined by calculating the 

arithmetic average of all hourly 

emission rates for PM each boiler 

operating day, except for data obtained 

during startup, shutdown, and 

malfunction. For affected facilities that 

commence construction, modification, 

or reconstruction after May 3, 2011, 

compliance with applicable daily 

average PM emission limitations is 

determined by calculating the sum of all 

PM emissions for PM each boiler 

operating day divided by the sum of all 

the gross useful output for PM each 

boiler operating day, except for data 

obtained during malfunction. Averages 

are only calculated for boiler operating 

days that have non-out-of-control data 

for at least 18 hours of unit operation 

during which the standard applies. 

Instead, all of the non-out-of-control 

hourly emission rates of the operating 

day(s) not meeting the minimum 18 

hours non-out-of-control data daily 

average requirement are averaged with 

all of the non-out-of-control hourly 

emission rates of the next boiler 

operating day with 18 hours or more of 

non-out-of-control PM CEMS data to 

determine compliance. 

* * * * * 

(k) * * * 

(1) * * * 

(i) The emission rate (E) of NOX shall 

be computed using Equation 2 in this 

section: 


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Where: 

E = Emission rate of NOX from the duct 

burner, ng/J (lb/MWh) gross output; 

Csg = Average hourly concentration of NOX

exiting the steam generating unit, ng/ 

dscm (lb/dscf); 

Cte = Average hourly concentration of NOX in 

the turbine exhaust upstream from duct 

burner, ng/dscm (lb/dscf); 

Qsg = Average hourly volumetric flow rate of 

exhaust gas from steam generating unit, 

dscm/hr (dscf/hr); 

Qte = Average hourly volumetric flow rate of 

exhaust gas from combustion turbine, 

dscm/hr (dscf/hr); 

Osg = Average hourly gross energy output 

from steam generating unit, J/h (MW); 

and 

h = Average hourly fraction of the total heat 

input to the steam generating unit 

derived from the combustion of fuel in 

the affected duct burner. 

* * * * * 

(2) * * * 

(i) The emission rate (E) of NOX shall 

be computed using Equation 3 in this 

section: 

Where: 

E = Emission rate of NOX from the duct 

burner, ng/J (lb/MWh) gross output; 

Csg = Average hourly concentration of NOX

exiting the steam generating unit, ng/ 

dscm (lb/dscf); 

Qsg = Average hourly volumetric flow rate of 

exhaust gas from steam generating unit, 

dscm/hr (dscf/hr); and 

Occ = Average hourly gross energy output 

from entire combined cycle unit, J/h 

(MW). 

* * * * * 

(iv) The owner or operator may, in 

lieu of installing, operating, and 

recording data from the continuous flow 

monitoring system specified in 

§ 60.49Da(l), determine the mass rate 

(lb/hr) of NOX emissions by installing, 

operating, and maintaining continuous 

fuel flowmeters following the 

appropriate measurements procedures 

specified in appendix D of part 75 of 

this chapter. If this compliance option is 

selected, the emission rate (E) of NOX

shall be computed using Equation 4 in 

this section: 

Where: 

E = Emission rate of NOX from the duct 

burner, ng/J (lb/MWh) gross output; 

ERsg = Average hourly emission rate of NOX

exiting the steam generating unit heat 

input calculated using appropriate F 

factor as described in Method 19 of 

appendix A of this part, ng/J (lb/ 

MMBtu); 

Hcc = Average hourly heat input rate of entire 

combined cycle unit, J/hr (MMBtu/hr); 

and 

Occ = Average hourly gross energy output 

from entire combined cycle unit, J/h 

(MW). 

* * * * * 

(n) Compliance provisions for sources 

subject to § 60.42Da(c)(1). The owner or 

operator of an affected facility subject to 

§ 60.42Da(c)(1) shall calculate PM 

emissions by multiplying the average 

hourly PM output concentration 

(measured according to the provisions 

of § 60.49Da(t)), by the average hourly 

flow rate (measured according to the 

provisions of § 60.49Da(l) or 

§ 60.49Da(m)), and divided by the 

average hourly gross energy output 

(measured according to the provisions 

of § 60.49Da(k)). 

* * * * * 

(p) * * * 

(5) At a minimum, non-out-of-control 

valid CEMS hourly averages shall be 

obtained for 75 percent of all operating 

hours on a 30 boiler operating day 

rolling average basis. Beginning on 

January 1, 2012, non-out-of-control 

CEMS hourly averages shall be obtained 

for 90 percent of all operating hours on 

a 30 boiler operating day rolling average 

basis. 

(i) At least two data points per hour 

shall be used to calculate each 1-hour 

arithmetic average. 

(ii) [Reserved] 

* * * * * 

(7) All non-out-of-control CEMS data 

shall be used in calculating average 

emission concentrations even if the 

minimum CEMS data requirements of 

paragraph (j)(5) of this section are not 

met. 

(8) When PM emissions data are not 

obtained because of CEMS breakdowns, 

repairs, calibration checks, and zero and 

span adjustments, emissions data shall 

be obtained by using other monitoring 

systems as approved by the 

Administrator to provide, as necessary, 

non-out-of-control emissions data for a 

minimum of 90 percent (only 75 percent 

is required prior to January 1, 2012) of 

all operating hours per 30 boiler 

operating day rolling average. 

* * * * * 

(r) Affirmative Defense for 

Exceedance of Emission Limit During 

Malfunction. In response to an action to 

enforce the standards set forth in 

paragraph §§ 60.42Da, 60.43Da, and 

60.44Da, you may assert an affirmative 

defense to a claim for civil penalties for 

exceedances of such standards that are 

caused by malfunction, as defined at 40 

CFR 60.2. Appropriate penalties may be 

assessed, however, if you fail to meet 

your burden of proving all of the 

requirements in the affirmative defense. 

The affirmative defense shall not be 

available for claims for injunctive relief. 

(1) To establish the affirmative 

defense in any action to enforce such a 

limit, you must timely meet the 

notification requirements in paragraph 

(b) of this section, and must prove by a 

preponderance of evidence that: 

(i) The excess emissions: 

(A) Were caused by a sudden, 

infrequent, and unavoidable failure of 

air pollution control and monitoring 

equipment, process equipment, or a 

process to operate in a normal or usual 

manner, and 

(B) Could not have been prevented 

through careful planning, proper design 

or better operation and maintenance 

practices; and 

(C) Did not stem from any activity or 

event that could have been foreseen and 

avoided, or planned for; and 

(D) Were not part of a recurring 

pattern indicative of inadequate design, 

operation, or maintenance; and 

(ii) Repairs were made as 

expeditiously as possible when the 

applicable emission limitations were 

being exceeded. Off-shift 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 


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25098 Federal Register / Vol. 76, No. 85 / Tuesday, May 3, 2011 / Proposed Rules 

methods and engineering judgment, the 

amount of excess emissions that were 

the result of the malfunction. 

(2) The owner or operator of the 

facility experiencing an exceedance of 

its emission limit(s) during a 

malfunction shall notify the 

Administrator by telephone or facsimile 

(FAX) transmission as soon as possible, 

but no later than two business days after 

the initial occurrence of the 

malfunction, if it wishes to avail itself 

of an affirmative defense to civil 

penalties for that malfunction. The 

owner or operator seeking to assert an 

affirmative defense shall also submit a 

written report to the Administrator 

within 45 days of the initial occurrence 

of the exceedance of the standards in 

§§ 60.42Da, 60.43Da, and 60.44Da to 

demonstrate, with all necessary 

supporting documentation, that it has 

met the requirements set forth in 

paragraph (a) of this section. The owner 

or operator may seek an extension of 

this deadline for up to 30 additional 

days by submitting a written request to 

the Administrator before the expiration 

of the 45 day period. Until a request for 

an extension has been approved by the 

Administrator, the owner or operator is 

subject to the requirement to submit 

such report within 45 days of the initial 

occurrence of the exceedance. 

17. Section 60.49Da is amended as 

follows: 

a. By revising paragraphs (a)(1), (a)(2), 

and (a)(3) introductory text. 

b. By revising paragraphs (b) 

introductory text and (b)(2). 

c. By revising paragraph (e). 

d. By revising paragraph (k) 

introductory text. 

e. By revising paragraph (l). 

f. By removing and reserving 

paragraph (p). 

g. By removing and reserving 

paragraph (q). 

h. By removing and reserving 

paragraph (r). 

i. By revising paragraph (t). 

j. By revising paragraphs (u)(1)(iii) 

and (u)(4). 

§ 60.49Da Emission monitoring. 

(a) * * * 

(1) Except as provided for in 

paragraph (a)(2) of this section, the 

owner or operator of an affected facility 

subject to an opacity standard, shall 

install, calibrate, maintain, and operate 

a COMS, and record the output of the 

system, for measuring the opacity of 

emissions discharged to the atmosphere. 

If opacity interference due to water 

droplets exists in the stack (for example, 

from the use of an FGD system), the 

opacity is monitored upstream of the 

interference (at the inlet to the FGD 

system). If opacity interference is 

experienced at all locations (both at the 

inlet and outlet of the SO2 control 

system), alternate parameters indicative 

of the PM control system’s performance 

and/or good combustion are monitored 

(subject to the approval of the 

Administrator). 

(2) As an alternative to the monitoring 

requirements in paragraph (a)(1) of this 

section, an owner or operator of an 

affected facility that meets the 

conditions in either paragraph (a)(2)(i), 

(ii), (iii), or (iv) of this section may elect 

to monitor opacity as specified in 

paragraph (a)(3) of this section. 

(i) The affected facility uses a fabric 

filter (baghouse) to meet the standards 

in § 60.42Da and a bag leak detection 

system is installed and operated 

according to the requirements in 

paragraphs § 60.48Da(o)(4)(i) through 

(v); 

(ii) The affected facility burns only 

gaseous or liquid fuels (excluding 

residual oil) with potential SO2

emissions rates of 26 ng/J (0.060 lb/ 

MMBtu) or less, and does not use a postcombustion technology to reduce 

emissions of SO2 or PM; 

(iii) The affected facility meets all of 

the conditions specified in paragraphs 

(a)(2)(iii)(A) through (C) of this section; 

or 

(A) No post-combustion technology 

(except a wet scrubber) is used for 

reducing PM, SO2, or carbon monoxide 

(CO) emissions; 

(B) Only natural gas, gaseous fuels, or 

fuel oils that contain less than or equal 

to 0.30 weight percent sulfur are 

burned; and 

(C) Emissions of CO discharged to the 

atmosphere are maintained at levels less 

than or equal to 1.4 lb/MWh on a boiler 

operating day average basis as 

demonstrated by the use of a CEMS 

measuring CO emissions according to 

the procedures specified in paragraph 

(u) of this section. 

(iv) The affected facility uses an ESP 

and uses an ESP predictive model to 

monitor the performance of the ESP 

developed in accordance and operated 

according to the most current 

requirements in section § 60.48Da of 

this part. 

(3) The owner or operators of an 

affected facility that meets the 

conditions in paragraph (a)(2) of this 

section may, as an alternative to using 

a COMS, elect to monitor visible 

emissions using the applicable 

procedures specified in paragraphs 

(a)(3)(i) through (iv) of this section. The 

opacity performance test requirement in 

paragraph (a)(3)(i) must be conducted by 

April 29, 2011, within 45 days after 

stopping use of an existing COMS, or 

within 180 days after initial startup of 

the facility, whichever is later. 

* * * * * 

(b) The owner or operator of an 

affected facility shall install, calibrate, 

maintain, and operate a CEMS, and 

record the output of the system, for 

measuring SO2 emissions, except where 

natural gas and/or liquid fuels 

(excluding residual oil) with potential 

SO2 emissions rates of 26 ng/J (0.060 lb/ 

MMBtu) or less are the only fuels 

combusted, as follows: 

* * * * * 

(2) For a facility that qualifies under 

the numerical limit provisions of 

§ 60.43Da SO2 emissions are only 

monitored as discharged to the 

atmosphere. 

* * * * * 

(e) The CEMS under paragraphs (b), 

(c), and (d) of this section are operated 

and data recorded during all periods of 

operation of the affected facility 

including periods of startup, shutdown, 

malfunction, and emergency conditions, 

except for CEMS breakdowns, repairs, 

calibration checks, and zero and span 

adjustments. 

* * * * * 

(k) The procedures specified in 

paragraphs (k)(1) through (3) of this 

section shall be used to determine gross 

output for sources demonstrating 

compliance with an output-based 

standard. 

* * * * * 

(l) The owner or operator of an 

affected facility demonstrating 

compliance with an output-based 

standard shall install, certify, operate, 

and maintain a continuous flow 

monitoring system meeting the 

requirements of Performance 

Specification 6 of appendix B of this 

part and the CD assessment, RATA and 

reporting provisions of procedure 1 of 

appendix F of this part, and record the 

output of the system, for measuring the 

volumetric flow rate of exhaust gases 

discharged to the atmosphere; or 

* * * * * 

(t) The owner or operator of an 

affected facility demonstrating 

compliance with the output-based 

emissions limitation under § 60.42Da 

shall install, certify, operate, and 

maintain a CEMS for measuring PM 

emissions according to the requirements 

of paragraph (v) of this section. An 

owner or operator of an affected facility 

demonstrating compliance with the 

input-based emission limitation in 

§ 60.42Da may install, certify, operate, 

and maintain a CEMS for measuring PM 

emissions according to the requirements 

of paragraph (v) of this section. 


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(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). 

* * * * * 

(4) As of January 1, 2012 and within 

60 days after the date of completing 

each performance test, as defined in 

§ 63.2, conducted to demonstrate 

compliance with this subpart, you must 

submit relative accuracy test audit (i.e., 

reference method) data and performance 

test (i.e., compliance test) data, except 

opacity data, electronically to EPA’s 

Central Data Exchange (CDX) by using 

the Electronic Reporting Tool (ERT) (see 

http://www.epa.gov/ttn/chief/ert/ert 

tool.html/) or other compatible 

electronic spreadsheet. Only data 

collected using test methods compatible 

with ERT are subject to this requirement 

to be submitted electronically into 

EPA’s WebFire database. 

18. Section 60.50Da is amended as 

follows: 

a. By revising paragraphs (b)(2) and 

(b)(4). 

b. By removing paragraph (g). 

c. By removing paragraph (h). 

d. By removing paragraph (i). 

§ 60.50Da Compliance determination 

procedures and methods. 

* * * * * 

(b) * * * 

(2) For the filterable particular matter 

concentration, Method 5 of appendix A 

of this part shall be used at affected 

facilities without wet FGD systems and 

Method 5B of appendix A of this part 

shall be used after wet FGD systems. 

* * * * * 

(4) Total particular matter 

concentration consists of the sum of the 

filterable and condensable fractions. 

The condensable fraction shall be 

measured using Method 202 of 

appendix M of part 51, and the filterable 

fraction shall be measured using 

Method 5 of appendix A of this part. 

* * * * * 

19. Section 60.51Da is amended as 

follows: 

a. By revising paragraph (a). 

b. By removing and reserving 

paragraph (g). 

c. By revising paragraph (k). 

§ 60.51 Da Reporting requirements. 

(a) For SO2, NOX, and PM emissions, 

the performance test data from the 

initial and subsequent performance test 

and from the performance evaluation of 

the continuous monitors (including the 

transmissometer) are submitted to the 

Administrator. 

* * * * * 

(k) The owner or operator of an 

affected facility may submit electronic 

quarterly reports for SO2 and/or NOX

and/or opacity in lieu of submitting the 

written reports required under 

paragraphs (b), (g), and (i) of this 

section. The format of each quarterly 

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(a) [Removed and reserved] 

20. Section 60.52Da is amended by 

removing and reserving paragraph (a). 

Subpart Db—[Amended] 

21. Section 60.40b is amended as 

follows: 

a. By revising paragraph (c). 

b. By revising paragraph (h). 

c. By revising paragraph (i). 

d. By adding paragraph (1). 

§ 60.40b Applicability and delegation of 

affected facility. 

* * * * * 

(c) Affected facilities that also meet 

the applicability requirements under 

subpart J or subpart Ja (Standards of 

performance for petroleum refineries) 

are subject to the PM and NOX

standards under this subpart and the 

SO2 standards under subpart J or 

subpart Ja. 

* * * * * 

(h) Any affected facility that meets the 

applicability requirements and is 

subject to subpart Ea, subpart Eb, 

subpart AAAA, or subpart CCCC of this 

part is not subject to this subpart. 

(i) Affected facilities (i.e. heat 

recovery steam generators) that are 

associated with stationary combustion 

turbines and that meet the applicability 

requirements of subpart KKKK of this 

part are not subject to this subpart. This 

subpart will continue to apply to all 

other affected facilities (i.e. heat 

recovery steam generators with duct 

burners) that are capable of combusting 

more than 29 MW (100 MMBtu/hr) heat 

input of fossil fuel. If the affected 

facility (i.e. heat recovery steam 

generator) is subject to this subpart, only 

emissions resulting from combustion of 

fuels in the steam generating unit are 

subject to this subpart. (The stationary 

combustion turbine emissions are 

subject to subpart GG or KKKK, as 

applicable, of this part.) 

* * * * * 

(l) Affected facilities that also meet 

the applicability requirements under 

subpart BB (Standards of Performance 

for Kraft Pulp Mills) are subject to the 

SO2 and NOX standards under this 

subpart and the PM standards under 

subpart BB. 

* * * * * 

22. Section 60.41b is amended by 

revising the definition of ‘‘distillate oil’’ 

to read as follows: 

§ 60.41b Definitions. 

* * * * * 

Distillate oil means fuel oils that 

contain 0.05 weight percent nitrogen or 

less and comply with the specifications 

for fuel oil numbers 1 and 2, as defined 

by the American Society of Testing and 

Materials in ASTM D396 (incorporated 

by reference, see § 60.17), diesel fuel oil 

numbers 1 and 2, as defined by the 

American Society for Testing and 

Materials in ASTM D975 (incorporated 

by reference, see § 60.17), kerosene, as 

defined by the American Society of 

Testing and Materials in ASTM D3699 

(incorporated by reference, see § 60.17), 

biodiesel as defined by the American 

Society of Testing and Materials in 

ASTM D6751 (incorporated by 

reference, see § 60.17), or biodiesel 

blends as defined by the American 

Society of Testing and Materials in 

ASTM D7467 (incorporated by 

reference, see § 60.17). 

* * * * * 

23. Section 60.44b is amended by 

revising paragraphs (c) and (d) to read 

as follows: 

§ 60.44b Standard for nitrogen oxides 

(NO). 

* * * * * 

(c) Except as provided under 

paragraph (d) and (l) of this section, on 

and after the date on which the initial 

performance test is completed or is 

required to be completed under § 60.8, 

whichever date comes first, no owner or 

operator of an affected facility that 

simultaneously combusts coal or oil, or 

a mixture of these fuels with natural gas, 

and wood, municipal-type solid waste, 

or any other fuel shall cause to be 

discharged into the atmosphere any 

gases that contain NOX in excess of the 

emission limit for the coal or oil, or 

mixtures of these fuels with natural gas 

combusted in the affected facility, as 

determined pursuant to paragraph (a) or 

(b) of this section, unless the affected 

facility has an annual capacity factor for 

coal or oil, or mixture of these fuels 


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with natural gas of 10 percent (0.10) or 

less and is subject to a federally 

enforceable requirement that limits 

operation of the affected facility to an 

annual capacity factor of 10 percent 

(0.10) or less for coal, oil, or a mixture 

of these fuels with natural gas. 

(d) On and after the date on which the 

initial performance test is completed or 

is required to be completed under 

§ 60.8, whichever date comes first, no 

owner or operator of an affected facility 

that simultaneously combusts natural 

gas or distillate oil with a potential SO2

emissions rate of 26 ng/J (0.060 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. 

* * * * * 

24. 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 

60 days after the date of completing 

each performance test, as defined in 

§ 63.2, conducted to demonstrate 

compliance with this subpart, you must 

submit relative accuracy test audit (i.e., 

reference method) data and performance 

test (i.e., compliance test) data, except 

opacity data, electronically to EPA’s 

Central Data Exchange (CDX) by using 

the Electronic Reporting Tool (ERT) (see 

http://www.epa.gov/ttn/chief/ert/ert 

tool.html/) or other compatible 

electronic spreadsheet. Only data 

collected using test methods compatible 

with ERT are subject to this requirement 

to be submitted electronically into 

EPA’s WebFIRE database. 

25. Section 60.48b is amended as 

follows: 

a. By revising paragraphs (a) 

introductory text and (a)(1)(i). 

b. By revising paragraph (j) 

introductory text. 

c. By revising paragraph (j)(5). 

d. By revising paragraph (j)(6). 

e. By adding paragraph (j)(7). 

§ 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; 

* * * * * 

(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. 

* * * * * 

Subpart Dc—[Amended] 

26. Section 60.40c is amended as 

follows: 

a. By revising paragraph (e). 

b. By revising paragraph (f). 

c. By revising paragraph (g). 

§ 60.40c Applicability and delegation of 

authority. 

* * * * * 

(e) Affected facilities (i.e. heat 

recovery steam generators and fuel 

heaters) that are associated with 

stationary combustion turbines and 

meet the applicability requirements of 

subpart KKKK of this part are not 

subject to this subpart. This subpart will 

continue to apply to all other heat 

recovery steam generators, fuel heaters, 

and other affected facilities that are 

capable of combusting more than or 

equal to 2.9 MW (10 MMBtu/hr) heat 

input of fossil fuel but less than or equal 

to 29 MW (100 MMBtu/hr) heat input of 

fossil fuel. If the heat recovery steam 

generator, fuel heater, or other affected 

facility is subject to this subpart, only 

emissions resulting from combustion of 

fuels in the steam generating unit are 

subject to this subpart. (The stationary 

combustion turbine emissions are 

subject to subpart GG or KKKK, as 

applicable, of this part). 

(f) Any facility that meets the 

applicability requirements of and is 

subject to subpart AAAA or subpart 

CCCC of this part is not subject to this 

subpart. 

(g) Any facility that meets the 

applicability requirements of and is 

subject to an EPA approved State or 

Federal section 111(d)/129 plan 

implementing subpart BBBB of this part 

is not subject to this subpart. 

27. Section 60.41c is amended by 

removing the definition of 

‘‘Cogeneration’’ and revising the 

definition of ‘‘Distillate oil’’ to read as 

follows: 

§ 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 


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Materials in ASTM D396 (incorporated 

by reference, see § 60.17), diesel fuel oil 

numbers 1 or 2, as defined by the 

American Society for Testing and 

Materials in ASTM D975 (incorporated 

by reference, see § 60.17), kerosene, as 

defined by the American Society of 

Testing and Materials in ASTM D3699 

(incorporated by reference, see § 60.17), 

biodiesel as defined by the American 

Society of Testing and Materials in 

ASTM D6751 (incorporated by 

reference, see § 60.17), or biodiesel 

blends as defined by the American 

Society of Testing and Materials in 

ASTM D7467 (incorporated by 

reference, see § 60.17). 

* * * * * 

28. Section 60.42c is amended as 

follows: 

a. By revising paragraph (d). 

b. By revising paragraph (h) 

introductory text. 

c. By revising paragraph (h)(3). 

d. By adding paragraph (h)(4). 

§ 60.42c Standard for sulfur dioxide (SO2). 

* * * * * 

(d) On and after the date on which the 

initial performance test is completed or 

required to be completed under § 60.8, 

whichever date comes first, no owner or 

operator of an affected facility that 

combusts oil shall cause to be 

discharged into the atmosphere from 

that affected facility any gases that 

contain 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. 

* * * * * 

(h) For affected facilities listed under 

paragraphs (h)(1), (2), (3), or (4) of this 

section, compliance with the emission 

limits or fuel oil sulfur limits under this 

section may be determined based on a 

certification from the fuel supplier, as 

described under § 60.48c(f), as 

applicable. 

* * * * * 

(3) Coal-fired affected facilities with 

heat input capacities between 2.9 and 

8.7 MW (10 and 30 MMBtu/hr). 

(4) Other fuels-fired affected facilities 

with heat input capacities between 2.9 

and 8.7 MW (10 and 30 MMBtu/hr). 

* * * * * 

29. Section 60.45c is amended by 

revising paragraph (c)(14) to read as 

follows: 

§ 60.45c Compliance and performance test 

methods and procedures for particulate 

matter. 

* * * * * 

(c)(14) As of January 1, 2012, and 

within 60 days after the date of 

completing each performance test, as 

defined in § 63.2, conducted to 

demonstrate compliance with this 

subpart, you must submit relative 

accuracy test audit (i.e., reference 

method) data and performance test (i.e., 

compliance test) data, except opacity 

data, electronically to EPA’s Central 

Data Exchange (CDX) by using the 

Electronic Reporting Tool (ERT) (see 

http://www.epa.gov/ttn/chief/ert/ert 

tool.html/) or other compatible 

electronic spreadsheet. Only data 

collected using test methods compatible 

with ERT are subject to this requirement 

to be submitted electronically into 

EPA’s WebFIRE database. 

* * * * * 

30. Section 60.47c is amended as 

follows: 

a. By revising paragraphs (a) 

introductory text and (a)(1)(i). 

b. By revising paragraph (f). 

c. By revising paragraph (g). 

d. By adding paragraph (h). 

§ 60.47c Emission monitoring for 

particulate matter. 

(a) Except as provided in paragraphs 

(c), (d), (e), (f), (g), and (h) of this 

section, the owner or operator of an 

affected facility combusting coal, oil, or 

wood that is subject to the opacity 

standards under § 60.43c shall install, 

calibrate, maintain, and operate a 

continuous opacity monitoring system 

(COMS) for measuring the opacity of the 

emissions discharged to the atmosphere 

and record the output of the system. The 

owner or operator of an affected facility 

subject to an opacity standard in 

§ 60.43c(c) that is not required to use a 

COMS due to paragraphs (c), (d), (e), (f), 

or (g) of this section that elects not to 

use a COMS shall conduct a 

performance test using Method 9 of 

appendix A–4 of this part and the 

procedures in § 60.11 to demonstrate 

compliance with the applicable limit in 

§ 60.43c by April 29, 2011, within 45 

days of stopping use of an existing 

COMS, or within 180 days after initial 

startup of the facility, whichever is later, 

and shall comply with either paragraphs 

(a)(1), (a)(2), or (a)(3) of this section. The 

observation period for Method 9 of 

appendix A–4 of this part performance 

tests may be reduced from 3 hours to 60 

minutes if all 6-minute averages are less 

than 10 percent and all individual 15- 

second observations are less than or 

equal to 20 percent during the initial 60 

minutes of observation. 

(1) * * * 

(i) If no visible emissions are 

observed, a subsequent Method 9 of 

appendix A–4 of this part performance 

test must be completed within 12 

calendar months from the date that the 

most recent performance test was 

conducted or within 45 days of the next 

day that fuel with an opacity standard 

is combusted, whichever is later; 

* * * * * 

(f) Owners and operators of an 

affected facility that is subject to an 

opacity standard in § 60.43c(c) and that 

uses a bag leak detection system to 

monitor the performance of a fabric 

filter (baghouse) according to the most 

current requirements in section 

§ 60.48Da of this part is not required to 

operate a COMS. 

(g) The affected facility uses an ESP 

as the primary PM control device and 

uses an ESP predictive model to 

monitor the performance of the ESP 

developed in accordance and operated 

according to the most current 

requirements in section § 60.48Da of 

this part. 

(h) Owners and operators of an 

affected facility that is subject to an 

opacity standard in § 60.43c(c) and that 

burns only gaseous fuels and/or fuel oils 

that contain less than or equal to 0.5 

weight percent sulfur and operates 

according to a written site-specific 

monitoring plan approved by the 

permitting authority is not required to 

operate a COMS. This monitoring plan 

must include procedures and criteria for 

establishing and monitoring specific 

parameters for the affected facility 

indicative of compliance with the 

opacity standard. 

Subpart HHHH—[Removed and 

Reserved] 

31. Subpart HHHH is removed and 

reserved. 

PART 63—[AMENDED] 

32. The authority citation for part 63 

continues to read as follows: 

Authority: 42 U.S.C. 7401, et seq. 

33. Part 63 is amended by adding 

subpart UUUUU to read as follows: 

Subpart UUUUU—National Emission 

Standards for Hazardous Air 

Pollutants: Coal- and Oil-Fired Electric 

Utility Steam Generating Units 

Sec. 

What This Subpart Covers 

63.9980 What is the purpose of this 

subpart? 

63.9981 Am I subject to this subpart? 

63.9982 What is the affected source of this 

subpart? 


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63.9983 Are any EGUs not subject to this 

subpart? 

63.9984 When do I have to comply with 

this subpart? 

Emission Limitations and Work Practice 

Standards 

63.9990 What are the subcategories of 

EGUs? 

63.9991 What emission limitations, work 

practice standards, and operating limits 

must I meet? 

General Compliance Requirements 

63.10000 What are my general requirements 

for complying with this subpart? 

63.10001 Affirmative Defense for 

Exceedence of Emission Limit During 

Malfunction. 

Testing, Fuel Analyses, 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, fuel analyses, or tuneups? 

63.10007 What methods and other 

procedures must I use for the 

performance tests? 

63.10008 What fuel analyses and 

procedures must I use for the 

performance tests? 

63.10009 May I use emission averaging to 

comply with this subpart? 

63.10010 What are my monitoring, 

installation, operation, and maintenance 

requirements? 

63.10011 How do I demonstrate initial 

compliance with the emission 

limitations and work practice standards? 

Continuous Compliance Requirements 

63.10020 How do I monitor and collect data 

to demonstrate continuous compliance? 

63.10021 How do I demonstrate continuous 

compliance with the emission 

limitations and work practice standards? 

63.10022 How do I demonstrate continuous 

compliance under the emission 

averaging provision? 

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—Fuel 

Analysis Requirements 

Table 7 to Subpart UUUUU of Part 63— 

Establishing Operating Limits 

Table 8 to Subpart UUUUU of Part 63— 

Demonstrating Continuous Compliance 

Table 9 to Subpart UUUUU of Part 63— 

Reporting Requirements 

Table 10 to Subpart UUUUU of Part 63— 

Applicability of General Provisions to 

Subpart UUUUU 

Appendix A to Subpart UUUUU—Hg 

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). 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. 

§ 63.9982 What is the affected source of 

this subpart? 

(a) This subpart applies to each 

individual or group of one or more new, 

reconstructed, and existing affected 

source(s) as described in paragraphs 

(a)(1) and (2) of this section within a 

contiguous area and under common 

control. 

(1) The affected source of this subpart 

is the collection of all existing coal- or 

oil-fired EGUs as defined in § 63.10042. 

(2) The affected source of this subpart 

is each new or reconstructed coal- or 

oil-fired EGU as defined in § 63.10042. 

