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6560-50-P

ENVIRONMENTAL PROTECTION AGENCY

40 CFR Part 63

[EPA-HQ-OAR-2006-0790; FRL- ]

RIN 2060-AM44

National Emission Standards for Hazardous Air Pollutants for 

Area Sources: Industrial, Commercial, and Institutional Boilers

AGENCY: Environmental Protection Agency (EPA).

ACTION: Final rule.

SUMMARY: EPA is promulgating national emission standards for 

control of hazardous air pollutants from two area source 

categories: industrial boilers and commercial and institutional

boilers. The final emission standards for control of mercury 

and polycyclic organic matter emissions from coal-fired area 

source boilers are based on the maximum achievable control 

technology. The final emission standards for control of 

hazardous air pollutants emissions from biomass-fired and oilfired area source boilers are based on EPA’s determination as to 

what constitutes the generally available control technology or 

management practices.

EFFECTIVE DATE: This final rule is effective on [INSERT THE 

DATE 60 DAYS AFTER THE DATE OF PUBLICATION OF THIS FINAL RULE IN 

THE FEDERAL REGISTER]. The incorporation by reference of 

certain publications listed in this final rule were approved by 
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the director of the Federal Register as of [INSERT THE DATE 60 

DAYS AFTER THE DATE OF PUBLICATION OF THIS FINAL RULE IN THE 

FEDERAL REGISTER].

ADDRESSES: EPA established a docket under Docket ID No. EPA–HQ–

OAR–2006-0790 for this action. All documents in the docket are 

listed on the http://www.regulations.gov website. 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, 

is not placed on the Internet and will be publicly available 

only in hard copy form. Publicly available docket materials are 

available either electronically through 

http://www.regulations.gov or in hard copy at EPA’s Docket 

Center, Public Reading Room, EPA West Building, Room 3334, 1301 

Constitution Ave., NW, Washington, DC. This Docket Facility is 

open from 8:30 a.m. to 4:30 p.m., Monday through Friday, 

excluding legal holidays. The telephone number for the Public 

Reading Room is (202) 566–1744, and the telephone number for the 

Air Docket is (202) 566–1742.

FOR FURTHER INFORMATION CONTACT: Mr. James Eddinger, Energy 

Strategies Group, Sector Policies and Programs Division, (D243-

01), Office of Air Quality Planning and Standards, U.S. 
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Environmental Protection Agency, Research Triangle Park, North 

Carolina 27711; Telephone number: (919) 541-5426; Fax number 

(919) 541-5450; e-mail address: eddinger.jim@epa.gov. 

SUPPLEMENTARY INFORMATION:

Acronyms and Abbreviations

Btu British thermal unit

. The following acronyms and 

abbreviations are used in this document.

CAA Clean Air Act

CBI Confidential Business Information

CEMS Continuous Emission Monitoring System

CFR Code of Federal Regulations

CO Carbon monoxide

ERT Electronic Reporting Tool

FR Federal Register

GACT Generally Available Control Technology

HAP Hazardous Air Pollutant

HCl Hydrogen chloride

ICR Information Collection Request

kWh kilowatt hour

MACT Maximum Achievable Control Technology

MMBtu/h Million Btu per hour

NAICS North American Industry Classification System
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NESHAP National Emission Standards for Hazardous Air 

Pollutants

NOx Nitrogen oxides

NSPS New Source Performance Standards

PM particulate matter

PM2.5 fine particulate matter

POM Polycyclic organic matter

ppm parts per million

RCRA Resource Conservation and Recovery Act

TBtu trillion British thermal units

tpy tons per year

SO2 sulfur dioxide

UPL Upper Prediction limit

VOC volatile organic compound

Organization of This Document. The information in this 

preamble is organized as follows:

I. General Information

A. Does this action apply to me?

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

C. Judicial Review

II. Background Information

A. What is the statutory authority and regulatory approach for 

this final rule?

B. What source categories are affected by the standards?

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

national emission standards?

D. How did we gather information for this rule?

E. How are the area source boiler HAP addressed by this rule?
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III. Summary of this final rule

A. Do these standards apply to my source?

B. What is the affected source? 

C. When must I comply with the final standards?

D. What are the MACT and GACT standards?

E. What are the Startup, Shutdown, and Malfunction (SSM)

requirements?

F. What are the initial compliance requirements?

G. What are the continuous compliance requirements?

H. What are the notification, recordkeeping and reporting 

requirements?

I. Submission of Emissions Test Results to EPA 

IV. Summary of Significant Changes Following Proposal

A. Changes to Subcategories

B. Change from MACT to GACT for Biomass and Oil Subcategories

C. MACT Floor UPL Methodology/Emission Limits

D. Clarification of Energy Assessment Requirements

E. Revised Subcategory Limits

F. Demonstrating Compliance

G. Affirmative Defense

H. Technical/Editorial Corrections

V. Significant Area Source Public Comments and Rationale for 

Changes to Proposed Rule

A. Legal and Applicability Issues

B. CO Limits

C. MACT Floor Analysis

D. Beyond the Floor Analysis

E. GACT Standards

F. Subcategories

G. Startup, Shutdown, and Malfunction

H. Compliance Requirements

I. Cost/Economic Impacts

VI. Summary of the ImpactsRelationship of this Final RuleAction to 

CAA Section 112(c)(6)

VII. Summary of the Impacts of this Final Rule

A. What are the air impacts?

B. What are the cost impacts?

C. What are the economic impacts?

D. What are the benefits?

E. What are the water and solid waste impacts?

F. What are the energy impacts?

VII. Relationship of this Action to CAA Section 112(c)(6)

VIII. Statutory and Executive Order Review

A. Executive Order 12866: Regulatory Planning and Review

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B. Paperwork Reduction Act

C. Regulatory Flexibility Act (RFA)

D. Unfunded Mandates Reform Act of 1995

E. Executive Order 13132: Federalism

F. Executive Order 13175: Consultation and Coordination with 

Indian Tribal Governments

G. Executive Order 13045: Protection of Children from 

Environmental Health Risks and Safety Risks

H. Executive Order 13211: Actions Concerning Regulations That 

Significantly Affect Energy Supply, Distribution, or Use

I. National Technology Transfer and Advancement Act

J. Executive Order 12898: Federal Actions to Address 

Environmental Justice in Minority Populations and Low-Income 

Populations

K. Congressional Review Act

I. General Information

A. 

The regulated categories and entities potentially affected 

by the final standards include:

Does this action apply to me? 
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Category NAICS 

code1

Examples of regulated

Entities

Any area source 

facility using a 

boiler as defined 

in this proposed 

rule.

321 Wood product manufacturing.

11 Agriculture, greenhouses.

311 Food manufacturing.

327 Nonmetallic mineral product 

manufacturing.

424 Wholesale trade, nondurable 

goods.

531 Real estate.

611 Educational services.

813 Religious, civic, 

professional, and similar 

organizations.

92 Public administration.

722 Food services and drinking 

places.

62 Health care and social 

assistance.

1 North American Industry Classification System.

 

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., is regulated by this 

action, you should examine the applicability criteria in 40 CFR 

63.11193 of subpart JJJJJJ (National Emission Standards for 

Hazardous Air Pollutants for Industrial, Commercial, and 

Institutional Boilers Area Sources). If you have any questions 
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regarding the applicability of this action to a particular 

entity, consult either the delegated regulatory authority for 

the entity or your EPA regional representative as listed in 40 

CFR 63.13 of subpart A (General Provisions).

B. 

In addition to being available in the docket, an electronic 

copy of this final action will also be available on the 

Worldwide Web (WWW) through the Technology Transfer Network 

(TTN). Following signature, a copy of the final action will be 

posted on the TTN’s policy and guidance page for newly proposed 

or promulgated rules at the following address: 

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

technology exchange in various areas of air pollution control.

Where can I get a copy of this document?

C.

Under section 307(b)(1) of the CAA, judicial review of this 

final rule is available only by filing a petition for review in 

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

(the Court) by [

Judicial Review

INSERT THE DATE 60 DAYS FROMAFTER THE DATE OF

PUBLICATION IN THE FEDERAL REGISTER]. Under CAA section 

307(d)(7)(B), only an objection to this final rule that was 

raised with reasonable specificity during the period for public 

comment can be raised during judicial review. CAA section 
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307(d)(7)(B) also provides a mechanism for EPA to convene a 

proceeding for reconsideration, “[i]f the person raising an 

objection can demonstrate to EPA that it was impracticable to 

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

if the grounds for such objection arose after the period for 

public comment (but within the time specified for judicial 

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

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

demonstration to us should submit a Petition for Reconsideration 

to the Office of the Administrator, Environmental Protection 

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

NW., Washington, DC 20460, with a copy to the person listed in 

the preceding FOR FURTHER GENERAL INFORMATION CONTACT section, 

and the Associate General Counsel for the Air and Radiation Law 

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

Environmental Protection Agency, 1200 Pennsylvania Ave., NW., 

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

requirements established by this final rule may not be 

challenged separately in any civil or criminal proceedings 

brought by EPA to enforce these requirements.

II. Background Information

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

Section 112(d) of the CAA requires us to establish NESHAP

for both major and area sources of HAP that are listed for 

regulation under CAA section 112(c). A major source emits or 

has the potential to emit 10 tpy or more of any single HAP or 25

tpy or more of any combination of HAP. An area source is a HAPemitting stationary source that is not a major source.

Section 112(k)(3)(B) of the CAA calls for EPA to identify 

at least 30 HAP which, as the result of emissions from area 

sources, pose the greatest threat to public health in the 

largest number of urban areas. EPA implemented this provision 

in 1999 in the Integrated Urban Air Toxics Strategy (Strategy), 

(64 FR 38715, July 19, 1999). Specifically, in the Strategy, 

EPA identified 30 HAP that pose the greatest potential health 

threat in urban areas, and these HAP are referred to as the “30 

urban HAP.” CAA section 112(c)(3) requires EPA to list 

sufficient categories or subcategories of area sources to ensure 

that area sources representing 90 percent of the emissions of 

the 30 urban HAP are subject to regulation. A primary goal of 

the Strategy is to achieve a 75 percent reduction in cancer 

incidence attributable to HAP emitted from stationary sources.

Under CAA section 112(d)(5), we may elect to promulgate 
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standards or requirements for area sources "which provide for 

the use of generally available control technologies [“GACT”] or 

management practices by such sources to reduce emissions of 

hazardous air pollutants." Additional information on GACT is 

found in the Senate report on the legislation (Senate Report 

Number 101-228, December 20, 1989), which describes GACT as:

. . . methods, practices and techniques which are 

commercially available and appropriate for application 

by the sources in the category considering economic 

impacts and the technical capabilities of the firms to 

operate and maintain the emissions control systems.

Consistent with the legislative history, we can consider 

costs and economic impacts in determining GACT, which is 

particularly important when developing regulations for source 

categories that may have many small businesses such as these.

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 

analogous source category 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 
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whether such technologies and practices could be considered

generally available for the area source categories at issue. 

Finally, as noted above, 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.

While GACT may be a basis for standards for most types of 

HAP emitted from area sources, CAA section 112(c)(6) requires 

that EPA list categories and subcategories of sources assuring 

that sources accounting for not less than 90 percent of the 

aggregate emissions of each of seven specified HAP are subject 

to standards under CAA sections 112(d)(2) or (d)(4), which 

require the application of the more stringent MACT. The seven 

HAP specified in CAA section 112(c)(6) are as follows: 

alkylated lead compounds, POM, hexachlorobenzene, mercury, 

polychlorinated biphenyls (PCBs), 2,3,7,8-

tetrachlorodibenzofurans, and 2,3,7,8-tetrachlorodibenzo-pdioxin. 

The CAA section 112(c)(6) list of source categories 

currently includes industrial coal combustion, industrial oil 

combustion, industrial wood combustion, commercial coal 

combustion, commercial oil combustion, and commercial wood 
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combustion. (See 63 FR 17849 (,April 10, 1998).).) We listed

these source categories under CAA section 112(c)(6) based on the 

source categories’ contribution of mercury and POM. In the 

documentation for the CAA section 112(c)(6) listing, the 

commercial fuel combustion categories included institutional 

fuel combustion. (See “1990 Emissions Inventory of Section 

112(c)(6) Pollutants, Final Report,” April 1998.) As discussed 

in the preamble to the proposed rule, we concluded we only 

needed to address mercury emissions from the coal-fueled portion 

of these categories in order to ensure that 90 percent of the 

aggregate emissions of mercury would be subject to standards 

under CAA sections 112(d)(2) or 112(d)(4). (See 75 FR 31898, 

June 4, 2010.) As discussed in this preamble, based on public 

comments received, we re-examined the emission inventory and the 

need to address POM emissions from the area source subcategories 

to meet the CAA section 112(c)(6) 90 percent requirement, and 

concluded we only need to address POM emissions from the coalfueled portion of these categories under CAA section 112(d)(2)

or 112(d)(4).

With this final rule and the major source boilers rule, we

currently believe that we have subjected to regulation at least 

90 percent of the CAA section 112(c)(6) 1990 emissions inventory 
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for mercury and POM. Consequently, we are regulating coal-fired 

area source boilers under MACT because we need these sources to 

meet the 90 percent requirement for mercury and POM in CAA 

section 112(c)(6). 

The “MACT” required by CAA sections 112(d)(2) or 112(d)(4) 

can be based on the emissions reductions achievable through 

application of measures, processes, methods, systems, or 

techniques including, but not limited to: (1) reducing the 

volume of, or eliminating emissions of, such pollutants through 

process changes, substitutions of materials, or other 

modifications; (2) enclosing systems or processes to eliminate 

emissions; (3) collecting, capturing, or treating such 

pollutants when released from a process, stack, storage or 

fugitive emission point; (4) design, equipment, work practices, 

or operational standards as provided in CAA section 112(h); or 

(5) a combination of the above.

The MACT floor is the minimum control level allowed for 

NESHAP and is defined under CAA section 112(d)(3). For new 

sources, MACT based standards cannot be less stringent than the 

emission control achieved in practice by the best-controlled 

similar source, as determined by the Administrator. The MACT 

based standards for existing sources can be less stringent than 
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standards for new sources, but they cannot be less stringent 

than the average emission limitation achieved by the best 

performing 12 percent of existing sources in the category or 

subcategory (for which the Administrator has emission 

information) for source categories and subcategories with 30 or 

more sources, or the best performing 5 sources for categories 

and subcategories with fewer than 30 sources (CAA section 

112(d)(3)(A) and (B)).

Although emission standards are often structured in terms 

of numerical emissions limits, alternative approaches are 

sometimes necessary and authorized pursuant to CAA section 112. 

For example, in some cases, physically measuring emissions from 

a source may be not practicable due to technological and

economic limitations. Section 112(h) of the CAA authorizes the 

Administrator to promulgate a design, equipment, work practice, 

or operational standard, or combination thereof, 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 prescribe or enforce an emission standard. Section 112(h)(2) 

of the CAA provides that the phrase “not feasible to prescribe 

or enforce an emission standard” includes “the situation in 

which the Administrator determines that ... the application of 
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measurement methodology to a particular class of sources is not 

practicable due to technological and economic limitations.”

As noted above in this section of the preamble, we listed 

industrial coal combustion, industrial oil combustion,

industrial wood combustion, commercial coal combustion, 

commercial oil combustion, and commercial wood combustion under 

CAA section 112(c)(6) based on the source categories’ 

contribution of mercury and POM. We listed these same 

categories under CAA section 112(c)(3) for their contribution of 

mercury, arsenic, beryllium, cadmium, lead, chromium, manganese, 

nickel, POM (as 7-PAH (polynuclear aromatic hydrocarbons)), 

ethylene dioxide, and PCBs.

We have developed final standards to reflect the 

application of MACT for mercury and POM from coal-fired area 

source boilers and have applied GACT for the urban HAP noted 

above for boilers firing other fuels and for urban HAP (other 

than mercury and POM) from coal-fired area source boilers.

B. What source categories are affected by the standards?

The source categories affected by the standards are 

industrial boilers and commercial and institutional boilers. 

Both source categories were included in the area source list 

published on July 19, 1999 (64 FR 38721). The inclusion of 
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these two source categories on the CAA section 112(c)(3) area 

source category list is based on 1990 emissions data, as EPA 

used 1990 as the baseline year for that listing. We describe 

above in Section II.A of this preamble the pollutants that 

formed the basis of the listings.

This rule applies to all existing and new industrial 

boilers, institutional boilers, and commercial boilers located 

at area sources. Boiler means an enclosed combustion device 

having the primary purpose of recovering thermal energy in the 

form of steam or hot water. The industrial boiler source 

category includes boilers used in manufacturing, processing, 

mining, refining, or any other industry. The commercial boiler 

source category includes boilers used in commercial 

establishments such as stores/malls, laundries, apartments, 

restaurants, and hotels/motels. The institutional boiler source 

category includes boilers used in medical centers (e.g., 

hospitals, clinics, nursing homes), educational and religious 

facilities (e.g., schools, universities, churches), and 

municipal buildings (e.g., courthouses, prisons).

Boiler means an enclosed combustion device having the primary 

purpose of recovering thermal energy in the form of steam or hot

water. 

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

national emission standards?

This rule regulates industrial boilers and 

institutional/commercial boilers that are located at area 

sources of HAP. Today, in a parallel action, a NESHAP for 

industrial, commercial, and institutional boilers and process 

heaters located at major sources is being promulgated reflecting 

the application of MACT. The major source NESHAP regulates 

emissions of PM (as a surrogate for non-mercury metals), 

mercury, HCl (as a surrogate for acid gases), dioxins/furans, 

and CO (as a surrogate for non-dioxin organic HAP) from existing 

and new major source boilers. 

This rule covers boilers located at area source facilities. 