(b) An EGU is new if you commence 

construction of the coal- or oil-fired 

EGU after May 3, 2011, and you meet 

the applicability criteria at the time you 

commence construction. 

(c) An EGU is reconstructed if you 

meet the reconstruction criteria as 

defined in § 63.2, you commence 

reconstruction after May 3, 2011, and 

you meet the applicability criteria at the 

time you commence reconstruction. 

(d) An EGU is existing if it is not new 

or reconstructed. An existing electric 

utility steam generating unit that has 

switched completely to burning a 

different coal rank or fuel type is 

considered to be an existing affected 

source under this subpart. 

§ 63.9983 Are any EGUs not subject to this 

subpart? 

The types of EGUs listed in 

paragraphs (a) through (c) 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), covered by 40 CFR part 63, 

subpart YYYY. 

(b) Any EGU that is not a coal- or oilfired 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. 

(c) Any EGU that has the capability of 

combusting more than 73 MWe (250 

million Btu/hr, MMBtu/hr) heat input 

(equivalent to 25 MWe output) of coal 

or oil but did not fire 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. 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). 

§ 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 [DATE THE FINAL RULE IS 

PUBLISHED IN THE FEDERAL 

REGISTER] or upon startup of your 

EGU, whichever is later. 

(b) If you have an existing EGU, you 

must comply with this subpart no later 

than [3 YEARS AFTER DATE THE 

FINAL RULE IS PUBLISHED IN THE 

FEDERAL REGISTER]. 

(c) You must meet the notification 

requirements in § 63.10030 according to 

the schedule in § 63.10030 and in 

subpart A of this part. Some of the 

notifications must be submitted before 

you are required to comply with the 

emission limits and work practice 

standards in this subpart. 

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 


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(a)(2) of this section and as defined in 

§ 63.10042. 

(1) EGUs designed for coal ≥ 8,300 

Btu/lb, and 

(2) EGUs designed for coal < 8,300 

Btu/lb. (b) Oil-fired EGUs are 

subcategorized as noted in paragraphs 

(b)(1) through (b)(2) of this section and 

as defined in § 63.10042. 

(1) EGUs designed to burn liquid oil, 

and 

(2) 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 

paragraph (a)(1)(i) and (ii) or under 

§ 63.10009. 

(i) You may not use the alternate SO2

limit if your coal-fired EGU does not 

have a system using wet or dry flue gas 

desulfurization technology installed on 

the unit. 

(ii) You may not use the alternate SO2

limit if your oil-fired EGU does not have 

a system using wet or dry flue gas 

desulfurization technology installed on 

the unit. 

(iii) You must operate the wet or dry 

flue gas desulfurization technology 

installed on the unit at all times in order 

to qualify to use the alternate SO2 limit. 

(2) You must meet each operating 

limit in Table 4 to this subpart that 

applies to your EGU. If you use a control 

device or combination of control 

devices not covered in Table 4 to this 

subpart, or you wish to establish and 

monitor an alternative operating limit 

and alternative monitoring parameters, 

you must apply to the EPA 

Administrator for approval of 

alternative monitoring under § 63.8(f). 

(b) As provided in § 63.6(g), EPA may 

approve use of an alternative to the 

work practice standards in this section. 

General Compliance Requirements 

§ 63.10000 What are my general 

requirements for complying with this 

subpart? 

(a) You must be in compliance with 

the emission limits and operating limits 

in this subpart. These limits apply to 

you at all times. 

(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. For non-mercury HAP 

metals, you demonstrate continuous 

compliance through use of a particulate 

matter (PM) CEMS; initial compliance is 

determined by establishing an 

operational limit for filterable PM 

obtained during total PM emissions 

testing. As an alternative to using a PM 

CEMS, you may demonstrate initial and 

continuous compliance by conducting 

total HAP metals testing or individual 

non-mercury (Hg) metals testing. For 

acid gases, you demonstrate initial and 

continuous compliance through use of a 

continuous hydrogen chloride (HCl) 

CEMS. As an alternative to HCl CEMS, 

you may demonstrate initial and 

continuous compliance by conducting 

performance testing. As another 

alternative to HCl CEMS, you may 

demonstrate initial and continuous 

compliance through use of a certified 

sulfur dioxide (SO2) CEMS, provided 

the unit has a system using wet or dry 

flue gas desulfurization technology. For 

mercury (Hg), if your unit does not 

qualify as a low emitting EGU (LEE), 

you must demonstrate initial and 

continuous compliance through use of a 

Hg CEMS or a sorbent trap monitoring 

system. 

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

demonstrate initial and continuous 

compliance for HCl, hydrogen fluoride 

(HF), and individual or total HAP 

metals by conducting performance 

testing. As an alternative to conducting 

performance testing, you may 

demonstrate compliance with the 

applicable emissions limit for HCl, HF, 

and individual or total HAP metals 

using fuel analysis provided the 

emission rate calculated according to 

§ 63.10011(c) is less than the applicable 

emission limit. 

(d) 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), or 

through the use of a sorbent trap 

monitoring system for Hg, you must 

develop a site-specific monitoring plan 

and submit this site-specific monitoring 

plan, if requested, at least 60 days before 

your initial performance evaluation 

(where applicable) of your CMS or 

sorbent trap monitoring system. This 

requirement also applies to you if you 

petition the EPA Administrator for 

alternative monitoring parameters under 

§ 63.8(f). This requirement to develop 

and submit a site-specific monitoring 

plan does not apply to 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. The 

monitoring plan must address the 

provisions in paragraphs (d)(1) through 

(7) of this section. 

(1) Installation of the CMS 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). 

(2) Performance and equipment 

specifications for the sample interface, 

the pollutant concentration or 

parametric signal analyzer, and the data 

collection and reduction systems. 

(3) Schedule for conducting initial 

and periodic performance evaluations. 

(4) 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) or Appendix A 

to this subpart, as applicable. 

(5) Ongoing operation and 

maintenance procedures in accordance 

with the general requirements of 

§ 63.8(c)(1)(ii), (c)(3), and (c)(4)(ii) or 

Appendix A to this subpart, as 

applicable. 

(6) Conditions that define a 

continuous monitoring system 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) or Appendix 

A to this subpart, as applicable. 


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(7) Ongoing recordkeeping and 

reporting procedures in accordance with 

the general requirements of § 63.10(c), 

(e)(1), and (e)(2)(i) and Appendix A to 

this subpart, as applicable. 

(e) You must operate and maintain the 

CMS or sorbent trap monitoring system 

according to the site-specific monitoring 

plan. 

§ 63.10001 Affirmative Defense for 

Exceedence of Emission Limit During 

Malfunction. 

In response to an action to enforce the 

standards set forth in paragraph 

§ 63.9991 you may assert an affirmative 

defense to a claim for civil penalties for 

exceedances of such standards that are 

caused by malfunction, as defined at 40 

CFR 63.2. Appropriate penalties may be 

assessed, however, if the respondent 

fails to meet its 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, the owners or operators of 

facilities 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 facility 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) The owner or operator of the 

facility experiencing an exceedence of 

its emission limit(s) during a 

malfunction shall notify the EPA 

Administrator by telephone or facsimile 

(FAX) transmission as soon as possible, 

but no later than two (2) business days 

after the initial occurrence of the 

malfunction, if it wishes to avail itself 

of an affirmative defense to civil 

penalties for that malfunction. The 

owner or operator seeking to assert an 

affirmative defense shall also submit a 

written report to the EPA Administrator 

within 45 days of the initial occurrence 

of the exceedence of the standard in 

§ 63.9991 to demonstrate, with all 

necessary supporting documentation, 

that it has met the requirements set forth 

in paragraph (a) of this section. The 

owner or operator may seek an 

extension of this deadline for up to 30 

additional days by submitting a written 

request to the Administrator before the 

expiration of the 45 day period. Until a 

request for an extension has been 

approved by the Administrator, the 

owner or operator is subject to the 

requirement to submit such report 

within 45 days of the initial occurrence 

of the exceedances. 

Testing, Fuel Analyses, and Initial 

Compliance Requirements 

§ 63.10005 What are my initial compliance 

requirements and by what date must I 

conduct them? 

(a) General requirements. Affected 

EGUs must demonstrate initial 

compliance with each of the applicable 

emissions limits in Tables 1 or 2 of this 

subpart through performance testing, 

along with one or more of the following 

activities: conducting a fuel analysis for 

each type of fuel combusted, 

establishing operating limits where 

applicable according to § 63.10011 and 

Table 7 to this subpart; conducting CMS 

performance evaluations where 

applicable; and conducting sorbent trap 

monitoring system performance 

evaluations, where applicable, in 

conjunction with performance testing. If 

you use a CMS that measures pollutant 

concentrations directly (i.e., a CEMS or 

a sorbent trap monitoring system), the 

performance test consists of the first 30 

operating days of data collected with the 

certified monitoring system, after the 

applicable compliance date. If you use 

a continuous monitoring system that 

measures a surrogate for a pollutant 

(e.g., an SO2 monitor), you must perform 

initial emission testing during the same 

compliance test period and under the 

same process (e.g., fuel) and control 

device operating conditions of the 

pollutant and surrogate, in addition to 

conducting the initial 30-day 

performance test. If you wish to 

demonstrate that a unit qualifies as a 

low emitting EGU (LEE), you must 

conduct performance testing in 

accordance with paragraphs (k) and (l) 

of this section. 

(b) Performance Testing 

Requirements. Affected EGUs must 

demonstrate initial compliance with 

each of the applicable emissions limits 

in Tables 1 or 2 of this subpart by 

conducting performance tests according 

to § 63.10007 and Table 5 to this 

subpart. 

(1) For affected EGUs that do not rely 

on CMS, sorbent trap monitoring 

systems, or 28 to 30 day Method 30B 

testing to demonstrate initial 

compliance, performance test data and 

results from a prior performance test 

may be used to demonstrate initial 

compliance, provided the performance 

tests meet the following conditions: 

(i) The performance test was 

conducted within the last twelve 

months; 

(ii) The performance test was 

conducted in accordance with all 

requirements contained in § 63.10007 

and Table 5 of this subpart; and 

(iii) You certify, and have and keep 

documentation demonstrating, that the 

EGU configuration, control devices, and 

materials/fuel have remained constant 

since the prior performance test was 

conducted. 

(2) [Reserved] 

(c) Fuel Analysis Requirements. 

Affected liquid oil-fired EGUs may 

choose to demonstrate initial 

compliance with each of the applicable 

emissions limits in Tables 1 or 2 of this 

subpart by conducting a fuel analysis for 

each type of fuel combusted, except 


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those affected EGUs that meet the 

exemptions identified in paragraphs 

(c)(4) and (5) of this section and those 

affected EGUs that opt to comply with 

the individual or total HAP metals 

limits in Tables 1 or 2 of this subpart 

which must comply by conducting a 

fuel analysis as described in paragraph 

(c)(1) of this section. 

(1) For affected liquid oil-fired EGUs 

demonstrating compliance with the 

applicable emissions limits in Tables 1 

or 2 of this subpart for HCl or individual 

or total HAP metals through fuel 

analysis, your initial compliance 

requirement is to conduct a fuel analysis 

for each type of fuel burned in your 

EGU according to § 63.10008 and Table 

6 to this subpart and establish operating 

limits according to § 63.10011 and Table 

8 to this subpart. 

(2) For affected liquid oil-fired EGUs 

that elect to demonstrate compliance 

with the applicable emissions limits in 

Tables 1 or 2 of this subpart for HF, your 

initial compliance requirement is to 

conduct a fuel analysis for each type of 

fuel burned in your EGU according to 

§ 63.10008 and Table 6 to this subpart 

and establish operating limits according 

to § 63.10011 and Table 8 to this 

subpart. 

(3) Fuel analysis data and results from 

a prior fuel analysis may be used to 

demonstrate initial compliance, 

provided the fuel analysis meets the 

following conditions: 

(i) The fuel analysis was conducted 

within the last twelve months; 

(ii) The fuel analysis was conducted 

in accordance with all requirements 

contained in § 63.10008 and Table 6 of 

this subpart; and 

(iii) You certify, and have and keep 

documentation demonstrating, that the 

EGU configuration, control devices, and 

materials/fuel have remained constant 

since the prior fuel analysis was 

conducted. 

(4) For affected EGUs that combust a 

single type of fuel, you are exempted 

from the initial compliance 

requirements of conducting a fuel 

analysis for each type of fuel burned in 

your EGU according to § 63.10008 and 

Table 6 to this subpart. 

(5) For purposes of this subpart, EGUs 

that use a supplemental fuel only for 

startup, unit shutdown, or transient 

flame stability purposes qualify as 

affected EGUs that combust a single 

type of fuel, the supplemental fuel is not 

subject to the fuel analysis requirements 

under § 63.10008 and Table 6 to this 

subpart, and you are exempted from the 

initial compliance requirements of 

conducting a fuel analysis for each type 

of fuel burned in your EGU according to 

§ 63.10008 and Table 6 to this subpart. 

(d) CMS Requirements. (1) For 

affected liquid oil-fired EGUs that elect 

to demonstrate initial compliance with 

the applicable emissions limits in 

Tables 1 or 2 of this subpart for HCl 

through use of HCl CEMS, initial 

compliance is determined using the 

average hourly HCl concentrations 

obtained during the first 30 day 

operating period after the monitoring 

system is certified. 

(2) For affected liquid oil-fired EGUs 

that elect to demonstrate initial 

compliance with the applicable 

emissions limits in Tables 1 or 2 of this 

subpart for HF through use of HF CEMS, 

initial compliance is determined using 

the average hourly HF concentrations 

obtained during the first 30 day 

operating period after the monitoring 

system is certified. 

(3) For affected solid oil-derived fuelor coal-fired EGUs that demonstrate 

initial compliance with the applicable 

emissions limits in Tables 1 or 2 of this 

subpart for HCl through use of HCl 

CEMS, initial compliance is determined 

using the average hourly HCl 

concentrations obtained during the first 

30 day operating period after the 

monitoring system is certified. 

(4) For affected solid oil-derived fuelor coal-fired EGUs with installed 

systems that use wet or dry flue gas 

desulfurization technology to 

demonstrate initial compliance with the 

applicable emissions limits in Tables 1 

or 2 of this subpart for SO2 through use 

of SO2 CEMS, initial compliance is 

determined using the average hourly 

SO2 concentrations obtained during the 

first 30 day operating period after the 

monitoring system is certified. 

(5) For affected solid oil-derived fuelor coal-fired EGUs that demonstrate 

initial compliance with the applicable 

emissions limits in Tables 1 or 2 of this 

subpart for PM through use of PM 

CEMS, initial compliance is determined 

using the average hourly PM 

concentrations obtained during the first 

30 day operating period after the 

monitoring system is certified. 

(6) For affected EGUs that 

demonstrate initial compliance with the 

applicable emissions limits in Tables 1 

or 2 of this subpart for Hg through use 

of Hg CEMS, initial compliance is 

determined using the average hourly Hg 

concentrations obtained during the first 

30 day operating period after the 

monitoring system is certified. 

(7) For affected EGUs that elect to 

demonstrate initial compliance with the 

applicable emissions limits in Tables 1 

or 2 of this subpart for PM, non-Hg HAP 

metals, HCl, HF, or Hg through use of 

CPMS, initial compliance is determined 

using the average hourly PM, non-Hg 

HAP metals, HCl, HF, or Hg 

concentrations obtained during the first 

30 day operating period. 

(e) Sorbent Trap Monitoring System 

Requirements. For affected EGUs that 

demonstrate initial compliance with the 

applicable emissions limits in Tables 1 

or 2 of this subpart for Hg through use 

of Hg sorbent trap monitoring system, 

initial compliance is determined using 

the average hourly Hg concentrations 

obtained during the first 30 day 

operating period. 

(f) Tune-ups. For affected EGUs 

subject to work practice standards in 

Table 3 of this subpart, your initial 

compliance requirement is to conduct a 

tune-up of your EGU according to 

§ 63.10021(a)(16)(i) through (vi). 

(g) For existing affected sources, you 

must demonstrate initial compliance no 

later than 180 days after the compliance 

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 10 to this subpart. 

(h) If your new or reconstructed 

affected source commenced 

construction or reconstruction between 

May 3, 2011 and [DATE 60 DAYS 

AFTER PUBLICATION OF THE FINAL 

RULE IN THE FEDERAL REGISTER], 

you must demonstrate initial 

compliance with either the proposed 

emission limits or the promulgated 

emission limits no later than 180 days 

after [DATE 60 DAYS AFTER 

PUBLICATION OF THE FINAL RULE 

IN THE FEDERAL REGISTER] or within 

180 days after startup of the source, 

whichever is later, according to 

§ 63.7(a)(2)(ix). 

(i) If your new or reconstructed 

affected source commenced 

construction or reconstruction between 

May 3, 2011, and [DATE 60 DAYS 

AFTER PUBLICATION OF THE FINAL 

RULE IN THE FEDERAL REGISTER], 

and you chose 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 

[DATE 60 DAYS AFTER PUBLICATION 

OF THE FINAL RULE IN THE 

FEDERAL REGISTER] or within 3 years 

after startup of the affected source, 

whichever is later. 

(j) If your new or reconstructed 

affected source commences construction 

or reconstruction after [DATE 60 DAYS 

AFTER PUBLICATION OF THE FINAL 

RULE IN THE FEDERAL REGISTER], 

you must demonstrate initial 

compliance with the promulgated 

emission limits no later than 180 days 

after startup of the source. 


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(k) Low emitting EGU. Your existing 

EGU may qualify for low emitting EGU 

(LEE) status provided that initial 

performance test data that meet the 

requirements of § 63.10005(b) and 

paragraph (l) of this section 

demonstrate: 

(1) With the exception of mercury, 

emissions less than 50 percent of the 

appropriate emissions limitation, or 

(2) For mercury, emissions less than 

10 percent of the mercury emissions 

limitation or less than 22.0 pounds per 

year. Only existing affected units may 

qualify for LEE status for Hg. When 

qualifying for LEE status for Hg 

emissions less than 22.0 pounds per 

year, the affected unit must also 

demonstrate compliance with the 

applicable emission limitation. 

(3) The following provisions apply in 

demonstrating that a unit qualifies as a 

LEE. For all pollutants or surrogates 

except for Hg, conduct the initial 

performance tests as described in 

§ 63.10007 but note that the required 

minimum sampling volume must be 

increased nominally by a factor of two; 

follow the instructions in Table 5 to this 

subpart to convert the test data to the 

units of the applicable standard. For Hg, 

you must conduct a 28 to 30 operating 

day performance test, using Method 30B 

in appendix A–8 to part 60 of this 

chapter, to determine Hg concentration. 

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–8 

to part 60 of this chapter and conduct 

at least three nominally equal length test 

runs over the 28 to 30 day test period. 

You may not use a pair of sorbent traps 

to sample the stack gas for more than 10 

days. Collect diluent gas data over the 

corresponding time period, and if 

preferred for calculation of pounds per 

year of Hg, stack flow rate data using 

Method 2 in appendix A–1 to part 60 of 

this chapter or a certified flow rate 

monitor and moisture data using 

Method 4 in appendix A–1 to part 60 of 

this chapter or a moisture monitor. 

Record parametric data during each 

performance test, to establish operating 

limits, in accordance with the 

applicable provisions of 

§ 63.10010(k)(3). Calculate the average 

Hg concentration, in μg/m3, for the 28 

to 30 day performance test, as the 

arithmetic average of all sorbent trap 

results. Calculate the average CO2 or O2

concentration for the test period. Use 

the average Hg concentration and 

diluent gas values to express the 

performance test results in units of lb of 

Hg/TBtu, as described in section 6.2.1 of 

appendix A to this subpart, and, if 

elected, pounds of Hg per year, using 

the expected fuel input over a year 

period. You may also opt to calculate 

pounds of Hg per year using the average 

Hg concentration, average stack gas flow 

rate, average stack gas moisture, and 

maximum operating hours per year. 

(1) Startup and Shutdown default 

values for calculations. For the purposes 

of this rule and only during periods of 

startup or shutdown, use a default 

diluent gas concentration value of 10.0 

percent O2 or the corresponding fuelspecific CO2 concentration in 

calculating emissions in units of lb/ 

MMBtu or lb/TBtu. For calculating 

emissions in units of lb/MWh or lb/ 

GWh only during startup or shutdown 

periods, use a nominal electrical 

production rate equal to 5 percent of 

rated capacity. 

§ 63.10006 When must I conduct 

subsequent performance tests, fuel 

analyses, or tune-ups? 

(a) For solid oil-derived fuel- and 

coal-fired EGUs using total PM 

emissions as a surrogate for non-Hg 

HAP metals emissions and using PM 

CEMS to measure filterable PM 

emissions as a surrogate for total PM 

emissions, you must conduct all 

applicable performance tests for PM and 

non-Hg HAP metals emissions during 

the same compliance test period and 

under the same process (e.g., fuel) and 

control device operating conditions 

according to Table 5 and § 63.10007 at 

least every 5 years. 

(b) For solid oil-derived fuel- and 

coal-fired EGUs with installed systems 

that use wet or dry flue gas 

desulfurization technology using sulfur 

dioxide (SO2) emissions as a surrogate 

for HCl emissions and using SO2 CEMS 

to measure SO2 emissions, you must 

conduct all applicable performance tests 

for SO2 and HCl emissions during the 

same compliance test period and under 

the same process (e.g., fuel) and control 

device operating conditions according 

to Table 5 and § 63.10007 at least every 

5 years. 

(c) For affected units meeting the LEE 

requirements of § 63.1005(k), provided 

that the unit operates within the 

operating limits established during the 

initial performance test, you need only 

repeat the performance test once every 

5 years according to Table 5 and 

§ 63.10007 and conduct fuel sampling 

and analysis according to Table 6 and 

§ 63.10008 at least every month. 

However, if the unit fails to operate 

within the operating limits during any 

5 year compliance period, LEE status is 

lost. If this should occur: 

(1) For all pollutants or surrogates 

except for Hg, you must initiate periodic 

emission testing, as required in the 

applicable paragraph(s) of this section, 

within a six month period. 

(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 a one year period. 

(d) For solid oil-derived fuel- and 

coal-fired EGUs without PM CEMS but 

with PM emissions control devices, you 

must conduct all applicable 

performance tests for PM and non-Hg 

HAP metals emissions during the same 

compliance test period and under the 

same process (e.g., fuel) and control 

device operating conditions according 

to Table 5 and § 63.10007 at least every 

year and you must conduct non-Hg HAP 

metals emissions testing according to 

Table 5 and § 63.10007 at least every 

other month. 

(e) For solid oil-derived fuel- and 

coal-fired EGUs without PM CEMS and 

without PM emissions control devices, 

you must conduct all applicable 

performance tests for non-Hg HAP 

metals emissions according to Table 5 

and § 63.10007 at least every month. 

(f) For liquid oil-fired EGUs with nonHg HAP metals control devices, you 

must conduct all applicable 

performance tests for individual or total 

HAP metals emissions according to 

Table 5 and § 63.10007 at least every 

other month. 

(g) For liquid oil-fired EGUs without 

non-Hg HAP metals control devices, you 

must conduct all applicable 

performance tests for individual or total 

HAP metals emissions according to 

Table 5 and § 63.10007 at least every 

month. 

(h) For solid oil-derived fuel- and 

coal-fired EGUs without SO2 CEMS but 

with installed systems that use wet or 

dry flue gas desulfurization technology, 

you must conduct all applicable 

performance tests for SO2 and HCl 

emissions during the same compliance 

test period and under the same process 

(e.g., fuel) and control device operating 

conditions according to Table 5 and 

§ 63.10007 at least every year and you 

must conduct SO2 emissions testing 

according to § 63.10007 at least every 

other month. 

(i) For solid oil-derived fuel- and coalfired EGUs without SO2 CEMS and 

without installed systems that use wet 

or dry flue gas desulfurization 

technology, you must conduct all 

applicable performance tests for SO2

and HCl emissions during the same 

compliance test period and under the 

same process (e.g., fuel) and control 

device operating conditions according 

to Table 5 and § 63.10007 at least every 

year and you must conduct HCl 


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emissions testing according to Table 5 

and § 63.10007 at least every month. 

(j) For solid oil-derived fuel- and coalfired EGUs without HCl CEMS but with 

HCl emissions control devices, you 

must conduct all applicable 

performance tests for HCl emissions 

according to Table 5 and § 63.10007 at 

least every other month. 

(k) For solid oil-derived fuel- and 

coal-fired EGUs without HCl CEMS and 

without HCl emissions control devices, 

you must conduct all applicable 

performance tests for HCl emissions 

according to Table 5 and § 63.10007 at 

least every month. 

(l) For liquid oil-fired EGUs without 

HCl and HF CEMS but with HCl and HF 

emissions control devices, you must 

conduct all applicable performance tests 

for HCl and HF emissions according to 

Table 5 and § 63.10007 at least every 

other month. 

(m) For liquid oil-fired EGUs without 

HCl and HF CEMS and without HCl and 

HF emissions control devices, you must 

conduct all applicable performance tests 

for HCl and HF emissions according to 

Table 5 and § 63.10007 at least every 

month. 

(n) Unless you follow the 

requirements listed in paragraphs (o) 

through (q) of this section, performance 

tests required at least every 5 years must 

be completed within 58 to 62 months 

after the previous performance test; 

performance tests required at least every 

year must be completed no more than 

13 months after the previous 

performance test; performance tests 

required at least every 2 months must be 

completed between 52 and 69 days after 

the previous performance test; and 

performance tests required at least every 

month must be completed between 

21 and 38 days after the previous 

performance test. 

(o) For EGUs with annual or more 

frequent performance testing 

requirements, you can conduct 

performance stack tests less often for a 

given pollutant if your performance 

stack tests for the pollutant for at least 

3 consecutive years show that your 

emissions are at or below 50 percent of 

the emissions limit, and if there are no 

changes in the operation of the affected 

source or air pollution control 

equipment that could increase 

emissions. In this case, you do not have 

to conduct a performance test for that 

pollutant for the next 2 years. You must 

conduct a performance test during the 

third year and no more than 37 months 

after the previous performance test. If 

you elect to demonstrate compliance 

using emission averaging under 

§ 63.10009, you must continue to 

conduct performance stack tests at the 

appropriate frequency given in section 

(c) through (m) of this paragraph. 

(p) If your EGU continues to meet the 

emissions limit for the pollutant, you 

may choose to conduct performance 

stack tests for the pollutant every third 

year if your emissions are at or below 

the emission limit, and if there are no 

changes in the operation of the affected 

source or air pollution control 

equipment that could increase 

emissions, but each such performance 

test must be conducted no more than 37 

months after the previous performance 

test. If you elect to demonstrate 

compliance using emission averaging 

under § 63.10009, you must continue to 

conduct performance stack tests at the 

appropriate frequency given in section 

(c) through (m) of this paragraph. 

(q) If a performance test shows 

emissions in excess of 50 percent of the 

emission limit, you must conduct 

performance tests at the appropriate 

frequency given in section (c) through 

(m) of this paragraph for that pollutant 

until all performance tests over a 

consecutive 3-year period show 

compliance. 

(r) If you are required to meet an 

applicable tune-up work practice 

standard, you must conduct a 

performance tune-up according to 

§ 63.10007. Each performance tune-up 

specified in § 63.10007 must be no more 

than 18 months after the previous 

performance tune-up. 

(s) If you demonstrate compliance 

with the Hg, individual or total non-Hg 

HAP metals, HCl, or HF emissions limit 

based on fuel analysis, you must 

conduct a monthly fuel analysis 

according to § 63.10008 for each type of 

fuel burned. If you burn a new type of 

fuel, you must conduct a fuel analysis 

before burning the new type of fuel in 

your EGU. You must still meet all 

applicable continuous compliance 

requirements in § 63.10021. 

(t) You must report the results of 

performance tests, performance tuneups, and fuel analyses within 60 days 

after the completion of the performance 

tests, performance tune-ups, and fuel 

analyses. This report must also verify 

that the operating limits for your 

affected EGU have not changed or 

provide documentation of revised 

operating parameters established 

according to § 63.10011 and Table 7 to 

this subpart, as applicable. 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) You must conduct all performance 

tests according to § 63.7(c), (d), (f), and 

(h). You must also develop a sitespecific test plan according to the 

requirements in § 63.7(c). 

(b) You must conduct each 

performance test according to the 

requirements in Table 5 to this subpart. 

(c) You must conduct each 

performance test under the specific 

conditions listed in Tables 5 and 7 to 

this subpart. You must conduct 

performance tests at the maximum 

normal operating load while burning the 

type of fuel or mixture of fuels that has 

the highest content of chlorine, fluorine, 

non-Hg HAP metals, and Hg, and you 

must demonstrate initial compliance 

and establish your operating limits 

based on these tests. These requirements 

could result in the need to conduct 

more than one performance test. 

Moreover, should you desire to have 

differing operating limits which 

correspond to loads other than 

maximum normal operating load, you 

should conduct testing at those other 

loads to determine those other operating 

limits. Following each performance test 

and until the next performance test, you 

must comply with the operating limit 

for operating load conditions specified 

in Table 4 of this subpart. 

(d) For performance testing that does 

not involve CMS or a sorbent trap 

monitoring system, you must conduct 

three separate test runs for each 

performance test required, as specified 

in § 63.7(e)(3). Each test run must 

comply with the minimum applicable 

sampling times or volumes specified in 

Tables 1 and 2 to this subpart. For 

performance testing that involves CMS 

or a sorbent trap monitoring system, 

compliance shall be determined as 

described in § 63.10005(d) and (e). 

(e) To determine compliance with the 

emission limits, you must use the F– 

Factor methodology and equations in 

sections 12.2 and 12.3 of EPA Method 

19 at 40 CFR part 60, Appendix A–7 of 

this chapter to convert the measured PM 

concentrations, the measured HCl and 

HF concentrations, the measured SO2

concentrations, the measured individual 

and total non-Hg HAP metals 

concentrations, and the measured Hg 

concentrations that result from the 

initial performance test to pounds per 

million Btu (lb/MMBtu) (pounds per 

trillion Btu, lb/TBtu, for Hg) heat input 

emission rates using F-factors. 

(f) Performance tests shall be 

conducted under such conditions as the 

EPA Administrator specifies to the 

owner or operator based on 


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representative performance of the 

affected source for the period being 

tested. Upon request, the owner or 

operator shall make available to the EPA 

Administrator such records as may be 

necessary to determine the conditions of 

performance tests. 

§ 63.10008 What fuel analyses and 

procedures must I use for the performance 

tests? 

(a) You must conduct performance 

fuel analysis tests according to the 

procedures in paragraphs (b) through (e) 

of this section and Table 6 to this 

subpart, as applicable. You are not 

required to conduct fuel analyses for 

fuels used only for startup, unit 

shutdown, or transient flame stability 

purposes. 

(b) You must develop and submit a 

site-specific fuel analysis plan to the 

EPA Administrator for review and 

approval according to the following 

procedures and requirements in 

paragraphs (b)(1) and (2) of this section. 

(1) You must submit the fuel analysis 

plan no later than 60 days before the 

date that you intend to demonstrate 

compliance. 

(2) You must include the information 

contained in paragraphs (b)(2)(i) 

through (vi) of this section in your fuel 

analysis plan. 

(i) The identification of all fuel types 

anticipated to be burned in each EGU. 

(ii) For each fuel type, the notification 

of whether you or a fuel supplier will 

be conducting the fuel analysis. 

(iii) For each fuel type, a detailed 

description of the sample location and 

specific procedures to be used for 

collecting and preparing the composite 

samples if your procedures are different 

from paragraph (c) or (d) of this section. 

Samples should be collected at a 

location that most accurately represents 

the fuel type, where possible, at a point 

prior to mixing with other dissimilar 

fuel types. 

(iv) For each fuel type, the analytical 

methods from Table 6, with the 

expected minimum detection levels, to 

be used for the measurement of 

chlorine, fluorine, non-Hg HAP metals, 

or Hg. 

(v) If you request to use an alternative 

analytical method other than those 

required by Table 6 to this subpart, you 

must also include a detailed description 

of the methods and procedures that you 

are proposing to use. Methods in Table 

6 shall be used until the requested 

alternative is approved. 

(vi) If you will be using fuel analysis 

from a fuel supplier in lieu of sitespecific sampling and analysis, the fuel 

supplier must use the analytical 

methods required by Table 6 to this 

subpart. 

(c) At a minimum, you must obtain 

three composite fuel samples for each 

fuel type according to the procedures in 

paragraph (c)(1) or (2) of this section. 

(1) If sampling from a belt (or screw) 

feeder, collect fuel samples according to 

paragraphs (c)(1)(i) and (ii) of this 

section. 

(i) Stop the belt and withdraw a 6- 

inch wide sample from the full crosssection of the stopped belt to obtain a 

minimum two pounds of sample. You 

must collect all the material (fines and 

coarse) in the full cross-section. You 

must transfer the sample to a clean 

plastic bag. 

(ii) Each composite sample will 

consist of a minimum of three samples 

collected at approximately equal 1-hour 

intervals during the testing period. 

(2) If sampling from a fuel pile or 

truck, you must collect fuel samples 

according to paragraphs (c)(2)(i) through 

(iii) of this section. 

(i) For each composite sample, you 

must select a minimum of five sampling 

locations uniformly spaced over the 

surface of the pile. 

(ii) At each sampling site, you must 

dig into the pile to a depth of 18 inches. 

You must insert a clean flat square 

shovel into the hole and withdraw a 

sample, making sure that large pieces do 

not fall off during sampling. 

(iii) You must transfer all samples to 

a clean plastic bag for further 

processing. 

(d) You must prepare each composite 

sample according to the procedures in 

paragraphs (d)(1) through (7) of this 

section. 

(1) You must thoroughly mix and 

pour the entire composite sample over 

a clean plastic sheet. 

(2) You must break sample pieces 

larger than 3 inches into smaller sizes. 

(3) You must make a pie shape with 

the entire composite sample and 

subdivide it into four equal parts. 

(4) You must separate one of the 

quarter samples as the first subset. 

(5) If this subset is too large for 

grinding, you must repeat the procedure 

in paragraph (d)(3) of this section with 

the quarter sample and obtain a onequarter subset from this sample. 

(6) You must grind the sample in a 

mill. 

(7) You must use the procedure in 

paragraph (d)(3) of this section to obtain 

a one-quarter subsample for analysis. If 

the quarter sample is too large, 

subdivide it further using the same 

procedure. 

(e) You must determine the 

concentration of pollutants in the fuel 

(Hg, HAP metals, and/or chlorine) in 

units of lb/MMBtu of each composite 

sample for each fuel type according to 

the procedures in Table 6 to this 

subpart. 

§ 63.10009 May I use emission averaging 

to comply with this subpart? 

(a) As an alternative to meeting the 

requirements of § 63.9991 for PM, HF, 

HCl, non-Hg HAP metals, or Hg on an 

EGU-specific basis, if you have more 

than one existing EGU in the same 

subcategory located at one or more 

contiguous properties, belonging to a 

single major industrial grouping, which 

are under common control of the same 

person (or persons under common 

control), you may demonstrate 

compliance by emission averaging 

among the existing EGUs in the same 

subcategory, if your averaged emissions 

for such EGUs are equal to or less than 

the applicable emission limit, according 

to the procedures in this section. 

(b) Separate stack requirements. For a 

group of two or more existing EGUs in 

the same subcategory that each vent to 

a separate stack, you may average PM, 

HF, HCl, non-Hg HAP metals, or Hg 

emissions to demonstrate compliance 

with the limits in Table 2 to this subpart 

if you satisfy the requirements in 

paragraphs (c), (d), (e), (f), and (g) of this 

section. 

(c) For each existing EGU in the 

averaging group, the emission rate 

achieved during the initial compliance 

test for the HAP being averaged must 

not exceed the emission level that was 

being achieved on [THE DATE 30 DAYS 

AFTER PUBLICATION OF THE FINAL 

RULE IN THE FEDERAL REGISTER] 

or the control technology employed 

during the initial compliance test must 

not be less effective for the HAP being 

averaged than the control technology 

employed on [THE DATE 30 DAYS 

AFTER PUBLICATION OF THE FINAL 

RULE IN THE FEDERAL REGISTER]. 

(d) The averaged emissions rate from 

the existing EGUs participating in the 

emissions averaging option must be in 

compliance with the limits in Table 2 to 

this subpart at all times following the 

compliance date specified in § 63.9984. 

(e) You must demonstrate initial 

compliance according to paragraph 

(e)(1) or (2) of this section using the 

maximum normal operating load of each 

EGU and the results of the initial 

performance tests or fuel analysis. 

(1) You must use Equation 1 of this 

section to demonstrate that the PM, HF, 

SO2, HCl, non-Hg HAP metals, or Hg 

emissions from all existing units 

participating in the emissions averaging 

option do not exceed the emission 

limits in Table 2 to this subpart. 


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Ave Weighted Emissions = (Er Hm) Hm

i=1

n

i=1

n

× ÷∑∑ (Eq. 1)

Where: 

Ave Weighted Emissions = Average weighted 

emissions for PM, HF, SO2, HCl, non-Hg 

HAP metals, or Hg, in units of lb/MMBtu 

(lb/TBtu for Hg) of heat input. 

Er = Emissions rate (as determined during the 

most recent performance test, according 

to Table 5 to this subpart) for PM, HF, 

HCl, non-Hg HAP metals, or Hg or by 

fuel analysis for Cl, F, non-Hg HAP 

metals, or Hg as calculated by the 

applicable equation in § 63.10011(c) for 

unit, i, for PM, HF, SO2, HCl, non-Hg 

HAP metals, or Hg, in units of lb/MMBtu 

(lb/TBtu for Hg) of heat input. 

Hm = Maximum rated heat input capacity of 

unit, i, in units of million Btu per hour. 

n = Number of units participating in the 

emissions averaging option. 

(2) If you are not capable of 

monitoring heat input, and the EGU 

generates steam for purposes other than 

generating electricity, you may use 

Equation 2 of this section as an 

alternative to using Equation 1 of this 

section to demonstrate that the PM, HF, 

HCl, non-Hg HAP metals, and Hg 

emissions from all existing units 

participating in the emissions averaging 

option do not exceed the emission 

limits in Table 2 to this subpart. 

Ave Weighted Emissions = (Er Sm Cfi) Sm Cfi

i=1

n

i=1

n

∑ ×× ÷ × ∑ (Eq. 2)

Where: 

Ave Weighted Emissions = Average weighted 

emission level for PM, HF, HCl, non-Hg 

HAP metals, or Hg, in units of lb/MMBtu 

(lb/TBtu for Hg) of heat input. 

Er = Emissions rate (as determined during the 

most recent performance test, according 

to Table 5 to this subpart) for PM, HF, 

HCl, non-Hg HAP metals, or Hg or by 

fuel analysis for Cl, F, non-Hg HAP 

metals, or Hg as calculated by the 

applicable equation in § 63.10011(c)) for 

unit, i, for PM, HCl, HF, HAP metals, or 

Hg, in units of lb/MMBtu (lb/TBtu for 

Hg) of heat input. 

Sm = Maximum steam generation by unit, i, 

in units of pounds. 

Cf = Conversion factor, calculated from the 

most recent compliance test, in units of 

million Btu of heat input per pounds of 

steam generated for unit, i. 

n = Number of units participating in the 

emissions averaging option. 

(f) You must demonstrate compliance 

on a monthly basis determined at the 

end of every month (12 times per year) 

according to paragraphs (f)(1) through 

(3) of this section. The first monthly 

period begins on the compliance date 

specified in § 63.9984. 

(1) For each calendar month, you 

must use Equation 3 of this section to 

calculate the monthly average weighted 

emission rate using the actual heat 

capacity for each existing unit 

participating in the emissions averaging 

option. 

Ave Weighted Emissions = (Er Hb) Hb

i=1

n

i=1

n

× ÷∑∑ (Eq. 3)

Where: 

Ave Weighted Emissions = Monthly average 

weighted emission level for PM, HCl, 

HF, non-Hg HAP metals, or Hg, in units 

of lb/MMBtu (lb/TBtu for Hg) of heat 

input. 

Er = Emissions rate, (as determined during 

the most recent performance test, 

according to Table 5 to this subpart) for 

PM, HCl, HF, non-Hg HAP metals, or Hg 

or by fuel analysis for Cl, F, non-Hg HAP 

metals, or Hg as calculated by the 

applicable equation in § 63.10011(c)) for 

unit, i, for PM, HCl, HF, non-Hg HAP 

metals, or Hg, in units of lb/MMBtu (lb/ 

TBtu for Hg) of heat input. 

Hb = The average heat input for each 

calendar month of EGU, i, in units of 

million Btu. 

n = Number of units participating in the 

emissions averaging option. 

(2) If you are not capable of 

monitoring heat input, you may use 

Equation 4 of this section as an 

alternative to using Equation 3 of this 

section to calculate the monthly 

weighted emission rate using the actual 

steam generation from the units 

participating in the emissions averaging 

option. 

Ave Weighted Emissions = (Er Sa Cfi) Sa Cfi

i=1

n

i=1

n

∑ ×× ÷ × ∑ (Eq. 4)

Where: 

Ave Weighted Emissions = Monthly average 

weighted emission level for PM, HCl, 

HF, HAP metals, or Hg, in units of lb/ 

MMBtu (lb/TBtu for Hg) of heat input. 

Er = Emissions rate, (as determined during 

the most recent performance test, as 

calculated according to Table 5 to this 

subpart) for PM, HCl, HF, non-Hg HAP 

metals, or Hg or by fuel analysis for Cl, 

F, and non-Hg HAP metals, or Hg as 

calculated by the applicable equation in 

§ 63.10011(c)) for unit, i, for PM, HCl, 

HF, non-Hg HAP metals, or Hg, in units 

of lb/MMBtu (lb/TBtu for Hg) of heat 

input. 

Sa = Actual steam generation for each 

calendar month by EGU, i, in units of 

pounds. 

Cf = Conversion factor, as calculated during 

the most recent compliance test, in units 

of million Btu of heat input per pounds 

of steam generated for unit, i. 

n = Number of units participating in the 

emissions averaging option. 

(3) Until 12 monthly weighted average 

emission rates have been accumulated, 

calculate and report only the monthly 


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25110 Federal Register / Vol. 76, No. 85 / Tuesday, May 3, 2011 / Proposed Rules 

average weighted emission rate 

determined under paragraph (f)(1) or (2) 

of this section. After 12 monthly 

weighted average emission rates have 

been accumulated, for each subsequent 

calendar month, use Equation 5 of this 

section to calculate the 12-month rolling 

average of the monthly weighted 

average emission rates for the current 

month and the previous 11 months. 

Eavg = ERi 12

i=1

n

∑ ÷ (Eq. 5)

Where: 

Eavg = 12-month rolling average emissions 

rate, (lb/MMBtu heat input; lb/TBtu for 

Hg). 

ERi = Monthly weighted average, for month 

‘‘i’’ (lb/MMBtu (lb/TBtu for Hg) heat 

input)(as calculated by (f)(1) or (2)). 

(g) You must develop, and submit to 

the applicable regulatory authority for 

review and approval upon request, an 

implementation plan for emission 

averaging according to the following 

procedures and requirements in 

paragraphs (g)(1) through (4) of this 

section. 

(1) You must submit the 

implementation plan no later than 180 

days before the date that the facility 

intends to demonstrate compliance 

using the emission averaging option. 

(2) You must include the information 

contained in paragraphs (g)(2)(i) through 

(vii) of this section in your 

implementation plan for all emission 

sources included in an emissions 

average: 

(i) The identification of all existing 

EGUs in the averaging group, including 

for each either the applicable HAP 

emission level or the control technology 

installed as of [DATE 60 DAYS AFTER 

PUBLICATION OF THE FINAL RULE 

IN THE FEDERAL REGISTER] and the 

date on which you are requesting 

emission averaging to commence; 

(ii) The process parameter (heat input 

or steam generated) that will be 

monitored for each averaging group; 

(iii) The specific control technology or 

pollution prevention measure to be used 

for each emission EGU in the averaging 

group and the date of its installation or 

application. If the pollution prevention 

measure reduces or eliminates 

emissions from multiple EGUs, the 

owner or operator must identify each 

EGU; 

(iv) The test plan for the measurement 

of PM, HF, HCl, individual or total nonHg HAP metals, or Hg emissions in 

accordance with the requirements in 

§ 63.10007; 

(v) The operating parameters to be 

monitored for each control system or 

device consistent with § 63.9991 and 

Table 4, and a description of how the 

operating limits will be determined; 

(vi) If you request to monitor an 

alternative operating parameter 

pursuant to § 63.10010, you must also 

include: 

(A) A description of the parameter(s) 

to be monitored and an explanation of 

the criteria used to select the 

parameter(s); and 

(B) A description of the methods and 

procedures that will be used to 

demonstrate that the parameter 

indicates proper operation of the control 

device; the frequency and content of 

monitoring, reporting, and 

recordkeeping requirements; and a 

demonstration, to the satisfaction of the 

applicable regulatory authority, that the 

proposed monitoring frequency is 

sufficient to represent control device 

operating conditions; and 

(vii) A demonstration that compliance 

with each of the applicable emission 

limit(s) will be achieved under 

representative operating conditions. 

(3) The regulatory authority shall 

review and approve or disapprove the 

plan according to the following criteria: 

(i) Whether the content of the plan 

includes all of the information specified 

in paragraph (g)(2) of this section; and 

(ii) Whether the plan presents 

sufficient information to determine that 

compliance will be achieved and 

maintained. 

(4) The applicable regulatory 

authority shall not approve an emission 

averaging implementation plan 

containing any of the following 

provisions: 

(i) Any averaging between emissions 

of differing pollutants or between 

differing sources; or 

(ii) The inclusion of any emission 

source other than an existing unit in the 

same subcategory. 

(h) Common stack requirements. For 

a group of two or more existing affected 

units, each of which vents through a 

single common stack, you may average 

PM, HF, HCl, individual or total non-Hg 

HAP metals, or Hg emissions to 

demonstrate compliance with the limits 

in Table 2 to this subpart if you satisfy 

the requirements in paragraph (i) or (j) 

of this section. 

(i) For a group of two or more existing 

units in the same subcategory, each of 

which vents through a common 

emissions control system to a common 

stack, that does not receive emissions 

from units in other subcategories or 

categories, you may treat such averaging 

group as a single existing unit for 

purposes of this subpart and comply 

with the requirements of this subpart as 

if the group were a single unit. 

(j) For all other groups of units subject 

to paragraph (h) of this section, the 

owner or operator may elect to: 

(1) Conduct performance tests 

according to procedures specified in 

§ 63.10007 in the common stack if 

affected units from other subcategories 

vent to the common stack. The emission 

limits that the group must comply with 

are determined by the use of equation 6. 

En = (ELi Hi) Hi

i=1

n

i=1

n

× ÷∑∑ (Eq. 6)

Where: 

En = HAP emissions limit, lb/MMBtu (lb/ 

TBtu for Hg), ppm, or ng/dscm. 

ELi = Appropriate emissions limit from Table 

2 to this subpart for unit i, in units of lb/ 

MMBtu (lb/TBtu for Hg), ppm, or ng/ 

dscm. 

Hi = Heat input from unit i, MMBtu. 

n = Number of units. 

(2) Conduct performance tests 

according to procedures specified in 

§ 63.10007 in the common stack. If 

affected units from nonaffected units 

vent to the common stack,the units from 

nonaffected units must be shut down or 

vented to a different stack during the 

performance test or each affected and 

each nonaffected unit must meet the 

most stringent emissions limit; and 

(3) Meet the applicable operating limit 

specified in § 63.10021 and Table 8 to 

this subpart for each emissions control 

system (except that, if each unit venting 

to the common stack has an applicable 

opacity operating limit, then a single 

continuous opacity monitoring system 

may be located in the common stack 

instead of in each duct to the common 

stack). 

(k) Combination requirements. The 

common stack of a group of two or more 

existing EGUs in the same subcategory 

subject to paragraph (h) of this section 

may be treated as a single stack for 

purposes of paragraph (b) of this section 

and included in an emissions averaging 

group subject to paragraph (b) of this 

section. 

§ 63.10010 What are my monitoring, 

installation, operation, and maintenance 

requirements? 

(a) In some cases, existing affected 

units may exhaust through a common 

stack configuration or may include a 

bypass stack. Emission monitoring 

system installation provisions for 

possible stack configurations are as 

follows. 

(1) Single Unit-Single Stack 

Configuration. For an affected unit that 

exhausts to the atmosphere through a 

single, dedicated stack, the owner or 

operator shall install CEMS and sorbent 

trap monitoring systems in accordance 


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Federal Register / Vol. 76, No. 85 / Tuesday, May 3, 2011 / Proposed Rules 25111 

with the applicable performance 

specification or Appendix A to this 

subpart. 

(2) Unit Utilizing Common Stack with 

Other Affected Unit(s). When an 

affected unit utilizes a common stack 

with one or more other affected units, 

but no non-affected units, the owner or 

operator shall either: 

(i) Install CEMS and sorbent trap 

monitoring systems described in this 

section in the duct to the common stack 

from each unit; or 

(ii) Install CEMS and sorbent trap 

monitoring systems described in this 

section in the common stack. 

(3) Unit Utilizing Common Stack with 

Non-affected Units. When one or more 

affected units shares a common stack 

with one or more non-affected units, the 

owner or operator shall either: 

(i) Install CEMS and sorbent trap 

monitoring systems described in this 

section in the duct to the common stack 

from each affected unit; or 

(ii) Install CEMS 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). 

(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, the owner and operator shall 

install CEMS and the monitoring 

systems described in paragraph 2.1 of 

this section on both the main stack and 

the bypass stack. 

(5) Unit with Multiple Stack or Duct 

Configuration. If the flue gases from an 

affected unit either: are discharged to 

the atmosphere through more than one 

stack; or are fed into a single stack 

through two or more ducts and the 

owner or operator chooses to monitor in 

the ducts rather than in the stack, the 

owner or operator shall either: 

(i) Install CEMS and sorbent trap 

monitoring systems described in this 

section in each of the multiple stacks; or 

(ii) Install CEMS and sorbent trap 

monitoring systems described in this 

section in each of the ducts that feed 

into the stack. 

(b) If you use an oxygen (O2) or carbon 

dioxide (CO2) continuous emissions 

monitoring system (CEMS), install, 

operate, and maintain a CEMS for 

oxygen or carbon dioxide according to 

the procedures in paragraphs (b)(1) 

through (5) of this section by the 

compliance date specified in § 63.9984. 

The oxygen or carbon dioxide shall be 

monitored at the same location as the 

other pollutant CEMS, i.e., at the outlet 

of the EGU. Alternatively, an owner or 

operator may install, certify, maintain, 

operate and quality assure the data from 

an O2 or CO2 CEMS according to 

Appendix A of this subpart in lieu of 

the procedures in paragraphs (a)(1) 

through (a)(3) of this section. 

(1) Install, operate, and maintain the 

O2 or CO2 CEMS according to the 

applicable procedures under 

Performance Specification (PS) 3 of 40 

CFR part 60, Appendix B; and according 

to the applicable procedures under 

Quality Assurance Procedure 1 of 40 

CFR part 60, Appendix F; and according 

to the site-specific monitoring plan 

developed according to § 63.10000(d). 

(2) Conduct a performance evaluation 

of the CEMS according to the 

requirements in § 63.8 and according to 

PS 3 of 40 CFR part 60, Appendix B. 

(3) Design and operate the CEMS to 

complete a minimum of one cycle of 

operation (sampling, analyzing, and 

data recording) for each successive 15- 

minute period. 

(4) Reduce the CEMS data as specified 

in § 63.8(g)(2) and (4). 

(5) Consistent with § 63.10020, 

calculate and record a 30 boiler 

operating day rolling average emissions 

rate on a daily basis. Daily, calculate a 

new 30 boiler operating day rolling 

average emissions rate as the average of 

all of the hourly oxygen emissions data 

for the preceding 30 boiler operating 

days. 

(c) If you use an HCl CEMS, install, 

operate, and maintain a CEMS for HCl 

according to the procedures in 

paragraphs (c)(1) through (5) of this 

section by the compliance date specified 

in § 63.9984. The HCl shall be 

monitored at the outlet of the EGU. 

(1) Install, operate, and maintain the 

CEMS according to the applicable 

procedures under Performance 

Specification (PS) 15 or 6 of 40 CFR part 

60, Appendix B; and according to the 

applicable procedures under Quality 

Assurance Procedure 1 of 40 CFR part 

60, Appendix F; and according to the 

site-specific monitoring plan developed 

according to § 63.10000(d). 

(2) Conduct a performance evaluation 

of the CEMS according to the 

requirements in § 63.8 and according to 

PS 15 or 6 of 40 CFR part 60, Appendix 

B. 

(3) Design and operate the CEMS to 

complete a minimum of one cycle of 

operation (sampling, analyzing, and 

data recording) for each successive 15- 

minute period. 

(4) Reduce the CEMS data as specified 

in § 63.8(g)(2) and (4). 

(5) Consistent with § 63.10020, 

calculate and record a 30 boiler 

operating day rolling average emissions 

rate on a daily basis. Daily, calculate a 

new 30 boiler operating day rolling 

average emissions rate as the average of 

all of the hourly HCl emissions data for 

the preceding 30 boiler operating days. 

(d) If you use an HF CEMS, install, 

operate, and maintain a CEMS for HF 

according to the procedures in 

paragraphs (d)(1) through (5) of this 

section by the compliance date specified 

in § 63.9984. The HF shall be monitored 

at the outlet of the EGU. 

(1) Install, operate, and maintain the 

CEMS according to the applicable 

procedures under Performance 

Specification (PS) 15 of 40 CFR part 60, 

Appendix B; and according to the 

applicable procedures under Quality 

Assurance Procedure 1 of 40 CFR part 

60, Appendix F; and according to the 

site-specific monitoring plan developed 

according to § 63.10000(d). 

(2) Conduct a performance evaluation 

of the CEMS according to the 

requirements in § 63.8 and according to 

PS 15 or 6 of 40 CFR part 60, Appendix 

B. 

(3) Design and operate the CEMS to 

complete a minimum of one cycle of 

operation (sampling, analyzing, and 

data recording) for each successive 15- 

minute period. 

(4) Reduce the CEMS data as specified 

in § 63.8(g)(2) and (4). 

(5) Consistent with § 63.10020, 

calculate and record a 30 boiler 

operating day rolling average emissions 

rate on a daily basis. Daily, calculate a 

new 30 boiler operating day rolling 

average emissions rate as the average of 

all of the hourly HF emissions data for 

the preceding 30 boiler operating days. 

(e) If you use an SO2 CEMS, install, 

operate, and maintain a CEMS for SO2

according to the procedures in 

paragraphs (e)(1) through (5) of this 

section by the compliance date specified 

in § 63.9984. The SO2 shall be 

monitored at the outlet of the EGU. 

Alternatively, for an affected source that 

is also subject to the SO2 monitoring 

requirements of Part 75 of this chapter, 

the or operator may install, certify, 

maintain, operate and quality assure the 

data from an SO2 CEMS according to 

Part 75 of this chapter in lieu of the 

procedures in paragraphs (g)(1) through 

(g)(3) of this section with the additional 

provisions of paragraph (g)(6). 

(1) Install, operate, and maintain the 

CEMS according to the applicable 

procedures under Performance 

Specification (PS) 2 of 40 CFR part 60, 

Appendix B; and according to the 

applicable procedures under Quality 

Assurance Procedure 1 of 40 CFR part 

60, Appendix F; and according to the 

site-specific monitoring plan developed 

according to § 63.10000(d). 

(2) Conduct a performance evaluation 

of the CEMS according to the 


jlentini on DSKJ8SOYB1PROD with PROPOSALS2
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requirements in § 63.8 and according to 

PS 2 or 6 of 40 CFR part 60, Appendix 

B. 

(3) Design and operate the CEMS to 

complete a minimum of one cycle of 

operation (sampling, analyzing, and 

data recording) for each successive 15- 

minute period. 

(4) Reduce the CEMS data as specified 

in § 63.8(g)(2) and (4). 

(5) Consistent with § 63.10020, 

calculate and record a 30 boiler 

operating day rolling average emissions 

rate on a daily basis. Daily, calculate a 

new 30 boiler operating day rolling 

average emissions rate is calculated as 

the average of all of the hourly SO2

emissions data for the preceding 30 

boiler operating days. 

(6) When electing to use a Part 75 

certified SO2 CEMS to meet the 

requirements of this subpart, you must 

additionally meet the provisions listed 

in paragraphs (6)(i) through (6)(iii) 

below. 

(i) You must perform the 7-day 

calibration error test required in 

appendix A to Part 75 on the SO2 CEMS 

whether or not it has a span of 50 ppm 

or less. 

(ii) You must perform the linearity 

check test required in appendix A to 

Part 75 on the SO2 CEMS whether or not 

it has a span of 30 ppm or less. 

(iii) The initial and quarterly linearity 

checks required under appendix A and 

appendix B of Part 75 must include a 

calibration gas (at a fourth level, if 

necessary) nominally at a concentration 

level equivalent to the applicable 

emission limit. 

(f) If you use a Hg CEMS or a sorbent 

trap monitoring system for Hg, install, 

operate, and maintain the monitoring 

system in accordance with Appendix A 

to this subpart. 

(g) If you use a PM CEMS, install, 

operate, and maintain a CEMS for PM 

according to the procedures in 

paragraphs (g)(1) through (6) of this 

section by the compliance date specified 

in § 63.9984. The PM shall be monitored 

at the outlet of the EGU. 

(1) Install, operate, and maintain 

according to the applicable procedures 

under Performance Specification (PS) 11 

of 40 CFR part 60, Appendix B; and 

according to the applicable procedures 

under Quality Assurance Procedure 2 of 

40 CFR part 60, Appendix F; and 

according to the site-specific monitoring 

plan developed according to 

§ 63.10000(d). 

(2) Conduct a performance evaluation 

of the CEMS according to the 

requirements in § 63.8 and according to 

PS 11 of 40 CFR part 60, Appendix B. 

(3) Design and operate the CEMS to 

complete a minimum of one cycle of 

operation (sampling, analyzing, and 

data recording) for each successive 15- 

minute period. 

(4) Reduce the CEMS data as specified 

in § 63.8(g)(2) and (4). 

(5) Consistent with § 63.10020, 

calculate and record a 30 boiler 

operating-day rolling average emissions 

rate on a daily basis. Daily, calculate a 

new 30 boiler operating day rolling 

average emissions rate is calculated as 

the average of all of the hourly 

particulate emissions data for the 

preceding 30 boiler operating days. 

(h) If you are required to install a 

continuous parameter monitoring 

system (CPMS) as specified in Table 5 

of this subpart, you must install, 

operate, and maintain each CPMS 

according to the requirements in 

paragraphs (h)(1) through (3) of this 

section by the compliance date specified 

in § 63.9984. 

(1) Install, operate, and maintain each 

CPMS according to the procedures in 

your approved site-specific monitoring 

plan developed in accordance with 

§ 63.10000(d) of this subpart and the 

design criteria and quality assurance 

and quality control procedures specified 

in paragraphs (h)(1) through (3) of this 

section. You may request approval of 

monitoring system quality assurance 

and quality control procedures 

alternative to those specified in 

paragraphs (h)(1) through (3) of this 

section in your site-specific monitoring 

plan. 

(2) Design and operate the CPMS to 

collect and record data measurements at 

least once every 15 minutes (see also 

§ 63.10020), to reduce the measured 

values to a hourly averages or other 

appropriate period (e.g., instantaneous 

alarms) for calculating operating values 

in terms of the applicable averaging 

period, and to meet the specific CPMS 

requirements given in (i) through (v) of 

this section. 

(i) If you have an operating limit that 

requires the use of a flow monitoring 

system, you must meet the requirements 

in (i)(A) through (D) of this section. 

(A) Install the flow sensor and other 

necessary equipment in a position that 

provides a representative flow. 

(B) Use a flow sensor with a 

measurement sensitivity of no greater 

than 2 percent of the expected flow rate. 

(C) Minimize the effects of swirling 

flow or abnormal velocity distributions 

due to upstream and downstream 

disturbances. 

(D) Conduct a flow monitoring system 

performance evaluation in accordance 

with your monitoring plan at the time 

of each performance test but no less 

frequently than annually. 

(ii) If you have an operating limit that 

requires the use of a pressure 

monitoring system, you must meet the 

requirements in (ii)(A) through (F) of 

this section. 

(A) Install the pressure sensor(s) in a 

position that provides a representative 

measurement of the pressure (e.g., PM 

scrubber pressure drop). 

(B) Minimize or eliminate pulsating 

pressure, vibration, and internal and 

external corrosion. 

(C) Use a pressure sensor with a 

minimum tolerance of 1.27 centimeters 

of water or a minimum tolerance of 1 

percent of the pressure monitoring 

system operating range, whichever is 

less. 

(D) Perform checks at least once each 

boiler operating day to ensure pressure 

measurements are not obstructed (e.g., 

check for pressure tap pluggage daily). 

(E) Conduct a performance evaluation 

of the pressure measurement monitoring 

system in accordance with your 

monitoring plan at the time of each 

performance test but no less frequently 

than annually. 