In addition to the major source MACT for boilers being issued 

today, the Agency is also issuing emission standards today 

pursuant to CAA section 129 for commercial and industrial solid 

waste incineration units. In a parallel action, EPA is 

finalizing a solid waste definition rulemaking pursuant to 

subtitle D of RCRA. That action is relevant to this proceeding 

because if an industrial, commercial, or institutional boiler

located at an area source combusts secondary materials that are 

“solid waste,” as that term is defined by the Administrator 
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under RCRA, those boilers would be subject to section 129 of the 

CAA, not section 112.

As background, in 2007, the United States Court of Appeals 

for the District of Columbia Circuit (D.C. Circuit) vacated the 

“CISWI Definitions Rule” (70 FR 55568, September 22, 2005), 

which amended the definitions of “commercial and industrial 

solid waste incinerator (CISWI),” “commercial or industrial 

waste,” and “solid waste” in 40 CFR 60, subparts CCCC and DDDD, 

and which EPA issued pursuant to CAA section 129. The Court 

found that the definitions in that rule were inconsistent with 

the CAA. Specifically, the Court held that the term “solid 

waste incineration unit” in CAA section 129(g)(1) “unambiguously 

include[s] among the incineration units subject to its standards 

any facility that combusts any commercial or industrial solid 

waste material at all — subject to the four statutory exceptions 

identified [in CAA section 129(g)(1)].” NRDC v. EPA, 489 F.3d 

at 1257–58.

Based on the information available to the Agency, we 

determined that the boilers that are subject to this area source 

rule combust predominantly coal, oil, or biomass. We have 

further determined that the boilers subject to this rule may

combust non-hazardous secondary materials that do not meet the 
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definition of "solid waste" pursuant to the rulemaking of 

subtitle D of RCRA. A boiler located at an area source burning 

any secondary materials considered "solid waste" would be 

considered a solid waste incineration unit subject to regulation 

under CAA section 129. In the final area source boiler 

rulemaking, EPA is providing specific language to ensure clarity 

regarding the necessary steps that must be followed for 

combustion units that begin combusting non-hazardous solid waste 

materials and become subject to section 129 standards instead of 

section 112 standards or combustion units that discontinue 

combustion of non-hazardous solid waste materials and become 

subject to section 112 standards instead of section 129 

standards.

Some of the affected sources subject to this rule may also 

be subject to the NSPS for industrial, commercial, and 

institutional boilers (40 CFR part 60, subparts Db and Dc). EPA 

codified these NSPS in 1986, and revised portions of them in 

1999 and 2006. The two NSPS regulate emissions of PM, SO2, and 

NOX from boilers constructed after June 19, 1984. Sources 

subject to the NSPS that are located at area source facilities 

are also subject to this rule because this rule regulates HAP. 

In developing this rule, we have streamlined the monitoring and 
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recordkeeping requirements to avoid duplicating requirements in 

the NSPS.

D. How did we gather information for this rule?

We gathered information for this rule from States’states’

boiler inspection lists, company websites, published literature, 

Statestate permits, current Statestate and Federalfederal

regulations, and from an ICR conducted for the major source 

NESHAP. After proposal, we received additional emission test 

reports during the public comment period.

We developed an initial nationwide population of area

source boilers based on boiler inspector data-bases from 13 

Statesstates. The boiler inspector data-bases include steam 

boilers that are required to be inspected for safety or 

insurance purposes. We classified the area source boilers to 

NAICS codes based on the “name” of the facility at which the 

boiler was located. However, many of the boilers in the boiler 

inspector data-base could not be readily assigned to an NAICS 

code and, thus, we did not categorize them. 

We reviewed Statestate and other Federalfederal regulations 

that apply to the area sources in the source categories for 

information concerning existing HAP emission control approaches.

For example, as noted above, the NSPS for small industrial, 
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commercial, and institutional boilers in 40 CFR part 60, subpart 

Dc apply to boilers at some area sources. Similarly, permit 

requirements established by the Ohio, Illinois, Vermont, New 

Hampshire, and Maine air regulatory agencies apply to some area

sources. We also reviewed standards for boilers at major 

sources that would be appropriate for and transferable to

boilers at area sources. For example, we determined that 

management practices, such as, annual tune-ups and operator 

training applicable to major source boilers are equallyalso

feasible for boilers at area sources.

E. How are the area source boiler HAP addressed by this rule?

As explained in Section II.A of this preamble, industrial 

coal combustion, industrial oil combustion, industrial wood 

combustion, commercial coal combustion, commercial oil 

combustion, and commercial wood combustion are listed under CAA 

section 112(c)(6) due to contributions of mercury and POM and 

these same categories are listed under CAA section 112(c)(3) for 

their contribution of mercury, arsenic, beryllium, cadmium, 

lead, chromium, manganese, nickel, POM, ethylene dioxide, and 

PCB.

With respect to the CAA section 112(c)(3) pollutants, we 

used surrogates because, as explained in this section of the 
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preamble, it was not practical to establish individual standards 

for each specific HAP. We grouped the CAA section 112(c)(3) 

pollutants, which formed the basis for the listing of these two 

source categories, into three common groupings: mercury, nonmercury metallic HAP (arsenic, beryllium, cadmium, chromium, 

lead, manganese, and nickel), and organic HAP (POM, ethylene 

dichloride, and PCB). In general, the pollutants within each 

group have similar characteristics and can be controlled with 

the same techniques. 

For the non-mercury metallic HAP, we selected PM as a 

surrogate. The inherent variability and unpredictability of the 

non-mercury metal HAP compositions and amounts in fuel has a 

material effect on the composition and amount of non-mercury

metal HAP in the emissions from the boiler. As a result, 

establishing individual numerical emissions limits for each nonmercury HAP metal species is difficult given the level of 

uncertainty about the individual non-mercury metal HAP 

compositions of the fuels that will be combusted. An emission 

characteristic common to all boilers is that the non-mercury

metal HAP are a component of the PM contained in the fly ash 

emitted from the boiler. A sufficient correlation exists 

between PM and non-mercury metallic HAP to rely on PM as a 
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surrogate for these HAP and for their control.1

For organic urban HAP, we selected CO as a surrogate for

organic compounds, including POM, emitted from the various fuels 

burned in boilers. The presence of CO is an indicator of 

incomplete combustion. A high level of CO in emissions is a 

potential indication of elevated organic HAP emissions. because 

organic HAP, like CO, are formed as a byproduct of combustion, 

and both would increase with an increase in the level of 

incomplete combustion. Monitoring equipment for CO is readily 

available, which is not the case for organic HAP. Also, it is 

significantly easier and less expensive to measure and monitor 

 Therefore, the 

same control techniques that would be used to control the flyash PM will control non-mercury metallic HAP. Emissions limits 

established to achieve control of PM will also achieve control 

of non-mercury metallic HAP. Furthermore, establishing separate 

standards for each individual HAP would impose costly and 

significantly more complex compliance and monitoring 

requirements and achieve little, if any, HAP emissions 

reductions beyond what would be achieved using the surrogate 

pollutant approach. 

 

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

2000), the court upheld EPA’s use of particulate matter as a 

surrogate for HAP metals.
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CO emissions than to measure and monitor emissions of each 

individual organic HAP. We considered other surrogates, such as 

total hydrocarbon (THC), but lacked data on emissions and permit 

limits for area source boilers. Therefore, using CO as a 

surrogate for organic urban HAP is a reasonable approach because 

minimizing CO emissions will result in minimizing organic urban 

HAP emissions. 

Based on these considerations, we are promulgating GACT 

standards for PM (as a surrogate for the individual urban metal 

HAP) for coal, biomass, and oil-fired boilers and CO (as a 

surrogate pollutant for the individual urban organic HAP) for

biomass-fired and oil-fired boilers. We are also establishing

MACT standards for mercury and for POM (using CO as a surrogate 

pollutant) for coal-fired boilers. The MACT standard for POM 

from coal-fired boilers would also be GACT for urban organic HAP 

other than POM.

III. Summary of this Final RruleRule

A. Do these standards apply to my source?

This rule applies to you if you own or operate a boiler

combusting solid fossil fuels, biomass, or liquid fuels located 

at an area source. The standards do not apply to boilers that 

are subject to another standard under 40 CFR part 63 or to a 
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standard developed under CAA section 129.

This rule applies to you if you own or operate a boiler 

combusting natural gas, located at an area source, thatwhich

switches to combusting solid fossil fuels, biomass, or liquid 

fuel after June 4, 2010.

B. What is the affected source? 

This final rule affects industrial boilers, institutional 

boilers, and commercial boilers. The affected source is the 

collection of all existing boilers within a subcategory located 

at an area source facility or each new boiler located at an area 

source facility.

C. When must I comply with these standards?

The owner or operator of an existing source subject to a work 

practice or management practice standard of a tune-up is 

required to comply with this final rule no later than [INSERT 

THE DATE 1 YEAR AFTER THE DATE OF PUBLICATION OF THIS FINAL RULE 

IN THE FEDERAL REGISTER]. The owner or operator of an existing 

source subject to emission limits or an energy assessment 

requirement is required to comply with this final rule no later 

than [INSERT THE DATE 3 YEARS AFTER THE DATE OF PUBLICATION OF 

THIS FINAL RULE IN THE FEDERAL REGISTER]. The owner or operator 

of a new source is required to comply on [INSERT THE DATE 60 
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DAYS AFTER THE DATE OF PUBLICATION OF THIS FINAL RULE IN THE 

FEDERAL REGISTER] or upon startup of the facility, whichever is 

later. Owners and operators subject to 40 part CFR 60, subpart 

CCCC or subpart DDDD who cease combusting solid waste must be in 

compliance with this subpart on the effective date that the unit

ceased combusting solid waste, consistent with 40 CFR part 60, 

subpart CCCC or subpart DDDD.

D. What are the MACT and GACT standards?

Emission standards are in the form of numerical emission 

limits for new and existing area source boilers. The MACT 

emission limits for mercury and CO (as a surrogate for POM) are 

presented, along with the GACT emission limits for PM (as a 

surrogate for urban metals), in Table 1 of this preamble. The 

units are pounds of PM or mercury per million British thermal 

units (lb/MMBtu) and ppm for CO.

Table 1. Emission Limits for Area Source Boilers 

Subcategory

Heat Input 

(MMBtu/h) Pollutants Emission Limits

New coalfired 

boiler

≥ 30 a. Particulate Matter

b. Mercury

c. Carbon Monoxide

0.03 lb per MMBtu of heat 

input.

0.0000048 lb per MMBtu of 

heat input.

400 ppm by volume on a 

dry basis corrected to 3

percent oxygen. 

Merged Cells

Formatted Table

Merged Cells
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b. Mercury

0.0000048 lb per MMBtu of 

heat input.

c. Carbon Monoxide 400 ppm by volume on a 

dry basis corrected to 3

percent oxygen.

≥ 10 

and < 30 

a. Particulate Matter

b. Mercury

c. Carbon Monoxide

0.42 lb per MMBtu of heat 

input.

0.0000048 lb per MMBtu of 

heat input.

400 ppm by volume on a 

dry basis corrected to 3

percent oxygen.

b. Mercury 0.0000048 lb per MMBtu of 

heat input.

c. Carbon Monoxide 400 ppm by volume on a 

dry basis corrected to 3

percent oxygen.

New 

biomassfired 

boiler

≥ 30 Particulate Matter 0.03 lb per MMBtu of heat 

input.

≥ 10 

and < 30

Particulate Matter 0.07 lb per MMBtu of heat 

input.

New oilfired 

boiler

≥ 30 Particulate Matter 0.03 lb per MMBtu of heat 

input.

≥ 10 

and < 30

Particulate Matter 0.03 lb per MMBtu of heat 

input.

Formatted Table
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Existing 

coal-Fired 

boiler

≥ 10 a. Mercury

b. Carbon Monoxide

0.0000048 lb per MMBtu of 

heat input.

400 ppm by volume on a 

dry basis corrected to 7 

percent oxygen. 

b. Carbon Monoxide 400 ppm by volume on a 

dry basis corrected to 7 

percent oxygen.

The emission limits for PM apply only to new boilers. The 

emission limits for mercury and CO apply only to boilers in the 

coal subcategory; the emission limits for existing area source 

boilers in the coal subcategory are applicable only to area 

source boilers that have a designed heat input capacity of 10 

million MMBtu/h or greater. 

If your boiler burns any solid fossil fuel and no more than 

15 percent biomass on a total fuel annual heat input basis, the 

boiler is in the coal subcategory. If your boiler burns at 

least 15 percent biomass on a total fuel annual heat input 

basis, the unit is in the biomass subcategory. If your boiler 

burns any liquid fuel and is not in either the coal or the

biomass subcategory, the unit is in the oil subcategory, except 

if the unit burns oil only during periods of gas curtailment.

As allowed under CAA section 112(h), a work practice 

standard is being promulgated for new and existing coal-fired 

area source boilers with a designed heat input capacity of less 

than 10 MMBtu/h. The work practice standard for new and 

Merged Cells

Formatted Table

Merged Cells
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existing coal-fired area source boilers requires the 

implementation of a tune-up program. We are also requiring all 

biomass-fired and oil-fired area source boilers to implement a 

tune-up program as a management practice.

An additional standard is being promulgated for existing 

area source facilities having an affected boiler with a designed 

heat input capacity of 10 MMBtu/h or greater that requires the

performance of an energy assessment, by qualified personnel, on 

the boiler and its energy use systems to identify cost-effective 

energy conservation measures.

E. What are the Startup, Shutdown, and Malfunction (SSM)

requirements?

The United States Court of Appeals for the District of 

Columbia Circuit vacated portions of two provisions in EPA’s CAA 

section 112 regulations governing the emissions of HAP during 

periods of startup, shutdown, and malfunction (SSM). Sierra 

Club v. EPA, 551 F.3d 1019 (D.C. Cir. 2008), cert. denied, 130 

S. Ct. 1735 (U.S. 2010). Specifically, the 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” (40 CFR 63, subpart A), that 

EPA promulgated under CAA section 112 of the CAA. When 
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incorporated into CAA section 112(d) regulations for specific 

source categories, these two provisions exempted sources from 

the requirement to comply with the otherwise applicable CAA 

section 112(d) emission standard during periods of SSM.

Consistent with Sierra Club v. EPA, EPA has established 

standards in this rule that apply at all times. EPA has 

attempted to ensure that we have not incorporated into the 

regulatory language any provisions that are inappropriate, 

unnecessary, or redundant in the absence of an SSM exemption. 

In establishing the standards in this rule, EPA has taken 

into account startup and shutdown periods and, for the reasons 

explained below, has established different standards for those 

periods. 

EPA has revised this final rule to require sources to 

perform onlymeet a work practice standardsstandard, including 

following the manufacturer’s recommended procedures for 

minimizing startup and shutdown periods, to demonstrate 

compliance with the CO emission limits for all subcategories of 

new and existing area source coal-fired boilers (that would 

otherwise be subject to numeric emission limits) during periods 

of startup and shutdown. As discussed in Section VI.G of this 

preamble, we considered whether continuous emission monitoring 
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or performance testing, and therefore, enforcement of numeric 

emission limits, would be feasible for area source 

boilerspracticable during periods of startup, and shutdown, and 

malfunction. This final rule only requires emission limits for 

mercury and CO for existing coal-fired boilers.. With regards 

to performance testing, EPA determined that it is not 

technically feasible to requirecomplete stack testing - in 

particular, to repeat the multiple required test runs - during 

periods of startup and shutdown due to physical limitations and 

the short duration of startup and shutdown periods. Therefore, 

we have established the separate work practice standardsstandard

for periods of startup and shutdown.

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 
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promulgated, apply at all times. In Mossville Environmental 

Action Now v. EPA, 370 F.3d 1232, 1242 (D.C. Cir. 2004), the 

court upheld as reasonable standards that had factored in 

variability of emissions under all operating conditions. 

However, nothing in 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 (D.C. Cir. 

1978) (“ In the nature of things, no general limit, individual 

permit, or even any upset provision can anticipate all upset 

situations. After a certain point, the transgression of 

regulatory limits caused by ‘uncontrollable acts of third 

parties,’ such as strikes, sabotage, operator intoxication or 

insanity, and a variety of other eventualities, must be a matter 

for the administrative exercise of case-by-case enforcement 

discretion, not for specification in advance by regulation.”).

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 
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malfunctioning presents significant difficulties. The goal of 

best performing sources is to operate in such a way as to avoid 

malfunctions of their units. Similarly, although standards for 

area sources are generally not required to be set based on “best 

performers,” we believe that what is "generally available" 

should not be based on periods in which there is a “failure to 

operate.” 

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 area source boilers. 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 112(d) standards as a result of a 

malfunction event (see 40 CFR 63.2 (definition of malfunction), 

EPA must determine an appropriate response based on, among other 

things, the good faith efforts of the source to minimize 
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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 adding to 

this final rule an affirmative defense to civil penalties for 

exceedances of emission limits that are caused by malfunctions. 

(See 40 CFR 63.11226 (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 
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and objectively evaluated in a judicial or administrative 

proceeding).) We also have added other regulatory provisions to 

specify the elements that are necessary to establish this 

affirmative defense; the source must prove by a preponderance of 

the evidence that it has met all of the elements set forth in 

63.11226. (See 40 CFR 22.24.) The criteria ensure that the 

affirmative defense is available only where the event that 

causes an exceedance of the emission limit meets the narrow 

definition of malfunction in 40 CFR 63.2 (sudden, infrequent, 

not reasonable 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, short, 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 63.11205(a)), 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 
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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 of the CAA

(see also 40 CFR 22.77). 

F. What are the initial compliance requirements?

For new and existing area source boilers with applicable 

emission limits, you must conduct initial performance tests to 

determine compliance with the PM, mercury, and CO emission 

limits. The performance tests to demonstrate compliance with 

the mercury emission limit can be either a stack test, which 

also requires a fuel analysis, or only a fuel analysis. 

As part of the initial compliance demonstration, you must 

monitor specified operating parameters during the initial 

performance tests that demonstrate compliance with the PM,

mercury, and CO emission limits for area source boilers. The 

test average establishes your site-specific operating levels.