(F) If at any time the measured 

pressure exceeds the manufacturer’s 

specified maximum operating pressure 

range, conduct a performance 

evaluation of the pressure monitoring 

system in accordance with your 

monitoring plan and confirm that the 

pressure monitoring system continues to 

meet the performance requirements in 

your monitoring plan. Alternatively, 

install and verify the operation of a new 

pressure sensor. 

(iii) If you have an operating limit that 

requires a total secondary electric power 

monitoring system for an electrostatic 

precipitator (ESP), you must meet the 

requirements in (iii)(A) through (B) of 

this section. 

(A) Install sensors to measure 

(secondary) voltage and current to the 

precipitator plates. 

(B) Conduct a performance evaluation 

of the electric power monitoring system 

in accordance with your monitoring 

plan at the time of each performance 

test but no less frequently than 

annually. 

(iv) If you have an operating limit that 

requires the use of a monitoring system 

to measure sorbent injection rate (e.g., 

weigh belt, weigh hopper, or hopper 

flow measurement device), you must 

meet the requirements in (iv)(A) through 

(B) of this section. 

(A) Install each system in a position 

that provides a representative 

measurement of the total sorbent 

injection rate. 

(B) Conduct a performance evaluation 

of the sorbent injection rate monitoring 

system in accordance with your 


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monitoring plan at the time of each 

performance test but no less frequently 

than annually. 

(v) If you have an operating limit that 

requires the use of a fabric filter bag leak 

detection system to comply with the 

requirements of this subpart, you must 

install, calibrate, maintain, and 

continuously operate a bag leak 

detection system as specified in (v)(A) 

through (F) of this section. 

(A) Install a bag leak detection 

sensor(s) in a position(s) that will be 

representative of the relative or absolute 

PM loadings for each exhaust stack, roof 

vent, or compartment (e.g., for a positive 

pressure fabric filter) of the fabric filter. 

(B) Use a bag leak detection system 

certified by the manufacturer to be 

capable of detecting PM emissions at 

concentrations of 10 milligrams per 

actual cubic meter or less. 

(C) Conduct a performance evaluation 

of the bag leak detection system in 

accordance with your monitoring plan 

and consistent with the guidance 

provided in EPA–454/R–98–015 

(incorporated by reference, see § 63.14). 

(D) Use a bag leak detection system 

equipped with a device to continuously 

record the output signal from the sensor. 

(E) Use a bag leak detection system 

equipped with a system that will alert 

when an increase in relative PM 

emissions over a preset level is detected. 

The alarm must be located where it can 

be detected and recognized easily by an 

operator. 

(F) Where multiple bag leak detectors 

are required, the system’s 

instrumentation and alarm may be 

shared among detectors. 

(3) Conduct the CPMS equipment 

performance evaluations as specified in 

your site-specific monitoring plan. 

§ 63.10011 How do I demonstrate initial 

compliance with the emission limits and 

work practice standards? 

(a) You must demonstrate initial 

compliance with each emission limit 

that applies to you by conducting initial 

performance tests and fuel analyses and 

establishing operating limits, as 

applicable, according to § 63.10007, 

paragraph (c) of this section, and Tables 

5 and 7 to this subpart. 

(b) If you demonstrate compliance 

through performance testing, you must 

establish each site-specific operating 

limit in Table 4 to this subpart that 

applies to you according to the 

requirements in § 63.10007, Table 7 to 

this subpart, and paragraph (c)(6) of this 

section, as applicable. You must also 

conduct fuel analyses according to 

§ 63.10008 and establish maximum fuel 

pollutant input levels according to 

paragraphs (c)(1) through (5) of this 

section, as applicable. 

(1) You must establish the maximum 

chlorine fuel input (Cinput) during the 

initial performance testing according to 

the procedures in paragraphs (c)(1)(i) 

through (iii) of this section. 

(i) You must determine the fuel type 

or fuel mixture that you could burn in 

your EGU that has the highest content 

of chlorine. 

(ii) During the performance testing for 

HCl, you must determine the fraction of 

the total heat input for each fuel type 

burned (Qi) based on the fuel mixture 

that has the highest content of chlorine, 

and the average chlorine concentration 

of each fuel type burned (Ci). 

(iii) You must establish a maximum 

chlorine input level using Equation 7 of 

this section. 

Clinput = (Ci Qi)

i=1

n

∑ × (Eq. 7)

Where: 

Clinput = Maximum amount of chlorine 

entering the EGU through fuels burned 

in units of lb/MMBtu. 

Ci = Arithmetic average concentration of 

chlorine in fuel type, i, analyzed 

according to § 63.10008, in units of lb/ 

MMBtu. 

Qi = Fraction of total heat input from fuel 

type, i, based on the fuel mixture that 

has the highest content of chlorine. If 

you do not burn multiple fuel types 

during the performance testing, it is not 

necessary to determine the value of this 

term. Insert a value of ‘‘1’’ for Qi. 

n = Number of different fuel types burned in 

your EGU for the mixture that has the 

highest content of chlorine. 

(2) You must establish the maximum 

Hg fuel input level (Mercuryinput) during 

the initial performance testing using the 

procedures in paragraphs (c)(3)(i) 

through (iii) of this section. 

(i) You must determine the fuel type 

or fuel mixture that you could burn in 

your EGU that has the highest content 

of Hg. 

(ii) During the compliance 

demonstration for Hg, you must 

determine the fraction of total heat 

input for each fuel burned (Qi) based on 

the fuel mixture that has the highest 

content of Hg, and the average Hg 

concentration of each fuel type burned 

(HGi). 

(iii) You must establish a maximum 

Hg input level using Equation 8 of this 

section. 

Mercuryinput = (HGi Qi)

i=1

n

∑ × (Eq. 8)

Where: 

Mercuryinput = Maximum amount of Hg 

entering the EGU through fuels burned 

in units of lb/TBtu. 

HGi = Arithmetic average concentration of 

Hg in fuel type, i, analyzed according to 

§ 63.10008, in units of lb/TBtu. 

Qi = Fraction of total heat input from fuel 

type, i, based on the fuel mixture that 

has the highest Hg content. If you do not 

burn multiple fuel types during the 

performance test, it is not necessary to 

determine the value of this term. Insert 

a value of ‘‘1’’ for Qi. 

n = Number of different fuel types burned in 

your EGU for the mixture that has the 

highest content of Hg. 

(3) You must establish the maximum 

non-Hg HAP metals fuel input level 

(HAP metalinput) during the initial 

performance testing using the 

procedures in paragraphs (c)(3)(i) 

through (iii) of this section. 

(i) You must determine the fuel type 

or fuel mixture that you could burn in 

your EGU that has the highest content 

of non-Hg HAP metals. 

(ii) During the compliance 

demonstration for non-Hg HAP metals, 

you must determine the fraction of total 

heat input for each fuel burned (Qi) 

based on the fuel mixture that has the 

highest content of non-Hg HAP metals, 

and the average non-Hg HAP metals 

concentration of each fuel type burned 

(HAP metali). 

(iii) You must establish a maximum 

non-Hg HAP metal input level using 

Equation 9 of this section. 

HAP metalinput = × ∑(HAP metali Qi) (Eq. 9)

i=1

n

Where: 

HAP metalinput = Maximum amount of nonHg HAP metals entering the EGU 

through fuels burned in units of lb/ 

MMBtu. 

HAP metali = Arithmetic average 

concentration of non-Hg HAP metals in 

fuel type, i, analyzed according to 

§ 63.10008, in units of lb/MMBtu. 

Qi = Fraction of total heat input from fuel 

type, i, based on the fuel mixture that 


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25114 Federal Register / Vol. 76, No. 85 / Tuesday, May 3, 2011 / Proposed Rules 

has the highest non-Hg HAP metal 

content. If you do not burn multiple fuel 

types during the performance test, it is 

not necessary to determine the value of 

this term. Insert a value of ‘‘1’’ for Qi. 

n = Number of different fuel types burned in 

your EGU for the mixture that has the 

highest content of non-Hg HAP metals. 

(4) You must establish the maximum 

fluorine fuel input (Finput) during the 

initial performance testing according to 

the procedures in paragraphs (c)(1)(i) 

through (iii) of this section. 

(i) You must determine the fuel type 

or fuel mixture that you could burn in 

your EGU that has the highest content 

of fluorine. 

(ii) During the performance testing for 

HF, you must determine the fraction of 

the total heat input for each fuel type 

burned (Qi) based on the fuel mixture 

that has the highest content of fluorine, 

and the average fluorine concentration 

of each fuel type burned (Fi). 

(iii) You must establish a maximum 

fluorine input level using Equation 10 of 

this section. 

Flinput Fi Qi) (Eq. 10) i=1

n = × ∑ (

Where: 

Fl input = Maximum amount of fluorine 

entering the EGU through fuels burned 

in units of lb/MMBtu. 

Fi = Arithmetic average concentration of 

fluorine in fuel type, i, analyzed 

according to § 63.10008, in units of lb/ 

MMBtu. 

Qi = Fraction of total heat input from fuel 

type, i, based on the fuel mixture that 

has the highest content of chlorine. If 

you do not burn multiple fuel types 

during the performance testing, it is not 

necessary to determine the value of this 

term. Insert a value of ‘‘1’’ for Qi. 

n = Number of different fuel types burned in 

your EGU for the mixture that has the 

highest content of fluorine. 

(6) You must establish parameter 

operating limits according to paragraphs 

(c)(4)(i) through (v) of this section. 

(i) For a wet PM scrubber, you must 

establish the minimum liquid flow rate 

and pressure drop as defined in 

§ 63.10042, as your operating limits 

during the three-run performance test. If 

you use a wet PM scrubber and you 

conduct separate performance tests for 

PM, non-Hg HAP metals, or Hg 

emissions, you must establish one set of 

minimum liquid flow rate and pressure 

drop operating limits. If you conduct 

multiple performance tests, you must 

set the minimum liquid flow rate and 

pressure drop operating limits at the 

highest minimum hourly average values 

established during the performance 

tests. 

(ii) For a wet acid gas scrubber, you 

must establish the minimum liquid flow 

rate and pH as defined in § 63.10042, as 

your operating limits during the threerun performance test. If you use a wet 

acid gas scrubber and you conduct 

separate performance tests for HCl, HF, 

or SO2 emissions, you must establish 

one set of minimum liquid flow rate and 

pH operating limits. If you conduct 

multiple performance tests, you must 

set the minimum liquid flow rate and 

pH operating limits at the highest 

minimum hourly average values 

established during the performance 

tests. 

(iii) For an electrostatic precipitator, 

you must establish the minimum hourly 

average secondary voltage and 

secondary amperage and calculate the 

total secondary power input as 

measured during the three-run 

performance test and as defined in 

§ 63.10042, as your operating limit. 

(iv) For a dry scrubber or dry sorbent 

injection (DSI) system, you must 

establish the minimum hourly average 

sorbent injection rate for each sorbent, 

as measured during the three-run 

performance test and as defined in 

§ 63.10042, as your operating. 

(v) The operating limit for EGUs with 

fabric filters that choose to demonstrate 

continuous compliance through bag leak 

detection systems is that a bag leak 

detection system be installed according 

to the requirements in § 63.10010, and 

that the sum duration of bag leak 

detection system alarms does not exceed 

5 percent of the process operating time 

during a 6-month period. 

(c) If you elect to demonstrate 

compliance with an applicable emission 

limit through fuel analysis, you must 

conduct fuel analyses according to 

§ 63.10008 and follow the procedures in 

paragraphs (c)(1) through (7) of this 

section. 

(1) If you burn more than one fuel 

type, you must determine the fuel 

mixture you could burn in your EGU 

that would result in the maximum 

emission rates of the pollutants that you 

elect to demonstrate compliance 

through fuel analysis. 

(2) You must determine the 90th 

percentile confidence level fuel 

pollutant concentration of the 

composite samples analyzed for each 

fuel type using the one-sided z-statistic 

test described in Equation 11 of this 

section. 

P90 mean SD t) (Eq. 11) = +× (

Where: 

P90 = 90th percentile confidence level 

pollutant concentration, in lb/MMBtu 

(lb/TBtu for Hg). 

mean = Arithmetic average of the fuel 

pollutant concentration in the fuel 

samples analyzed according to 

§ 63.10008, in units of lb/MMBtu (lb/ 

TBtu for Hg). 

SD = Standard deviation of the pollutant 

concentration in the fuel samples 

analyzed according to § 63.10008, in 

units of lb/MMBtu (lb/TBtu for Hg). 

t = t distribution critical value for 90th 

percentile (0.1) probability for the 

appropriate degrees of freedom (number 

of samples minus one) as obtained from 

a Distribution Critical Value Table. 

(3) To demonstrate compliance with 

the applicable emission limit for HCl, 

the HCl emission rate that you calculate 

for your EGU using Equation 12 of this 

section must not exceed the applicable 

emission limit for HCl. 

HCl= (Ci90 Qi 1.028) (Eq. 12)

i=1

n

∑ × ×

Where: 

HCl = HCl emissions rate from the EGU in 

units of lb/MMBtu. 

Ci90 = 90th percentile confidence level 

concentration of chlorine in fuel type, i, 

in units of lb/MMBtu as calculated 

according to Equation 12 of this section. 

Qi = Fraction of total heat input from fuel 

type, i, based on the fuel mixture that 

has the highest content of chlorine. If 

you do not burn multiple fuel types, it 

is not necessary to determine the value 

of this term. Insert a value of ‘‘1’’ for Qi. 

n = Number of different fuel types burned in 

your EGU for the mixture that has the 

highest content of chlorine. 

1.028 = Molecular weight ratio of HCl to 

chlorine. 

(4) To demonstrate compliance with 

the applicable emission limit for Hg, the 

Hg emissions rate that you calculate for 

your EGU using Equation 13 of this 

section must not exceed the applicable 

emission limit for Hg. 

Mercury (HGi90 Qi (Eq. 13)

i=1

n

= × ∑ )

Where: 

Mercury = Hg emissions rate from the EGU 

in units of lb/TBtu. 

HGi90 = 90th percentile confidence level 

concentration of Hg in fuel, i, in units of 

lb/TBtu as calculated according to 

Equation 8 of this section. 

Qi = Fraction of total heat input from fuel 

type, i, based on the fuel mixture that 

has the highest Hg content. If you do not 

burn multiple fuel types, it is not 

necessary to determine the value of this 

term. Insert a value of ‘‘1’’ for Qi. 

n = Number of different fuel types burned in 

your EGU for the mixture that has the 

highest Hg content. 

(5) To demonstrate compliance with 

the applicable emission limit for non-Hg 

HAP metals, the non-Hg HAP metal 

emissions rate that you calculate for 

your EGU using Equation 14 of this 


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Federal Register / Vol. 76, No. 85 / Tuesday, May 3, 2011 / Proposed Rules 25115 

section must not exceed the applicable 

emissions limit for non-Hg HAP metals. 

HAPmetals (HAPmetalsi90 Qi (Eq. 14)

i=1

n

= × ∑ )

Where: 

HAPmetals = Non-Hg HAP metals emission 

rate from the EGU in units of lb/MMBtu. 

HAPmetalsi90 = 90th percentile confidence 

level concentration of non-Hg HAP 

metals in fuel, i, in units of lb/MMBtu 

as calculated according to Equation 9 of 

this section. 

Qi = Fraction of total heat input from fuel 

type, i, based on the fuel mixture that 

has the highest non-Hg HAP metals 

content. If you do not burn multiple fuel 

types, it is not necessary to determine 

the value of this term. Insert a value of 

‘‘1’’ for Qi. 

n = Number of different fuel types burned in 

your EGU for the mixture that has the 

highest non-Hg HAP metals content. 

(6) To demonstrate compliance with 

the applicable emission limit for HF, the 

HF emissions rate that you calculate for 

your EGU using Equation 15 of this 

section must not exceed the applicable 

emission limit for HF. 

HF (Fi90 Qi (Eq. 15)

i=1

n

= ×× ∑ 1 053 . )

Where: 

HF = HF emissions rate from the EGU in 

units of lb/MMBtu. 

Fi90 = 90th percentile confidence level 

concentration of fluorine in fuel type, i, 

in units of lb/MMBtu as calculated 

according to Equation 7 of this section. 

Qi = Fraction of total heat input from fuel 

type, i, based on the fuel mixture that 

has the highest content of fluorine. If you 

do not burn multiple fuel types, it is not 

necessary to determine the value of this 

term. Insert a value of ‘‘1’’ for Qi. 

n = Number of different fuel types burned in 

your EGU for the mixture that has the 

highest content of fluorine. 

1.053 = Molecular weight ratio of HF to 

fluorine. 

(d) For units combusting coal or solid 

oil-derived fuel and electing to use PM 

as a surrogate for non-Hg HAP metals, 

you must install, certify, and operate 

PM CEMS in accordance with 

Performance Specification (PS) 11 in 

Appendix B to 40 CFR part 60, and to 

perform periodic, ongoing quality 

assurance (QA) testing of the CEMS 

according to QA Procedure 2 in 

Appendix F to 40 CFR Part 60. You 

must determine an operating limit (PM 

concentration in mg/dscm) during 

performance testing for initial PM 

compliance. The operating limit will be 

the average of the PM filterable results 

of the three Method 5 performance test 

runs. To determine continuous 

compliance, the hourly average PM 

concentrations will be averaged on a 

rolling 30 boiler operating day basis. 

Each 30 boiler operating day average 

would have to meet the PM operating 

limit. 

(e) You must submit the Notification 

of Compliance Status containing the 

results of the initial compliance 

demonstration according to the 

requirements in § 63.10030(e). 

(f) If you are a LEE, the results of your 

initial performance test demonstrate 

your initial compliance. 

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. A 

monitoring system malfunction is any 

sudden, infrequent, not reasonably 

preventable failure of the monitoring 

system to provide valid data. 

Monitoring system failures that are 

caused in part by poor maintenance or 

careless operation are not malfunctions. 

You are required to affect monitoring 

system repairs in response to 

monitoring system malfunctions and to 

return the monitoring system to 

operation as expeditiously as 

practicable. 

(c) You may not use data recorded 

during monitoring system malfunctions 

or out-of-control periods, repairs 

associated with monitoring system 

malfunctions or 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 out-of-control 

periods, repairs associated with 

monitoring system malfunctions or 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 and work practice standards? 

(a) You must demonstrate continuous 

compliance with each emission limit, 

operating limit, and work practice 

standard in Tables 1 through 4 to this 

subpart that applies to you according to 

the methods specified in Table 8 to this 

subpart and paragraphs (a)(1) through 

(17) of this section. 

(1) Following the date on which the 

initial performance test is completed or 

is required to be completed under 

§§ 63.7 and 63.10005, whichever date 

comes first, you must not operate above 

any of the applicable maximum 

operating limits or below any of the 

applicable minimum operating limits 

listed in Table 4 to this subpart at any 

time. Operation above the established 

maximum or below the established 

minimum operating limits shall 

constitute a deviation of established 

operating limits. Operating limits must 

be confirmed or reestablished during 

performance tests. 

(2) As specified in § 63.10031(c), you 

must keep records of the type and 

amount of all fuels burned in each EGU 

during the reporting period to 

demonstrate that all fuel types and 

mixtures of fuels burned would either 

result in lower emissions of HCl, HF, 

SO2, non-Hg HAP metals, or Hg, than 

the applicable emission limit for each 

pollutant (if you demonstrate 

compliance through fuel analysis), or 

result in lower fuel input of chlorine, 

fluorine, sulfur, non-Hg HAP metals, or 

Hg than the maximum values calculated 

during the last performance tests (if you 

demonstrate compliance through 

performance stack testing). 


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25116 Federal Register / Vol. 76, No. 85 / Tuesday, May 3, 2011 / Proposed Rules 

(3) If you demonstrate compliance 

with an applicable HCl emissions limit 

through fuel analysis and you plan to 

burn a new type of fuel, you must 

recalculate the HCl emissions rate using 

Equation 15 of § 63.10011 according to 

paragraphs (a)(3)(i) through (iii) of this 

section. 

(i) You must determine the chlorine 

concentration for any new fuel type in 

units of lb/MMBtu, based on supplier 

data or your own fuel analysis, 

according to the provisions in your sitespecific fuel analysis plan developed 

according to § 63.10008(b). 

(ii) You must determine the new 

mixture of fuels that will have the 

highest content of chlorine. 

(iii) Recalculate the HCl emissions 

rate from your EGU under these new 

conditions using Equation 15 of 

§ 63.10011. The recalculated HCl 

emissions rate must be less than the 

applicable emission limit. 

(4) If you demonstrate compliance 

with an applicable HCl emissions limit 

through performance testing and you 

plan to burn a new type of fuel or a new 

mixture of fuels, you must recalculate 

the maximum chlorine input using 

Equation 7 of § 63.10011. If the results 

of recalculating the maximum chlorine 

input using Equation 7 of § 63.10011 are 

higher than the maximum chlorine 

input level established during the 

previous performance test, then you 

must conduct a new performance test 

within 60 days of burning the new fuel 

type or fuel mixture according to the 

procedures in § 63.10007 to demonstrate 

that the HCl emissions do not exceed 

the emissions limit. You must also 

establish new operating limits based on 

this performance test according to the 

procedures in § 63.10011(b). 

(5) If you are a liquid oil-fired EGU 

and demonstrate compliance with an 

applicable individual Hg emissions 

limit (rather than the total HAP metal 

emission limit) through fuel analysis, 

and you plan to burn a new type of fuel, 

you must recalculate the Hg emissions 

rate using Equation 11 of § 63.10011 

according to the procedures specified in 

paragraphs (a)(5)(i) through (iii) of this 

section. 

(i) You must determine the Hg 

concentration for any new fuel type in 

units of lb/TBtu, based on supplier data 

or your own fuel analysis, according to 

the provisions in your site-specific fuel 

analysis plan developed according to 

§ 63.10008(b). 

(ii) You must determine the new 

mixture of fuels that will have the 

highest content of Hg. 

(iii) Recalculate the Hg emissions rate 

from your EGU under these new 

conditions using Equation 11 of 

§ 63.10011. The recalculated Hg 

emission rate must be less than the 

applicable emission limit. 

(6) If you demonstrate compliance 

with an applicable Hg emissions limit 

through performance testing, and you 

plan to burn a new type of fuel or a new 

mixture of fuels, you must recalculate 

the maximum Hg input using Equation 

8 of § 63.10011. If the results of 

recalculating the maximum Hg input 

using Equation 8 of § 63.10011 are 

higher than the maximum Hg input 

level established during the previous 

performance test, then you must 

conduct a new performance test within 

60 days of burning the new fuel type or 

fuel mixture according to the 

procedures in § 63.10007 to demonstrate 

that the Hg emissions do not exceed the 

emissions limit. You must also establish 

new operating limits based on this 

performance test according to the 

procedures in § 63.10011(b). 

(7) If you are a liquid oil-fired EGU 

and demonstrate compliance with an 

applicable HAP metals emission limit 

through fuel analysis, and you plan to 

burn a new type of fuel, you must 

recalculate the HAP metals emission 

rate using Equation 14 of § 63.10011 

according to the procedures specified in 

paragraphs (a)(7)(i) through (iii) of this 

section. 

(i) You must determine the HAP 

metals concentration for any new fuel 

type in units of lb/MMBtu, based on 

supplier data or your own fuel analysis, 

according to the provisions in your sitespecific fuel analysis plan developed 

according to § 63.10008(b). 

(ii) You must determine the new 

mixture of fuels that will have the 

highest content of HAP metals. 

(iii) Recalculate the HAP metals 

emission rate from your EGU under 

these new conditions using Equation 14 

of § 63.10011. The recalculated HAP 

metals emission rate must be less than 

the applicable emissions limit. 

(8) If you demonstrate compliance 

with an applicable HAP metals 

emissions limit through performance 

testing, and you plan to burn a new type 

of fuel or a new mixture of fuels, you 

must recalculate the maximum HAP 

metals input using Equation 9 of 

§ 63.10011. If the results of recalculating 

the maximum Hg input using Equation 

9 of § 63.10011 are higher than the 

maximum HAP metals input level 

established during the previous 

performance test, then you must 

conduct a new performance test within 

60 days of burning the new fuel type or 

fuel mixture according to the 

procedures in § 63.10007 to demonstrate 

that the HAP metal emissions do not 

exceed the emissions limit. You must 

also establish new operating limits 

based on this performance test 

according to the procedures in 

§ 63.10011(b). 

(9) If your unit is controlled with a 

fabric filter, and you demonstrate 

continuous compliance using a bag leak 

detection system, you must initiate 

corrective action within 1 hour of a bag 

leak detection system alarm and 

complete corrective actions as soon as 

practical, and operate and maintain the 

fabric filter system such that the sum 

duration of alarms does not exceed 5 

percent of the process operating time 

during a 6-month period. You must also 

keep records of the date, time, and 

duration of each alarm, the time 

corrective action was initiated and 

completed, and a brief description of the 

cause of the alarm and the corrective 

action taken. You must also record the 

percent of the operating time during 

each 6-month period that the alarm 

sounds. In calculating this operating 

time percentage, if inspection of the 

fabric filter demonstrates that no 

corrective action is required, no alarm 

time is counted. If corrective action is 

required, each alarm shall be counted as 

a minimum of 1 hour. If you take longer 

than 1 hour to initiate corrective action, 

the alarm time shall be counted as the 

actual amount of time taken to initiate 

corrective action. 

(10) If you are required to install a 

CEMS according to § 63.10010(a), then 

you must meet the requirements in 

paragraphs (a)(10)(i) through (iii) of this 

section. 

(i) You must continuously monitor 

oxygen according to §§ 63.10010(a) and 

63.10020. 

(ii) Keep records of oxygen levels 

according to § 63.10032(b). 

(11) The owner or operator of an 

affected source using a CEMS measuring 

PM emissions to meet requirements of 

this subpart shall install, certify, 

operate, and maintain the CEMS as 

specified in paragraphs (a)(11)(i) 

through (iv) of this section. 

(i) The owner or operator shall 

conduct a performance evaluation of the 

CEMS according to the applicable 

requirements of § 60.13 of 40 CFR, 

Performance Specification 11 in 

Appendix B of 40 CFR part 60, and 

procedure 2 in Appendix F of 40 CFR 

part 60. 

(ii) During each PM correlation testing 

run of the CEMS required by 

Performance Specification 11 in 

Appendix B of 40 CFR part 60, PM and 

O2 (or CO2) data shall be collected 

concurrently (or within a 30- to 60- 

minute period) by both the CEMS and 

conducting performance tests using 


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Method 5 or 5D of Appendix A–3 of 40 

CFR part 60. 

(iii) Quarterly accuracy 

determinations and daily calibration 

drift tests shall be performed in 

accordance with procedure 2 in 

Appendix F of this chapter. Relative 

Response Audits must be performed 

annually and Response Correlation 

Audits must be performed every 3 years. 

(iv) As of January 1, 2012 and within 

60 days after the date of completing 

each performance test, as defined in 

§ 63.2 and as required in this subpart, 

you must submit performance 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/). Only data collected 

using test methods compatible with ERT 

are subject to this requirement to be 

submitted electronically into EPA’s 

WebFIRE database. 

(v) Within 60 days after the date of 

completing each CEMS performance 

evaluation test, as defined in § 63.2 and 

required by this subpart, you must 

submit the relative accuracy test audit 

data electronically into EPA’s Central 

Data Exchange by using the Electronic 

Reporting Tool as mentioned in 

paragraph (11)(iv) of this section. Only 

data collected using test methods 

compatible with ERT are subject to this 

requirement to be submitted 

electronically into EPA’s WebFIRE 

database. 

(vi) All reports required by this 

subpart not subject to the requirements 

in paragraphs (11)(iv) and (v) of this 

section must be sent to the 

Administrator at the appropriate 

address listed in § 63.13. If acceptable to 

both the Administrator and the owner or 

operator of a source, these reports may 

be submitted on electronic media. The 

Administrator retains the right to 

require submittal of reports subject to 

paragraph (11)(iv) and (v) of this section 

in paper format. 

(12) The owner or operator of an 

affected source using a CEMS measuring 

HCl emissions to meet requirements of 

this subpart shall install, certify, 

operate, and maintain the CEMS as 

specified in paragraphs (a)(12)(i) 

through (iii) of this section. 

(i) The owner or operator shall 

conduct a performance evaluation of the 

CEMS according to the applicable 

requirements of § 60.13 of 40 CFR, 

Performance Specifications 6 or 15 in 

Appendix B of 40 CFR part 60, and 

procedure 2 in Appendix F of 40 CFR 

part 60. 

(ii) Quarterly accuracy determinations 

and daily calibration drift tests shall be 

performed in accordance with 

procedure 1 in Appendix F of 40 CFR 

part 60. 

(13) The owner or operator of an 

affected source using a CEMS measuring 

SO2 emissions to meet requirements of 

this subpart shall install, certify, 

operate, and maintain the CEMS as 

specified in paragraphs (a)(13)(i) 

through (iii) of this section. 

(i) The owner or operator shall 

conduct a performance evaluation of the 

CEMS according to the applicable 

requirements of § 60.13 of 40 CFR part 

60, Performance Specification 2 or 6 in 

Appendix B of 40 CFR part 60, and 

procedure 1 in Appendix F of 40 CFR 

part 60. 

(ii) Quarterly accuracy determinations 

and daily calibration drift tests shall be 

performed in accordance with 

procedure 1 in Appendix F of 40 CFR 

part 60. 

(14) The owner or operator of an 

affected source using a CEMS measuring 

Hg emissions to meet requirements of 

this subpart shall install, certify, 

operate, and maintain the CEMS as 

specified in paragraphs (a)(14)(i) 

through (iii) of this section. 

(i) The owner or operator shall 

conduct a performance evaluation of the 

CEMS according to the applicable 

requirements of Appendix A of this 

subpart. 

(ii) Quarterly accuracy determinations 

and daily calibration drift tests shall be 

performed in accordance with 

procedure 5 in Appendix F of 40 CFR 

part 60. 

(15) As an alternative to measuring Hg 

emissions using Hg CEMS, the owner or 

operator of an affected source using a 

sorbent trap monitoring system to meet 

requirements of this subpart shall 

install, certify, operate, and maintain 

the sorbent trap monitoring system in 

accordance with Appendix A to this 

subpart. 

(16) You must conduct a performance 

tune-up of the EGU to demonstrate 

continuous compliance as specified in 

paragraphs (a)(16)(i) through (a)(16)(vii) 

of this section. 