For owners or operators of existing and new coal-fired area 
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source boilers having a heat input capacity of less than 10 

MMBtu/h and all existing and new biomass-fired and oil-fired 

area source boilers, you must submit to the delegated authority

or EPA, as appropriate, documentation that a tune-up was 

conducted.

For owners or operators of existing area source facilities 

having a boiler with a heat input capacity of 10 MMBtu/h or 

greater and subject to this rule, you must submit to the 

delegated authority or EPA, as appropriate, documentation that 

the energy assessment was performed and the cost-effective 

energy conservation measures identified.

G. What are the continuous compliance requirements?

If you demonstrate initial compliance with the emission 

limits by performance (stack) tests, then you must conduct stack 

tests on an annual basis. Furthermore, to demonstrate 

continuous compliance with the PM, CO, and mercury emission 

limits, you must monitor and comply with the applicable sitespecific operating limits.

For area source boilers that must comply with the PM and 

mercury emission limits, you must continuously monitor opacity 

and maintain the opacity at or below 10 percent (daily block 

average) or:
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1. If the boiler is controlled with a fabric filter, the 

fabric filter may be continuously operated such that the 

alarm on the bag leak detection system does not sound more 

than 5 percent of the operating time during any 6-month 

period.

2. If the boiler is controlled with an electrostatic 

precipitator (ESP), you must maintain the minimum voltage 

and secondary amperage (or total power input) of the ESP at 

or above the minimum operating limits established during 

the performance test.

3. If the boiler is controlled with a wet scrubber, you must 

monitor pressure drop and liquid flow rate of the scrubber 

and maintain the daily block averages at or above the 

minimum operating limits established during the performance 

test.

4. For boilers with sorbent or carbon injection systems which 

must comply with an applicable mercury emission limit, you 

must maintain the daily block averages at or above the 

minimum sorbent flow rate, as calculated according to 40 

CFR 63.11221(a)(5). 

If you elected to demonstrate initial compliance with the 

mercury emission limit by fuel analysis, as determined according 
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to 40 CFR 63.11211(b), you must conduct a monthly fuel analysis 

and maintain the annual average at or below the limit indicated 

in Table 1 of this preamble. 

For boilers that demonstrate compliance with the PM and 

mercury emission limits by performance (stack) tests, you must 

maintain monthly fuel records that demonstrate that you burned 

no new fuel type or new mixture (monthly average) as set during 

the performance test. If you plan to burn a new fuel type or 

new mixture that is different from what was burned during the 

initial performance test, then you must conduct a new 

performance test to demonstrate continuous compliance with the 

PM emission limit and mercury emission limit.

For boilers that must comply with the CO emission limits, 

you must continually monitor oxygen and maintain an oxygen 

concentration level, on a 30-day rolling average basis, at no 

less than 90 percent of the average oxygen concentration 

measured during the most recent performance test.

Biomass and oil-fired boilers must meet the management 

practice standards defined in Table 2 to 40 CFR part 63, subpart 

JJJJJJ.

H. What are the notification, recordkeeping and reporting 

requirements?
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All new and existing sources will be required to comply 

with some requirements of the General Provisions (40 CFR part 

63, subpart A), which are identified in Table 6 to subpart 

JJJJJJ. The General Provisions include specific requirements 

for notifications, recordkeeping, and reporting. If performance 

tests are required under subpart JJJJJJ, then the notification

and reporting requirements for performance tests in the General

Provisions also apply.

Each owner or operator is required to submit a notification 

of compliance status report, as required by 40 CFR 63.9(h) of 

the General Provisions. Subpart JJJJJJ rule requires the owner 

or operator to include in the notification of compliance status 

report certifications of compliance with rule requirements.

If your unit is subject to an emission limit, then you must 

prepare, by March 1 of each year, an annual compliance 

certification report for the previous calendar year certifying 

the truth, accuracy and completeness of the notification and a 

statement of whether the source has complied with all the 

relevant standards and other requirements of this subpart.

This rule requires records to demonstrate compliance with 

each emission limit, work practice standard, and management 
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practice. These recordkeeping requirements are specified 

directly in the General Provisions to 40 CFR part 63.

Records for applicable management practices must be

maintained. Specifically, the owner or operator must keep 

records of the dates and the results of each boiler tune-up.

Records are required for either continuously monitored 

parameter data for a control device, if a device is used to 

control the emissions, or continuous opacity monitoring system

(COMS) data.

Each owner and operator is required to keep the following 

records:

(1) All reports and notifications submitted to comply with 

this final rule;

(2) Continuous monitoring data as required in this final 

rule;

(3) Each instance in which you did not meet each emission 

limit, work/management practice, and operating limit (i.e., 

deviations from this final rule);

(4) Monthly fuel use by each boiler including a 

description of the type(s) of fuel(s) burned, amount of each 

fuel type burned, and units of measure;

(5) A copy of the results of all performance tests, energy 
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assessments, opacity observations, performance evaluations, or 

other compliance demonstrations conducted to demonstrate initial 

or continuous compliance with this final rule; and

(6) A copy of your site-specific monitoring plan developed 

for this final rule, if applicable.

Records must be retained for at least 5 years. In 

addition, monitoring plans, operating and maintenance plans, and

other plans must be updated as necessary and kept for as long as 

they are still current.

I. Submission of Emissions Test Results to EPA

Compliance test data are necessary for many purposes 

including compliance determinations, development of emission 

factors, and determining annual emission rates. EPA has found 

it burdensome and time consuming to collect emission test data

because of varied locations for data storage and varied data 

storage methods.

One improvement that has occurred in recent years is the 

availability of stack test reports in electronic format as a 

replacement for bulky paper copies.

In this action, we are taking a step to improve data 

accessibility for stack tests (and in the future continuous

monitoring data). Boiler area sources are required to submit to 
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WebFIRE (an EPA electronic data base) an electronic copy of 

stack test reports as well as process data. Data entry requires 

only access to the Internet and is expected to be completed by 

the stack testing company as part of the work that it is 

contracted to perform.

Please note that the requirement to submit source test data 

electronically to EPA does not require any additional

performance testing. In addition, when a facility submits

performance test data to WebFIRE, there are no additional 

requirements for data compilation; instead, we believe industry 

will greatly benefit from improved emissions factors, fewer

information requests, and better regulation development as 

discussed below. Because the information that is being reported 

is already required in the existing test methods and is

necessary to evaluate the conformance to the test methods, 

facilities are already collecting and compiling these data. The 

Electronic Reporting Tool (ERT) was developed with input from 

stack testing companies, who already collect and compile

performance test data electronically. One major advantage of

submitting source test data through ERT is that it provides a 

standardized method to compile and store all the documentation 

required by subpart JJJJJJ. Another important benefit of
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submitting these data to EPA at the time the source test is 

conducted is that these data should reduce the effort involved 

in data collection activities in the future for these source 

categories. This results 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). Finally, another 

benefit of submitting these data to WebFIRE electronically is 

that these data will greatly improve the overall quality of the 

existing and new emissions factors by supplementing the pool of 

emissions test data upon which emissions factors are based and 

by ensuring that data are more representative of current 

industry operational procedures. A common complaint we hear 

from industry and regulators is that emissions factors are outdated or not representative of a particular source category. 

Receiving recent performance test results would ensure that 

emissions factors are updated and more accurate. In summary, 

receiving these test data already collected for other purposes 

and using them in the emissions factors development program will 

save industry, Statestate/local/tribal agencies, and EPA time 

and money.
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As mentioned earlier, the electronic data -base that will 

be used is EPA’s WebFIRE, which is a Web site accessible through 

EPA’s TTN (technology transfer network). The WebFIRE website

was constructed to store emissions test data for use in 

developing emission factors. A description of the WebFIRE data

-base can be found at 

http://cfpub.epa.gov/oarweb/index.cfm?action=fire.main. The ERT

will be able to transmit the electronic report through EPA’s 

Central Data Exchange (CDX) network for storage in the WebFIRE 

data base. Although ERT is not the only electronic interface 

that can be used to submit source test data to the CDX for entry 

into WebFIRE, it makes 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 ERT can be used to document the conduct of stack tests 

for various pollutants including PM, mercury, dioxin/furan, and

HCl. Presently, the ERT does not accept opacity data or CEMS

data.

IV. Summary of Significant Changes Following Proposal

A. Changes to Subcategories

We have redefined the coal, biomass and oil subcategories 

for area source boilers to clarify the fuel-type inputs that 
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would define each subcategory. The proposed rule defined the 

biomass subcategory to include any boiler that burns any amount

of biomass, either alone or in combination with a liquid or 

gaseous fuel. This definition excluded boilers that burned 

biomass with coal; boilers burning greater than 10 percent coal 

on an annual fuel heat input basis were defined under the coalfired subcategory. This final rule defines the biomass 

subcategory to include any boiler that burns at least 15 percent 

of biomass on an annual heat input basis. 

Similarly, the proposed rule defined the oil subcategory to 

include any boiler that burns any liquid fuel either alone or in 

combination with gaseous fuels, and excluded boilers that burned 

solid fossil fuels (coal).. We have revised this final rule to 

define the oil subcategory to include any boiler that burns any 

liquid fuel and is not in either the biomass or coal 

subcategory. 

The coal subcategory in this final rule has been revised to 

include any boiler combusting any solid fossil fuels and no more 

than 15 percent biomass. This final rule defines solid fossil 

fuels to include, but not limited to, coal, petroleum coke, and 

tire derived fuel (TDF). 

B. Change from MACT to GACT for Biomass and Oil Subcategories
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The proposed rule set MACT-based emission limits for CO (as 

a surrogate pollutant for the individual urban organic HAP) from 

new and existing biomass-fired and oil-fired boilers. With 

respect toFor POM from area source boilers classified as 

biomass-fired or oil-fired, as well as with respect to other 

urban HAP besides POM, we have revised this final rule standards 

to reflect GACT for these two area source subcategories (see 

Section V.D of this preamble). We are implementing management 

practice standards, as allowed by CAA section 112(d)(5), for 

control of POM from new and existing area source boilers in the 

biomass and oil subcategories. The management practice standard 

requires the implementation of a tune-up program. 

C. MACT Floor UPL Methodology/Emission Limits

At proposal, we used a 99 percent UPL calculation to 

determine variability. In this final rule, we have determined 

that 99 percent UPL is appropriate for fuel based HAP and a 99.9 

percent UPL is appropriate for combustion dependent HAP (i.e., 

CO). We have modified our assumptions when results of the 

skewness and kurtosis tests result in a tie between normal and 

log-normal calculations, or when there is not enough data to 

complete the skewness and kurtosis tests, to choose the lognormal results. We have also revised the UPL calculation to 
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convert log-normally distributed data to an arithmetic mean 

instead of a geometric mean. Further, for fuel based HAP (i.e., 

mercury), we have implemented an additional fuel variability

factor in the emission limits. 

D. Clarification of Energy Assessment Requirements

The proposed rule required owners and operators of existing 

area source boilers with a heat input capacity of 10 MMBtu/h and 

greater to have an energy assessment performed by a qualified 

professional. The proposed rule defined an energy assessment as 

an "in-depth assessment of a facility to identify immediate and 

long-term opportunities to save energy, focusing on the steam 

and process heating systems which involves a thorough 

examination of potential savings from energy efficiency 

improvements, waste minimization and pollution prevention, and 

productivity improvement." The requirements for the energy 

assessment, defined in Table 3 of the proposed rule, included 

visually inspecting the boiler system, establishing operating 

characteristics and energy system specifications, identifying

the boiler’s major energy consuming systems, listing major 

energy conservation measures, and a comprehensive report 

detailing the ways to improve efficiency, the cost of specific 

improvements, and the benefits associated with such. 
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This final rule requires an energy assessment for all 

existing boilers with a heat input capacity of 10 MMBtu/h or 

greater, and clarifies the definition of energy assessment with 

respect to the requirements of Table 3 of this final rule. The 

revised definition provides a maximum duration for performing 

the energy assessment and defines the evaluation requirements 

for each boiler system and energy use system. These 

requirements are based on the total annual heat input of the 

affected boilers. 

This final rule requires an energy assessment for 

facilities with affected boilers using less than 0.3 trillion 

Btu per year heat input to be one day in length maximum. The 

boiler system and energy use system accounting for at least 50 

percent of the energy output from the boilers must be evaluated 

to identify energy savings opportunities within the limit of 

performing a one day energy assessment. An energy assessment 

for a facility with affected boilers using 0.3 to 1 TBtu/year 

must be three days in length maximum. From these boilers, the 

boiler system and any energy use system accounting for at least 

33 percent of the energy output will be evaluated, within the 

limit of performing a three day energy assessment. For 

facilities with affected boilers using greater than 1 TBtu/year
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heat input, the energy assessment must comprise the boiler 

system and any energy use system accounting for at least 20 

percent of the energy output to identify energy savings 

opportunities.

We have also added a definition for "energy use systems" to 

clarify the components, in addition to the boiler system, which 

must be considered during the energy assessment.

E. Revised Subcategory Limits

The MACT emission limits for the coal subcategory have been 

revised based on the revised MACT floor approach (see Section V 

of this preamble). The revised limits ensure that the MACT 

floors can be achieved by all units within a subcategory using 

appropriate emission reduction strategies, and reflect 

achievable emissions reductions for boilers of varying 

capacities.

The proposed rule set emission limits for PM (as a 

surrogate for the individual urban metal HAP) for all new area 

source boilers and CO (as a surrogate pollutant for the 

individual urban organic HAP) for all new area source boilers 

and for existing area source boilers with a heat input capacity 

of 10 MMBtu/h or greater. The proposed rule also set emission 

limits for mercury from new and existing coal-fired boilers. 
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In this final rule, the emission limits for mercury and CO 

have been revised for existing coal-fired boilers with a heat 

input capacity greater than 10 MMBtu/h. The MACT emission 

limits for the coal subcategory have been revised based on the 

revised MACT floor approach (see Section V of this preamble). 

Existing boilers in the biomass and oil subcategories are not 

required to meet emission limits for CO in this final rule; 

these units must meet the management practice standards of 

implementing a boiler tune-up program.

In this final rule, the PM emission limits for new area 

source boilers have been revised based on the size category. 

For new boilers in the coal, biomass, and oil subcategories with 

a heat input capacity less than 10 MMBtu/h, GACT is a management 

practice of a tune-up. For new boilers between 10 and 30 

MMBtu/h heat input, the PM limit has been revised to reflect the 

performance of GACT, which is a multiclone. The emission limits 

for mercury and CO have been revised for new and existing coalfired boilers with a heat input capacity greater than 10 

MMBtu/h. Existing and newNew boilers in the biomass and oil 

subcategories are not required to meet emission limits for CO in 

this final rule; these units must meet the management practice 

standards in Table 2 of 40 CFR part 63, subpart JJJJJJ. of a 
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tune-up.

Table 2 of this preamble summarizes the revised emission 

limits for each pollutant for each subcategory. 

Table 2. Revised Emission Limits for Subpart JJJJJJ

Subcategory

Heat Input 

(MMBtu/hr) Pollutant

Proposed 

Emission 

Limit

Final Emission 

Limit

New coalfired 

boiler

≥ 30 Particulate 

Matter

Mercury

Carbon 

Monoxide

0.03 lb 

per MMBtu 

of heat 

input.

0.000003 

lb per 

MMBtu of 

heat 

input.

310 ppm 

by volume 

on a dry 

basis 

corrected 

to 7

percent 

oxygen.

0.03 lb per MMBtu 

of heat input.

0.0000048 lb per 

MMBtu of heat 

input.

400 ppm by volume 

on a dry basis 

corrected to 3

percent oxygen.

Mercury 0.000003 

lb per 

MMBtu of 

heat 

input.

0.0000048 lb per 

MMBtu of heat 

input.

Carbon 

Monoxide

310 ppm 

by volume 

on a dry 

basis 

corrected 

to 7

400 ppm by volume 

on a dry basis 

corrected to 3 

percent oxygen.

Formatted Table

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percent 

oxygen.

≥ 10 

and < 30

Particulate 

Matter

Mercury

Carbon 

Monoxide

0.03 lb 

per MMBtu 

of heat 

input.

0.000003 

lb per 

MMBtu of 

heat 

input.

310 ppm 

by volume 

on a dry 

basis 

corrected 

to 7

percent 

oxygen.

0.42 lb per MMBtu 

of heat input.

0.0000048 lb per 

MMBtu of heat 

input.

400 ppm by volume 

on a dry basis 

corrected to 3

percent oxygen.

.

Mercury 0.000003 

lb per 

MMBtu of 

heat 

input.

0.0000048 lb per 

MMBtu of heat 

input.

Carbon 

Monoxide

310 ppm 

by volume 

on a dry 

basis 

corrected 

to 7

percent 

oxygen.

400 ppm by volume 

on a dry basis 

corrected to 3

percent oxygen
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New 

biomassfired 

boiler

≥ 30 Particulate 

Matter

Carbon 

Monoxide

0.03 lb 

per MMBtu 

of heat 

input.

100 ppm 

by volume 

on a dry 

basis 

corrected 

to 7 

percent 

oxygen.

0.03 lb per MMBtu 

of heat input.

Management 

Practice Standards 

(see Table 2 to 

subpart JJJJJJ)

Carbon 

Monoxide

100 ppm 

by volume 

on a dry 

basis 

corrected 

to 7 

percent 

oxygen.

Management 

Practice Standards 

(see Table 2 to 

subpart JJJJJJ)

≥ 10 

and < 30

Particulate 

Matter

Carbon 

Monoxide

0.03 lb 

per MMBtu 

of heat 

input.

100 ppm 

by volume 

on a dry 

basis 

corrected 

to 7 

percent 

oxygen.

0.07 lb per MMBtu 

of heat input.