(i) As applicable, inspect the burner, 

and clean or replace any components of 

the burner as necessary (you may delay 

the burner inspection until the next 

scheduled unit shutdown, but you must 

inspect each burner at least once every 

18 months); 

(ii) Inspect the flame pattern, as 

applicable, and make any adjustments 

to the burner necessary to optimize the 

flame pattern. The adjustment should be 

consistent with the manufacturer’s 

specifications, if available; 

(iii) Inspect the system controlling the 

air-to-fuel ratio, as applicable, and 

ensure that it is correctly calibrated and 

functioning properly; 

(iv) Optimize total emissions of CO 

and NOX. This optimization should be 

consistent with the manufacturer’s 

specifications, if available; 

(v) Measure the concentration in the 

effluent stream of CO and NOX in ppm, 

by volume, and oxygen in volume 

percent, before and after the 

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); and 

(vi) Maintain on-site and submit, if 

requested by the Administrator, an 

annual report containing the 

information in paragraphs (a)(16)(vi)(A) 

through (C) of this section, 

(A) The concentrations of CO and 

NOX in the effluent stream in ppm by 

volume, and oxygen in volume percent, 

measured before and after the 

adjustments of the EGU; 

(B) A description of any corrective 

actions taken as a part of the 

combustion adjustment; and 

(C) The type and amount of fuel used 

over the 12 months prior to an 

adjustment, but only if the unit was 

physically and legally capable of using 

more than one type of fuel during that 

period. 

(vii) After December 31, 2011, and 

within 60 days after the date of 

completing each performance tune-up 

conducted to demonstrate compliance 

with this subpart, you must submit a 

notice of completion of the performance 

tune-up to EPA by successfully 

submitting the data electronically into 

an EPA database. 

(17) For LEEs, the results of your 

initial and subsequent emissions tests, 

along with records of your fuel analyses, 

demonstrate your continuous 

compliance and continued eligibility as 

a LEE. 

(i) As of January 1, 2012 and within 

60 days after the date of completing 

each performance test, as defined in 

§ 63.2 and as required in this subpart, 

you must submit performance 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/). Only data collected 

using test methods compatible with ERT 

are subject to this requirement to be 

submitted electronically into EPA’s 

WebFIRE database. 

(ii) Within 60 days after the date of 

completing each CEMS performance 

evaluation test, as defined in 63.2 and 

required by this subpart, you must 

submit the relative accuracy test audit 

data electronically into EPA’s Central 

Data Exchange by using the Electronic 


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Reporting Tool as mentioned in 

paragraph (17)(i) of this section. Only 

data collected using test methods 

compatible with ERT are subject to this 

requirement to be submitted 

electronically into EPA’s WebFIRE 

database. 

(iii) All reports required by this 

subpart not subject to the requirements 

in paragraphs (17)(i) and (ii) of this 

section must be sent to the 

Administrator at the appropriate 

address listed in § 63.13. If acceptable to 

both the Administrator and the owner or 

operator of a source, these reports may 

be submitted on electronic media. The 

Administrator retains the right to 

require submittal of reports subject to 

paragraph (17)(i) and (ii) of this section 

in paper format. 

(b) You must report each instance in 

which you did not meet each emission 

limit and operating limit in Tables 1 

through 4 to this subpart that apply to 

you. These instances are deviations 

from the emission limits in this subpart. 

These deviations must be reported 

according to the requirements in 

§ 63.10031. 

(c) Consistent with § 63.10010, 

§ 63.10020, and your site-specific 

monitoring plan, you must determine 

the 3-hour rolling average of the CPMS 

data collected for all periods the process 

is operating. 

§ 63.10022 How do I demonstrate 

continuous compliance under the emission 

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 (8) of this section. 

(1) For each calendar month, 

demonstrate compliance with the 

average weighted emissions limit for the 

existing units participating in the 

emissions averaging option as 

determined in § 63.10009(f) and (g); 

(2) For each existing unit participating 

in the emissions averaging option that is 

equipped with a wet scrubber for PM 

control, maintain the 3-hour average 

parameter values at or below the 

operating limits established during the 

most recent performance test; 

(3) For each existing unit participating 

in the emissions averaging option that is 

equipped with a fabric filter but without 

PM CEMS, maintain the 3-hour average 

parameter values at or below the 

operating limits established during the 

most recent performance test; 

(4) For each existing unit participating 

in the emissions averaging option that is 

equipped with dry sorbent injection, 

maintain the 3-hour average parameter 

values at or below the operating limits 

established during the most recent 

performance test; 

(5) For each existing unit participating 

in the emissions averaging option that is 

equipped with an ESP, maintain the 3- 

hour average parameter values at or 

below the operating limits established 

during the most recent performance test; 

(6) For each existing unit participating 

in the emissions averaging option that is 

equipped with an ESP, maintain the 

monthly fuel content values at or below 

the operating limits established during 

the most recent performance test; 

(7) For each existing unit participating 

in the emissions averaging option that 

has an approved alternative operating 

plan, maintain the 3-hour average 

parameter values at or below the 

operating limits established in the most 

recent performance test. 

(8) 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 (8) of this 

section is a deviation. 

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 

[DATE 60 DAYS AFTER PUBLICATION 

OF THE FINAL RULE IN THE 

FEDERAL REGISTER], you must submit 

an Initial Notification not later than 120 

days after [DATE 60 DAYS AFTER 

PUBLICATION OF THE FINAL RULE 

IN THE FEDERAL REGISTER]. 

(c) As specified in § 63.9(b)(4) and 

(b)(5), if you startup your new or 

reconstructed affected source on or after 

[DATE 60 DAYS AFTER PUBLICATION 

OF THE FINAL RULE IN THE 

FEDERAL REGISTER], you must submit 

an Initial Notification not later than 15 

days after the actual date of startup of 

the affected source. 

(d) If you are required to conduct a 

performance test you must submit a 

Notification of Intent to conduct a 

performance test at least 30 days before 

the performance test is scheduled to 

begin. 

(e) If you are required to conduct an 

initial compliance demonstration as 

specified in § 63.10011(a), you must 

submit a Notification of Compliance 

Status according to § 63.9(h)(2)(ii). For 

each initial compliance demonstration, 

you must submit the Notification of 

Compliance Status, including all 

performance test results and fuel 

analyses, before the close of business on 

the 60th day following the completion 

of the performance test and/or other 

initial compliance demonstrations 

according to § 63.10(d)(2). The 

Notification of Compliance Status report 

must contain all the information 

specified in paragraphs (e)(1) through 

(6), as applicable. 

(1) A description of the affected 

source(s) including identification of 

which subcategory the source is in, the 

design 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 and fuel analysis; 

performance testing with operational 

limits (e.g., CEMS for surrogates or 

CPMS); CEMS; or sorbent trap 

monitoring system. 

(4) Identification of whether you plan 

to demonstrate compliance by emissions 

averaging. 

(5) A signed certification that you 

have met all applicable emission limits 

and work practice standards. 

(6) If you had a deviation from any 

emission limit, work practice standard, 

or operating limit, you must also submit 

a description of the deviation, the 

duration of the deviation, and the 

corrective action taken in the 

Notification of Compliance Status 

report. 

(7) In addition to the information 

required in § 63.9(h)(2), your 

notification of compliance status must 

include the following certification of 

compliance and must be signed by a 

responsible official: 

(i) ‘‘This EGU complies with the 

requirement in § 63.10021(a)(16)(i) 

through (vi).’’ 


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§ 63.10031 What reports must I submit and 

when? 

(a) You must submit each report in 

Table 9 to this subpart that applies to 

you. 

(b) Unless the EPA Administrator has 

approved a different schedule for 

submission of reports under § 63.10(a), 

you must submit each report by the date 

in Table 9 to this subpart and according 

to the requirements in paragraphs (b)(1) 

through (5) of this section. 

(1) The first compliance report must 

cover the period beginning on the 

compliance date that is specified for 

your affected source in § 63.9984 and 

ending on June 30 or December 31, 

whichever date is the first date that 

occurs at least 180 days after the 

compliance date that is specified for 

your source in § 63.9984. 

(2) The first compliance report must 

be postmarked or delivered no later than 

July 31 or January 31, whichever date is 

the first date following the end of the 

first calendar half after the compliance 

date that is specified for your source in 

§ 63.9984. 

(3) Each subsequent compliance 

report must cover the semiannual 

reporting period from January 1 through 

June 30 or the semiannual reporting 

period from July 1 through December 

31. 

(4) Each subsequent compliance 

report must be postmarked or delivered 

no later than July 31 or January 31, 

whichever date is the first date 

following the end of the semiannual 

reporting period. 

(5) For each affected source that is 

subject to permitting regulations 

pursuant to 40 CFR part 70 or 40 CFR 

part 71, and if the permitting authority 

has established dates for submitting 

semiannual reports pursuant to 40 CFR 

70.6(a)(3)(iii)(A) or 40 CFR 

71.6(a)(3)(iii)(A), you may submit the 

first and subsequent compliance reports 

according to the dates the permitting 

authority has established instead of 

according to the dates in paragraphs 

(b)(1) through (4) of this section. 

(c) The compliance report must 

contain the information required in 

paragraphs (c)(1) through (9) of this 

section. 

(1) Company name and address. 

(2) Statement by a responsible official 

with that official’s name, title, and 

signature, certifying the truth, accuracy, 

and completeness of the content of the 

report. 

(3) Date of report and beginning and 

ending dates of the reporting period. 

(4) 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. 

(5) A summary of the results of the 

annual performance tests and 

documentation of any operating limits 

that were reestablished during this test, 

if applicable. If you are conducting stack 

tests once every three years consistent 

with § 63.10006(o) or (p), the date of the 

last three stack tests, a comparison of 

the emission level you achieved in the 

last three stack tests to the 50 percent 

emission limit threshold required in 

§ 63.10006(o) or (p), and a statement as 

to whether there have been any 

operational changes since the last stack 

test that could increase emissions. 

(6) A signed statement indicating that 

you burned no new types of fuel. Or, if 

you did burn a new type of fuel, you 

must submit the calculation of chlorine 

input, using Equation 7 of § 63.10011, 

that demonstrates that your source is 

still within its maximum chlorine input 

level established during the previous 

performance testing (for sources that 

demonstrate compliance through 

performance testing) or you must submit 

the calculation of HCl emission rate 

using Equation 15 of § 63.10011 that 

demonstrates that your source is still 

meeting the emission limit for HCl 

emissions (for EGUs that demonstrate 

compliance through fuel analysis). If 

you burned a new type of fuel, you must 

submit the calculation of Hg input, 

using Equation 8 of § 63.10011, that 

demonstrates that your source is still 

within its maximum Hg input level 

established during the previous 

performance testing (for sources that 

demonstrate compliance through 

performance testing), or you must 

submit the calculation of Hg emission 

rate using Equation 11 of § 63.10011 that 

demonstrates that your source is still 

meeting the emission limit for Hg 

emissions (for EGUs that demonstrate 

compliance through fuel analysis). 

(7) If you wish to burn a new type of 

fuel and you cannot demonstrate 

compliance with the maximum chlorine 

input operating limit using Equation 7 

of § 63.10011 or the maximum Hg input 

operating limit using Equation 8 of 

§ 63.10011, you must include in the 

compliance report a statement 

indicating the intent to conduct a new 

performance test within 60 days of 

starting to burn the new fuel. 

(8) If there are no deviations from any 

emission limits or operating limits in 

this subpart that apply to you, a 

statement that there were no deviations 

from the emission limits or operating 

limits during the reporting period. 

(9) If there were no deviations from 

the monitoring requirements including 

no periods during which the CMSs, 

including CEMS, and CPMS, were out of 

control as specified in § 63.8(c)(7), a 

statement that there were no deviations 

and no periods during which the CMS 

were out of control during the reporting 

period. 

(10) Include the date of the most 

recent tune-up for each unit subject to 

the requirement to conduct a 

performance tune-up according to 

§ 63.10021(a)(16)(i) through (vi). Include 

the date of the most recent burner 

inspection if it was not done annually 

and was delayed until the next 

scheduled unit shutdown. 

(d) For each deviation from an 

emission limit or operating limit in this 

subpart that occurs at an affected source 

where you are not using a CMS to 

comply with that emission limit or 

operating limit, the compliance report 

must additionally contain the 

information required in paragraphs 

(d)(1) through (4) of this section. 

(1) The total operating time of each 

affected source during the reporting 

period. 

(2) A description of the deviation and 

which emission limit or operating limit 

from which you deviated. 

(3) Information on the number, 

duration, and cause of deviations 

(including unknown cause), as 

applicable, and the corrective action 

taken. 

(4) A copy of the test report if the 

annual performance test showed a 

deviation from the emission limits. 

(e) For each deviation from an 

emission limit, operating limit, and 

monitoring requirement in this subpart 

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 paragraphs (e)(1) through 

(12) of this section. This includes any 

deviations from your site-specific 

monitoring plan as required in 

§ 63.10000(d). 

(1) The date and time that each 

deviation started and stopped and 

description of the nature of the 

deviation (i.e., what you deviated from). 

(2) The date and time that each CMS 

was inoperative, except for zero (lowlevel) and high-level checks. 

(3) The date, time, and duration that 

each CMS was out of control, including 

the information in § 63.8(c)(8). 

(4) The date and time that each 

deviation started and stopped, and 

whether each deviation occurred during 


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a period of startup, shutdown, or 

malfunction or during another period. 

(5) A summary of the total duration of 

the deviation during the reporting 

period and the total duration as a 

percent of the total source operating 

time during that reporting period. 

(6) An analysis of the total duration of 

the deviations during the reporting 

period into those that are due to startup, 

shutdown, control equipment problems, 

process problems, other known causes, 

and other unknown causes. 

(7) A summary of the total duration of 

CMSs downtime during the reporting 

period and the total duration of CMS 

downtime as a percent of the total 

source operating time during that 

reporting period. 

(8) An identification of each 

parameter that was monitored at the 

affected source for which there was a 

deviation. 

(9) A brief description of the source 

for which there was a deviation. 

(10) A brief description of each CMS 

for which there was a deviation. 

(11) The date of the latest CMS 

certification or audit for the system for 

which there was a deviation. 

(12) A description of any changes in 

CMSs, processes, or controls since the 

last reporting period for the source for 

which there was a deviation. 

(f) Each affected source that has 

obtained a title V operating permit 

pursuant to 40 CFR part 70 or 40 CFR 

part 71 must report all deviations as 

defined in this subpart in the 

semiannual monitoring report required 

by 40 CFR 70.6(a)(3)(iii)(A) or 40 CFR 

71.6(a)(3)(iii)(A). If an affected source 

submits a compliance report pursuant to 

Table 9 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. However, submission 

of a compliance report does not 

otherwise affect any obligation the 

affected source may have to report 

deviations from permit requirements to 

the permit authority. 

(g) In addition to the information 

required in § 63.9(h)(2), your 

notification must include the following 

certification(s) of compliance, as 

applicable, and signed by a responsible 

official: 

(1) ‘‘This facility complies with the 

requirements in § 63.10021(a)(10) to 

conduct an annual performance test of 

the unit’’. 

(2) ‘‘No secondary materials that are 

solid waste were combusted in any 

affected unit.’’ 

(h)(1) As of January 1, 2012 and 

within 60 days after the date of 

completing each performance test, as 

defined in § 63.2 and as required in this 

subpart, you must submit performance 

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/). Only data collected 

using test methods compatible with ERT 

are subject to this requirement to be 

submitted electronically into EPA’s 

WebFIRE database. 

(2) Within 60 days after the date of 

completing each CEMS performance 

evaluation test, as defined in 63.2 and 

required by this subpart, you must 

submit the relative accuracy test audit 

data electronically into EPA’s Central 

Data Exchange by using the Electronic 

Reporting Tool as mentioned in 

paragraph (h)(1) of this section. Only 

data collected using test methods 

compatible with ERT are subject to this 

requirement to be submitted 

electronically into EPA’s WebFIRE 

database. 

(3) All reports required by this 

subpart not subject to the requirements 

in paragraphs (h)(1) and (2) of this 

section must be sent to the 

Administrator at the appropriate 

address listed in § 63.13. If acceptable to 

both the Administrator and the owner or 

operator of a source, these reports may 

be submitted on electronic media. The 

Administrator retains the right to 

require submittal of reports subject to 

paragraph (h)(1) and (2) of this section 

in paper format. 

(i) If you had a malfunction during the 

reporting period, the report must 

include the number, duration, and a 

brief description for each type of 

malfunction which occurred during the 

reporting period and which caused or 

may have caused any applicable 

emission limitation to be exceeded. The 

report must also include a description of 

actions taken by an owner or operator 

during a malfunction of an affected 

source to minimize emissions in 

accordance with § 63.10000(b), 

including actions taken to correct a 

malfunction. 

§ 63.10032 What records must I keep? 

(a) You must keep records according 

to paragraphs (a)(1) through (2) of this 

section. 

(1) A copy of each notification and 

report that you submitted to comply 

with this subpart, including all 

documentation supporting any Initial 

Notification or Notification of 

Compliance Status or semiannual 

compliance report that you submitted, 

according to the requirements in 

§ 63.10(b)(2)(xiv). 

(2) Records of performance stack tests, 

fuel analyses, or other compliance 

demonstrations and performance 

evaluations, as required in 

§ 63.10(b)(2)(viii). 

(b) For each CEMS and CPMS, you 

must keep records according to 

paragraphs (b)(1) through (4) of this 

section. 

(1) Records described in 

§ 63.10(b)(2)(vi) through (xi). 

(2) Previous (i.e., superseded) 

versions of the performance evaluation 

plan as required in § 63.8(d)(3). 

(3) Request for alternatives to relative 

accuracy test for CEMS as required in 

§ 63.8(f)(6)(i). 

(4) Records of the date and time that 

each deviation started and stopped, and 

whether the deviation occurred during a 

period of startup, shutdown, or 

malfunction or during another period. 

(c) You must keep the records 

required in Table 8 to this subpart 

including records of all monitoring data 

and calculated averages for applicable 

operating limits such as pressure drop 

and pH to show continuous compliance 

with each emission limit and operating 

limit that applies to you. 

(d) For each EGU subject to an 

emission limit, you must also keep the 

records in paragraphs (d)(1) through (5) 

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) A copy of all calculations and 

supporting documentation of maximum 

chlorine fuel input, using Equation 7 of 

§ 63.10011, that were done to 

demonstrate continuous compliance 

with the HCl emission limit, for sources 


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that demonstrate compliance through 

performance testing. For sources that 

demonstrate compliance through fuel 

analysis, a copy of all calculations and 

supporting documentation of HCl 

emission rates, using Equation 15 of 

§ 63.10011, that were done to 

demonstrate compliance with the HCl 

emission limit. Supporting 

documentation should include results of 

any fuel analyses and basis for the 

estimates of maximum chlorine fuel 

input or HCl emission rates. You can 

use the results from one fuel analysis for 

multiple EGUs provided they are all 

burning the same fuel type. However, 

you must calculate chlorine fuel input, 

or HCl emission rate, for each EGU. 

(4) A copy of all calculations and 

supporting documentation of maximum 

Hg fuel input, using Equation 8 of 

§ 63.10011, that were done to 

demonstrate continuous compliance 

with the Hg emission limit for sources 

that demonstrate compliance through 

performance testing. For sources that 

demonstrate compliance through fuel 

analysis, a copy of all calculations and 

supporting documentation of Hg 

emission rates, using Equation 11 of 

§ 63.10011, that were done to 

demonstrate compliance with the Hg 

emission limit. Supporting 

documentation should include results of 

any fuel analyses and basis for the 

estimates of maximum Hg fuel input or 

Hg emission rates. You can use the 

results from one fuel analysis for 

multiple EGUs provided they are all 

burning the same fuel type. However, 

you must calculate Hg fuel input, or Hg 

emission rates, for each EGU. 

(5) If consistent with § 63.10032(b) 

and (c), you choose to stack test less 

frequently than annually, you must keep 

annual records that document that your 

emissions in the previous stack test(s) 

were less than 90 percent of the 

applicable emission limit, and 

document that there was no change in 

source operations including fuel 

composition and operation of air 

pollution control equipment that would 

cause emissions of the pollutant to 

increase within the past year. 

(e) If you elect to average emissions 

consistent with § 63.10009, you must 

additionally keep a copy of the emission 

averaging implementation plan required 

in § 63.10009(g), all calculations 

required under § 63.10009, including 

daily records of heat input or steam 

generation, as applicable, and 

monitoring records consistent with 

§ 63.10022. 

(f) Records of the occurrence and 

duration of each startup and/or 

shutdown. 

(g) Records of the occurrence and 

duration of each malfunction of 

operation (i.e., process equipment) or 

the air pollution control and monitoring 

equipment. 

(h) Records of actions taken during 

periods of malfunction to 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. 

§ 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 10 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; 

however, the U.S. EPA retains oversight 

of this subpart and can take enforcement 

actions, as appropriate. 

(1) Approval of alternatives to the 

non-opacity emission limits and work 

practice standards in § 63.9991(a) and 

(b) under § 63.6(g). 

(2) Approval of major change to test 

methods in Table 5 to this subpart 

under § 63.7(e)(2)(ii) and (f) and as 

defined in § 63.90, approval of minor 

and intermediate changes to monitoring 

performance specifications/procedures 

in Table 5 where the monitoring serves 

as the performance test method (see 

definition of ‘‘test method’’ in § 63.2), 

and approval of alternative analytical 

methods requested under 

§ 63.10008(b)(2). 

(3) Approval of major change to 

monitoring under § 63.8(f) and as 

defined in § 63.90, and approval of 

alternative operating parameters under 

§§ 63.9991(a)(2) and 63.10009(g)(2). 

(4) Approval of major change to 

recordkeeping and reporting under 

§ 63.10(e) and as defined in § 63.90. 

§ 63.10042 What definitions apply to this 

subpart? 

Terms used in this subpart are 

defined in the Clean Air Act (CAA), in 

§ 63.2 (the General Provisions), and in 

this section as follows: 

Affirmative defense means, in the 

context of an enforcement proceeding, a 

response or defense put forward by a 

defendant, regarding which the 

defendant has the burden of proof, and 

the merits of which are independently 

and objectively evaluated in a judicial 

or administrative proceeding. 

Anthracite coal means solid fossil fuel 

classified as anthracite coal by 

American Society of Testing and 

Materials (ASTM) Method D388–77, 90, 

91, 95, 98a, or 99 (incorporated by 

reference, see 40 CFR 63.14(b)(39)). 

Bag leak detection system means a 

group of instruments that are capable of 

monitoring PM loadings in the exhaust 

of a fabric filter (i.e., baghouse) in order 

to detect bag failures. A bag leak 

detection system includes, but is not 

limited to, an instrument that operates 

on electrodynamic, triboelectric, light 

scattering, light transmittance, or other 

principle to monitor relative PM 

loadings. 

Bituminous coal means coal that is 

classified as bituminous according to 

ASTM Method D388–77, 90, 91, 95, 98a, 

or 99 (Reapproved 2004) ε1

(incorporated by reference, see 40 CFR 

63.14(b)(39)). 

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. 

Coal means all solid fuels classifiable 

as anthracite, bituminous, subbituminous, or lignite by ASTM Method 

D388–9911 (incorporated by reference, 


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see 40 CFR 63.14(b)(39)), and coal 

refuse. Synthetic fuels derived from coal 

for the purpose of creating useful heat 

including but not limited to, coal 

derived gases (not meeting the 

definition of natural gas), solventrefined coal, coal-oil mixtures, and 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 or coal refuse either 

exclusively, in any combination 

together, or in any combination with 

other fuels in any amount. 

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 (or mechanical) 

and useful thermal energy from the 

same primary energy source. 

Cogeneration unit means a stationary, 

fossil fuel-fired EGU meeting the 

definition of ‘‘fossil fuel-fired’’ or 

stationary, integrated gasification 

combined cycle: 

(1) Having equipment used to produce 

electricity and useful thermal energy for 

industrial, commercial, heating, or 

cooling purposes through the sequential 

use of energy; and 

(2) Producing during the 12-month 

period starting on the date the unit first 

produces electricity and during any 

calendar year after which the unit first 

produces electricity: 

(i) For a topping-cycle cogeneration 

unit, 

(A) Useful thermal energy not less 

than 5 percent of total energy output; 

and 

(B) Useful power that, when added to 

one-half of useful thermal energy 

produced, is not less than 42.5 percent 

of total energy input, if useful thermal 

energy produced is 15 percent or more 

of total energy output, or not less than 

45 percent of total energy input, if 

useful thermal energy produced is less 

than 15 percent of total energy output. 

(ii) For a bottoming-cycle 

cogeneration unit, useful power not less 

than 45 percent of total energy input. 

(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. 

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. 

Distillate oil means fuel oils, 

including recycled oils, that comply 

with the specifications for fuel oil 

numbers 1 and 2, as defined by ASTM 

Method D396–02a (incorporated by 

reference, see § 63.14(b)(40)). 

Dry flue gas desulfurization 

technology, or dry FGD, or spray dryer 

absorber (SDA), or spray dryer, or dry 

scrubber means an add-on air pollution 

control system located downstream of 

the steam generating unit that injects a 

dry alkaline sorbent (dry sorbent 

injection) or sprays an alkaline sorbent 

slurry (spray dryer) to react with and 

neutralize acid gases such as SO2 and 

HCl in the exhaust stream forming a dry 

powder material. 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 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. 

Electrostatic precipitator or ESP 

means an add-on air pollution control 

device that is located downstream of the 

steam generating unit used to capture 

PM by charging the particles using an 

electrostatic field, collecting the 

particles using a grounded collecting 

surface, and transporting the particles 

into a hopper. 

Emission limitation means any 

emissions limit or operating limit. 

Equivalent means the following only 

as this term is used in Table 6 to subpart 

UUUUU: 

(1) An equivalent sample collection 

procedure means a published voluntary 

consensus standard or practice (VCS) or 

EPA method that includes collection of 

a minimum of three composite fuel 

samples, with each composite 

consisting of a minimum of three 

increments collected at approximately 

equal intervals over the test period. 

(2) An equivalent sample compositing 

procedure means a published VCS or 

EPA method to systematically mix and 

obtain a representative subsample (part) 

of the composite sample. 

(3) An equivalent sample preparation 

procedure means a published VCS or 

EPA method that: Clearly states that the 

standard, practice or method is 

appropriate for the pollutant and the 

fuel matrix; or is cited as an appropriate 

sample preparation standard, practice or 

method for the pollutant in the chosen 

VCS or EPA determinative or analytical 

method. 

(4) An equivalent procedure for 

determining heat content means a 

published VCS or EPA method to obtain 

gross calorific (or higher heating) value. 

(5) An equivalent procedure for 

determining fuel moisture content 

means a published VCS or EPA method 

to obtain moisture content. If the sample 

analysis plan calls for determining 

metals (especially the Hg, selenium, or 

arsenic) using an aliquot of the dried 

sample, then the drying temperature 

must be modified to prevent vaporizing 

these metals. On the other hand, if 

metals analysis is done on an ‘‘as 

received’’ basis, a separate aliquot can be 

dried to determine moisture content and 

the metals concentration 

mathematically adjusted to a dry basis. 

(6) An equivalent pollutant (Hg) 

determinative or analytical procedure 

means a published VCS or EPA method 

that clearly states that the standard, 

practice, or method is appropriate for 

the pollutant and the fuel matrix and 

has a published detection limit equal or 

lower than the methods listed in Table 


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6 to subpart UUUUU for the same 

purpose. 

Fabric filter, or FF, or baghouse means 

an add-on air pollution control device 

that is located downstream of the steam 

generating unit used to capture PM by 

filtering gas streams through filter 

media. 

Federally enforceable means all 

limitations and conditions that are 

enforceable by the EPA Administrator, 

including the requirements of 40 CFR 

parts 60, 61, and 63; requirements 

within any applicable State 

implementation plan; and any permit 

requirements established under 40 CFR 

52.21 or under 40 CFR 51.18 and 40 

CFR 51.24. 

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 73 

MWe (250 million Btu/hr, MMBtu/hr) 

heat input (equivalent to 25 MWe 

output) of fossil fuels. To be ‘‘capable of 

combusting’’ fossil fuels, an EGU would 

need to have these fuels allowed in their 

permits and have the appropriate fuel 

handling facilities on-site (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 the previous 3 calendar 

years or for more than 15.0 percent of 

the annual heat input during any one of 

those calendar years. 

Fuel type means each category of fuels 

that share a common name or 

classification. Examples include, but are 

not limited to, bituminous coal, 

subbituminous coal, lignite, anthracite, 

biomass, residual oil. Individual fuel 

types received from different suppliers 

are not considered new fuel types. 

Fluidized bed boiler, or fluidized bed 

combustor, or circulating fluidized 

boiler, or CFB means a boiler utilizing 

a fluidized bed combustion process. 

Fluidized bed combustion means a 

process where a fuel is burned in a bed 

of granulated particles which are 

maintained in a mobile suspension by 

the forward flow of air and combustion 

products. 

Gaseous fuel includes, but is not 

limited to, natural gas, process gas, 

landfill gas, coal derived gas, solid oilderived gas, refinery gas, and biogas. 

Blast furnace gas is exempted from this 

definition. 

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, including any such 

electricity used in the power production 

process (which process includes, but is 

not limited to, any on-site processing or 

treatment of fuel combusted at the unit 

and any on-site emission controls), or 

mechanical output plus 75 percent of 

the useful thermal output measured 

relative to ISO conditions that is not 

used to generate additional electrical or 

mechanical output or to enhance the 

performance of the unit (i.e., steam 

delivered to an industrial process). 

Heat input means heat derived from 

combustion of fuel in an EGU 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 that burns a 

synthetic gas derived from coal or solid 

oil-derived fuel in a combined-cycle gas 

turbine. No coal or solid oil-derived fuel 

is directly burned in the unit during 

operation. 

ISO conditions means a temperature 

of 288 Kelvin, a relative humidity of 60 

percent, and a pressure of 101.3 

kilopascals. 

Lignite coal means coal that is 

classified as lignite A or B according to 

ASTM Method D388–77, 90, 91, 95, 98a, 

or 99 (Reapproved 2004) ε1

(incorporated by reference, see 

§ 63.14(a)(39)). 

Liquid fuel includes, but is not 

limited to, distillate oil and residual oil. 

Minimum pressure drop means 90 

percent of the test average pressure drop 

measured according to Table 7 to this 

subpart during the most recent 

performance test demonstrating 

compliance with the applicable 

emission limit. 

Minimum scrubber effluent pH means 

90 percent of the test average effluent 

pH measured at the outlet of the wet 

scrubber according to Table 7 to this 

subpart during the most recent 

performance test demonstrating 

compliance with the applicable HCl 

emission limit. 

Minimum scrubber flow rate means 90 

percent of the test average flow rate 

measured according to Table 7 to this 

subpart during the most recent 

performance test demonstrating 

compliance with the applicable 

emission limit. 

Minimum sorbent injection rate 

means 90 percent of the test average 

sorbent (or activated carbon) injection 

rate for each sorbent measured 

according to Table 7 to this subpart 

during the most recent performance test 

demonstrating compliance with the 

applicable emission limits. 

Minimum voltage or amperage means 

90 percent of the test average voltage or 

amperage to the electrostatic 

precipitator measured according to 

Table 7 to this subpart during the most 

recent performance test demonstrating 

compliance with the applicable 

emission limits. 