Management 

Practice Standards 

(see Table 2 to 

subpart JJJJJJ)

Carbon 

Monoxide

100 ppm 

by volume 

on a dry 

basis 

corrected 

to 7 

percent 

oxygen.

Management 

Practice Standards 

(see Table 2 to 

subpart JJJJJJ)

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New oilfired 

boiler

≥ 30 Particulate 

Matter

Carbon

Monoxide

0.03 lb 

per MMBtu 

of heat 

input.

1 ppm by 

volume on 

a dry 

basis 

corrected 

to 3 

percent 

oxygen.

0.03 lb per MMBtu 

of heat input.

Management 

Practice Standards 

(see Table 2 to 

subpart JJJJJJ)

Carbon

Monoxide

1 ppm by 

volume on 

a dry 

basis 

corrected 

to 3 

percent 

oxygen.

Management 

Practice Standards 

(see Table 2 to 

subpart JJJJJJ)

≥ 10 

and < 30

Particulate 

Matter

Carbon

Monoxide

0.03 lb 

per MMBtu 

of heat 

input.

1 ppm by 

volume on 

a dry 

basis 

corrected 

to 3 

percent 

oxygen.

0.03 lb per MMBtu 

of heat input.

Management 

Practice Standards 

(see Table 2 to 

subpart JJJJJJ)

Carbon

Monoxide

1 ppm by 

volume on 

a dry 

basis 

corrected 

to 3 

percent 

oxygen.

Management 

Practice Standards 

(see Table 2 to 

subpart JJJJJJ)

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Existing 

coal-Fired 

boiler

≥ 10 Mercury 0.000003

lb per 

MMBtu of 

heat 

input.

0.000012 lb per 

MMBtu of heat 

input.

Existing 

coal-Fired 

boiler

≥ 10 Mercury

Carbon

Monoxide

0.000003

lb per 

MMBtu of 

heat 

input.

310 ppm 

by volume 

on a dry 

basis 

corrected 

to 7

percent 

oxygen.

0.000012 lb per 

MMBtu of heat 

input.

400 ppm by volume 

on a dry basis 

corrected to 3 

percent oxygen.

Existing 

biomassfired 

boiler

Carbon 

Monoxide

160 ppm 

by volume 

on a dry 

basis 

corrected 

to 7 

percent 

oxygen.

Management 

Practice Standards 

(see Table 2 to 

subpart JJJJJJ)

Existing 

coal-fired 

boiler

Carbon 

Monoxide

2 ppm by 

volume on 

a dry 

basis 

corrected 

to 3

percent 

oxygen.

Management 

Practice Standards 

(see Table 2 to 

subpart JJJJJJ)

F. Demonstrating Compliance

We have revised the compliance dates for existing affected 

sources according to the applicable provisions for each affected 

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source (e.g., work practice standards, emission limits, 

management practice standards, and/or an energy assessment). 

Under the proposed rule, owners and operators of existing 

sources would have had to comply with this final rule within 3 

years following [INSERT THE DATE OF PUBLICATION OF THIS FINAL 

RULE IN THE FEDERAL REGISTER]. This final rule requires that if 

you own or operate an existing source subject to a work practice 

or management practice standard of a tune-up, you must comply 

with this final rule no later than [INSERT THE DATE 1 YEAR AFTER 

THE DATE OF PUBLICATION OF THIS FINAL RULE IN THE FEDERAL 

REGISTER]. If you own or operate an existing source subject to 

an emission limit or an energy assessment requirement, you must

comply with this final rule no later than [INSERT THE DATE 3 

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

As under the proposed ruleOF THIS FINAL RULE IN THE FEDERAL 

REGISTER]. Under the proposed rule, the owner or operator of a 

new source would have been required to comply on the date of 

publication of the final rule or upon startup of the facility, 

which ever was later. Because this rule is subject to the 

Congressional Review Act, the owner or operator of a new source 

is required to comply on [INSERT THE DATE 60 DAYS AFTER THE DATE 

OF PUBLICATION OF THIS FINAL RULE IN THE FEDERAL REGISTER] or 

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upon startup of the facility, whichever is later. 

Additionally, we have clarified the compliance requirements 

for commercial and industrial solid waste incineration units 

subject to 40 CFR part 60, subpart CCCC or subpart DDDD that 

cease combusting solid waste and become subject to Subpart 

JJJJJJ. Owners and operators of commercial and industrial solid 

waste incineration units must be in compliance with this 

subpart on the effective date of the waste to fuel switch (at 

least 12 months from the date that the owner or operator ceased 

combusting solid waste), if the effective date is after the 

applicable compliance dates discussed above.

We have also revised the proposed continuous compliance 

requirementrequirements to be consistent with changes to the 

emission limits in this final rule, and are no longer requiring

CO CEMS for biomass, oil, and coal-fired units to be consistent 

with changes to the emission limits in this final rule. For new 

and existing coal units with a heat input capacity greater than 

10 MMBtu/h, we are requiring annual stack testing to demonstrate 

compliance with the CO emission limits. Because boilers in the 

biomass and oil subcategories are only required to meet the 

management practice standards in Table 2 of 40 CFR part 63, 

subpart JJJJJJ, no testing for CO emissions is required for 
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these units. 

G. Affirmative Defense

We have added provisions to this final rule to include an 

affirmative defense to civil penalties for exceedances of 

emission limits that are caused by malfunctions. Consistent 

with Sierra Club v. EPA, EPA has established standards in this 

rule that apply at all times. However, in response to an action 

to enforce the standards set forth in 40 CFR 63.11201, you may 

assert an affirmative defense for exceedances of such standards 

that are caused by malfunction, as defined at 40 CFR 63.2. (See 

40 CFR 63.11226 (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). The included provisions specify the elements that 

are necessary to establish an affirmative defense for periods of 

malfunction, including evidence and notification requirements 

that must be prepared by the source.

H. Technical/Editorial Corrections

In this final action, we are making a number of technical 

corrections and clarifications to subpart JJJJJJ. These changes 
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improve the clarity and procedures for implementing the emission 

limitations to affected sources. We are also clarifying several 

definitions to help affected sources determine their 

applicability. We have modified some of the regulatory language 

that we proposed based on public comments.

We made several changes to the initial compliance 

demonstration requirements. We revised 40 CFR 63.11211(a) to 

clarify that sources using a second fuel only for start up, 

shutdown, and/or transient flame stability are still considered 

to be sources using a single fuel. We deleted 40 CFR 

63.11210(b) to remove the requirement that boilers with a heat 

input capacity above 100 MMBtu/h are required to demonstrate 

compliance by conducting a performance evaluation of their CO 

CEMS. 

We made a change to the monitoring requirements in 40 CFR 

63.11225 (40 CFR 63.11224 in the proposed rule). We deleted

paragraph (e) to remove the requirement that boilers having a 

heat input capacity of 100 MMBtu/h and subject to a CO limit to 

install a CO CEMS.

In response to comments asking for clarification, we have 

added definitions to 40 CFR 63.11237 for “Annual heat input 

basis,” “Energy use system,” “Hot water heater,” “Minimum 
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scrubber pressure drop,” “Minimum voltage or amperage,” 

“Qualified energy assessor,” and “Solid fossil fuel.” We have 

also revised several definitions in that section based on public 

comments. For example, we revised the definition of 

“boilerBoiler” to describe what is meant by the term “controlled 

flame combustion” as used in that definition.

Several of the definitions in 40 CFR 64.11237 were revised 

to clarify the types of equipment to which different standards 

apply. For example, the definition of “Waste heat boiler” was 

revised to remove the criteria that 50 percent of total rated 

heat input capacity had to be from waste gases.supplemental 

burners. We also revised the definition of “Natural gas” to 

include gas derived from naturally occurring mixtures found in 

geological formations as long as the principal constituent is 

methane, consistent with the definition provided in 40 CFR part 

60 subpart Db. A definition of propane, was also incorporated 

into the definition of natural gas.

V. Significant Area Source Public Comments and Rationale for 

Changes to Proposed Rule
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This section contains a brief summary of major comments and 

responses. EPA received many comments on this subpart covering 

numerous topics. EPA’s responses to all comments, including 

those below, can be found in the comment response document for 

Area Source Industrial, Commercial, and Institutional Boilers in 

the docket.

A. Legal and Applicability Issues

Section 112(c)(6) of the CAA

Comment: Some commenters stated that EPA misinterpreted 

the statute in using MACT instead of GACT for area sources. 

These commenters argued that the statute allows for setting a

standard under CAA section 112(d)(2) that can be satisfied using 

the alternative GACT procedure specified in CAA section

112(d)(5) to meet the 112(c)(6) requirements. 

Response: We disagree with the comment that the CAA gives 

EPA discretion to promulgate GACT standards pursuant to section 

112(d)(5) for area source categories required to be regulated 

under section 112(c)(6). Section 112(c)(6) of the CAA 

explicitly requires that “sources accounting for not less than 

90 per centum of the aggregate emissions of each [pollutant 

specified in this provision] are subject to standards under 

subsection 112(d)(2) or (d)(4)....” (Emphasis added). The plain 
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language of section 112(c)(6) requires that the Agency set 

standards under section 112(d)(2) or (d)(4). There is no 

ambiguity in this language and thus the legislative history 

cited by the commenter is irrelevant. As such, the Agency is 

appropriately setting standards for the sources at issue 

pursuant to section 112(d)(2).

The commenter argues that section 112(d)(5) trumps the very 

specific language in section 112(c)(6). We disagree. Congress 

unambiguously required the Agency to set standards for these 

persistent, bioaccumulative HAP under section 112(d)(2) or 

(d)(4). Had Congress wanted us to permit EPA to issue GACT 

standards for the 112 (c)(6) HAP, it would have said that EPA 

could issue standards under section 112(d), as it did in section 

112(k)(3)(B) of the Act, noting that area sources shall be 

subject to standards issued pursuant to “subsection (d) of this

section.” Congress could not have been more precise in section 

112(c)(6), and we reject the commenter’s interpretation. 

EPA has consistently maintained that standards under 

section 112(d)(2) or (d)(4) are required for the pollutants 

listed in section 112(c)(6). In this case, we are setting a 

section 112(d)(2) MACT standard for mercury and CO (as a 

surrogate for POM) for coal-fired area source boilers, which are
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the 112(c)(6) pollutants that formsform the basis for the 

listing of the source category at issue here.

Comment: One commenter argued that EPA did not provide 

justification for its decision that mercury and POM must be 

regulated pursuant to CAA section 112(c)(6) at area source 

boilers to satisfy the requirements that 90 percent of 

nationwide emissions of these pollutants must be reduced. The 

commenter further stated that the proposed rule and supporting 

documentation provide no rationalerational basis or adequate 

factual justification for the need to regulate area source POM 

or mercury emissions to satisfy CAA section 112(c)(6). 

Specifically, the commenter stated that neither the proposed 

rule nor the MACT floor memo provide data that support the 

proposed determination that 90.3 percent of the 1990 emissions 

inventory for mercury is already subject to regulation. In 

contrast, another commenter said that, once a category is listed 

under CAA section 112(c)(6), the only procedure available to EPA 

for refraining from promulgating a MACT-based standard for the 

category is to remove the category from the CAA section 112(c) 

list through the use of CAA section 112(c)(9), regardless of 

whether the category is needed to meet the 90 percent 

requirement in CAA section 112(c)(6). 
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Response: The statute does not limit EPA’s discretion as 

to how it fulfills its obligations under CAA section 112(c)(6). 

To the extent that the commenters seek to challenge whether EPA 

has selected appropriate categories to meet its obligations 

under CAA section 112(c)(6) or whether EPA has met the 

requirement in CAA section 112(c)(6) to regulate categories 

emitting at least 90 percent of the specified pollutants (in 

this case, mercury and POM), such challenges should not be 

reviewed in the context of a review of an individual NESHAP. 

Rather, if review is appropriate, it should be in the context of 

an EPA finding that it has fulfilled its obligations under CAA 

section 112(c)(6), and an accounting by the agency of how it 

reached the 90 percent threshold for each pollutant. 

Nevertheless, the docket for this rulemaking contains a 

spreadsheet that demonstrates our belief that we have met the 90 

percent requirement for POM and for mercury with this final 

rule.

While we are promulgating GACT-based provisions at this 

time for not only mercury but alsoand POM from biomass-fired and 

oil-fired area source boilers, note that we have not removed or 

“delisted” oil-fired and biomass-fired area source boilers by 

this action. We simply are not promulgating MACT-based 
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regulations at this time because they are unnecessary to meet 

the requirements of CAA section 112(c)(6). 

Comment: Comments received suggested EOM was not 

appropriate for representing POM emissions. The commenters 

noted a drawback to using EOM as a surrogate for POM is the 

limited amount of data available to quantify 

emissions,emissionsand the few EOM inventories or emission 

factors exist, andin existence. Commenters also stated that EOM 

includes other extractible organics in addition to the PAHs. 

The commenters suggest that the reasonable assumption is that 

any observed health effects come from the PAH factionfraction

and since EOM includes compounds other than PAH, it should not 

be used as a surrogate for POM. 

Response: This issue primarily affects whether biomassfired and oil-fired boilers are needed to meet the CAA section 

112(c)(6) requirements. EPA has considered commenter input and 

revised the final rule based on our analysis of existing and new 

data submitted during the public comment period.re-examination

of our section 112(c)(6) baseline inventory for POM. As we 

noted in the proposed rule, we reexamine the inventory 

associated with the original listing as we learn more about the 

source category in the rule development process. (75 FR 
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31904.). Based on a re-examination of the emission inventory in 

light of comments, we have determined that we only neededneed to 

address the coal-fired portion of the area source segments of 

these categories under CAA section 112(c)(6) in order to meet 

the 90 percent threshold requirement of that provision for both 

mercury and POM. 

As discussed in the preamble to the June 2010 proposed rule 

(75 FR 31896), we have determined that we must regulate mercury 

and POM from coal-fired area source boilers in order to meet the 

requirements in CAA section 112(c)(6), and we are establishing

MACT-based limits for mercury and POM (using CO as a surrogate) 

for this subcategory. We are implementing work practice 

standards, as allowed by CAA section 112(h), for control of 

mercury and POM from new and existing area source boilers in the 

coal subcategory with a designed heat input capacity less than 

10 MMBtu/h. 

In the CAA section 112(c)(6) source listing, we used three 

indicators (7-PAH, 16-PAH, and extractable organic matter (EOM)) 

were used to represent POM emissions. While it was possible to 

attain the 90 percent threshold for 7-PAH and 16-PAH by 

promulgating MACT-based regulations only for coal-fired area 

source boilers and without regulating biomass-fired and oil-
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fired boilers under MACT, we believed at the time of proposal 

that we needed to promulgate MACT-based limits for biomass-fired 

and oil-fired boilers in order to ensure that the 90 percent 

threshold for our third POM indicator, EOM, would be met. In 

our proposed rule, we used CO as a surrogate for allcompiled

three separate baseline inventories for POM, one for each 

indicators of POM because we believed low CO levels were 

indicators of good combustion, which was our method of control 

for POM. The proposed CO limits were based on MACT because all 

types of area source boilers were, at that time, thought to be 

needed to meet our CAA. In light of the comment described above 

regarding EOM, we re-examined our three section 112(c)(6) 

obligationsbaseline inventories for POM.

We For the reason stated below, we have analyzed these 

comments and determined that EOM should not be used as one of 

the indicators for POM. decided to use only the baseline 

inventory for 16-PAH in determining the 90 percent threshold 

under section 112(c)(6).

We agree with the commenters who have identified data gaps 

in our knowledge of what source categories are emitting EOM. 

There are While we have data on 16-PAH emissions estimates for 

16-PAH for many more94 categories than there are estimates for, 

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we only have available data on EOM. The use of 16-PAH allows 

for the most accurate representation of the universe of 

categories that emit POM and which are needed to meet our 90 

percent requirement. The 16-PAH inventory has emissions 

estimates for over four times as many sources as EOM and three 

times as many as 7-PAH.

While the relatively few estimates of 7-PAH would suggest 

simply relying on 16-PAH as an indicator for POM, both 7-PAH and 

16-PAH include the compounds with the most well established 

links to adverse health effects. In contrast, EOM includes 

extractible organic matter that is not POM (in fact, most of it 

not POM). It is unclear whether the health effects of EOM are 

due to the PAH component captured by the other measures of POM 

or due to non-POM compounds. In short, we cannot say EOM is a 

good surrogate for the health effects of POM.

In our judgment, the for 18 source categories. The lack of 

available data on EOM emission estimates for EOM creates a 

distorted picture of the relative contributions of source 

categories for which there are available EOM estimatesdata. The 

lack of source categories making up the total EOM inventory 

makes the relative contribution of the few categories that do 

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have data unrealistically inflated.2

We have analyzed these comments and determined, 

considerably fewer than the 94 categories for which we have 16-

PAH data. Because the 16-PAH inventory allows for the most 

accurate representation of the universe of categories that emit 

POM, we have decided to use that EOM should not be used as one 

of the indicatorsbaseline inventory for determining the 90 

percent threshold for POM. Therefore, we re-examined the 

emission inventory using PAH (7-PAH and 16-PAH) as the 

indicator. under section 112(c)(6). Based on this reexaminationthe baseline inventory for 16-PAH, regulating POM 

emissions from area source biomass and oil boilers are not 

needed to meet the CAA section 112(c)(6) obligations. Thus, POM 

emissions from area source boilers in the biomass and oil 

 We therefore cannot say 

with confidence that by using EOM as an indicator the baseline 

inventory for POM thatEOM we are capturing a significant 

percentage90 percent of either EOM emittedthe baseline POM 

emissions, as required by allsection 112(c)(6). Similarly, we 

have data on 7-PAH for 32 categories or POM emissions.

 

2 When justifying its use in the 1998 inventory, we said that EPA 

would undertake an effort to develop a robust inventory for EOM 

sources to feed into the CAA section 112(c)(6) inventory. Had 

more data been gathered, perhaps EOM would have proved to be a 

more useful indicator of POM. However, the anticipated 

inventory was not developed. 