Natural gas means: 

(1) A naturally occurring mixture of 

hydrocarbon and nonhydrocarbon gases 

found in geologic formations beneath 

the earth’s surface, of which the 

principal constituent is methane; or 

(2) Liquid petroleum gas, as defined 

by ASTM Method D1835–03a 

(incorporated by reference, see 

§ 63.14(b)(41)). 

Net-electric output means the gross 

electric sales to the utility power 

distribution system minus purchased 

power on a calendar year basis. 

Non-cogeneration unit means a unit 

that has a combustion unit of more than 

25 MWe and that supplies more than 25 

MWe to any utility power distribution 

system for sale. 

Noncontinental area means the State 

of Hawaii, the Virgin Islands, Guam, 

American Samoa, the Commonwealth of 

Puerto Rico, or the Northern Mariana 

Islands. 

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 oil-derived fuels (not meeting the 

definition of natural gas). 

Oil-fired electric utility steam 

generating unit means an electric utility 

steam generating unit that either burns 

oil exclusively, or burns oil alternately 

with burning fuels other than oil at 

other times. 

Particulate matter or PM means any 

finely divided solid or liquid material, 

other than uncombined water, as 

measured by the test methods specified 

under this subpart, or an alternative 

method. 

Pulverized coal boiler means an EGU 

in which pulverized coal is introduced 

into an air stream that carries the coal 


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to the combustion chamber of the EGU 

where it is fired in suspension. 

Residual oil means crude oil, and all 

fuel oil numbers 4, 5 and 6, as defined 

by ASTM Method D396–02a 

(incorporated by reference, see 

§ 63.14(b)(40)). 

Responsible official means 

responsible official as defined in 40 CFR 

70.2. 

Stationary combustion turbine means 

all equipment, including but not limited 

to the turbine, the fuel, air, lubrication 

and exhaust gas systems, control 

systems (except emissions control 

equipment), and any ancillary 

components and sub-components 

comprising any simple cycle stationary 

combustion turbine, any regenerative/ 

recuperative cycle stationary 

combustion turbine, the combustion 

turbine portion of any stationary 

cogeneration cycle combustion system, 

or the combustion turbine portion of 

any stationary combined cycle steam/ 

electric generating system. Stationary 

means that the combustion turbine is 

not self propelled or intended to be 

propelled while performing its function. 

Stationary combustion turbines do not 

include turbines located at a research or 

laboratory facility, if research is 

conducted on the turbine itself and the 

turbine is not being used to power other 

applications at the research or 

laboratory facility. 

Steam generating unit means any 

furnace, boiler, or other device used for 

combusting fuel for the purpose of 

producing steam (including fossil-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 

overfeed. Overfeed stokers include mass 

feed and spreader stokers. 

Subbituminous coal means coal that 

is classified as subbituminous A, B, or 

C according to ASTM Method D388–77, 

90, 91, 95, 98a, or 99 (Reapproved 

2004) ε1 (incorporated by reference, see 

§ 60.14(a)(39)). 

Unit designed for coal > 8,300 Btu/lb 

subcategory includes any EGU designed 

to burn a coal having a calorific value 

(moist, mineral matter-free basis) of 

greater than or equal to 19,305 

kilojoules per kilogram (kJ/kg) (8,300 

British thermal units per pound (Btu/ 

lb)) in an EGU with a height-to-depth 

ratio of less than 3.82. 

Unit designed for coal < 8,300 Btu/lb 

includes any EGU designed to burn a 

nonagglomerating virgin coal having a 

calorific value (moist, mineral matterfree basis) of less than 19,305 kJ/kg 

(8,300 Btu/lb) in an EGU with a heightto-depth ratio of 3.82 or greater. 

Unit designed to burn liquid oil fuel 

subcategory includes any EGU that 

burned any liquid 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 gaseous fuels. 

Unit designed to burn solid oilderived fuel subcategory includes 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. 

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. 

EPA/OAQPS has by precedent only 

used VCS that are written in English. 

Examples of VCS bodies are: American 

Society of Testing and Materials 

(ASTM), American Society of 

Mechanical Engineers (ASME), 

International Standards Organization 

(ISO), Standards Australia (AS), British 

Standards (BS), Canadian Standards 

(CSA), European Standard (EN or CEN) 

and German Engineering Standards 

(VDI). The types of standards that are 

not considered VCS are standards 

developed by: The U.S. States, e.g., 

California (CARB) and Texas (TCEQ); 

industry groups, such as American 

Petroleum Institute (API), Gas 

Processors Association (GPA), and Gas 

Research Institute (GRI); and other 

branches of the U.S. government, e.g. 

Department of Defense (DOD) and 

Department of Transportation (DOT). 

This does not preclude EPA from using 

standards developed by groups that are 

not VCS bodies within their rule. When 

this occurs, EPA has done searches and 

reviews for VCS equivalent to these 

non-EPA methods. 

Wet flue gas desulfurization 

technology, or wet FGD, or wet scrubber 

means any add-on air pollution control 

device that is located downstream of the 

steam generating unit that mixes an 

aqueous stream or slurry with the 

exhaust gases from an EGU to control 

emissions of PM and/or to absorb and 

neutralize acid gases, such as SO2 and 

HCl. 

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 

As stated in § 63.9991, you must 

comply with the following applicable 

emission limits: 

TABLE 1 TO SUBPART UUUUU OF PART 63—EMISSION LIMITS FOR NEW OR RECONSTRUCTED EGUS

If your EGU is in this 

subcategory . . . For the following pollutants . . . 

You must meet the following 

emission limits and work practice 

standards . . . 

Using these requirements, as 

appropriate, (e.g., specified 

sampling volume or test run 

duration) with the test methods in 

Table 5 . . . 

1. Coal-fired unit designed for coal 

≥ 8,300 Btu/lb.

a. Total particulate matter (PM) ... 0.050 lb per MWh ........................ Collect a minimum of 4 dscm per 

run. 

OR OR 

Total non-Hg HAP metals ............ 0.000040 lb per MWh .................. Collect a minimum of 4 dscm per 

run. 

OR OR 

Individual HAP metals: Collect a minimum of 4 dscm per 

run. 

Antimony (Sb) .............................. 0.000080 lb/GWh .........................

Arsenic (As) .................................. 0.00020 lb/GWh ...........................

Beryllium (Be) ............................... 0.000030 lb/GWh .........................

Cadmium (Cd) .............................. 0.00040 lb/GWh ...........................


jlentini on DSKJ8SOYB1PROD with PROPOSALS2
Federal Register / Vol. 76, No. 85 / Tuesday, May 3, 2011 / Proposed Rules 25125 

TABLE 1 TO SUBPART UUUUU OF PART 63—EMISSION LIMITS FOR NEW OR RECONSTRUCTED EGUS—Continued 

If your EGU is in this 

subcategory . . . For the following pollutants . . . 

You must meet the following 

emission limits and work practice 

standards . . . 

Using these requirements, as 

appropriate, (e.g., specified 

sampling volume or test run 

duration) with the test methods in 

Table 5 . . . 

Chromium (Cr) ............................. 0.020 lb/GWh ...............................

Cobalt (Co) ................................... 0.00080 lb/GWh ...........................

Lead (Pb) ..................................... 0.00090 lb/GWh ...........................

Manganese (Mn) .......................... 0.0040 lb/GWh .............................

Nickel (Ni) ..................................... 0.0040 lb/GWh .............................

Selenium (Se) .............................. 0.030 lb/GWh ...............................

b. Hydrogen chloride (HCl) .......... 0.30 lb per GWh ........................... For Method 26A, collect a minimum of 4 dscm per run. 

OR 

Sulfur dioxide (SO2) 1 ................... 0.40 lb per MWh .......................... SO2 CEMS. 

c. Mercury (Hg) ............................ 0.000010 lb per GWh ................... Hg CEMS or Sorbent trap monitoring system. 

2. Coal-fired unit designed for coal 

< 8,300 Btu/lb.

a. Total particulate matter (PM) ... 0.050 lb per MWh ........................ Collect a minimum of 4 dscm per 

run. 

OR OR 

Total non-Hg HAP metals ............ 0.000040 lb per MWh .................. Collect a minimum of 4 dscm per 

run. 

OR OR 

Individual HAP metals: Collect a minimum of 4 dscm per 

run. 

Antimony (Sb) .............................. 0.000080 lb/GWh .........................

Arsenic (As) .................................. 0.00020 lb/GWh ...........................

Beryllium (Be) ............................... 0.000030 lb/GWh .........................

Cadmium (Cd) .............................. 0.00040 lb/GWh ...........................

Chromium (Cr) ............................. 0.020 lb/GWh ...............................

Cobalt (Co) ................................... 0.00080 lb/GWh ...........................

Lead (Pb) ..................................... 0.00090 lb/GWh ...........................

Manganese (Mn) .......................... 0.0040 lb/GWh .............................

Nickel (Ni) ..................................... 0.0040 lb/GWh .............................

Selenium (Se) .............................. 0.030 lb/GWh ...............................

b. Hydrogen chloride (HCl) .......... 0.30 lb per GWh ........................... For Method 26A, collect a minimum of 4 dscm per run. 

OR OR 

Sulfur dioxide (SO2) 2 ................... 0.40 lb per MWh .......................... SO2 CEMS. 

c. Mercury (Hg) ............................ 0.040 lb per GWh ......................... Hg CEMS or Sorbent trap monitoring system. 

3. IGCC unit .................................... a. Particulate matter (PM) ............ 0.050 lb per MWh ........................ Collect a minimum of 4 dscm per 

run. 

OR OR 

Total non-Hg HAP metals ............ 0.000040 lb per MWh .................. Collect a minimum of 4 dscm per 

run. 

OR OR 

Individual HAP metals: Collect a minimum of 4 dscm per 

run. 

Antimony (Sb) .............................. 0.000080 lb/GWh .........................

Arsenic (As) .................................. 0.00020 lb/GWh ...........................

Beryllium (Be) ............................... 0.000030 lb/GWh .........................

Cadmium (Cd) .............................. 0.00040 lb/GWh ...........................

Chromium (Cr) ............................. 0.020 lb/GWh ...............................

Cobalt (Co) ................................... 0.00080 lb/GWh ...........................

Lead (Pb) ..................................... 0.00090 lb/GWh ...........................

Manganese (Mn) .......................... 0.0040 lb/GWh .............................

Nickel (Ni) ..................................... 0.0040 lb/GWh .............................

Selenium (Se) .............................. 0.030 lb/GWh ...............................

b. Hydrogen chloride (HCl) .......... 0.30 lb per GWh ........................... For Method 26A, collect a minimum of 4 dscm per run. 

OR 

Sulfur dioxide (SO2) 3 ................... 0.40 lb per MWh .......................... SO2 CEMS. 

c. Mercury (Hg) ............................ 0.000010 lb per GWh ................... Hg CEMS or Sorbent trap monitoring system. 

4. Liquid oil-fired unit ....................... a. Total HAP metals ..................... 0.00040 lb/MWh ........................... Collect a minimum of 4 dscm per 

run. 

OR OR 

Individual HAP metals: Collect a minimum of 4 dscm per 

run. 

Antimony (Sb) .............................. 0.0020 lb/GWh .............................


jlentini on DSKJ8SOYB1PROD with PROPOSALS2
25126 Federal Register / Vol. 76, No. 85 / Tuesday, May 3, 2011 / Proposed Rules 

TABLE 1 TO SUBPART UUUUU OF PART 63—EMISSION LIMITS FOR NEW OR RECONSTRUCTED EGUS—Continued 

If your EGU is in this 

subcategory . . . For the following pollutants . . . 

You must meet the following 

emission limits and work practice 

standards . . . 

Using these requirements, as 

appropriate, (e.g., specified 

sampling volume or test run 

duration) with the test methods in 

Table 5 . . . 

Arsenic (As) .................................. 0.0020 lb/GWh .............................

Beryllium (Be) ............................... 0.00070 lb/GWh ...........................

Cadmium (Cd) .............................. 0.00040 lb/GWh ...........................

Chromium (Cr) ............................. 0.020 lb/GWh ...............................

Cobalt (Co) ................................... 0.0060 lb/GWh .............................

Lead (Pb) ..................................... 0.0060 lb/GWh .............................

Manganese (Mn) .......................... 0.030 lb/GWh ...............................

Nickel (Ni) ..................................... 0.040 lb/GWh ...............................

Selenium (Se) .............................. 0.0040 lb/GWh .............................

Mercury (Hg) ................................ 0.00010 lb/GWh ........................... For Method 30B sample volume 

determination (8.2.4), the estimated Hg concentration should 

nominally be < 1⁄2 the standard. 

b. Hydrogen chloride (HCl) .......... 0.00050 lb/MWh ........................... For Method 26A, collect a minimum of 4 dscm per run. 

c. Hydrogen fluoride (HF) ............ 0.00050 lb/MWh ........................... For Method 26A, collect a minimum of 4 dscm per run. 

5. Solid oil-derived fuel-fired unit .... a. Particulate matter (PM) ............ 0.050 lb/MWh ............................... Collect a minimum of 4 dscm per 

run. 

OR OR 

Total non-Hg HAP metals ............ 0.00020 lb/MWh ........................... Collect a minimum of 4 dscm per 

run. 

OR OR 

Individual HAP metals: Collect a minimum of 4 dscm per 

run. 

Antimony (Sb) .............................. 0.00090 lb/GWh ...........................

Arsenic (As) .................................. 0.0020 lb/GWh .............................

Beryllium (Be) ............................... 0.000080 lb/GWh .........................

Cadmium (Cd) .............................. 0.0070 lb/GWh .............................

Chromium (Cr) ............................. 0.0060 lb/GWh .............................

Cobalt (Co) ................................... 0.0020 lb/GWh .............................

Lead (Pb) ..................................... 0.020 lb/GWh ...............................

Manganese (Mn) .......................... 0.0070 lb/GWh .............................

Nickel (Ni) ..................................... 0.0070 lb/GWh .............................

Selenium (Se) .............................. 0.00090 lb/GWh ...........................

b. Hydrogen chloride (HCl) .......... 0.00030 lb/MWh ........................... For Method 26A, collect a minimum of 4 dscm per run. 

OR 

Sulfur dioxide (SO2) 4 ................... 0.40 lb/MWh ................................. SO2 CEMS. 

c. Mercury (Hg) ............................ 0.0020 lb/GWh ............................. Hg CEMS or Sorbent trap monitoring system. 

As stated in § 63.9991, you must 

comply with the following applicable 

emission limits: 5

TABLE 2 TO SUBPART UUUUU OF PART 63—EMISSION LIMITS FOR EXISTING EGUS

If your EGU is in this subcategory 

. . . For the following pollutants . . . 

You must meet the following 

emission limits and work practice 

standards . . . 

Using these requirements, as appropriate (e.g., specified sampling 

volume or test run duration) with 

the test methods in Table 5 . . . 

1. Coal-fired unit designed for coal 

≥ 8,300 Btu/lb.

a. Total particulate matter (PM) ... 0.030 lb/MMBtu or 0.30 lb/MWh .. Collect a minimum of 2 dscm per 

run. 

OR OR 

Total non-Hg HAP metals ............ 0.000040 lb/MMBtu 

0.00040 lb/MWh 

Collect a minimum of 4 dscm per 

run. 

OR OR 

Individual HAP metals: Collect a minimum of 4 dscm per 

run. 

Antimony (Sb) ............................... 0.60 lb/TBtu or 0.0060 lb/GWh.

Arsenic (As) .................................. 2.0 lb/TBtu or 0.020 lb/GWh.

Beryllium (Be) ............................... 0.20 lb/TBtu or 0.0020 lb/GWh.

Cadmium (Cd) .............................. 0.30 lb/TBtu or 0.0030 lb/GWh.


jlentini on DSKJ8SOYB1PROD with PROPOSALS2
Federal Register / Vol. 76, No. 85 / Tuesday, May 3, 2011 / Proposed Rules 25127 

TABLE 2 TO SUBPART UUUUU OF PART 63—EMISSION LIMITS FOR EXISTING EGUS—Continued 

If your EGU is in this subcategory 

. . . For the following pollutants . . . 

You must meet the following 

emission limits and work practice 

standards . . . 

Using these requirements, as appropriate (e.g., specified sampling 

volume or test run duration) with 

the test methods in Table 5 . . . 

Chromium (Cr) .............................. 3.0 lb/TBtu or 0.030 lb/GWh.

Cobalt (Co) ................................... 0.80 lb/TBtu or 0.0080 lb/GWh.

Lead (Pb) ...................................... 2.0 lb/TBtu or 0.020 lb/GWh.

Manganese (Mn) .......................... 5.0 lb/TBtu or 0.050 lb/GWh.

Nickel (Ni) ..................................... 4.0 lb/TBtu or 0.040 lb/GWh.

Selenium (Se) ............................... 6.0 lb/TBtu or 0.060 lb/GWh.

b. Hydrogen chloride (HCl) ........... 0.0020 lb per MMBtu or 0.020 lb 

per MWh.

For Method 26A, collect a minimum of 0.75 dscm per run; for 

Method 26, collect a minimum 

of 60 liters per run. 

OR 

Sulfur dioxide (SO2) 6 ................... 0.20 lb per MMBtu or 2.0 lb per 

MWh.

SO2 CEMS. 

c. Mercury (Hg) ............................. 1.0 lb/TBtu or 0.008 lb/GWh ........ LEE Testing for 28–30 days with 

10 days maximum per run or 

Hg CEMS or Sorbent trap monitoring system. 

2. Coal-fired unit designed for coal 

< 8,300 Btu/lb ................................

a. Total particulate matter (PM) ... 0.030 lb/MMBtu or 0.30 lb/MWh .. Collect a minimum of 4 dscm per 

run. 

OR OR 

Total non-Hg HAP metals ............ 0.000040 lb/MMBtu 

0.00040 lb/MWh 

Collect a minimum of 4 dscm per 

run. 

OR OR 

Individual HAP metals: Collect a minimum of 4 dscm per 

run. 

Antimony (Sb) ............................... 0.60 lb/TBtu or 0.0060 lb/GWh.

Arsenic (As) .................................. 2.0 lb/TBtu or 0.020 lb/GWh.

Beryllium (Be) ............................... 0.20 lb/TBtu or 0.0020 lb/GWh.

Cadmium (Cd) .............................. 0.30 lb/TBtu or 0.0030 lb/GWh.

Chromium (Cr) .............................. 3.0 lb/TBtu or 0.030 lb/GWh.

Cobalt (Co) ................................... 0.80 lb/TBtu or 0.0080 lb/GWh.

Lead (Pb) ...................................... 2.0 lb/TBtu or 0.020 lb/GWh.

Manganese (Mn) .......................... 5.0 lb/TBtu or 0.050 lb/GWh.

Nickel (Ni) ..................................... 4.0 lb/TBtu or 0.040 lb/GWh.

Selenium (Se) ............................... 6.0 lb/TBtu or 0.060 lb/GWh.

b. Hydrogen chloride (HCl) ........... 0.0020 lb per MMBtu or 0.020 lb 

per MWh.

For Method 26A, collect a minimum of 0.75 dscm per run; for 

Method 26, collect a minimum 

of 60 liters per run. 

OR 

Sulfur dioxide (SO2) 7 ................... 0.20 lb per MMBtu or 2.0 lb per 

MWh.

SO2 CEMS. 

c. Mercury (Hg) ............................. 4.0 lb/TBtu or 0.040 lb/GWh ........ LEE Testing for 28–30 days with 

10 days maximum per run or 

Hg CEMS or Sorbent trap monitoring system. 

3. IGCC unit ................................... a. Total particulate matter (PM) ... 0.050 lb/MMBtu or 0.30 lb/MWh .. Collect a minimum of 4 dscm per 

run. 

OR OR 

Total non-Hg HAP metals ............ 5.0 lb/TBtu or 0.050 lb/GWh ........ Collect a minimum of 4 dscm per 

run. 

OR OR 

Individual HAP metals: Collect a minimum of 4 dscm per 

run. 

Antimony (Sb) ............................... 0.40 lb/TBtu or 0.0040 lb/GWh.

Arsenic (As) .................................. 2.0 lb/TBtu or 0.020 lb/GWh.

Beryllium (Be) ............................... 0.030 lb/TBtu or 0.0030 lb/GWh.

Cadmium (Cd) .............................. 0.20 lb/TBtu or 0.0020 lb/GWh.

Chromium (Cr) .............................. 3.0 lb/TBtu or 0.020 lb/GWh.

Cobalt (Co) ................................... 2.0 lb/TBtu or 0.0040 lb/GWh.

Lead (Pb) ...................................... 0.0002 lb/MMBtu or 0.003 lb/MWh.

Manganese (Mn) .......................... 3.0 lb/TBtu or 0.020 lb/GWh.

Nickel (Ni) ..................................... 5.0 lb/TBtu or 0.050 lb/GWh.

Selenium (Se) ............................... 22.0 lb/TBtu or 0.20 lb/GWh.

b. Hydrogen chloride (HCl) ........... 0.00050 lb/MMBtu or 0.0030 lb/ 

MWh.

For Method 26A, collect a minimum of 4 dscm per run. 


jlentini on DSKJ8SOYB1PROD with PROPOSALS2
25128 Federal Register / Vol. 76, No. 85 / Tuesday, May 3, 2011 / Proposed Rules 

TABLE 2 TO SUBPART UUUUU OF PART 63—EMISSION LIMITS FOR EXISTING EGUS—Continued 

If your EGU is in this subcategory 

. . . For the following pollutants . . . 

You must meet the following 

emission limits and work practice 

standards . . . 

Using these requirements, as appropriate (e.g., specified sampling 

volume or test run duration) with 

the test methods in Table 5 . . . 

c. Mercury (Hg) ............................. 3.0 lb/TBtu or 0.020 lb/GWh ........ LEE Testing for 28–30 days with 

10 days maximum per run or 

Hg CEMS or Sorbent trap monitoring system. 

4. Liquid oil-fired unit ..................... a. Total HAP metals ..................... 0.000030 lb/MMBtu or 0.00030 lb/ 

MWh.

Collect a minimum of 4 dscm per 

run. 

OR OR 

Individual HAP metals: Collect a minimum of 4 dscm per 

run. 

Antimony (Sb) ............................... 0.20 lb/TBtu or 0.0030 lb/GWh.

Arsenic (As) .................................. 0.60 lb/TBtu or 0.0070 lb/GWh.

Beryllium (Be) ............................... 0.060 lb/TBtu or 0.00070 lb/GWh.

Cadmium (Cd) .............................. 0.10 lb/TBtu or 0.0020 lb/GWh.

Chromium (Cr) .............................. 2.0 lb/TBtu or 0.020 lb/GWh.

Cobalt (Co) ................................... 3.0 lb/TBtu or 0.020 lb/GWh.

Lead (Pb) ...................................... 2.0 lb/TBtu or 0.030 lb/GWh.

Manganese (Mn) .......................... 5.0 lb/TBtu or 0.060 lb/GWh.

Nickel (Ni) ..................................... 8.0 lb/TBtu or 0.080 lb/GWh.

Selenium (Se) ............................... 2.0 lb/TBtu or 0.020 lb/GWh.

Mercury (Hg) ................................. 0.050 lb/TBtu or 0.00070 lb/GWh For Method 29, collect a minimum 

of 4 dscm per run or for Method 

30B sample volume determination (8.2.4), the estimated Hg 

concentration should nominally 

be < 1⁄2 the standard. 

b. Hydrogen chloride (HCl) ........... 0.00030 lb/MMBtu or 0.0030 lb/ 

MWh.

For Method 26A, collect a minimum of 4 dscm per run. 

c. Hydrogen fluoride (HF) ............. 0.00020 lb/MMBtu or 0.0020 lb/ 

MWh.

For Method 26A, collect a minimum of 4 dscm per run. 

5. Solid oil-derived fuel-fired unit ... a. Total particulate matter (PM) ... 0.20 lb/MMBtu or 2.0 lb/MWh ...... Collect a minimum of 2 dscm per 

run. 

OR OR 

Total non-Hg HAP metals ............ 0.000050 lb/MMBtu or 0.0010 lb/ 

MWh.

Collect a minimum of 2 dscm per 

run. 

OR OR 

Individual HAP metals: Collect a minimum of 4 dscm per 

run. 

Antimony (Sb) ............................... 0.40 lb/TBtu or 0.0070 lb/GWh.

Arsenic (As) .................................. 0.40 lb/TBtu or 0.0040 lb/GWh.

Beryllium (Be) ............................... 0.070 lb/TBtu or 0.00070 lb/GWh.

Cadmium (Cd) .............................. 0.40 lb/TBtu or 0.0040 lb/GWh.

Chromium (Cr) .............................. 2.0 lb/TBtu or 0.020 lb/GWh.

Cobalt (Co) ................................... 2.0 lb/TBtu or 0.020 lb/GWh.

Lead (Pb) ...................................... 11.0 lb/TBtu or 0.020 lb/GWh.

Manganese (Mn) .......................... 3.0 lb/TBtu or 0.040 lb/GWh.

Nickel (Ni) ..................................... 9.0 lb/TBtu or 0.090 lb/GWh.

Selenium (Se) ............................... 2.0 lb/TBtu 0.020 lb/GWh.

b. Hydrogen chloride (HCl) ........... 0.0050 lb/MMBtu or 0.080 lb/GWh For Method 26A, collect a minimum of 1 dscm per run; for 

Method 26, collect a minimum 

of 60 liters per run. 

OR 

Sulfur dioxide (SO2) 8 ................... 0.40 lb/MMBtu or 5.0 lb/MWh ...... SO2 CEMS. 

c. Mercury (Hg) ............................. 0.20 lb/TBtu or 0.0020 lb/GWh .... LEE Testing for 28–30 days with 

10 days maximum per run or 

Hg CEMS or Sorbent trap monitoring system. 

5 footnote. 

6 footnote. 

7 footnote. 

8The alternate sulfur dioxide limit may not be used if your EGU does not have some form of flue gas desulfurization system installed. 

As stated in § 63.9991, you must 

comply with the following applicable 

work practice standards: 


jlentini on DSKJ8SOYB1PROD with PROPOSALS2
Federal Register / Vol. 76, No. 85 / Tuesday, May 3, 2011 / Proposed Rules 25129 

9For emissions calculations involving periods of 

startup or shutdown, use procedures in 

§ 63.10005(l). 

TABLE 3 TO SUBPART UUUUU OF PART 63—WORK PRACTICE STANDARDS

If your EGU is . . . You must meet the following . . . 

1. An existing EGU ...................... Conduct a performance test of the EGU annually as specified in § 63.10005. 

2. A new EGU ............................. Conduct a performance test of the EGU annually as specified in § 63.10005. 

TABLE 4 TO SUBPART UUUUU OF PART 63—OPERATING LIMITS FOR EGUS

If you demonstrate compliance 

using . . . You must meet these operating limits . . . 

1. Wet PM scrubber control ........ a. Maintain the pressure drop at or above the lowest 1-hour average pressure drop across the wet scrubber 

and the liquid flow rate at or above the lowest 1-hour average liquid flow rate measured during the most 

recent performance test demonstrating compliance with the PM emissions limitation. 

2. Wet acid gas scrubbers .......... a. Maintain the pH at or above the lowest 1-hour average pressure drop across the wet scrubber and the liquid flow-rate at or above the lowest 1-hour average liquid flow rate measured during the most recent performance test demonstrating compliance with the HCl emissions limitation. 

3. Fabric filter control .................. a. Install and operate a bag leak detection system according to § 63.10010 and operate the fabric filter such 

that the bag leak detection system does not initiate alarm mode more than 5 percent of the operating time 

during each 6-month period. 

4. Electrostatic precipitator control.a. This option is only for EGUs that operate additional wet control systems. Maintain the secondary power 

input of the electrostatic precipitator at or above the lowest 1-hour average secondary power measured 

during the most recent performance test demonstrating compliance with the PM emissions limitation. 

5. Dry scrubber, DSI, or carbon 

injection control.

Maintain the sorbent or carbon injection rate at or above the lowest 1-hour average sorbent flow rate measured during the most recent performance test demonstrating compliance with the Hg emissions limitation. 

6. Fuel analysis ........................... Maintain the fuel type or fuel mixture such that the applicable emission rate calculated according to 

§ 63.10011(d)(3), (4) and/or (5) is less than the applicable emission limits. 

7. Performance testing ................ For EGUs that demonstrate compliance with a performance test, maintain the operating load of each unit 

such that it does not exceed 110 percent of the average operating load recorded during the most recent 

performance test. 

8. PM CEMS ............................... Maintain the PM concentration (mg/dscm) at or below the highest 1-hour average measured during the most 

recent performance test demonstrating compliance with the total PM emissions limitation. 

As stated in § 63.10007, you must 

comply with the following requirements 

for performance testing for existing, new 

or reconstructed affected sources: 9

TABLE 5 TO SUBPART UUUUU OF PART 63—PERFORMANCE STACK TESTING REQUIREMENTS

To conduct a performance test for the following pollutant . . . 

Using . . . You must . . . Using . . .10

1. Particulate matter 

(PM).

Emissions Testing ...... a. Select sampling ports location and the 

number of traverse points.

Method 1 at 40 CFR part 60, Appendix A–1 

of this chapter. 

b. Determine velocity and volumetric flow-rate 

of the stack gas.

Method 2, 2F, or 2G at 40 CFR part 60, 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 40 CFR part 60, Appendix A–2 to part 60 of this chapter, or ANSI/ 

ASME PTC 19.10–1981. 

d. Measure the moisture content of the stack 

gas.

Method 4 at 40 CFR part 60, Appendix A–3 

of this chapter. 

e. Measure the PM emissions concentrations 

and determine the filterable and condensable fractions, as well as total PM.

Method 202 at 40 CFR part 51, Appendix M 

of this chapter for condensable PM emissions from units and Method 5 (positive 

pressure fabric filters must use Method 5D) 

at 40 CFR part 60, Appendix A–3 or A–6 of 

this chapter for filterable PM emissions. 

Note that the Method 5 front half temperature shall be 320 °F ± 25 °F. 

f. Convert emissions concentration to lb per 

MMBtu emissions rates or lb/MWh emissions rates.

Method 19 F-factor methodology at 40 CFR 

part 60, Appendix A–7 of this chapter, or 

calculate using mass emissions rate and 

electrical output data. 

2. Total or individual 

non-Hg HAP metals.

Emissions Testing ...... a. Select sampling ports location and the 

number of traverse points.

Method 1 at 40 CFR part 60, Appendix A–1 

of this chapter. 


jlentini on DSKJ8SOYB1PROD with PROPOSALS2
25130 Federal Register / Vol. 76, No. 85 / Tuesday, May 3, 2011 / Proposed Rules 

TABLE 5 TO SUBPART UUUUU OF PART 63—PERFORMANCE STACK TESTING REQUIREMENTS—Continued 

To conduct a performance test for the following pollutant . . . 