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subcategories can be regulated under GACT, instead of MACT.

With respect to mercury and POM from area source boilers 

classified as biomass-fired or oil-fired, as well as with 

respect to other urban HAP besides POM, we have revised the 

final rule standards to reflect GACT for these two area source 

subcategories (see Section IV.B of this preamble). We are 

implementing management practice standards, as allowed by CAA 

section 112(d)(5), for control of POM from new and existing area 

source boilers in the biomass and oil subcategories. The 

management practice standard for new and existing area source 

boilers requires the implementation of a tune-up program. 

As stated previously in the preamble to the June 2010 

proposed rule, we determined that the control technologies 

currently used by facilities in the source category to reduce 

non-mercury metallic HAP and PM (multiclone, fabric filters, and 

ESP) are generally available and cost effective for new area 

source boilers. Additionally, these controls are commonly 

required by state and other federal regulations that apply to 

the area source boilers in the source category. Therefore, we 

are establishing numeric emission limits representing GACT for 

all new area source boilers with a heat input capacity greater 

than 10 MMBtu/hrh (using PM as a surrogate). 
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Emission Standards for HAP Other than Mercury

Comment

The commenter said that EPA appears to believe that because 

area source boilers are needed only to reach the section 

112(c)(6) requirement of 90 percent for mercury and POM and not 

for the other pollutants enumerated in section 112(c)(6), EPA’s 

only obligation under section 112(c)(6) is to set section 

112(d)(2) standards for mercury and POM. The commenter said 

that section 112(c)(6) expressly requires EPA to issue section 

: One commenter stated that CAA section 112(c)(6) 

provides that EPA must “list categories and subcategories of 

sources assuring that sources accounting for not less than 90 

percent of each [enumerated] pollutant are subject to standards 

under subsection (d)(2) or (d)(4) of this section.” The 

commenter also stated that the D.C. Circuit has held repeatedly 

that when EPA sets standards for a category or subcategory of 

sources under section 112(d)(2), EPA has a statutory duty to set 

emission standards for each HAP that the sources in that 

category or subcategory emit. The commenter concluded that when 

EPA sets standards for area source boilers under section 

112(d)(2), as section 112(c)(6) requires it to do, EPA must set 

section 112(d)(2) emission standards for all the HAP that area 

source boilers emit. 
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112(d)(2) standards for the “sources” in the categories listed 

under section 112(c)(6), not some subset of the pollutants that 

those sources emit, and that section 112(d)(2) standards must 

include emission standards for each HAP that a source category 

emits. The commenter continued by stating that nothing in the 

CAA exempts EPA from this requirement. The commenter concluded 

that, had Congress wished to give EPA discretion to set 

standards for only some of the pollutants emitted by a category 

listed under section 112(c)(6), it would have done so expressly.

Response: EPA disagrees with the comment that, even though 

EPA lists a category under section 112(c)(6) due to the 

emissions of one or more HAP specified in that section, EPA must 

issue emission standards for all HAP (including HAP not listed 

in section 112(c)(6)) that sources in that category emit. The 

commenter cited in support the opinion by the United States 

Court of Appeals for the D.C. Circuit in National Lime Ass’n v. 

EPA, 233 F.3d 625, 633-634 (D.C. Cir. 2000)). The part of the 

National Lime opinion referenced in the comment dealt with EPA’s 

failure to set emission standards for certain HAP emitted by 

major sources of cement manufacturing because the Agency found 

no sources using control technologies for those HAP. In 

rejecting EPA’s argument, the court stated that EPA has “a 

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statutory obligation to set emission standards for each listed 

HAP.” Id. at 634. The Court noted the list of HAP in section 

112(b) and stated that section 112(d)(1) requires that EPA 

“promulgate regulations establishing emission standards for each

category or subcategory of major sources ... of hazardous air 

pollutants listed for regulation..” Id. (Emphasis added). For 

the reasons stated below, we do not believe that today’s final 

rule is controlled by or otherwise conflicts with the National 

Lime decision.

National Lime did not involve section 112(c)(6). That 

provision is ambiguous as to whether standards for listed source 

categories must address all HAP or only the section 112(c)(6) 

HAP for which the source category was listed. Section 112 

(c)(6) requires that “sources accounting for not less than 90 

per centum of the aggregate emissions of each such [specific] 

pollutant are subject to standards under subsection (d)(2) or 

(d)(4).” This language can reasonably be read to mean standards 

for the section 112(c)(6) HAP or standards for all HAP emitted 

by the source. Under either reading, the source would be 

subject to a section 112(d)(2) or (d)(4) standard.

The commenter insists that once a section 112(d)(2) 

standard comes into play, all HAP must be controlled (per 

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National Lime). But this result is not compelled by the 

pertinent provision, section 112(c)(6). That provision is 

obviously intended to ensure controls for specific persistent, 

bioaccumulative HAP, and this purpose is served by a reading 

which compels regulation under section 112(d)(2) only of the HAP 

for which a source category is listed under section 112(c)(6), 

rather than for all HAP. 

The facts here support the reasonableness of EPA’s 

approach. Area source boilers are included in source categories

listed under section 112(c)(6) for regulation under section 

112(d)(2) solely due to its mercury and POM emissions. There is 

special statutory sensitivity to regulation of area source 

categories in section 112. For example, an area source category 

may be listed for regulation under section 112 if EPA makes an 

adverse effects finding pursuant to Section 112(c)(3) or if EPA 

determines that the area source category is needed to meet its 

section 112(c)(3) obligations to regulate urban HAP or its 

section 112(c)(6) obligations to regulate certain persistent 

bioaccumulative HAP. Moreover, to the extent EPA lists an area 

source category pursuant to section 112(c)(3) (whether that 

finding is based on adverse effects to human health or the 

environment or a finding that the source is needed to meet the 
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90 percent requirement in section 112(c)(3),)), the statute 

gives EPA discretion to set GACT standards for such sources. 

(42 U.S.C. 7412(d)(5).)). 

EPA does not interpret section 112 (c)(6) to create a means 

of automatically compelling regulation of all HAP emitted by 

area sources unrelated to the core object of section 112(c)(6), 

which is control of the specific persistent, bioaccumulative 

HAP, and thereby bypassing these otherwise applicable 

preconditions to setting section 112(d) standards for area 

sources. Nor does National Lime address the issue, since the 

case dealt exclusively with major sources. (233 F. 3d at 

633.). Consequently, EPA disagrees with the comment that it is 

compelled to promulgate section 112(d)(2) MACT standards for all 

HAP emitted by area source boilers.

We are promulgating the proposed standard requiring the 

performance of an energy assessment for existing area source 

facilities having an affected boiler with a designed heat input 

capacity of 10 MMBtu/h or greater. This final rule requires the 

performance of an energy assessment, by qualified personnel, on 

the boiler and its energy use systems to identify cost-effective 

energy conservation measures. As discussed in the June 2010 

Beyond-the-floor option
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proposed rule, an energy assessment provides valuable 

information on improving energy efficiency. Owners and 

operators are encouraged, but not required, to use the results 

of the energy assessment to increase the energy-efficiency and 

cost-efficiency of their boiler system.

In the proposed rule, the energy assessment requirement was 

a beyond-the-floor option for the MACT-based mercury and CO 

emission standards because additional emission reductions would 

be realized as the results of these energy assessments., if 

implemented. In this final rule, the energy assessment 

requirement is both a beyond-the-floor control for the MACTbased standards for the coal subcategory and a GACT for the 

biomass and oil subcategory because energy assessments are 

generally available and have already been performed at numerous 

facilities.

The principleprincipal arguments against an energy

assessment requirement are: 1) EPA lacks authority to impose 

requirements on portions of the source that are not designated 

as part of the affected source, such as non-emitting energy 

using systems at a facility; 2) EPA has not quantified the 

reductions associated with the energy assessment requirement, 

therefore it cannot be "beyond the floor;" and 3) the bare 
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requirement to perform an audit without being required to 

implement its findings is not a standard under CAA section 

112(d). 

With respect to the first argument, we have carefully 

limited the requirement to perform an energy auditassessment to 

specific portions of the source that directly affect emissions 

from the affected sourceboiler, as indicated by the revised 

definition of an energy assessment in section 63.11237 of 

subpart JJJJJJ. The emissions that are being controlled come 

from the affected source. For coal-fired units, the process 

changes resulting from a change in an energy using system will 

reduce the volume of emissions at the affected source. For 

biomass-fired and oil-fired area sources, better management 

practices at energy using systems will reduce the emissions of 

HAP from the affected source by reducing fuel consumption and 

the HAP released through combustion of fuel. In either case, 

the requirement controls the emissions of the affected source. 

With respect to the second argument, the energy assessment 

will generate emission reductions through the reduction in fuel 

use beyond those required by the floor. While the precise 

quantity of emission reductions will vary from source to source 

and cannot be precisely estimated, the requirement is clearly 
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directionally sound and thus consistent with the requirement to 

examine beyond the floor controls. By definition, any emission 

reduction would be cost effective or else it would not be 

implemented. 

Finally, with respect to the third argument, the 

requirement to perform the energy audit is, of course, a 

requirement that can be enforced and thus a standard. As noted, 

while we do not know the precise reductions that will occur at 

individual sources, the record indicates that energy assessments 

reduce fuel consumption and that parties will implement 

recommendations from an auditor that they believe are prudent.3

 

Therefore, the requirement to perform an energy assessment can 

both be enforced and will result in emission reductions.

Comment: Commenters stated that setting work practice 

standards in lieu of emission standards for area source boilers 

with a heat input capacity less than 10 MMBtu/h is unlawful and 

arbitrary. Commenters cited EPA’s determination with respect to 

Section 112(h) of the CAA

 

3 Case studies and success stories highlighting energy savings 

achieved by companies that have participated in Save Energy Now

energy assessments and used Industrial Technologies Program 

software tools to improve energy efficiency can be found at 

http://www1.eere.energy.gov/industry/saveenergynow/case_studies.

html and at the Department of Energy’s Energy Assessment Centers 

Database http://iac.rutgers.edu/database.
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the technical and economic limitations on the enforcement of 

emission standards for boilers with heat input capacity less 

than 10 MMBtu/h, and stated that these limitations do not 

satisfy CAA section 112(h) conditions for setting work practice 

standards in lieu of emission standards. Some commenters argued 

that the technical limitations of measuring PM using Method 5, 

as discussed in the preamble to the proposed June 2010 rule, do 

not apply to mercury and CO. Other commenters remarked that the 

absence of sampling ports and stacks at area source boilers does 

not provide a basis for a technical or economic limitation, 

stating that sources are able to work around this issue. 

Multiple commenters said that the lack of measuring ports (which 

can affect retrofitting new boiler installations into existing 

buildings), other design requirements for efficient exhaust from 

smaller boilers, and the inapplicability of approved test 

methods would make measurement technically and economically 

impractical for both existing and new sources. Commenters 

specifically cited CAA section 112(h)(1) and (2), which allows 

the agency to prescribe work practice standards only if it is 

“not feasible to prescribe or enforce an emission standard.... 

due to technological or economic limitations.” 

Response: EPA disagrees with commenters. As discussed in 
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the preamble to the June 2010 proposed rule, CAA section 112(h) 

authorizes the Administrator to promulgate “a design, equipment, 

work practice, or operational standard, or combination thereof,” 

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 prescribe or enforce an emission standard. CAA 

section 112(h)(2)(B) further defines the term “not feasible” to 

mean when “the application of measurement technology to a 

particular class of sources is not practicable due to 

technological and economic limitations.” We have elected to 

implement work practice standards for coal-fired boilers with a 

heat input capacity of less than 10 MMBtu/h because we have 

determined that the standard reference methods for measuring 

emissions of mercury, CO (as a surrogate for POM), and PM (as a 

surrogate for urban non-mercury metals) are not applicable for 

sampling small diameter (less than 12 inches) stacks. 

Furthermore, through the comment process, we have learned that 

common, very small boilers (less than 5 MMBtu/h) typically 

exhaust through vents and not stacks, and that the 

instillationinstallation of ports into small diameter 

stacksvents for smaller boilers would likely interfere with the 

functionality of exhaust systems for new and existing boilers. 
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Because many existing area source boilers with a capacity below 

10 MMBtu/h generally have stacks with diameters less than 12 

inches, and because many area source boilers do not currently 

have sampling ports or a platform for accessing the exhaust 

stack, we have determined that the testing and monitoring costs 

that area source boiler facilities would incur to demonstrate 

compliance with the proposed emission limits would present an 

excessive burden for smaller sources. Thus, we are establishing 

work practice standards to limit the emissions of mercury and CO 

(as a surrogate for POM) for existing and new coal-fired area 

source boilers having a heat input capacity of less than 10 

MMBTU/h.

De minimis Levels

Comment: Several commenters stated that EPA should 

establish a de minimis heat input level (less than 1 MMBtu/h 

heat input capacity) below which area sources are not subject to 

regulation or only subject to work practice standards. These 

commenters referenced water heaters and small comfort heating 

units that are not used in industrial, commercial, or 

institutional processes but instead used to provide hot water 

for personal use or seasonal comfort heating. Other commenters 

noted that State rules that require work practice requirements 
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for boilers all have a lower limit on applicability of typically 

1 to 5 MMBtu/hrh; these commenters stated that EPA has provided 

no basis for applying work practice standards to boilers of this 

size.

Response: EPA must establish standards for each category 

or subcategory of major sources and area sources of HAP listed 

pursuant to CAA section 112(c). EPA may distinguish among 

classes, types, and size in establishing such standards but the 

standards established must be applicable to new and existing 

sources of HAP within the category. However, we agree with the 

commenters that the categories of boiler covered by this rule 

are industrial boilers, commercial boilers, and institutional 

boilers. In the proposed rule, we did not list hot water 

heaters as exempted as we did in the proposed Boiler MACT for 

major sources. As stated in the preamble to the proposed Boiler 

MACT, hot water heaters meet the definition of a boiler but are 

more appropriately described as residential-type boilers, not 

industrial, commercial, or institutional boilers because their 

output is intended for personal use rather than for use in an 

industrial, commercial, or institutional process. The primary 

reason for exempting hot water heaters in the Boiler MACT was

that hot water heaters are not part of the listed source 
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category. Because hot water heaters generally use natural gas

and gas-fired boilers were not part of the area source category, 

we did not include a similar exemption in the proposed rule. To 

be consistent with the Boiler MACT, we have included in this 

final rule a similar exemption and definition for hot water 

heaters.

B. CO Limits

Comment: Multiple commenters argued that EPA’s 

determination of using CO as a surrogate for POM is 

inappropriate. Several of these commenters reiterated that 

there is no reliable correlation between CO and POM. Some 

commenters stated that CO is not an appropriate surrogate for 

POM or organic HAP at lower CO emission levels. For instance, 

one commenter stated that while there is a linear correlation 

between decreasing CO and decreasing HAP at higher levels, once 

CO values fall under 100 ppm, further reduction of CO does not 

provide any substantial correlating reduction of HAP. Other 

commenters stated that CO is an inadequate surrogate for POM 

because there is no POM invariably present in CO; likewise, 

commenters stated that because CO and POM have different 

mechanisms of formation and reduction, CO cannot be considered 

as a reliable surrogate. 
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Several commenters suggested total hydrocarbon (THC) as a 

better surrogate, stating that THC levels are often more stable 

and less reactive to load swings than CO. Commenters noted that 

THC has been used as a surrogate for organic HAP emissions in 

other regulatory efforts, including the hazardous waste 

incinerator MACT.

Response: EPA acknowledges commenters’ concerns. Based on 

new data received during the public comment period, we have reexamined our analysis and revised the final standards for CO. 

As previously discussed, this final rule only establishes CO 

emission limits for coal-fired boilers pursuant to CAA section 

112(c)(6). We are implementing management practice standards, 

as allowed by CAA section 112(d)(5), for control of CO from new 

and existing area source boilers in the biomass and oil 

subcategories. Additionally, for the coal subcategory, we have 

revised the final CO emission limits to ensure a more accurate 

correlation between POM and CO levels. EPA is aware of one 

European study4

 

4 EUROPEAN WOOD-HEATING TECHNOLOGY SURVEY: AN OVERVIEW OF

COMBUSTION PRINCIPLES AND THE ENERGY AND EMISSIONS PERFORMANCE 

CHARACTERISTICS OF COMMERCIALLY AVAILABLE SYSTEMS IN AUSTRIA, 

GERMANY, DENMARK, NORWAY, AND SWEDEN; Final Report; Prepared for 

the New York State Energy Research and Development Authority; 

NYSERDA Report 10-01; April 2010.

that finds the correlation between CO and POM (or 

organic HAP, in general) is weaker at lower CO concentrations 
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(less than 100 ppmv) but we did not have the opportunity to 

examine the data relied on by the study and no data supporting 

this supposition were submitted as part of the public comments. 

We have revised the final standards (400 ppm) based on 99.9

percent UPL as discussed in Section IV.C of this preamble. EPA 

believes that CO is a reliable surrogate for POM at this 

emission level. EPA considered using THC as a surrogate for 

POM, however, we did not have available THC data for area 

sources. 

Comment: Several commenters expressed concern with respect 

to the proposed CO limits. Some commenters stated that the 

proposed CO limits are unachievable for some units, including 

liquid-fired boilers. Commenters further stated that meeting 

the CO limits would be more burdensome for area sources than 

major sources. Specifically, many commenters argued that the CO 

limits are unfeasible from a measurement, operability, and cost 

standpoint, particularly when considered simultaneously with 

other limits (NOx, VOC). Some commenters expressed concern that 

prioritizing CO reduction may promote boiler inefficiency and 

result in higher emissions of NOx. 