Using . . . You must . . . Using . . .10

b. Determine velocity and volumetric flow-rate 

of the stack gas.

Method 2, 2F, or 2G at 40 CFR part 60, 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 40 CFR part 60, Appendix A–2 to part 60 of this chapter, or ANSI/ 

ASME PTC 19.10–1981. 

d. Measure the moisture content of the stack 

gas.

Method 4 at 40 CFR part 60, Appendix A–3 

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 40 CFR part 60, Appendix A–8 

of this chapter. Determine total filterable 

HAP metals according to section 8.3.1.1 

prior to beginning metals analyses. 

f. Convert emissions concentrations (individual HAP metals, total filterable HAP metals, and total HAP metals) to lb per MMBtu 

or lb per MWh emissions rates.

Method 19 F-factor methodology at 40 CFR 

part 60, Appendix A–7 of this chapter, or 

calculate using mass emissions rate and 

electrical output data. 

3. Hydrogen chloride 

(HCl) and hydrogen 

fluoride (HF).

Emissions Testing ...... a. Select sampling ports location and the 

number of traverse points.

Method 1 at 40 CFR part 60, Appendix A–1 

of this chapter. 

b. Determine velocity and volumetric flow-rate 

of the stack gas.

Method 2, 2F, or 2G at 40 CFR part 60, Appendix A–2 of this chapter. 

c. Determine oxygen and carbon dioxide concentrations of the stack gas.Method 3A or 3B at 40 CFR part 60, Appendix A–2 of this chapter, or ANSI/ASME 

PTC 19.10–1981. 

d. Measure the moisture content of the stack 

gas.

Method 4 at 40 CFR part 60, Appendix A–3 

of this chapter. 

e. Measure the HCl and HF emissions concentrations.Method 26 if there are no entrained water 

droplets in the exhaust stream or 26A if 

there are entrained water droplets in the 

exhaust stream at 40 CFR part 60, Appendix A–8 of this chapter. 

f. Convert emissions concentration to lb per 

MMBtu or lb per MWh emissions rates.

Method 19 F-factor methodology at 40 CFR 

part 60, Appendix A–7 of this chapter, or 

calculate using mass emissions rate and 

electrical output data. 

OR OR 

HCl and/or HF CEMS a. Install, operate, and maintain the CEMS .... PS 15 or 6 at 40 CFR part 60, Appendix B of 

this chapter and QA Procedure 1 at 40 

CFR part 60, Appendix F of this chapter. 

b. Install, operate, and maintain the diluents 

gas, flow rate, and/or moisture monitoring 

systems.

Section 4.1.3 and 5.3 of Appendix A of this 

subpart. 

c. Convert hourly emissions concentrations to 

30 boiler operating day rolling average lb 

per MMBtu emissions rates or lb/MWh 

emissions rates.

Method 19 F-factor methodology at 40 CFR 

part 60, Appendix A–7 of this chapter, or 

calculate using mass emissions rate and 

electrical output data. 

4. Mercury (Hg) .......... Emissions Testing ...... a. Select sampling ports location and the 

number of traverse points.

Method 1 at 40 CFR part 60, Appendix A–1 

of this chapter. 

b. Determine velocity and volumetric flow-rate 

of the stack gas.

Method 2, 2F, or 2G at 40 CFR part 60, Appendix A–1 or A–2 of this chapter. 

c. Determine oxygen and carbon dioxide concentrations of the stack gas.Method 3A or 3B at 40 CFR part 60, Appendix A–1 of this chapter, or ANSI/ASME 

PTC 19.10–1981. 

d. Measure the moisture content of the stack 

gas.

Method 4 at 40 CFR part 60, Appendix A–3 

of this chapter. 

e. Measure the Hg emission concentration .... Method 29 or 30B at 40 CFR part 60, Appendix A–8 of this chapter or ASTM Method 

D6784–02 (2008) as specified. 

f. Convert emissions concentration to lb per 

TBtu emissions rates.

Section 6 of Appendix A of this subpart. 

OR OR 

Hg CEMS ................... a. Install, operate, and maintain the CEMS .... Sections 3.2.1 and 5.1 of Appendix A of this 

subpart. 

b. Install, operate, and maintain the diluents 

gas, flow rate, and/or moisture monitoring 

systems.

Section 4.1.3 and 5.3 of Appendix A of this 

subpart. 


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10All ASTM, ANSI, and ASME methods are 

incorporated by reference. 

11All ASTM, ANSI, and ASME methods are 

incorporated by reference. 

TABLE 5 TO SUBPART UUUUU OF PART 63—PERFORMANCE STACK TESTING REQUIREMENTS—Continued 

To conduct a performance test for the following pollutant . . . 

Using . . . You must . . . Using . . .10

c. Convert hourly emissions concentrations to 

30 boiler operating day rolling average lb 

per MMBtu emissions rates or lb/MWh 

emissions rates.

Section 6 of Appendix A of this subpart. 

OR OR 

Sorbent trap monitoring system a. Install, operate, and maintain the sorbent 

trap monitoring system.

Sections 3.2.2 and 5.2 of Appendix A of this 

subpart. 

b. Install, operate, and maintain the diluents 

gas, flow rate, and/or moisture monitoring 

systems.

Section 4.1.3 and 5.3 of Appendix A of this 

subpart. 

c. Convert emissions concentrations to 30 

boiler operating day rolling average lb per 

MMBtu emissions rates or lb/MWh emissions rates.

Section 6 of Appendix A of 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 40 CFR part 60, Appendix A–1 of 

this chapter. 

b. Determine velocity and volumetric flow-rate 

of the stack gas.

Method 2, 2F, or 2G at 40 CFR part 60, Appendix A–1 or A–2 of this chapter or flow 

monitoring systems certified by Section 

4.1.3 and 5.3 of Appendix A of this subpart. 

c. Determine oxygen and carbon dioxide concentrations of the stack gas.Method 3A or 3B at 40 CFR part 60, Appendix A–1 of this chapter, or ANSI/ASME 

PTC 19.10–1981 or diluent gas monitoring 

systems certified by Section 4.1.3 and 5.3 

of Appendix A of this subpart. 

d. Measure the moisture content of the stack 

gas.

Method 4 at 40 CFR part 60, Appendix A–3 

of this chapter or moisture monitoring systems certified by Section 4.1.3 and 5.3 of 

Appendix A of this subpart. 

e. Measure the Hg emission concentration .... Method 30B at 40 CFR part 60, Appendix A– 

8 of this chapter. 

f. Convert emissions concentrations to 30 

boiler operating day rolling average lb per 

MMBtu emissions rates or lb/MWh emissions rates.

Section 6 of Appendix A of this subpart. 

g. Convert 30 boiler operating day rolling average lb per MMBtu pr lb/MWh to lb per 

year.

Potential maximum annual heat input in 

MMBtu or potential maximum electricity 

generated in MWh. 

5. Sulfur dioxide (SO2) SO2 CEMS ................. a. Install, operate, and maintain the CEMS .... PS 2 or 6 at 40 CFR part 60, Appendix B of 

this chapter and QA Procedure 1 at 40 

CFR part 60, Appendix F of this chapter. 

b. Install, operate, and maintain the diluents 

gas, flow rate, and/or moisture monitoring 

systems.

Section 4.1.3 and 5.3 of Appendix A of this 

subpart. 

c. Convert hourly emissions concentrations to 

30 boiler operating day rolling average lb 

per MMBtu emissions rates or lb/MWh 

emissions rates.

Method 19 F-factor methodology at 40 CFR 

part 60, Appendix A–7 of this chapter, or 

calculate using mass emissions rate and 

electrical output data. 

As stated in § 63.10008, you must 

comply with the following requirements 

for fuel analysis testing for existing, 

new, or reconstructed affected sources. 

However, equivalent methods may be 

used in lieu of the prescribed methods 

at the discretion of the source owner or 

operator: 

TABLE 6 TO SUBPART UUUUU OF PART 63—FUEL ANALYSIS REQUIREMENTS

To conduct a fuel analysis for 

the following pollutant . . . You must . . . Using . . . 11

1. Mercury (Hg) ......................... a. Collect fuel samples ..................................... Procedure in § 63.10008(c) or ASTM D2234/D2234M (for 

coal) or equivalent. 

b. Composite fuel samples .............................. Procedure in § 63.10008(d) or equivalent. 


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TABLE 6 TO SUBPART UUUUU OF PART 63—FUEL ANALYSIS REQUIREMENTS—Continued 

To conduct a fuel analysis for 

the following pollutant . . . You must . . . Using . . . 11

c. Prepare composited fuel samples ............... EPA SW–846–3020A (for liquid samples) or ASTM D2013/ 

D2013M– (for coal) or equivalent. 

d. Determine heat content of the fuel type ...... ASTM D5865 (for coal) or equivalent. 

e. Determine moisture content of the fuel type ASTM D3173 or equivalent. 

f. Measure Hg concentration in fuel sample .... ASTM D6722–01 (for coal) or SW–846–7471A (for solid samples) or SW–846–7470A (for liquid samples) or equivalent. 

g. Convert concentration into units of pounds 

of pollutant per TBtu of heat content or lb 

per MWh.

Method 19 F-factor methodology at 40 CFR part 60, Appendix A–7 of this chapter, or calculate using mass emissions 

rate and electrical output data. 

2. Other non-Hg HAP metals .... a. Collect fuel samples ..................................... Procedure in § 63.10008(c) or ASTM D2234/D2234M (for 

coal) or equivalent. 

b. Composite fuel samples .............................. Procedure in § 63.10008(d) or equivalent. 

c. Prepare composited fuel samples ............... EPA SW–846–3020A (for liquid samples) or ASTM D2013/ 

D2013M– (for coal) or equivalent. 

d. Determine heat content of the fuel type ...... ASTM D5865 (for coal) or equivalent. 

e. Determine moisture content of the fuel type ASTM D3173 or equivalent. 

f. Measure other non-Hg HAP metals concentrations in fuel sample.EPA SW–846–6010B or ASTM D3683 (for coal samples) or 

equivalent; EPA SW–846–6010B (for other solid fuel samples) or equivalent; or EPA SW–846–6020 (for liquid fuel 

samples) or equivalent. 

g. Convert concentration into units of pounds 

of pollutant per TBtu of heat content or lb 

per MWh.

Method 19 F-factor methodology at 40 CFR part 60, Appendix A–7 of this chapter, or calculate using mass emissions 

rate and electrical output data. 

b. Composite fuel samples .............................. Procedure in § 63.10008(d) or equivalent. 

3. Hydrogen chloride (HCl) ....... a. Collect fuel samples ..................................... Procedure in § 63.10008(c) or D2234/D2234M (for coal) or 

equivalent. 

b. Composite fuel samples .............................. Procedure in § 63.10008(d) or equivalent. 

c. Prepare composited fuel samples ............... EPA SW–846–3020A (for liquid samples), EPA SW–846– 

3050B (for solid samples), or ASTM D2013/D2013M (for 

coal) or equivalent. 

d. Determine heat content of the fuel type ...... ASTM D5865 (for coal) or equivalent. 

e. Determine moisture content of the fuel type ASTM D3173 or equivalent. 

f. Measure chlorine concentration in fuel sample.EPA SW–846–9250 or ASTM D6721 (for coal) or equivalent, 

or EPA SW–846–9250 or ASTM E776 (for solid or liquid 

samples) or equivalent. 

g. Convert concentrations into units of pounds 

of pollutant per MMBtu of heat content or lb 

per MWh.

Method 19 F-factor methodology at 40 CFR part 60, Appendix A–7 of this chapter, or calculate using mass emissions 

rate and electrical output data. 

4. Hydrogen fluoride (HF) ......... a. Collect fuel samples ..................................... Procedure in § 63.10008(c) or D2234/D2234M (for coal) or 

equivalent. 

b. Composite fuel samples .............................. Procedure in § 63.10008(d) or equivalent. 

c. Prepare composited fuel samples ............... EPA SW–846–3020A (for liquid samples), EPA SW–846– 

3050B (for solid samples), or ASTM D2013/D2013M (for 

coal) or equivalent. 

d. Determine heat content of the fuel type ...... ASTM D5865 (for coal) or equivalent. 

e. Determine moisture content of the fuel type ASTM D3173 or equivalent. 

f. Measure chlorine concentration in fuel sample.EPA SW–846–9250 or ASTM D6721 (for coal) or equivalent, 

or EPA SW–846–9250 or ASTM E776 (for solid or liquid 

samples) or equivalent. 

g. Convert concentrations into units of pounds 

of pollutant per MMBtu of heat content.

Method 19 F-factor methodology at 40 CFR part 60, Appendix A–7 of this chapter. 

As stated in § 63.10007, you must 

comply with the following requirements 

for establishing operating limits: 


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TABLE 7 TO SUBPART UUUUU OF PART 63—ESTABLISHING OPERATING LIMITS

If you have an applicable 

emission limit for . . . 

And your operating limits 

are based on . . . You must . . . Using . . . According to the following requirements 

1. Particulate matter (PM), 

mercury (Hg), or other 

non-Hg HAP metals.

a. Wet scrubber operating 

parameters.

i. Establish a site-specific 

minimum pressure drop 

and minimum flow rate 

operating limit according 

to § 63.10011(c).

(1) Data from the pressure 

drop and liquid flow rate 

monitors and the PM, 

Hg, or other non-Hg 

HAP metals performance test.

(a) You must collect pressure drop and liquid 

flow-rate data every 15 

minutes during the entire 

period of the performance tests; 

(b) Determine the average 

hourly pressure drops 

and liquid flow rates for 

each individual test run 

in the three-run performance test by computing 

the average of all the 

15-minute readings 

taken during each test 

run. 

b. Electrostatic precipitator 

operating parameters 

(option only for units that 

operate wet scrubbers).

i. Establish a site-specific 

secondary power input 

according to 

§ 63.10011(c).

(1) Data from the secondary power input during the PM, Hg, or other 

non-Hg HAP metals performance test.

(a) You must collect secondary voltage and current and calculate total 

ESP secondary power 

input data every 15 minutes during the entire 

period of the performance tests; 

(b) Determine the average 

hourly total secondary 

power inputs for each individual test run in the 

three-run performance 

test by computing the 

average of all the 15- 

minute readings taken 

during each test run. 

c. Filterable PM results obtained from performance 

testing and are measured continuously using 

PM CEMS.

i. Establish a site-specific 

filterable PM concentration according to 

§ 63.10011(d).

(1) Data from the PM performance test.(a) You must collect at 

least 3 test runs of 

Method 5 filterable PM 

results. 

2. Hydrogen chloride (HCl) 

or hydrogen fluoride 

(HF).

a. Wet scrubber operating 

parameters.

i. Establish a site-specific 

minimum pH and flow 

rate operating limits according to § 63.10011(c).

(1) Data from the pH and 

liquid flow rate monitors 

and the HCl performance test.

(a) You must collect pH 

and liquid flow rate data 

every 15 minutes during 

the entire period of the 

performance tests; 

(b) Determine the average 

hourly pH liquid flow 

rates for each individual 

test run in the three-run 

performance test by 

computing the average 

of all the 15-minute 

readings taken during 

each test run. 

b. Dry scrubber or DSI operating parameters.i. Establish a site-specific 

minimum sorbent injection rate operating limit 

according to 

§ 63.10011(c). If different 

acid gas sorbents are 

used during the HCl performance test, the average value for each sorbent becomes the sitespecific operating limit 

for that sorbent.

(1) Data from the sorbent 

injection rate monitors 

and HCl or Hg performance test.

(a) You must collect sorbent injection rate data 

every 15 minutes during 

the entire period of the 

performance tests; 

(b) Determine the average 

hourly sorbent injection 

rates of the three test 

run averages measured 

during the performance 

test. 

As stated in § 63.10021, you must 

show continuous compliance with the 

emission limitations for affected sources 

according to the following: 


jlentini on DSKJ8SOYB1PROD with PROPOSALS2
25134 Federal Register / Vol. 76, No. 85 / Tuesday, May 3, 2011 / Proposed Rules 

TABLE 8 TO SUBPART UUUUU OF PART 63—DEMONSTRATING CONTINUOUS COMPLIANCE

If you must meet the following operating limits 

or work practice standards . . . You must demonstrate continuous compliance by . . . 

1. Fabric filter bag leak detection operation ....... Installing and operating a bag leak detection system according to § 63.10010 and operating 

the fabric filter such that the requirements in § 63.10021(a)(9) are met. 

2. Wet PM scrubber pressure drop and liquid 

flow-rate.

a. Collecting the pressure drop and liquid flow rate monitoring system data according to 

§§ 63.10010 and 63.10020; and 

b. Reducing the data to 12-hour block averages; and 

c. Maintaining the 12-hour average pressure drop and liquid flow-rate at or above the operating limits established during the performance test according to § 63.10011(c). 

3. Wet acid gas scrubber pH and liquid flow 

rate.

a. Collecting the pH and liquid flow rate monitoring system data according to §§ 63.10010 and 

63.10020; and 

b. Reducing the data to 12-hour block averages; and 

c. Maintaining the 12-hour average pH and liquid flow-rate at or above the operating limits established during the performance test according to § 63.10011(c). 

4. Dry scrubber or DSI sorbent or carbon injection rate.a. Collecting the sorbent or carbon injection rate monitoring system data for the dry scrubber 

or DSI according to §§ 63.10010 and 63.10020; and 

b. Reducing the data to 12-hour block averages; and 

c. Maintaining the 12-hour average sorbent or carbon injection rate at or above the operating 

limit established during the performance test according to § 63.10011(c). 

5. Electrostatic precipitator secondary power 

input.

a. Collecting the secondary power input monitoring system data for the electrostatic precipitator according to §§ 63.10010 and 63.10020; and 

b. Reducing the data to 12-hour block averages; and 

c. Maintaining the 12-hour average secondary power input at or above the operating limits established during the performance test according to § 63.10011(c). 

6. Fuel pollutant content ..................................... a. Only burning the fuel types and fuel mixtures used to demonstrate compliance with the applicable emission limit according to § 63.10011(c) or (d) as applicable; and 

b. Keeping monthly records of fuel use according to § 63.10021(a). 

7. Filterable PM as measured by PM CEMS ..... a. Collecting the PM concentration data using a PM CEMS installed, operated and maintained 

in accordance with PS 11 at 40 CFR part 60, Appendix B of this chapter and QA Procedure 

5 at 40 CFR part 60, Appendix F of this chapter; 

b. Converting hourly emissions concentrations to 30 boiler operating mg/dscm values; and 

c. Maintaining the 30 boiler operating day rolling average mg/dscm values below the operating 

limits established during the performance test according to § 63.10011(d). 

As stated in § 63.10031, you must 

comply with the following requirements 

for reports: 

TABLE 9 TO SUBPART UUUUU OF PART 63—REPORTING REQUIREMENTS

You must submit a(n) The report must contain . . . You must submit the report . . . 

1. Compliance report ....................... a. Information required in § 63.10031(c)(1) through (11) through (11); 

and 

Semiannually according to the requirements in § 63.10031(b). 

b. If there are no deviations from any emission limitation (emission 

limit and operating limit) that applies to you and there are no deviations from the requirements for work practice standards in Table 8 

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 

c. If you have a deviation from any emission limitation (emission limit 

and operating limit) or work practice standard during the reporting 

period, the report must contain the information in § 63.10031(d). If 

there were periods during which the CMSs, including continuous 

emissions monitoring system, and operating parameter monitoring 

systems, were out-of-control, as specified in § 63.8(c)(7), the report 

must contain the information in § 63.10031(e); and 

d. If you had a startup, shutdown, or malfunction during the reporting 

period and you took actions consistent with your startup, shutdown, 

and malfunction plan, the compliance report must include the information in § 63.10(d)(5)(i).


jlentini on DSKJ8SOYB1PROD with PROPOSALS2
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TABLE 9 TO SUBPART UUUUU OF PART 63—REPORTING REQUIREMENTS—Continued 

You must submit a(n) The report must contain . . . You must submit the report . . . 

2. An immediate startup, shutdown, 

and malfunction report if you had 

a startup, shutdown, or malfunction during the reporting period 

that is not consistent with your 

startup, shutdown, and malfunction plan, and the source exceeds any applicable emission 

limitation in the emission standard.

a. Actions taken for the event; and ....................................................... i. By fax or telephone within 2 

working days after starting actions inconsistent with the plan; 

and 

b. The information in § 63.10(d)(5)(ii) .................................................... ii. By letter within 7 working days 

after the end of the event unless 

you have made alternative arrangements with the permitting 

authority. 

As stated in § 63.10040, you must 

comply with the applicable General 

Provisions according to the following: 

TABLE 10 TO SUBPART UUUUU OF PART 63—APPLICABILITY OF GENERAL PROVISIONS TO SUBPART UUUUU 

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 .................................

63.8(c)(1)(i) ........................................................ General duty to minimize emissions and CMS 

operation.

§ 63.8(c)(1)(iii) .................................................... Requirement to develop SSM Plan for CMS ... No. 

§ 63.8(d)(3) ........................................................ Written procedures for CMS ............................ Yes, except for last sentence, which refers to 

an SSM plan. SSM plans are not required. 

§ 63.9 ................................................................. Notification Requirements ................................ Yes. 

§ 63.10(a), (b)(1), (c), (d)(1)–(2), (e), and (f) ..... Recordkeeping and Reporting Requirements .. Yes. 

§ 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. 


jlentini on DSKJ8SOYB1PROD with PROPOSALS2
25136 Federal Register / Vol. 76, No. 85 / Tuesday, May 3, 2011 / Proposed Rules 

TABLE 10 TO SUBPART UUUUU OF PART 63—APPLICABILITY OF GENERAL PROVISIONS TO SUBPART UUUUU— 

Continued 

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 63.10031(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. The monitoring, recordkeeping, 

and reporting provisions of this appendix 

shall be considered to be met to the extent 

that they have already been, and are 

continuing to be, met or exceeded under 

another Federal or State program. 

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 the CEMS 

fails to produce quality-assured Hg mass 

emissions data is counted as an hour of 

monitoring system downtime. 

2. Monitoring of Hg Emissions for Various 

Configurations 

2.1 Single Unit-Single Stack 

Configuration. For an affected unit that 

exhausts to the atmosphere through a single, 

dedicated stack, the owner or operator shall 

install, certify, maintain, and operate a Hg 

CEMS or a sorbent trap monitoring system 

and any other necessary monitoring 

components needed to express the measured 

Hg emissions in the units of the applicable 

emissions standard, in accordance with 

section 3.2 of this appendix. 

2.2 Unit Utilizing Common Stack with 

Other Affected Unit(s). When an affected unit 

utilizes a common stack with one or more 

other affected units, but no non-affected 

units, the owner or operator shall either: 

2.2.1 Install, certify, maintain, and 

operate the monitoring systems described in 

paragraph 2.1 of this section in the duct to 

the common stack from each unit; or 

2.2.2 Install, certify, maintain, and 

operate the monitoring systems described in 

paragraph 2.1 of this section in the common 

stack. 

2.3 Unit Utilizing Common Stack with 

Non-affected Units. When one or more 

affected units shares a common stack with 

one or more non-affected units, the owner or 

operator shall either: 

2.3.1 Install, certify, maintain, and 

operate the monitoring systems described in 

paragraph 2.1 of this section in the duct to 

the common stack from each affected unit; or 

2.3.2 Install, certify, maintain, and 

operate the monitoring systems described in 

paragraph 2.1 of this section in the common 

stack and attribute all of the Hg emissions 

measured at the common stack to the affected 

unit(s). 

2.4 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, the owner and operator shall 

either: 

2.4.1 Install, certify, maintain, and 

operate the monitoring systems described in 

paragraph 2.1 of this section on both the 

main stack and the bypass stack; or 

2.4.2 Install, certify, maintain, and 

operate the monitoring systems described in 

paragraph 2.1 of this section only on the 

main stack, and report the maximum 

potential Hg concentration (as defined in 

section 3.2.1.4.1 of this appendix) for each 

unit operating hour in which the bypass 

stack is used. 

2.5 Unit with Multiple Stack or Duct 

Configuration. If the flue gases from an 

affected unit either: are discharged to the 

atmosphere through more than one stack; or 

are fed into a single stack through two or 

more ducts and the owner or operator 

chooses to monitor in the ducts rather than 

in the stack, the owner or operator shall 

either: 

2.5.1 Install, certify, maintain, and 

operate the monitoring systems described in 

paragraph 2.1 of this section in each of the 

multiple stacks; or 

2.5.2 Install, certify, maintain, and 

operate the monitoring systems described in 

paragraph 2.1 of this section in each of the 

ducts that feed into the stack. 

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). 

3.1.2 Sorbent Trap Monitoring System 

means the equipment required to monitor Hg 

emissions continuously, 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 rate 

proportional to the stack gas volumetric flow 


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rate. The sampling is a batch process. The 

average Hg concentration in the stack gas for 

the sampling period is determined, in units 

of micrograms per dry standard cubic meter 

(μg/dscm), based on the sample volume 

measured by the gas flow meter and the mass 

of Hg collected in the sorbent traps. 

3.1.3 NIST means the National Institute 

of Standards and Technology, located in 

Gaithersburg, Maryland. 

3.1.4 NIST-traceable elemental Hg 

standards means either: compressed gas 

cylinders having known concentrations of 

elemental Hg, which have been prepared 

according to the ‘‘EPA Traceability Protocol 

for Assay and Certification of Gaseous 

Calibration Standards’’; or calibration gases 

having known concentrations of elemental 

Hg, produced by a generator that meets the 

performance requirements of the ‘‘EPA 

Traceability 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 known 

concentration of a gaseous species that is 

produced and certified in accordance with an 

EPA traceability protocol. 

3.1.7 Span value means a conservatively 

high estimate of the gas concentrations or 

stack gas flow rates to be measured by a 

CEMS. For a Hg pollutant concentration 

monitor, the span value should be set to 

approximately twice the concentration 

corresponding to the emission standard, 

rounded off as appropriate. 

3.1.8 Zero-Level Gas means calibration 

gas with a concentration that is below the 

level detectable by a gas monitoring system. 

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 either to assess the ability of a gas 

monitor to measure the concentrations of 

calibration gases accurately, or the ability of 

a flow monitor to read electronic reference 

signals accurately. A zero-level gas (or signal) 

and an upscale gas (or signal) are required for 

this test. For gas monitors, either a mid-level 

gas or a high-level gas may be used. For a 

flow monitor, an upscale signal of 50 to 70 

percent of the calibration span value is 

required. For a Hg CEMS, the upscale 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 gas analyzer is linear across its 

measurement range. Three calibration gas 

standards (i.e., low, mid, and high-level 

gases) are required for this test. For a Hg 

CEMS, elemental Hg calibration standards 

are required. 

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 gas monitor, 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. For a Hg 

CEMS, the high-level 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 

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 Unit Operating Day means a 

calendar day in which a unit combusts any 

fuel. 

3.1.20 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, 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 may be constructed of any 

material that is non-reactive to the gas being 

sampled. 

3.2.1.1.3.6 Calibration Gas System(s). 

Design and equip each Hg monitor 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 a converter, 

to a by-pass valve (for Hg speciating systems), 

or to 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 detectable limit of the 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 represents the emissions 

exiting to the atmosphere; and at which it is 

likely that the CEMS can pass the relative 

accuracy test. 

3.2.1.4 Monitor Span and Range 

Requirements. Determine the appropriate 

span and range value(s) for the Hg CEMS as 

described in paragraphs 3.2.1.4.1 through 

3.2.1.4.3 of this section. 

3.2.1.4.1 Maximum Potential 

Concentration. There are three options for 

determining the maximum potential Hg 

concentration (MPC). Option 1 applies to 

coal combustion. You may use a default 

value of 10 μg/scm for all coal ranks 

(including coal refuse) except for lignite; for 

lignite, use 16 μg/scm. Option 2 is to base the 

MPC on the results of site-specific Hg 

emission testing. This option may be used 

only if the unit does not have add-on Hg 

emission controls or a flue gas 

desulfurization system, or if testing is 

performed upstream of all emission control 

devices. If Option 2 is selected, perform at 

least three test runs at the normal operating 

load, and the highest Hg concentration 

obtained in any of the tests shall be the MPC. 

If different coals are blended as part of 

normal operation, use the highest MPC for 

any fuel in the blend. 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 μg/scm, use the result as the span value. 

Otherwise, round off the result to the next 

highest integer. Alternatively, you may round 

off the span value to the next highest 

multiple of 10 μg/scm. 

3.2.1.4.3 Full-Scale Range. The full-scale 

range of the Hg analyzer output must include 

the MPC. 

3.2.2 Sorbent Trap Monitoring System. A 

sorbent trap monitoring system (as defined in 

paragraph 3.1.2 of this section) may be used 

as an alternative to a Hg CEMS. If this option 

is selected, the monitoring system shall be 

installed, maintained, and operated in 

accordance with Performance Specification 

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 Monitoring 

Systems. When the applicable Hg emission 

limit is specified in units of lb/TBtu or lb/ 

GWh, some or all of the monitoring systems 

described in paragraphs 3.2.3.1 and 3.2.3.2 of 

this section will be needed to convert the 

measured Hg concentrations to the units of 

the emissions standard. These additional 

monitoring systems shall be installed, 

certified, maintained, operated, and qualityassured according to the applicable 

provisions of this appendix (see section 4.1.3 

of this appendix). 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 

(e.g., 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 

accounted for, as follows: 

3.2.3.1.1 Determine the stack gas 

moisture content using a certified continuous 

moisture monitoring system; or 

3.2.3.1.2 Use the moisture value 

determined during the most recent Hg 

emissions test while combusting the fuel type 

currently in use; or 

3.2.3.1.3 For coal combustion, use a fuelspecific moisture default value. For 

anthracite coal, use 3.0% H2O; for 

bituminous coal, use 6.0% H2O; for subbituminous coal, use 8.0% H2O; and for 

lignite, use 11.0% H2O. 

3.2.3.2 Electrical Output-Based Emission 

Rates. If the applicable Hg limit is electrical 

output-based (e.g., lb/GWh), hourly electrical 

load data and unit operating times are 

required in addition to hourly data from a 

certified flow rate monitor and (if applicable) 

moisture data. 

3.2.3.3 Span and Range of Flow Rate, 

Diluent Gas, and Moisture Monitors. Set the 

span value of a CO2 or O2 monitor at 1.00 to 

1.25 times the maximum potential 

concentration. Set the span value of a flow 

rate monitor at 1.00 to 1.25 times the 

maximum potential flow rate, in units of 

standard cubic feet per hour (scfh). If the 

units of measure for daily calibrations of the 

flow monitor are not expressed in scfh, 

convert the calculated span value from scfh 

to an equivalent ‘‘calibration span value’’ in 

the units of measure actually used for daily 

calibrations. Set the full-scale range of the 

CO2, O2, and flow monitors such that the 

majority of the data will fall between 20 and 

80% of full-scale. For a continuous moisture 

sensor, there is no span value requirement; 

set up and operate the instrument according 

to the manufacturer’s instructions. 