Other commenters suggested that the CO emission limits 

should be determined using long-term CEMS data to account for 
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natural variability in CO emissions. Commenters also offered 

alternatives for control of POM. One commenter suggested that 

EPA consider cleaner fuels or end of stack technologies for 

control, such as fabric filters and scrubbers that capture POM 

and POM-precursors. 

Response: As discussed above, this final rule establishes 

MACT-based emission limits for CO only for new and existing 

coal-fired boilers. In this final rule, area source boilers in 

the biomass and oil-fired subcategories are not required to meet 

CO emission limits; these boilers are instead required to meet 

the management practice standard which consists of a tune-up. 

The MACT-based CO emission limits are still required for coalfired area source boilers in order to meet our obligation under 

CAA section 112(c)(6). Based on the available CO data and the 

revised UPL calculation methodology, the final CO emission 

limits for coal-fired area source boilers are higher than the 

proposed limits which should provide more assurance that the 

limit can be achieved at all times. EPA notes that the 

available dataset did not include sufficient long-term CEMS data 

for area sources to be used to set a limit. Therefore, we have 

established the CO standards based on the data provided using 

the revised UPL methodology to account for variability over the 
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operating cycle of typical industrial, commercial, and 

institutional boilers. We also considered other appropriate 

control options for sources in each subcategory, including 

switching to clean fuels and end of stack technologies. We 

considered whether fuel switching could be technically achieved

by boilers in the subcategory considering the existing design of 

boilers and the availability of various types of fuel. We

determined that fuel switching was not an appropriate control 

technology based on the overall effect of fuel switching on HAP 

emissions and the technical and design considerations discussed 

previously in the preamble to the proposed June 2010 rule (75 FR 

31896). This determination is discussed in the memorandum

“Development of Fuel Switching Costs and Emission Reductions for 

Industrial, Commercial, and Institutional Boilers and Process 

Heaters National Emission Standards for Hazardous Air Pollutants 

– Area Source” located in the docket. Additionally, EPA did not 

identify add-on control technologies available for control of CO 

in use at area source boilers. 

C. MACT Floor Analysis

Pollutant-by-pollutant approach

Comment: Several commenters argued that the pollutant-bypollutant approach used by EPA is not appropriate. Commenters 
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rejected the pollutant-by-pollutant approach on the basis that 

both PM and CO emission limits are not achievable even for the 

best performing sources. These commenters argued that because 

the proposed area source MACT standards rely on a different set 

of best performing sources for each separate HAP standard, no 

single source is in the population of units for both the PM and 

CO emission limits, and therefore, the approach does not reflect 

the performance of the best performing boilers. Rather, 

commenters asserted that the proposed limits were unrealistic, 

unnecessarily stringent, and unachievable. Commenters further 

stated that the provisions of CAA sections 112(d)(1), (2), and 

(3) of the CAA require that standards must be based on actual 

sources, and cannot be the product of pollutant-by-pollutant 

"cherry-picking." Commenters stated that EPA does not have the 

authority to “distinguish” units and sources by individual 

pollutant. Other commenters stated that EPA must set limits for 

each HAP that the sources in the subcategory emit, and not 

solely mercury or POM. These commenters stated that to ignore 

the emitted HAP violates the CAA and the court order.

Response: EPA is mindful that MACT floors must reflect 

achieved performance. EPA is also mindful that that costs 

cannot be considered by EPA in ascertaining the level of the
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MACT floor. See, e.g., Brick MACT, 479 F. 3d at 880–81, 882–83; 

NRDC v. EPA, 489 F. 3d 1364, 1376 (DC Cir. 2007) (“Plywood 

MACT”); see also Cement Kiln Recycling Coalition v. EPA, 255 F.

3d 855, 861–62 (DC Cir. 2001) (“achievability” requirement of 

CAA section 112(d)(2) cannot override the requirement that 

floors be calculated on the basis of what best performers

actually achieved). 

EPA has carefully developed data for each standard, 

assessing both technological controls and HAP inputs in doing 

so. The MACT floor variability methodology is discussed in a 

later response.

Among all boilers at area sources, only new and existing 

coal-fired ones will need to meet MACT-based limits. 

Nevertheless, it is true that at least some coal-fired area 

source boilers will need to install controls to meet these 

standards, and that these controls have significant costs. This 

is part of the expected MACT process where, by definition, the

averaged performance of the very best performers sets the 

minimum level of the standard. The Agency believes that it has 

followed the statute and applicable case law in developing its

floor methodology. Although industry commenters maintain these 

sources cannot meet the standards, which are predicated on their 
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own performance without adding controls, this contention lacks a 

basis in the record. For mercury, 6 of the 7 boilers for which 

EPA has emissions data are meeting the MACT floor standards for

mercury. For CO, 13 of the 16 boilers in the MACT pool meet the 

promulgated standard. In those instances where commenters 

provided actual data on these plants’ performance, EPA took the 

information into account in developing the final standards. 

Indeed, EPA adjusted all of the standards based on actual data

presented. We have emissions data on a limited number of area 

source units. The available information does indicate that at 

least one unit meets both the final PM and CO emission limits.

Dataset for the MACT Floor Analysis

Comment: Commenters stated numerous objections to the 

dataset used for the MACT floor analysis. Some commenters 

stated that it is inappropriate to apply limits from data 

submitted as part of the major source industrial boiler MACT ICR

to area sources. Commenters objected to EPA's assertion that 

boilers at area sources are similar in size and operation to 

major source boilers; one commenter noted that EPA did not use 

test data from area source facilities to set major source 

floors. 

Other commenters stated that the emission limits are 
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significantly flawed because they are based on inadequate data 

and not representative of the units in the source category. 

These commenters stated that the data collected is insufficient 

because it represents the performance of less than 1 percent of 

almost 183,000 existing area source boilers, particularly given 

that EPA based the analysis on the top 12 percent of units for 

which data were available. Commenters further stated that there 

was insufficient data available to establish appropriate boilertype subcategories. 

Some commenters expressed that EPA must include emissions 

data collected by Statestate and local permitting authorities in 

establishing the MACT floor; these commenters stated that these

data are more objective than the newer industry testing and are

also necessary to fill in "gaps" in the existing data. Other 

commenters requested that certain data should be excluded from 

the MACT floor analysis. For instance, some commenters stated 

that non-detect data should be excluded or that the analysis 

should be adjusted to account for the capabilities of the test 

methods. These commenters stated that the non-detect data 

results in an unreasonably low MACT floor; some commenters 

stated that the proposed limits are in some cases below the 

detection capability of the required test method. Commenters 
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also stated that EPA has not justified using three times the 

detection level in its analysis. These commenters stated that 

this method biases the results towards higher HAP emissions, 

results in a hypothetical standard that is unrealistic and not 

determined as required by statute.

Response: EPA acknowledges commenters' concerns. As 

mentioned elsewhere in this preamble, EPA is required to 

establish MACT floor levels using existing emissions 

information. For all data sets, the final emission limits are 

based on the available data and EPA’s assessment of variability. 

Since proposal we have received updated data on certain boilers 

and used that data to revise our emission estimates from the 

best performing sources. We re-evaluated the information 

available for the area source category and revised the proposed 

MACT-based CO emission limits such that they only apply to 

boilers in the coal subcategory. As discussed above, based on 

information received during the public comment period, we 

determined that regulating POM emissions from area source 

biomass and oil boilers is not needed to meet our CAA section 

112(c)(6) obligations; we only need to regulate coal-fired area 

source boilers under section 112(d)2) to meet the 90 percent 

requirement set forth in CAA section 112(c)(6) for POM. The 
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emissions limits for CO for coal-fired boilers were based on the 

available information from the ICR and state operating permits,

as well as that received in comments.

EPA disagrees with commenters who stated that we excluded 

emissions data collected by Statestate and local permitting 

authorities in establishing the MACT floor. The available 

Statestate permits obtained for coal-fired area source boilers 

limiting CO emissions were for 11 units located in Ohio (3 

units), and Illinois (8 units). We also obtained CO emission 

data from five coal-fired area source boilers as part of the 

information collection effort for the major source NESHAP. Even 

though the latter data were gathered in the course of collecting 

data on major sources, the emission data on these five boilers 

is from emission sources in the area source coal-fired boiler 

subcategory.

With respect to non-detect data, EPA considered and 

accounted for non-detect data when conducting the MACT analysis 

for mercury for existing and new coal-fired boilers in this 

final rule. EPA developed a methodology to account for the 

imprecision introduced by incorporating non-detect data into the 

MACT floor calculation. At very low emission levels where 

emissions tests result in non-detect values, the inherent 
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imprecision in the pollutant measurement method has a large 

influence on the reliability of the data underlying the MACT 

floor emission limit. Because of sample and emission matrix 

effects, laboratory techniques, sample size, and other factors, 

method detection levels normally vary from test to test for any 

specific test method and pollutant measurement. The confidence 

level that a value, measured at the detection level is greater 

than zero, is about 99 percent. The expected measurement 

imprecision for an emissions value occurring at or near the 

method detection level is about 40 to 50 percent. Pollutant 

measurement imprecision decreases to a consistent level of 10 to 

15 percent for values measured at a level about three times the 

method detection level.5

One approach that we believe can be applied to account for 

measurement variability in this situation starts with defining a 

method detection level that is representative of the data used 

in the data pool. The first step in this approach would be to 

identify the highest test-specific method detection level 

reported in a data set that is also equal to or less than the 

average emission calculated for the data set. This approach has 

 

5

American Society of Mechanical Engineers, Reference Method 

Accuracy and Precision (ReMAP): Phase 1, Precision of Manual 

Stack Emission Measurements, CRTD Vol. 60, February 2001. 
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the advantage of relying on the data collected to develop the 

MACT floor emission limit, while to some degree, minimizing the 

effect of a test(s) with an inordinately high method detection 

level (e.g., the sample volume was too small, the laboratory 

technique was insufficiently sensitive or the procedure for 

determining the detection level was other than that specified). 

The second step is to determine the value equal to three

times the representative method detection level and compare it 

to the calculated MACT floor emission limit. If three times the 

representative method detection level were less than the 

calculated MACT floor emission limit, we would conclude that 

measurement variability is adequately addressed, and we would 

not adjust the calculated MACT floor emission limit. If, on the 

other hand, the value equal to three times the representative 

method detection level were greater than the calculated MACT 

floor emission limit, we would conclude that the calculated MACT 

floor emission limit does not account entirely for measurement 

variability. ThereforeTherefore, we revised the approach we 

used for the proposal and, for the final rule, we used the value 

equal to 3 times the method detection level in place of the 

calculated MACT floor emission limit to ensure that the MACT 
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floor emission limit for mercury accounts for measurement 

variability and imprecision. 

Variability

Comment: Numerous commenters stated that the floor 

methodology used by EPA is unlawful. Some commenters criticized 

EPA's application of the UPL to all the test results for all 

sources in the top twelve percent. These commenters stated that 

while EPA can consider variability in estimating an individual 

source's performance over time, it cannot account for 

differences in performance between sources. Specifically, these 

commenters stated that EPA may only account for differences in 

performance between sources except as CAA section 112(d)(3) 

provides, by averaging the emission levels achieved by the 

sources in the top 12 percent. Commenters stated that the UPL 

is not equivalent to the "average" emission level. For 

instance, some commenters stated that the methodology for the

mercury and CO emission limits for new coal fired units does not 

reflect the emission levels achieved by the single best 

performing source; these commenters stated that the proposed 

method results in higher emission levels for new sources than 

the average level of the best 12 percent.

Commenters further stated that EPA erred by relying on the 
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99 percent UPL only to reflect variability. Some commenters 

stated that EPA must collect and consider data on additional 

variability, such as that related to variable fuel quality or 

longer term variability, to supplement its analysis. These 

commenters stated that the short-term test data are not 

representative of long-term operation of a unit nor are they 

likely to reflect the “worst reasonably foreseeable 

circumstances” a unit may experience. Other commenters stated 

that EPA should use the upper tolerance limit (UTL) in lieu of 

the UPL; these commenters claimed that the UTL is more 

appropriate for situations where the available data does not 

represent the entire population.

Response: EPA disagrees with commenters and believes that 

the final emission limits appropriately account for variability. 

The Court has recognized that EPA may consider variability in 

estimating the degree of emission reduction achieved by the 

best-performing sources and in setting MACT floors that the best 

performing sources can expect to meet “every day and under all 

operating conditions". See Mossville Environmental Action Now 

v. EPA, 370 F.3d 1232, 1241–42 (D.C. Cir 2004). Furthermore, 

CAA section 112(d)(3) includes a provision stating that the MACT 

floor for existing sources cannot be less stringent than “the 
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average emission limitation achieved by the best-performing 12 

percent of the existing sources (for which the Administrator has 

emissions information).” We see no statutory prohibition in 

considering inter-source variability of the best performing 

sources (which is all our floor calculation does, by considering 

the pooled variability of the best performing sources). Section 

112(d)(3) of the CAA does not specify any single method of 

ascertaining an average. Considering the average variability 

among the group of best performing sources is well within the 

language of the provision (and was upheld in Chemical 

Manufacturers Association v. EPA; see 870 F. 2d at 228). The 

commenters' argument that "average" can only mean average of 

emission levels achieved in performance tests of an individual 

unit is inconsistent with the holding in Mossville, 370 F. 3d at 

1242, that EPA must account for variability in developing MACT 

floors and that individual performance tests do not by 

themselves account for such variability. Therefore, we believe 

that it is reasonable and necessary to account for inter-source 

variability of the best performing sources by taking the pooled 

average of the best performing sources' variability. This is an 

aspect of identifying the average performance of those sources. 
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Furthermore, EPA is confident that the UPL is an 

appropriate statistical tool to use in determining variability 

when there is a limited sampling of the source category. EPA 

has considered comments regarding suggested alternatives to the 

UPL statistic, such as the upper tolerance limit (UTL). Whereas 

a confidence interval covers a population parameter with a 

stated confidence, that is, a certain proportion of the time, a 

tolerance interval covers a fixed proportion of the population 

with a stated confidence. I.e.,That is, confidence limits are 

limits within which we expect a given population parameter, such 

as the mean, to lie; statistical tolerance limits are limits 

within which we expect a stated proportion of the population to 

lie. Given this definition, the 99 percent UTL represents the 

value which we can expect 99 percent of the measurements to fall 

below 99 percent of the time in repeated sampling. In other 

words, if we were to obtain another set of emission observations 

from the floor sources, we can be 99 percent confident that 99 

percent of these measurements will fall below a specified level. 

Since you must calculate the sample percentile, and the sample 

sizes for the area source boiler floor data are small, the 99th

percentile is underestimated. Therefore, EPA notes that the UTL 

should only be used where one can calculate a sample percentile, 

Formatted: Not Superscript/ Subscript, Raised

by 3 pt
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e.g., where there is a sample size of at least 100. On the 

other hand, a prediction interval for a future observation is an 

interval that will, with a specified degree of confidence, 

contain the next (or some other pre-specified) randomly selected 

observation from a population. In other words, the prediction 

interval estimates what future values will be, based upon 

present or past background samples taken. The UPL represents 

the value which we can expect the mean of 3 future observations 

(3-run average) to fall below, based upon the results of the 

independent sample of size n from the same population. Given 

the above considerations, EPA notes that only the UPL adequately 

gets at the notion of average emissions for a small sample size.

EPA has revised its default selection of data distributions 

consistent with its guidance document “Data Quality Assessment:

Statistical Methods for Practitioners EPA QA/G-9S”. This 

document indicates that most environmental data is lognormally 

distributed, so EPA has modified its assumptions when the 

results of the skewness and kurtosis tests result in a tie, or 

when there is not enough data to complete the skewness and 

kurtosis tests. With respect to the methods used to compute the 

UPL for a dataset that is determined to be lognormally 

distributed, EPA also considered the commenters suggested 
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revisions to the calculations in order to avoid skewing the UPL 

by calculating the UPL of an arithmetic mean instead of the UPL 

of a geometric mean. To adjust the calculation EPA considered a 

scale bias correction approach as well as a new UPL equation 

based on a Bhaumik and Gibbons 2004 paper, which calculates “An

Upper Prediction Limit for the Arithmetic Mean of a Lognormal 

Random Variable6

Additionally, EPA has determined that 99 percent UPL is 

appropriate for fuel based HAP, and a 99.9 percent UPL is 

appropriate for CO. For fuel-based HAP the 99 percent confidence 

level is consistent with other recent rulemakings (75 FR 

54975.). Further, as commenters have noted elsewhere, the 

sample sizes were limited and EPA determined that a level of 99 

percent is a good compromise and represents emission levels that 

are protective of human health and the environment. Given that 

the subcategories had limited data to establish the floor 

calculations, EPA determined it was inappropriate to use a 

confidence level lower than 99 percent. Further, for fuel based 

”. Given data availability, EPA selected the 

Bhaumik and Gibbons 2004 approach which addresses commenters 

concerns with the proposed computations.

 

6 Bhaumik, D. K. and R. D. Gibbons. 2004. An Upper Prediction 

Limit for the Arithmetic Mean of a Lognormal Random Variable. 

May 1, 2004. Technometrics 46(2): 239-248. 

doi:10.1198/004017004000000284
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HAP mercury, EPA has implemented an additional fuel variability 

analysis. Additionally, there are well established control 

measures currently used on units in the source category (fabric 

filters for PM and mercury) that serve to mitigate, to some 

degree, the variability in emissions that can be expected.

Given these additional considerations for fuel-based HAP, but 

recognizing the emission limits must be met at all times yet are 

based on short term stack test data, EPA selected the 99 percent 

confidence level. For CO, EPA considered both quantitative and 

qualitative comments received during the public comment period 

on how CO emissions vary with load, fuel mixes and other routine 

operating conditions. After considering these comments EPA 

determined that a 99.9 percent confidence level for CO would 

better account for some of these fluctuations.

Finally, EPA notes that where appropriate, we have 

accounted for variable fuel quality. EPA first took fuel into 

consideration, among other boiler design factors when it divided 

the source category into subcategories. EPA is aware that 

differences between given types of units, and fuel, can affect 

technical feasibility of applying emission control techniques. 

As noted in the preamble to the June 2010 proposed rule, EPA 

attempted to assess the impact of fuel variability for 
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development of the mercury standard. However, no fuel analysis 

data from boilers in the top 12 percent were available for 

assessing the impact of fuel variability on mercury emissions. 

EPA realizes that mercury is a fuel dependent HAP, and that the 

amount of mercury emitted from the boiler depends on the amount 

of mercury contained in the fuel. For this final rule, we have 

implemented a fuel variability factor into the mercury emission 

limit by determining a factor relating the highest mercury 

content to the average mercury content in coal that may be used 

at sources comprising the best 12 percent of sources. We also 

note that fuel usage can be reduced by improving the combustion 

efficiency of the boiler. Therefore, in the development of the 

final standards, we are establishing requirements for larger 

existing boilers (greater than 10 MMBtu/h heat input capacity) 

to conduct an energy assessment, and smaller boilers (both 

existing and new boilers with a heat input capacity less than 10 

MMBtu/h) to meet a work practice or management practice

requirements of a tune-up, in order to improve combustion 

efficiency.

D. Beyond the Floor Analysis

Comment: Several commenters objected to EPA's beyond-thefloor determination for new area source boilers. Many of these 
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commenters stated that the beyond the floor approach must 

consider fuel switching as an option. Other commenters objected 

to EPA's beyond-the-floor determination for existing boilers, 

specifically stating that EPA should require existing facilities 

to either comply with emission limits for larger units, or 

require fuel switching to the cleanest fuel in their class (fuel 

type). Commenters noted that while EPA identified substantial 

emissions reductions for mercury and POM from switching coalfired boilers to natural gas, EPA failed to rationalize why 

fuel-switching is not a technically feasible or economically 

achievable option. Commenters debated EPA's stated concerns 

regarding fuel availability and curtailment, arguing that there 

is sufficient capacity to meet the expected increased demand for 

natural gas. Furthermore, these commenters stated that the 

potential increases in metallic HAP emissions from fuelswitching were minor and should be considered in light of 

overall reductions for POM. 

Response: EPA has considered this comment and concluded 

that fuel switching is not an appropriate option for the beyond 

the floor level of control. EPA originally considered whether 

fuel switching would be an appropriate control option for 

sources in each subcategory under the proposed rule, including 
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the feasibility of fuel switching to other fuels used in the 

subcategory and to fuels from other subcategories. This

consideration included determining whether switching fuels would 

achieve lower HAP emissions. We also gave consideration to

whether fuel switching could be technically achieved by boilers 

in the subcategory considering the existing design of boilers 

and the availability of various types of fuel. After 

considering these factors, we determined that fuel switching was 

not an appropriate control technology for purposes of 

determining the MACT floor level or beyond the floor level of 

control for any subcategory. This decision is based on the 

overall effect of fuel switching on HAP emissions, technical and 

design considerations discussed previously in the preamble to 

the proposed June 2010 rule (75 FR 31896), and concerns about 

fuel availability. This determination is discussed in the

memorandum “Development of Fuel Switching Costs and Emission 

Reductions for Industrial, Commercial, and Institutional Boilers 

and Process Heaters National Emission Standards for Hazardous 

Air Pollutants – Area Source” located in the docket. 

Energy Assessments 

Comment: Several commenters disagreed with EPA's 

determination to require energy assessments as a beyond the 
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floor option. Commenters specifically stated that EPA cannot

require an energy assessment because an assessment is not an 

emission standard and there is no proven relationship between 

HAP emissions and the assessment. Other commenters argued that 

the proposed requirements for an energy assessment were not 

stringent enough; these commenters stated that an energy 

assessment cannot impose standards more stringent than the MACT 

floor. For instance, one commenter argued that if EPA did not 

require implementation of the energy assessment findings, no 

reductions in fuel use or HAP would result. The commenter 

further asserted that even an implemented energy assessment 

would not reduce HAP emissions consistent with the requirements 

of CAA section 112(d)(2). One commenter specifically stated 

that by only considering energy audits, EPA did not consider the 

full range of potential emission measures.

Other commenters argued that EPA does not have the authority 

to require an energy assessment, and that the proposed 

requirements were "too broad" or "too intrusive." Commenters 

were concerned that the energy assessment would include not only

than the affected source, but also the entire facility, which 

EPA does not have the authority to regulate. 

Response: EPA disagrees with commenters that state that 
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EPA does not have the authority to require an energy assessment. 

An energy assessment is an appropriate beyond-the-floor control 

technology because it is one of the measures identified in CAA 

section 112(d)(2). CAA section 112(d)(2) states that “Emission 

standards promulgated ... and applicable to new or existing 

sources ... is achievable ... through application of measures, 

processes, methods, systems or techniques including, but not 

limited to measures which –

(A) reduce the volume of, or eliminate emissions of, such 

pollutants through process changes, substitution of 

materials or other modifications,

. . .

(D) are design, equipment, work practice, or operational 

standards (including requirements for operator 

training or certification) as provided in subsection 

(h), or

(E) are a combination of the above."

The purpose of an energy assessment is to identify energy 

conservation measures (such as, process changes or other 

modifications to the facility) that can be implemented to reduce 

the facility energy demand which would result in reduced fuel 

use. Reduced fuel use will result in a corresponding reduction 
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in HAP, and non-HAP, emissions. Thus, an energy assessment, in 

combination with the MACT emission limits will result in the

maximum degree of reduction in emissions as required by CAA 

section 112(d)(2). 

It is not EPA's intent to require an energy assessment for 

the entire facility; the energy assessment is only applied to 

existing boilers and their energy use systems located at area 

sources. EPA acknowledges that the proposed definition for 

"energy assessment" is unclear, and we have revised this final 

rule to clarify the definition with respect to the requirements 

of Table 3 of subpart JJJJJJ (see 40 CFR 63.11237). In order to 

account for variability among boiler systems and energy use 

systems and to ensure that affected sources can adequately 

comply with the requirements, we have distinguished the 

requirements for the energy assessment based on the heat input 

use of the affected source. We have also added a definition for 

"energy use systems" to clarify the components for each boiler 

system and energy use system which must be considered during the 

energy assessment, including elements such as combustion 

management, thermal energy recovery, energy resource selection, 

and the steam end-use management of each affected boiler. These 

revisions clarify that an energy assessment is only required for 
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those portions of the facility using steamthe energy generated

from the affected boiler system.

Additionally, a facility may elect, but is not required, to 

implement the cost-effective energy conservation measures 

identified in the energy assessment. Because we lack 

information on whether implementation of the conservation 

measures will prove cost-effective or economically feasible for 

facilities, we are allowing the owner or operator to determine 

the implementation of energy conservation measures identified in 

the energy assessment. EPA notes that the cost of an energy 

assessment is minimal, in most cases, compared to the cost for 

testing and monitoring to demonstrate compliance with an 

emission limit. Furthermore, the costs of any energy 

conservation improvement for the owner or operator will be 

offset, at least in part, by the cost savings in lower fuel 

costs. Therefore, after considering the structure of the 

requirement, the incentives it presents, and the likely behavior 

of sources, it is our judgment that sources will find it costeffective to implement the conservation measures identified in 

the energy assessment, and we have elected to promulgate 

requirements for an energy assessment for all existing boilers 

with a heat input capacity greater than 10 MMBtu/h as a beyond 
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the floor option or GACT.

EPA disagrees with commenters that state that the option for 

an energy assessment included in the June 2010 proposed rule is

not stringent enough. An energy assessment refers to a process 

which involves a thorough examination of potential savings from 

energy efficiency improvements, pollution prevention, and 

productivity improvement. It leads to the reduction of 

pollutants through process changes and other efficiency 

modifications. Improving energy efficiency reduces negative 

impacts on the environment as well as operating and maintenance 

costs; improvements in energy efficiency result in decreased 

fuel use which results in a corresponding decrease in emissions 

(both HAP and non-HAP) from the boiler. The revised definitions

of "energy assessment" and "energy use systems," as discussed 

above, have been expanded to include the specific components 

that must be considered for an energy assessment. These changes 

elucidate the in-depth nature of the energy assessment, which 

requires identifying all energy conservation measures 

appropriate for a facility given its operating parameters.

EPA proposed the energy assessment as a beyond the floor 

option for existing area source boilers having a heat input 

capacity of greater than 10 MMBTU/h, rather than focusing on 
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smaller boilers. We also examined other emission measures 

currently in place. EPA did not have sufficient information to 

determine if requiring an energy assessment for area boilers 

with a heat input capacity of less than 10 MMBtu/h is 

economically feasible. For boilers with a heat input capacity 

less than 10 MMBtu/h, the data that we have suggests that area 

source boilers typically conduct boiler tune-ups. We also 

examined work practices listed in Statestate regulations for 

area source boilers with a heat input capacity less than 10 

MMBtu/h. These regulations included tune-ups (10 Statesstates), 

operator training (one Statestate), periodic inspections (two

Statesstates), and operation in accordance with manufacturer 

specifications (one Statestate).

When energy assessments have been undertaken in the past, 

they typically result in 10 to 15 percent reduction in fuel use, 

according to the Department of Energy who has conducted energy 

assessment at selected manufacturing facilities.7

 

7 Case studies and success stories highlighting energy savings 

achieved by companies that have participated in 

 While the 

efficiency gains may be somewhat less when the assessment is 

mandated for a source rather than voluntary, the absence of a 

energy 

assessments can be found at 

http://www1.eere.energy.gov/industry/saveenergynow/case_studies.

html and at the Department of Energy’s Energy Assessment Centers 

Database http://iac.rutgers.edu/database.
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requirement to implement the particular findings of the 

assessment should still result in measures being implemented 

that are cost-effective for the source and in emission 

reductions over and above what is otherwise required by MACT and 

other GACT measures. Therefore, we elected to promulgate 

requirements for an energy assessment for all existing boilers 

with a heat input capacity greater than 10 MMBtu/h, and require 

area source boilers in the biomass and oil subcategories with a 

heat input capacity of greater than 10 MMBtu/h to meet the 

management practice standard of a tune-up. These requirements 

represent the generally available and cost-effective pollution 

reduction measures that are already required or in place. 

E. GACT Standards

Comment: Commenters stated that the GACT standards should 

consist of work practice standards, rather than numeric emission 

limits. One commenter specifically stated that in order to 

reduce the burden on small facilities operating boilers, EPA 

should establish work practice standards for CO instead of 

emission limits, referencing requirements from the state of New 

Jersey. Other commenters stated that the emission limits and

testing procedures proposed for new boilers impose onerous 

capital and annual costs on potential project owners, which 
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typically include schools, small businesses, hospitals, and 

other institutions in rural areas. Some commenters stated that 

the CO emission limits were not achievable for small boilers 

over a range of operating periods, and that EPA should consider 

work practice standards in order to account for load 

variability.

Response: EPA has considered commenter's concerns. CAA 

section 112(d)(5) allows the Administrator, with respect to area 

sources, to promulgate standards which provide for the use of 

generally available control technologies or management practices 

to reduce emissions of HAP. Therefore, with respect to mercury 

and POM from area source boilers classified as biomass-fired or 

oil-fired, as well as with respect to other urban HAP besides 

POM, we have developed standards that reflect GACT for these two 

area source categories. 

While the June 2010 proposed rule (75 FR 31896) set numeric 

MACT standards for CO (as a surrogate pollutant for the 

individual urban organic HAP) and mercury, and numeric GACT 

emission limits for PM (as a surrogate for the individual urban 

metal HAP), EPA has revised the standards for area source 

boilers classified in the biomass and oil subcategories. Rather 

than require a numeric MACT emission limit for POM, new and 
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existing area source boilers in the biomass or oil subcategories 

must meet the requirements of GACT, which are management 

practice standards as described in Table 2 of 40 CFR part 63, 

subpart JJJJJJ.

However, for the purposes of regulating PM from new area 

source boilers, EPA has determined that the GACT standards 

should consist of numeric emission limits. PM is used as a 

surrogate for urban metals, which we are required to regulate 

pursuant to CAA section 112c)(6). The data that we have 

available suggests that the control technologies currently used 

by facilities in the source category for reduction of nonmercury metallic HAP and PM are multiclones, which are generally

used at area sources using solid fuel. We previously determined 

during the development of the June 2010 proposed rule that these 

controls are generally available and cost effective for new area 

source boilers. Additionally, we noted that new area source 

boilers with heat input capacity of 30 MMBtu/h or greater are 

subject to the NSPS for boilers (either subpart Db or Dc of 40 

CFR part 60), which regulate emissions of PM and require 

performance testing. Furthermore, new coal-fired area source 

boilers with heat input capacity of 10 MMBtu/h or greater will 

likely require a PM control device to comply with the proposed 
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mercury MACT standard and required performance testing. 

Therefore, a numerical limit for PM consistent with the devices 

required to meet mercury MACT should be generally achievable.

EPA has also revised the PM emission limits for area source 

boilers with a heat input capacity between 10 and 30 MMBtu/h; 

these limits have been revised to reflect the performance of

GACT, which are multiclones. The PM GACT limits were calculated 

as the average of the data from units using GACT technology. 

EPA has determined that the promulgated numeric emission limits 

for PM are appropriate GACT standards for new area source 

boilers with a heat input capacity greater than 10 MMbtu/h. For 

new boilers with a heat input capacity less than 10 MMBtu/h, 

GACT is a management practice of a tune-up because, as 

previously discussed, there are technical and economic 

limitations of conducting PM testing on boilers with small 

diameters stacks. 

Tune-ups

Comment: Several commenters expressed concern regarding 

proposed work practice standards for existing area source 

boilers, including the requirement of a tune-up for control of 

POM and mercury. Commenters stated that tune-ups aimed at 

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efficiency, and/or increase fuel use. Commenters noted that 

many typical tune-up requirements, including States'states'

requirements, are aimed at minimization of NOx and not CO. 

These commenters stated that the proposed tune-up requirements 

could violate the state tune-up requirements due to increases of 

NOx. Multiple commenters requested that EPA specify that tuneups consider optimizing efficiency and limiting increases of 

NOx, and not only require minimizing CO. 

Other commenters requested that EPA allow the use of 

portable instruments to measure CO for the tune-up requirements. 

Several commenters requested that EPA clarify that, for the 

tune-up procedures, gases do not have to measured using EPA 

Reference Methods. These commenters indicated that requiring 

EPA Methods would increase the cost burden for small facilities.

Response: EPA disagrees with commenters and is requiring 

tune-ups as a work practice standard for coal-fired area source

boilers with a heat input capacity less than 10 MMBtu/h and as a 

management practice standard for all biomass-fired and oil-fired 

area source boilers. EPA acknowledges that that a tune-up 

designed to specifically decrease CO emissions from an area 

source boiler would potentially increase emissions of NOx. 

However, it was not EPA's intent to require that area source 

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boilers be specifically tuned for the reduction of CO emissions, 

but rather to require good combustion practices (GCP) by 

ensuring that area source boilers are tuned to manufacturer's 

specifications. As discussed in the preamble to the June 2010 

proposed rule, boilers may be, at best, 85 percent efficient, 

and untuned boilers may have combustion efficiencies of 60 

percent or lower. Furthermore, as the combustion efficiency 

decreases, fuel usage increases to maintain energy output 

resulting in increased emissions. A tune-up performed to the 

manufacturer's specifications would ensure the highest energy 

efficiency and reduce fuel usage, which will ultimately reduce 

HAP emissions. As commenters noted, the tune-up requirements 

specified by area source boiler manufacturers are generally 

aimed at reducing NOX and would not increase emissions of NOX.

Therefore, theThe tune-up provisions incorporated in this final 

rule for area source boilers require that the owner or operator 

measure the concentration in the effluent stream of CO in ppm, 

by volume, dry basis (ppmvd), before and after adjustments are 

made to the boiler. EPA does not specify the instrument that 

must be used for measuring these concentrations, and allows 

owners and operators to choose the method of measurement. 

Therefore, EPA agrees with commenters that portable instruments 
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are permissible for this purpose. 

F. Subcategories

Comment: Several commenters raised concerns regarding the 

subcategories defined by EPA in the development of the proposed 

rule. Multiple commenters argued that the proposed 

subcategories are unlawful and arbitrary because they are not 

based on different classes, types, or sizes. At least one 

commenter specifically stated that the proposed 

subcategorization defied the explicit recommendation of the 

Small Entity Representatives (SERs) to the Small Business 

Advocacy Review (SBAR) Panel, which recommended that “EPA should 

subcategorize based on fuel type, boiler type, duty cycle, and 

location.” Many of these commenters suggested subcategories 

based on limited use, type of biomass (wood, bark, agricultural 

residue, moisture level) and/or coal (bituminous, anthracite), 

boiler design (stoker, fluidized bed, or suspension), heat input 

capacity smaller than 1 MMBtu/h, and combustion of secondary 

materials. Other commenters recommended that the same 

subcategories applied to major sources should be used for area 

sources.

Response: EPA disagrees with commenters. The Section 

112(d)(1) of the CAA allows EPA to divide source categories 

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intostates “the Administrator may distinguish among classes, 

types, and sizes of sources within a category or subcategory” in 

establishing emission standards. Thus, we have discretion in

determining appropriate subcategories whenbased on classes, 

types, and sizes of sources. We used this discretion in 

developing subcategories for the boiler area source category. 

Through subcategorization, we are able to define subsets of

similar emission sources within a source category if differences 

between given types of units lead to corresponding differences 

in the nature of in emissions or thecharacteristics, technical 

feasibility of applying emission control techniques, or 

opportunities for pollution prevention exist within the source

category. The design, operating, and emissions information that 

EPA reviewed during the area source rulemaking indicates the 

need to subcategorize based on boiler design which is based on 

the fuel type. EPA continues to believe that this 

subcategorization is appropriate. As noted in the preamble to 

the June 2010 proposed rule, boiler systems are designed for 

specific fuel types (e.g., coal, biomass, or oil) and will 

encounter problems if a fuel with characteristics other than 

those originally specified is fired. EPA has noted that 

emissions from boilers burning coal, biomass, and oil will also 
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differ, and that HAP formation, including emissions of metals 

and mercury, is dependent upon the composition of the fuel. 