4. Certification and Recertification 

Requirements 

4.1 Certification Requirements. All Hg 

CEMS and sorbent trap systems and the 

monitoring systems used to continuously 

measure Hg emissions in units of the 

applicable emissions standard in accordance 

with this appendix must be certified prior to 

the applicable compliance date specified in 

§ 63.9984. 

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. 

4.1.1.1 7-Day Calibration Error Test. 

Perform the 7-day calibration error test on 7 

consecutive operating days, using a zerolevel gas and either a high-level or a midlevel 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 each monitor 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. 


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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.

| 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. 

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/m3, 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 ¥. 

4.1.1.2 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 

each monitor at its normal operating 

temperature and conditions. 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. 

If moisture and/or chlorine is added to the 

calibration gas, the dilution effect of the 

moisture and/or chlorine addition on the 

calibration gas concentration must be 

accounted for in an appropriate manner. 

Record the monitor response from the data 

acquisition and handling system for each gas 

injection. At each concentration level, use 

the average analyzer response to calculate the 

linearity error (LE), as described in Table A– 

1. The LE must either meet the main 

performance specification or the alternative 

specification in Table A–1. 

4.1.1.3 Three-Level System Integrity 

Check. Perform the 3-level system integrity 

check using low, mid, and high-level 

calibration gas concentrations generated by a 

NIST-traceable 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–2. 

(Note: This test is not required if the CEMS 

does not have a converter). 

4.1.1.4 Cycle Time Test. Perform the 

cycle time test, using a zero-level gas and a 

high-level calibration gas. Either an 

elemental or oxidized NIST-traceable Hg 

standard may be used as the high-level gas. 

Perform the test in two stages—upscale and 

downscale. The slower of the upscale and 

downscale response times is the cycle time 

for the CEMS. Begin each stage of the test by 

injecting calibration gas after achieving a 

stable reading of the stack emissions. The 

cycle time is the amount of time it takes for 

the analyzer to register a reading that is 95 

percent of the way between the stable stack 

emissions reading and the final, stable 

reading of the calibration gas concentration. 

Use the following criterion to determine 

when a stable reading of stack emissions or 

calibration gas has been attained—the 

reading is stable if it changes by no more 

than 2.0 percent of the span value or 0.5 μg/ 

scm (whichever is less restrictive) for two 

minutes. 

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 (the Ontario Hydro Method) and 

Methods 29, 30A, and 30B in appendix A– 

8 to part 60 of this chapter. When Method 29 

or the Ontario Hydro Method is used, paired 

sampling trains are required. To validate a 

Method 29 or Ontario Hydro test run, 

calculate the relative deviation (RD) using 

Equation A–1 of this section, and assess the 

results as follows to validate the run. The RD 

must not exceed 10 percent, when the 

average Hg concentration is greater than 1.0 

μg/dscm. If the average concentration is ≤1.0 

μg/dscm, the RD must not exceed 20 percent. 

The RD results are also acceptable if the 

absolute difference between the two Hg 

concentrations does not exceed 0.03 μg/ 

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’’ (μg/ 

dscm) 

Cb = Hg concentration of Hg sample ‘‘b’’ (μg/ 

dscm) 

4.1.1.5.1 Special Considerations. Special 

Considerations. A minimum of nine valid 

test runs must be performed, directly 

comparing the CEMS measurements to the 

reference method. If 12 or more runs are 

performed, you may discard the results from 

a maximum of three runs for calculating 

relative accuracy. The minimum time per run 

is 21 minutes if Method 30A is used. If the 

Ontario Hydro Method, Method 29, or 

Method 30B 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 the 

Ontario Hydro Method or Method 29 is used, 

in which case up to 336 operating hours may 

be taken to finish the test. 

4.1.1.5.2 Calculation of RATA Results. 

Calculate the relative accuracy (RA) of the 

monitoring system, on a μg/scm basis, as 

described in section 12 of Performance 

Specification 2 or 6 in Appendix B to part 

60 of this chapter. The CEMS must either 

meet the main performance specification or 

the alternative specification in Table A–1. 


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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 system are listed in 

paragraph 4.1.1.5 of this section. 

4.1.2.2 Special Considerations. The 

special considerations specified in paragraph 

4.1.1.5.1 of this section apply to the RATA 

of a sorbent trap monitoring system. During 

the RATA, the monitoring system must be 

operated and quality-assured in accordance 

with Performance Specification 12B in 

Appendix B to part 60 of this chapter. The 

type of sorbent material used by the traps 

during the RATA must be the same as for 

daily operation of the monitoring system; 

however, the size of the traps used for the 

RATA may be smaller than the traps used for 

daily operation of the system. 

4.1.2.3 Calculation of RATA Results. 

Calculate the relative accuracy (RA) of the Hg 

concentration monitoring system, on a μg/ 

scm basis, as described in section 12 of 

Performance Specification 2 or 6 in appendix 

B to part 60 of this chapter. The main and 

alternative RATA performance specifications 

in Table A–1 for Hg CEMS also apply to the 

sorbent trap monitoring system. 

4.1.2.4 Bias Adjustment. Measurement or 

adjustment of sorbent trap monitoring system 

data for bias is not required. 

4.1.3 Diluent Gas, Flow Rate, and/or 

Moisture Monitoring Systems. Monitoring 

systems that are used to measure stack gas 

volumetric flow rate and/or diluent gas 

concentration and/or stack gas moisture 

content in order to convert Hg concentration 

data to units of the applicable emission limit 

must be certified. The minimum certification 

test requirements and performance 

specifications for these systems are shown in 

Table A–2, below. 

4.2 Recertification. Whenever the owner 

or operator makes a replacement, 

modification, or change to a certified Hg 

CEMS, sorbent trap monitoring system, flow 

rate monitoring system, diluent gas 

monitoring system, or moisture monitoring 

system that may significantly affect the 

ability of the system to accurately measure or 

record the Hg concentration, stack gas 

volumetric flow rate, CO2 concentration, O2

concentration, 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 flow or 

concentration 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. 

TABLE A–2—MINIMUM REQUIRED CERTIFICATION TESTS AND PERFORMANCE SPECIFICATIONS FOR OTHER MONITORING

SYSTEMS

For this required certification test . . . Of this auxiliary monitoring 

system . . . 

The main performance 

specification 1 is . . . 

The alternate performance 

specification 2 is . . . 

And the conditions of the 

alternate specification are 

. . . 

7-day calibration error test O2 or CO2 .......................... | R ¥ A| ≤ 0.5% O2 or 

CO2 for both the zero 

and upscale gases, on 

each day of the test.

7-day calibration error test Flow rate ........................... | R ¥A| ≤ 3.0% of calibration span value for both 

the zero and upscale 

signals, on each day of 

the test.

| R ¥ A| ≤ 0.01 in. H2O, 

for DP-type monitors.

The alternate specification 

may be used on any day 

of the tests. 

Linearity check .................. O2 or CO2 .......................... | R ¥ Aavg | ≤ 5.0% of the 

reference gas value.

| R ¥A| ≤ 0.5% O2 or CO2 The alternate specification 

may be used at any gas 

level. 

Cycle time test ................... O2 or CO2 .......................... ≤ 15 minutes. 

RATA ................................. O2 or CO2 .......................... 10.0% RA .......................... | RMavg ¥ Cavg | ≤ 1.0% O2

or % CO2.

RATA ................................. Flow rate ........................... 10.0% RA. 

RATA ................................. Moisture ............................ 10.0% RA .......................... | RMavg ¥ Cavg | ≤ 1.5% 

H2O.

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 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 ¥. 

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–3, below. 

5.1.2 Test Frequency. The frequency for 

the required QA tests of the Hg CEMS shall 

be as follows: 

5.1.2.1 Perform calibration error tests of 

the Hg CEMS daily. Use either NISTtraceable elemental Hg standards or NISTtraceable oxidized Hg standards for these 

calibrations. A zero-level 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. 


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TABLE A–3—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.

• 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 midor 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 168 unit operating hours. 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. 

5.1.2.3 A weekly single-level system 

integrity check (if required—see third 

column in Table A–3). 

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 stac operating hour 

grace period following that quarter. 

5.1.3 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 of the acceptance 

criteria for the required QA tests in Table A– 

3 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-ofcontrol period, the QA test that was either 

failed or not done on time must be performed 

and passed. 

5.1.4 Grace Periods. 

5.1.4.1 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. 

5.1.4.2 A 720 unit or stack operating hour 

grace period is available for RATAs of the Hg 

CEMS. 

5.1.4.3 There is no grace period for 

weekly system integrity checks. The test 

must be completed once every 168 unit or 

stack operating hours. 

5.1.5 Adjustment of Span. If the Hg 

concentration readings exceed the span value 

for a significant percentage of the unit 

operating hours in a calendar quarter, make 

any necessary adjustments to the MPC and 

span value. A diagnostic linearity check is 

required within 168 unit or stack operating 

hours after changing the span value. 

5.2 Sorbent Trap Monitoring Systems. 

5.2.1 Each sorbent trap monitoring 

system shall be continuously operated and 

maintained in accordance with Performance 

Specification 12B (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. 

5.2.2.2 The same RATA performance 

criteria specified in Table A–3 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. 

5.2.2.4 Data validation for RATAs of the 

system shall be done in accordance with 

paragraph 5.1.3 of this section. 

5.3 Flow Rate, Diluent Gas, and Moisture 

Monitoring Systems. The minimum on-going 

QA test requirements for these monitoring 

systems are summarized in Table A–4, 

below. The data validation provisions in 

paragraph 5.1.3 apply to these systems. The 

linearity grace period described in paragraph 

5.1.4.1 applies to the O2 and CO2 monitors. 

The RATA grace period in paragraph 5.1.4.2 

of this section applies to the O2, CO2, 

moisture, and flow rate monitors. 

5.4 QA/QC Program for Continuous 

Monitoring Systems. The owner or operator 

shall develop and implement a quality 

assurance/quality control (QA/QC) program 

for all continuous monitoring systems that 


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are used to provide data under this subpart 

(i.e., all Hg CEMS, sorbent trap monitoring 

systems, and any associated monitoring 

systems used to convert Hg concentration 

data to the appropriate units of measure). 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. 

TABLE A–4—MINIMUM ON-GOING QUALITY ASSURANCE TEST REQUIREMENTS FOR AUXILIARY MONITORING SYSTEMS

Perform this QA test . . . For this monitoring 

system . . . At this frequency . . . With these conditions and exceptions . . . 

The acceptance criteria 

are . . . 

Calibration error test .......... O2 or CO2 .......................... Daily .................................. • Use either a mid or high 

level gas.

| R ¥ A| ≤ 1.0% O2 or 

CO2. 

• Not required on non-operating days.

Calibration error test .......... Flow rate ........................... Daily .................................. • Not required on non-operating days.| R ¥ A| ≤ 6.0% of calibration span value or | R ¥ 

A| ≤ 0.02 in. H2O for a 

DP-type monitor. 

Interference check ............. Flow rate ........................... Daily .................................. • Not required on non-operating days.Must be passed. 

Linearity check .................. O2 or CO2 .......................... Quarterly ........................... • Required in each QA 

operating quarter—but 

no less than once every 

4 calendar quarters.

| R ¥ A| ≤ 5.0% of reference gas or | R ¥ A| 

≤ 1.0% O2 or CO2. 

• 168 operating hour 

grace period available.

Leak check ........................ Flow rate ........................... Quarterly ........................... • Required only for DPtype flow monitors.Must be passed. 

RATA ................................. O2 or CO2 .......................... Annual *** .......................... • Once every four QA operating quarters, not to 

exceed 8 calendar quarters.

RA ≤ 7.5%; or | RMavg ¥ 

Cavg | ≤ 0.7% O2 or CO2. 

RATA ................................. Flow rate ........................... Annual *** .......................... • Once every four QA operating quarters, not to 

exceed 8 calendar quarters.

RA ≤ 7.5%. 

RATA ................................. Moisture ............................ Annual *** .......................... • Once every four QA operating quarters, not to 

exceed 8 calendar quarters.

RA ≤ 7.5%; or | RMavg ¥ 

Cavg | ≤ 1.0% H2O. 

*** Note that these RATAs can still be passed at RA percentages up to and including 10.0% RA. Alternate specifications of | R ¥ A| ≤ 1.0% O2

or CO2 and | R ¥ A| ≤ 1.5% H2O are also acceptable. However, for all of these acceptance criteria, the test frequency becomes semiannual (i.e., 

once every two QA operating quarters) monitors. The RATA grace period in paragraph 5.1.4.2 of this section applies to the O2, CO2, and flow 

rate monitors. 

5.4.1 General Requirements. 

5.4.1.1 Preventive Maintenance. Keep a 

written record of procedures needed to 

maintain the monitoring system 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. 

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 monitoring 

system in a location and format suitable for 

inspection. A maintenance log may be used 

for this purpose. The following records 

should be maintained: date, time, and 

description of any testing, adjustment, repair, 

replacement, or preventive maintenance 

action performed on any monitoring system 

and records of any corrective actions 

associated with a monitor outage period. 

Additionally, any adjustment that may 

significantly affect a system’s ability to 

accurately measure emissions data must be 

recorded (e.g., changing of flow monitor 

polynomial coefficients or K factors, 

changing the dilution ratio of a gas monitor, 

etc.), and a written explanation of the 

procedures used to make the adjustment(s) 

shall be kept. 

5.4.2 Specific Requirements for Hg CEMS, 

Flow Rate, Diluent Gas, and Moisture 

Monitoring Systems. 

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 and all 

associated monitoring systems. If moisture 

and/or chlorine is added to the Hg calibration 

gas, explain how the dilution effect of the 

moisture and/or chlorine addition on the 

calibration gas concentration is accounted 

for. Also keep records of the procedures used 

to perform linearity checks (of the Hg CEMS 

and, if applicable, the CO2 or O2 monitor) 

and the procedures for system integrity 

checks of the Hg CEMS. Explain how the test 

results are calculated and evaluated. 

5.4.2.2 Monitoring System Adjustments. 

Explain how each component of the 

continuous emission monitoring system will 

be adjusted to provide correct responses to 

calibration gases or reference signals 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 monitoring systems. Indicate 

the reference methods used and explain 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 tracking 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. Explain the procedures used to 

perform the leak checks when a sorbent trap 

is placed in service and removed from 

service. Also explain 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 


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control criteria in Table 12B–1 in section 9.0 

of Performance Specification 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 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. Include in 

the discussion 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 and 

(as applicable) flow rate, diluent gas, and 

moisture monitoring systems 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. 

6.1.4 Operating hours in which valid data 

are not obtained, either for Hg concentration 

or for another parameter, are considered to be 

hours of monitor downtime. 

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 μg/ 

scm to lb/scf. 

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 If the heat input-based Hg 

emission rate limit must be met over a 

specified averaging period (e.g., a 30 boiler 

operating day rolling average), use Equation 

19–19 in EPA Method 19 to calculate the Hg 

emission rate for each averaging period. 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 First, 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 wetbasis measurements of Hg concentration) or 

Equation A–3 of this section (for dry-basis 

measurements), as applicable: 

Where: 

Mh = Hg mass emissions for the hour (lb) 

K = Units conversion constant, 6.236 × 10¥11

lb-scm/μg-scf 

Ch = Hourly average Hg concentration, wet 

basis (μg/scm) 

Qh = Stack gas volumetric flow rate for the 

hour (scfh). (Note: Use unadjusted flow 

rate values; bias adjustment is not 

required) 

th = Unit or stack operating time, fraction of 

the clock hour, expressed as a decimal. 

For example, th = 1.00 for a full operating 

hour, 0.50 for 30 minutes of operation, 

0.00 for a non-operating hour, etc.) or 

Where: 

Mh = Hg mass emissions for the hour (lb) 

K = Units conversion constant, 6.236 × 10¥11

lb-scm/μg-scf 

Ch = Hourly average Hg concentration, dry 

basis (μg/dscm) 

Qh = Stack gas volumetric flow rate for the 

hour (scfh). (Note: Use unadjusted flow 

rate values; bias adjustment is not 

required) 

th = Unit or stack operating time, fraction of 

the clock hour, expressed as a decimal. 

For example, th = 1.00 for a full operating 

hour, 0.50 for 30 minutes of operation, 

0.00 for a non-operating hour, etc.) 

Bws = Moisture fraction of the stack gas, 

expressed as a decimal (equal to %H2O/ 

100) 

6.2.2.2 Next, 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 emissions for the hour, from 

Equation A–2 or A–3 of this section, as 

applicable (lb) 

(MW)h = Electrical load for the hour, in 

megawatts (MW) 

th = Unit or stack operating time, fraction of 

the hour, expressed as a decimal. For 

example, th = 1.00 for a full operating 

hour, 0.50 for 30 minutes of operation, 

etc.) 

103 = Conversion factor from megawatts to 

gigawatts 

6.2.2.3 If the electrical output-based Hg 

emission rate limit must be met over a 

specified averaging period (e.g., a 30 boiler 

operating day rolling average), use Equation 

A–5 of this section to calculate the Hg 

emission rate for each averaging period. 


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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. The owner 

or operator shall, for each affected unit and 

each non-affected unit under section 2.3 of 

this appendix, 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. The file shall contain 

the information in paragraphs 7.1.1 through 

7.1.10 of this section. 

7.1.1 Monitoring Plan Records. The 

owner or operator of an affected unit shall 

prepare and maintain a monitoring plan for 

each affected unit or group of units 

monitored at a common stack and each nonaffected unit under section 2.3 of this 

appendix. The monitoring plan shall contain 

sufficient information on the continuous 

monitoring systems that provide data under 

this subpart, and how the data derived from 

these systems are sufficient to demonstrate 

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 the Hg CEMS, sorbent trap monitoring 

systems, and any flow rate and/or moisture, 

and/or diluent gas monitors used to provide 

data under this subpart, the monitoring plan 

shall contain the following information, as 

applicable: 

7.1.1.2.1 Electronic. Unit or stack IDs; 

monitoring location(s); type(s) of fuel 

combusted; type(s) of emission controls; 

maximum rated unit heat input(s); megawatt 

rating(s); monitoring methodologies used; 

monitoring system information (unique 

system and component ID numbers, 

parameters monitored); formulas used to 

calculate emissions and heat input; unit 

operating ranges and normal load level(s); 

monitor span and range information. 

7.1.1.2.2 Hard Copy. Schematics and/or 

blueprints showing the location of 

monitoring systems 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 each non-affected unit 

under section 2.3 of this appendix, 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: 

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 MWge); 

7.1.2.4 The hourly heat input rate 

(MMBtu/hr, rounded to the nearest tenth); 

7.1.2.5 An identification code for the 

formula used to calculate the hourly heat 

input rate, as provided in the monitoring 

plan; and 

7.1.2.6 The F-factor used for the heat 

input rate calculation. 

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 

(μg/scm, rounded to the nearest tenth); 

7.1.3.4 A special code, indicating 

whether or not a quality-assured Hg 

concentration is obtained for the hour; and 

7.1.3.5 Monitor availability, as a 

percentage of unit or stack operating hours. 

7.1.4 Hg Emissions Records (Sorbent 

Trap Monitoring Systems). For each affected 

unit or common stack using a sorbent trap 

monitoring system, each owner or operator 

shall record the following information for the 

unit or stack operating hour in each data 

collection period: 

7.1.4.1 The date and hour; 

7.1.4.2 Monitoring system and 

component identification codes, as provided 

in the monitoring plan, if the sorbent trap 

system provides a quality-assured value of 

Hg concentration for the hour; 

7.1.4.3 The hourly Hg concentration, if a 

quality-assured value is obtained for the hour 

(μg/scm, rounded to the nearest tenth). Note 

that when a quality-assured Hg concentration 

value is obtained for a particular data 

collection period, that single 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 

12B in Appendix B to part 60 of this chapter; 

and 

7.1.4.8 Data availability, as a percentage 

of unit or stack operating hours. 

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 12B in Appendix B to part 60 

of this chapter). Stack gas flow rate data are 

also needed in order to demonstrate 

compliance with heat input-based and 

electrical output-based Hg emissions limits, 

as provided in sections 6.2.1 and 6.2.2 of this 

appendix. 

7.1.5.2 For each affected unit or common 

stack, if measurements of stack gas flow rate 

are required, use a certified flow rate monitor 

to record the following information for each 

unit or stack operating hour: 

7.1.5.2.1 The date and hour; 

7.1.5.2.2 Monitoring system and 

component identification codes, as provided 

in the monitoring plan, if a quality-assured 

flow rate value is obtained for the hour; 

7.1.5.2.3 The hourly average volumetric 

flow rate, if a quality-assured flow rate value 

is obtained for the hour (in scfh, rounded to 

the nearest thousand); 

7.1.5.2.4 A special code, indicating 

whether or not a quality-assured flow rate 

value is obtained for the hour; and 

7.1.5.2.5 Monitor availability, as a 

percentage of unit or stack operating hours. 

7.1.6 Records of Stack Gas Moisture 

Content. 

7.1.6.1 Correction of Hg concentration 

data for moisture is sometimes required, 

when compliance with an applicable Hg 

emissions limit must be demonstrated, as 

provided in sections 6.2.1 and 6.2.2 of this 

appendix. In particular, these corrections are 

required for sorbent trap monitoring systems 

and for Hg CEMS that measure Hg 

concentration on a dry basis. 

7.1.6.2 If moisture corrections are 

required, use a certified moisture monitoring 

system to record the following information 

for each unit or stack operating hour (except 


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where a default moisture value is used; in 

that case, keep a record of the default value 

currently in use): 

7.1.6.2.1 The date and hour; 

7.1.6.2.2 Monitoring system and 

component identification codes for the 

system, as provided in the monitoring plan, 

if a quality-assured moisture value is 

obtained for the hour; 

7.1.6.2.3 Hourly average moisture content 

of the flue gas (percent H2O, rounded to the 

nearest tenth). If the continuous moisture 

monitoring system consists of wet- and drybasis oxygen analyzers, also record both the 

wet- and dry-basis oxygen hourly averages 

(in percent O2, rounded to the nearest tenth); 

7.1.6.2.4 A special code, indicating 

whether or not a quality-assured moisture 

value is obtained for the hour; and 

7.1.6.2.5 Monitor availability, as a 

percentage of unit or stack operating hours. 

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 (e.g., in units of 

lb/TBtu), hourly measurements of CO2 or O2

concentration are required, in order to 

calculate hourly heat input values. 

7.1.7.2 For each affected unit or common 

stack, if measurements of diluent gas 

concentration are required, use a certified 

CO2 or O2 monitor to record the following 

information for each unit or stack operating 

hour: 

7.1.7.2.1 The date and hour; 

7.1.7.2.2 Monitoring system and 

component identification codes, as provided 

in the monitoring plan, if a quality-assured 

O2 or CO2 concentration is obtained for the 

hour; 

7.1.7.2.3 The hourly average O2 or CO2

concentration (in percent, rounded to the 

nearest tenth); 

7.1.8.2.4 A special code, indicating 

whether or not a quality-assured O2 or CO2

concentration value is obtained for the hour; 

and 

7.1.7.2.5 Monitor availability, as a 

percentage of unit or stack operating hours. 

7.1.8 Hg Mass Emissions Records. When 

compliance with a Hg emission limit in units 

of lb/GWh is required, Hg mass emissions 

must be calculated. In such cases, record the 

following information for each operating 

hour of affected unit or common stack: 

7.1.8.1 The date and hour; 

7.1.8.2 The calculated hourly Hg mass 

emissions, from Equation A–2 or A–3 in 

section 6.2.2 of this appendix (lb, rounded to 

three decimal places), if valid values of Hg 

concentration, stack gas volumetric flow rate, 

and (if applicable) moisture data are all 

obtained for the hour; 

7.1.8.3 An identification code for the 

formula (either Equation A–2 or A–3 in 

section 6.2.2 of this appendix) used to 

calculate hourly Hg mass emissions from Hg 

concentration, flow rate and (if applicable) 

moisture data; and 

7.1.8.4 A code indicating that the Hg 

mass emissions were not calculated for the 

hour, if valid data for Hg concentration, flow 

rate, and/or moisture (as applicable) are not 

obtained for the hour. 

7.1.9 Hg Emission Rate Records. For 

applicable Hg emission limits in units of lb/ 

TBtu or lb/GWh, record the following 

information for each affected unit or common 

stack: 

7.1.9.1 The date and hour; 

7.1.9.2 The hourly Hg emissions rate (lb/ 

TBtu or lb/GWh, as applicable, rounded to 

three decimal places), if valid values of Hg 

concentration and all other required 

parameters (stack gas volumetric flow rate, 

diluent gas concentration, electrical load, and 

moisture data, as applicable) are obtained for 

the hour; 

7.1.9.3 An identification code for the 

formula (either the selected equation from 

Method 19 in section 6.2.1 of this appendix 

or Equation A–4 in section 6.2.2 of this 

appendix) used to derive the hourly Hg 

emission rate from Hg concentration, flow 

rate, electrical load, diluent gas 

concentration, and moisture data (as 

applicable); and 

7.1.9.4 A code indicating that the Hg 

emission rate was not calculated for the hour, 

if valid data for Hg concentration and/or any 

of the other necessary parameters are not 

obtained for the hour. 

7.1.10 Certification and Quality 

Assurance Test Records. For the continuous 

monitoring systems used to provide data 

under this subpart at each affected unit (or 

group of units monitored at a common stack) 

and each non-affected unit under section 2.3 

of this appendix, record the following 

certification and quality-assurance 

information: 

7.1.10.1 The reference values, monitor 

responses, and calculated calibration error 

(CE) values, for all required 7-day calibration 

error tests and daily calibration error tests of 

all volumetric flow rate monitors and gas 

monitors, including Hg CEMS; 

7.1.10.2 The results (pass/fail) of the 

required daily interference checks of flow 

monitors; 

7.1.10.3 The reference values, monitor 

responses, and calculated linearity error (LE) 

or system integrity error (SIE) values for all 

required linearity checks of all gas monitors, 

including Hg CEMS, and for all single-level 

and 3-level system integrity checks of Hg 

CEMS; 

7.1.10.4 The results (pass/fail) of all 

required quarterly leak checks of all 

differential pressure-type flow monitors (if 

applicable); 

7.1.10.5 The CEMS and reference method 

readings for each test run and the calculated 

relative accuracy results for all RATAs of all 

Hg CEMS, sorbent trap monitoring systems, 

and (as applicable) flow rate, diluent gas, and 

moisture monitoring systems; 

7.1.10.6 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 all gas 

monitors, including Hg CEMS; 

7.1.10.7 Supporting information for all 

required RATAs of volumetric flow rate 

monitoring systems, diluent gas monitoring 

systems, and moisture monitoring systems, 

including the raw field data and, as 

applicable, the results of reference method 

bias and drift checks, calibration gas 

certificates, the results of lab analyses, and 

records of sampling equipment calibrations. 

For the RATAs of Hg CEMS and sorbent trap 

monitoring systems, keep sufficient records 

of the test dates, the raw reference method 

and monitoring system data, and the results 

of sample analyses to substantiate the 

reported test results; and 

7.1.10.8 For sorbent trap monitoring 

systems, 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 12B in Appendix B to part 60 

of this chapter. 

7.2 Reporting Requirements. 

7.2.1 General Reporting Provisions. The 

owner or operator shall comply with the 

following reporting requirements for each 

affected unit (or group of units monitored at 

a common stack) and each non-affected unit 

under section 2.3 of this appendix: 

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. In addition to the 

notifications required elsewhere in this 

subpart, the owner or operator of any affected 

unit shall provide the following notifications 

for each affected unit (or group of units 

monitored at a common stack) and each nonaffected unit under section 2.3 of this 

appendix. Provide each notification at least 

21 days prior to the event: 

7.2.2.1 The date(s) of the required annual 

RATAs of the Hg CEMS, sorbent trap 

monitoring systems, and (as applicable) flow 

rate, diluent gas, and moisture monitoring 

systems used to provide data under this 

subpart; 

7.2.2.2 The date on which emissions first 

exhaust through a new stack or flue gas 

desulfurization system; and 

7.2.2.3 The date on which an affected 

unit is removed from service and placed into 

long-term cold storage, and the date on 

which the unit is expected to resume 

operation. 

7.2.3 Monitoring Plan Reporting. The 

owner or operator of any affected unit shall 

make electronic and hard copy monitoring 

plan submittals for each affected unit (or 

group of units monitored at a common stack) 

and each non-affected unit under section 2.3 

of this appendix, as follows: 

7.2.3.1 At least 21 days prior to the initial 

certification testing or recertification testing 

of a monitoring system used to provide data 

under this subpart; and 

7.2.3.2 Whenever an update of the 

monitoring plan is required, as provided in 

paragraph 7.1.1.1 of this section. An 

electronic monitoring plan information 

update must be submitted either prior to or 

concurrent with the quarterly report for the 

calendar quarter in which the update is 

required. 

7.2.4 The results of all required 

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assurance tests described in paragraphs 

7.1.10.3 through 7.1.10.6 of this section shall 

be submitted electronically, either prior to or 

concurrent with the relevant quarterly 

electronic report. 

7.2.5 Quarterly Reports. 

7.2.5.1 Beginning with the calendar 

quarter containing the program start date, the 

owner or operator of any affected unit shall 

submit electronic quarterly reports to the 

Administrator, in a format specified by the 

Administrator, for each affected unit (or 

group of units monitored at a common stack) 

and each non-affected unit under section 2.3 

of this appendix. 

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 7.1.19 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 and daily flow monitor 

interference checks, as described in 

paragraphs 7.1.10.1 and 7.1.10.2 of this 

section. 

7.2.5.4 Information which is 

incompatible with electronic reporting (e.g., 

field data sheets, lab analyses, stratification 

test results, sampling equipment calibrations, 

quality control plan information) is excluded 

from electronic reporting. 

7.2.5.5 Compliance Certification. The 

owner or operator shall submit a compliance 

certification in support of each electronic 

quarterly emissions monitoring report, based 

on reasonable inquiry of those persons with 

primary responsibility for ensuring that all 

Hg emissions from the affected unit(s) and (if 

applicable) any non-affected unit(s) under 

section 2.3 of this appendix have been 

correctly and fully monitored. The 

compliance certification shall indicate 

whether the monitoring data submitted were 

recorded in accordance with the applicable 

requirements of this appendix. 

[FR Doc. 2011–7237 Filed 5–2–11; 8:45 am] 

BILLING CODE 6560–50–P 


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