Organic HAP, on the other hand, are formed from incomplete 

combustion, which are a function of time, turbulence, and 

temperature, and are influenced by the design of the boiler and 

dependent in part on the type of fuel being burned. Because 

these different types of boilers have different emission 

characteristics which may influence the feasibility and 

effectiveness of emission control, we believe that 

subcategorizing them by fuel type is appropriate. 

Additionally, EPA notes that we lack sufficient emissions 

data for area source boilers to develop limits for additional

subcategories. We have elected to establish different 

subcategories for the major and area source rulemakings, as 

major source boilers have a different scale of operation and 

often different combustor designs. There is also more detailed 

emissions data available for the major source category, which 

favors the development of more specific subcategories. Because 

we lack the same level of detail for the area source category, 

EPA has determined that it would be inappropriate to establish 

the same subcategories for major and area source boilers. 

However, as discussed in the comments below, we have 
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established a small units subcategory for each type of fuel 

(area source boilers with a heat input capacity of less than 10 

MMBtu/h), and see no further need for smaller subcategories. We 

have also adjusted the definition for each fuel subcategory to 

account for the combustion of secondary materials. The 

definitions have been clarified to specify that the fuel 

subcategories are based on the fuel that the boiler is designed 

to combust, rather than the actual fuel that the boiler is 

combusting. 

Finally, as discussed earlier in this section, we have 

revised the MACT and GACT limits for the coal, oil, and biomass 

subcategories in this final rule. Existing oil and biomassfired boilers are no longer required to meet emission limits, 

and are only required to meet management practice standards 

under this final rule. Furthermore, coal-fired boilers with a 

heat input capacity of less than 10 MMBtu/h are only required to 

meet work practice standards. While more stringent limits under 

this final rule may have required subcategories based on the 

size of the unit, EPA has determined that the subcategories 

chosen are reasonable based on the applicable requirements of 

this final rule.

Combustion of Secondary Fuels
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Comment: Multiple commenters sought clarity for the 

combustion of secondary materials and/or alternative fuels 

within the proposed subcategories for area source boilers. 

Several of these commenters requested clarification of the 

defined fuels for the biomass, coal, and oil-fired 

subcategories, as well as additional clarification regarding 

gas-fired boilers. Some commenters stated that EPA's 

determination that the boilers subject to this rule do not 

combust any non-hazardous secondary materials is erroneous, and 

that to not consider standards for units burning secondary 

materials would be unlawful. 

Many commenters recommended that EPA classify boilers based 

on predominant use of a particular fuel; several commenters 

recommended redefining the subcategories to allow minimal 

burning of other fuels or for further clarification. For 

instance, some commenters expressed concern regarding 

“combination boilers” (boilers that co-fire coal in an amount 

greater than 10 percent heat input basis with at least 10

percent biomass), which do not cleanly fit into either the coalfired boiler subcategory or the biomass-fired boiler 

subcategory. Other commenters argued that the definition of 

gas-fired boilers should allow for units burning less than 10 
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percent liquid fuels. Many of the commenters suggested 

alternative definitions for the proposed subcategories or 

provided alternative thresholds. 

Alternatively, there were some commenters who expressed 

concern regarding the use of alternative fuels. Commenters 

specifically stated that allowing 10 percent alternative fuel 

use, or use of multiple alternatives from year to year, would 

create significant enforcement issues for states without 

detailed requirements for tracking, recordkeeping, and 

reporting. 

Response: EPA has considered these comments and revised 

the subcategories based on a revised MACT floor approach. As 

discussed in Section IV.A of this preamble, we have redefined 

the coal, biomass and oil subcategories for area source boilers 

to clarify the fuel inputs that define each subcategory. While 

the subcategories under the proposed rule accounted for 

secondary materials such as biomass, liquid or gaseous fuels

combusted in combination with traditional fuels, we wished to 

clarify each subcategory in order to account for the combustion 

of an array of secondary fuels. Area source boilers combusting 

coal, biomass or oil may also combust secondary materials as 

part of their fuel mix. It was not our intent to exclude 
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boilers combusting these non-hazardous secondary materials that 

do not meet the definition of "solid waste" from the coal, 

biomass or oil-fired subcategories. Therefore, we have revised 

the definition for each subcategory to account for the 

combustion of these non-hazardous secondary materials. 

For instance, the proposed rule limited the coal 

subcategory to boilers combusting coal or coal in combination 

with biomass, liquid, or gaseous fuels. We have redefined the 

coal subcategory to include boilers that burn any solid fossil 

fuel and no more than 15 percent biomass on an annual heat input 

basis. "Solid fossil fuels" has been defined to include, but 

not limited to, coal, petroleum coke, coal refuse, and tire 

derived fuel (TDF). Similarly, we have revised the biomass 

subcategory to account for boilers that may burn biomass and 

secondary materials. The biomass subcategory includes boilers 

combusting at least 15 percent of biomass. This definition 

differentiates these primarily biomass-fired boilers from the 

coal subcategory. Additionally, the oil subcategory has been 

revised to include boilers that burn any liquid fuel but are not 

included in either the coal or biomass subcategories. 

Based on new data submitted during the public comment 

period, EPA has determined that area source boilers may combust 
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secondary materials. Data submitted indicates that as much as 

15 percent of secondary materials, or alternative traditional 

fuel, may be mixed without causing problems with boiler 

operations. We wished to differentiate boilers combusting 

greater than 15 percent of biomass from the remaining 

subcategories, as these fuels will have higher rates of organic

HAP. due to the higher moisture content of biomass compared to 

fossil fuel. The revised definitions for the coal, biomass and 

oil subcategories clarify this by establishing the fuel type and 

the input ratio of each fuel type combusted. Therefore, the 

revised definitions more accurately reflect EPA's intent to 

include and account for boilers combusting secondary materials

in the coal, biomass, and oil subcategories and the effect of 

biomass on the combustion process. 

Comment: A number of commenters requested that EPA provide 

exemptions for specific unit types, including limited use 

boilers, recovery boilers, hot water heaters, boilers firing 

ultra low sulfur #2 fuel oil, and boilers with a heat input 

capacity of less than 1 MMBtu/h. Other commenters stated that 

EPA is not justified in providing an exemption for gas-fired 

boilers. 

Response: As noted in Section VII of the proposed June 
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2010 rule, in the Federal Register notice “Source Category 

Listing for Section 112(d)(2) Rulemaking Pursuant to Section 

112(c)(6) Requirements,” (63 FR 17838, 17849), Table 2 (1998), 

EPA identified “Industrial Coal Combustion,” “Industrial Oil 

Combustion,” Industrial Wood/Wood Residue Combustion,” 

“Commercial Coal Combustion,” “Commercial Oil Combustion,” and 

“Commercial Wood/Wood Residue Combustion” as source categories

“subject to regulation” for purposes of CAA section 112(c)(6). 

Notably, gas-fired units are not included in the source category 

listing for area source boilers. Without such a listing, EPA 

cannot address gas-fired boilers in this regulation. We have 

also included in this final rule an exemption for hot water 

heaters because these units are, as defined in this final rule, 

considered residential boilers. In addition, recovery boilers 

would be exempt because they are regulated under another section 

112 MACT standard. (See 40 CRF part 63, subpart MM). 

Conversely, EPA is required to set standards for other unit 

types, including limited use boilers and boilers firing ultra 

low sulfur fuel oil. These boilers are included in the source 

category listing for CAA section 112(d)(2) and emit the 

pollutants identified in CAA section 112(c)(3). As discussed 

above, EPA has set appropriate MACT and GACT limits to boilers 
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based on fuel type and size, including area source boilers with 

a heat input capacity of less than 10 MMBtu/h. EPA also notes 

that waste heat boilers have been excluded from the definition

of boiler.

G. Startup, Shutdown, and Malfunction

Comment: Several commenters stated that a separate 

standard must be developed for periods of startup and shutdown. 

Commenters stated that requiring emission limits during SSM 

directly conflicts with the requirement that MACT be achievable 

and is technically feasible; therefore EPA could not require 

emission limits during periods of SSM. Some commenters 

requested a separate standard for CO for startup; at least one 

commenter specifically stated that many area source boilers must 

operate under conditions driven by safety considerations, 

operational concerns, and warranty requirements that would 

likely generate unavoidable increases in CO emissions during 

startup and shutdown. The commenter therefore concluded that

requiring a CO emission limit during startup and shutdown would 

not only be technically unachievable, but would promote unsafe 

and improper operation. Several commenters suggested that work 

practice standards are more appropriate than emission limits, 

citing a lack of relevant data for periods of SSM. Other 
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commenters specifically objected to EPA's decision to base the 

SSM requirements on data from the proposed major source NESHAP

for industrial, commercial, and institutional boilers and stated 

that the data from the proposed major source rule cannot be

applied to area sources. 

Response: EPA has considered these comments and has 

revised this final rule to incorporate a work practice 

standardsstandard for periods of startup and shutdown. As part 

of the development of the proposed rule, we reviewed the cost 

information for CO CEMS provided by commenters on the NESHAP for 

major source boilers and determined that requiring CO CEMS for 

units with heat input capacities greater or equal to 100 

MMBtu/hr was reasonable. However, EPA has revised this final 

rule to only require emission limits for mercury and CO for 

coal-fired boilers. Furthermore, we are only requiring sources 

to perform a work practice standards, includingstandard,

following the manufacturer's recommended procedures, to 

demonstrate compliance with the CO emission limits for area 

source coal-fired boilers during periods of startup and 

shutdown. Based on the available dataset for facilities in the 

affected area source category, EPA determined that there are 

currently no existing coal-fired boilers with a heat input 
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capacity greater than 100 MMBtu/h located at area sources. 

Coal-fired boilers with a heat input capacity of greater than 50 

MMBtu/h are generally major sources of HAP. Therefore, 

requiring CEMS for boilers of this size is unnecessary for the 

defined source category. 

In lieu of CEMS, we also considered whether requirements 

for performance testing would be feasible for area source 

boilers during periods of startup and shutdown. Upon review of 

these requirements, EPA determined that it is not feasible to 

require stack testing - in particular, to complete the multiple 

required test runs - during periods of startup and shutdown due 

to physical limitations and the short duration of startup and 

shutdown periods. Therefore, a separate standard must be 

developed for these periods. 

In regards to malfunctions, EPA had previously determined 

in the development of the proposed rule 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. As discussed in Section III.E

of this preamble, EPA has added to this final rule an 

affirmative defense for civil penalties for exceedances of 
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numerical emission limits that are caused by malfunctions.

Therefore, as allowed under CAA section 112(h), we are 

requiring a work practice standardsstandard for all coal-fired 

area source boilers during periods of startup and shutdown. The 

work practice standards includestandard requires following the 

boiler manufacturer's specifications for periods of startup and 

shutdown.

H. Compliance Requirements

Rationale for Demonstrating Compliance 

Comment: Several commenters expressed concern that, given 

the large numbers of boilers that would be affected by the 

proposed rule and the limited capacity of existing vendors, 

contractors, and engineers, a 3-year time period would not be 

sufficient to allow completion of all of the required 

modifications. 

Response: EPA has re-evaluated the compliance dates for this 

final rule following the revised MACT and GACT standards. We 

have revised the initial compliance dates for existing affected 

sources according to the applicable provisions for each affected 

source (e.g., work practice or management practice standards, 

emission limits, and/or an energy assessment), as discussed in 

Section VI.E of this preamble. EPA has determined that existing 

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sources subject to a work practice standard of a tune-up must

comply with this final rule no later than [INSERT THE DATE 1 

YEAR AFTER THE DATE OF PUBLICATION OF IN THE FEDERAL 

REGISTER].one year after publication of this final rule. We 

have determined that one year is adequate time for affected 

sources to meet the work practice or management practice

standard, which includes a tune-up based on the manufacturer's 

recommendations. Existing sources subject to an emission limit 

or an energy assessment requirement are required to comply with 

this final rule no later than [INSERT THE DATE 3 YEARS AFTER THE 

DATE OF PUBLICATION IN THE FEDERAL REGISTER]. 3 years after 

publication of the final rule. Section 112(i)(3)(B) allows EPA, 

on a case-by-case basis to grant an extension permitting an 

existing source up to one additional year to comply with 

standards if such additional period is necessary for the 

installation of controls. The EPA feels that this provision is 

sufficient for those sources where the 3-year deadline would not 

provide adequate time to retrofit as necessary to comply with 

the requirements of the standard.

Comment: Commenters objected to proposed requirements to 

use CEMS and in some circumstances COMS. Commenters stated that 

these requirements are extremely burdensome on area sources 
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considering the testing requirements and costs, and that the 

requirements for CO CEMS for units less than 100 MMBtu/h are too 

onerous. Commenters noted that many units at this size in the 

industrial and institutional sector do not operate frequently;

therefore the cost of installing CO CEMS was not justified for 

units with such limited operation. Other commenters argued that 

requiring boilers to test for CO poses a significant regulatory 

burden. Several commenters stated that the proposed testing 

frequency was burdensome.

Response: EPA has considered these comments, and we have 

revised the proposed continuous compliance requirements to not 

require a CO CEMS for area source boilers. Per the revised MACT 

and GACT determinations, this final rule only requires emission 

limits for mercury and CO for coal-fired units. Therefore, for 

new and existing coal units with a heat input capacity greater 

than 10 MMBtu/h, we are requiring annual stack testing to 

demonstrate compliance with the CO emission limits. In the 

development of the proposed rule, we reviewed the cost 

information for CO CEMS provided by commenters on the NESHAP for 

major source boilers and determined that requiring CO CEMS for 

units with heat input capacities greater or equal to 100 MMBtu/h 

was reasonable. However, based on a review of the available 
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dataset for facilities in the affected area source category, we 

have determined that there are currently no existing coal-fired 

boilers with a heat input capacity greater than 100 MMBtu/h 

located at area sources. Therefore, requiring CEMS for coalfired boilers of this size is unnecessary for the defined source 

category. Additionally, boilers in the biomass and oil 

subcategories with a heat input capacity greater than 10 MMBtu/h 

are not required to meet emission limits for CO in this final 

rule; these boilers are subject to the management practice 

standards in Table 2 of 40 CFR part 63, subpart JJJJJJ, and 

therefore, no CO testing is required for these units. 

I. Cost/Economic Impacts

Comment: Multiple commenters stated that the economic 

impacts of the proposed rule were significantly underestimated. 

Many commenters stated that the CO limits would require costly 

controls, and specifically, that the cost of particulate control 

for biomass boilers was severely underestimated. Other 

commenters stated that EPA made erroneous assumptions in 

performing the cost calculations. For instance, one commenter 

stated that EPA does not have enough data to support the

assumption that fabric filters alone will be sufficient for area 

source coal-fired boilers to meet the proposed mercury limit. 
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Response: In light of changes to this final rule, EPA 

believes that these concerns are no longer an issue. We have 

revised the costs estimates for this final rule to reflect EPA's 

determination of the final MACT standards for coal-fired boilers 

and GACT standards for biomass and oil-fired boilers. For 

instance, EPA is only requiring particulate emission limits for 

new boilers with a heat input capacity of greater than 10 

MMBtu/h; smaller boilers must only meet the management practice 

standard of a tune-up. These changes have significantly 

decreased the costs presented in the proposed June 2010 rule. 

Additionally, commenters provided additional cost information 

during the public comment period; EPA has incorporated this 

information into the analysis for this final rule. Based on 

this re-analysis, EPA has determined that fabric filter controls 

are generally available and cost effective for new area source 

boilers. As noted previously, new area source boilers with a 

heat input capacity of 30 MMBtu/h or greater are subject to the 

NSPS for boilers (either subpart Db or Dc of 40 CFR part 60), 

which regulate emissions of PM and require performance testing. 

Furthermore, new coal-fired area source boilers will likely 

require a PM control device to comply with the proposed mercury 

MACT standard and required performance testing. We determined 
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in the context of the major source rulemaking, and from further 

analysis of new data submitted during the public comment period, 

that fabric filters are the most effective technology employed 

by industrial, commercial, and institutional boilers for 

controlling mercury and particulate emissions. Therefore, EPA 

has determined it is appropriate and cost-effective to estimate 

the cost of compliance based on fabric filters for new area 

source boilers. 

Comment: Some commenters stated that this final rule would 

have substantial impacts on rural communities. Commenters noted 

that many rural communities rely upon or significantly benefit 

from the use of biomass boilers for energy at manufacturing 

facilities, schools and hospitals. These commenters stated that 

the proposed rule will negatively impact both boiler owners and 

fuel suppliers in these communities. Similarly, other 

commenters stated that this final rule would have a significant 

adverse impact on the use of biomass renewable energy throughout 

the economy.

Response: In light of the changes made to the final 

regarding biomass-fired area source boilers, we believe these 

concerns are no longer an issue. ExistingIn the final rule, 

existing biomass area source boilers are only subject to the 
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management practice of a tune-up and only existing biomass-fired 

area source boilers with a heat input capacity of 10 MMBtu/h or 

greater are required to have an energy assessment performed. 

There are no testing or monitoring requirements in this final 

rule for existing biomass-fired area source boilers. For a 

typical existing biomass-fired boilers, this change resulted in 

reducing the annualized cost of compliance from about $420,000 

to about $2,200. 

New biomass-fired area source boilers with a heat input 

capacity of 10 MMBtu/h or greater are only subject to a PM 

emission limits which requires an annual PM test be conducted.

VI. Relationship of this Action to CAA Section 112(c)(6)

CAA section 112(c)(6) requires EPA to identify categories 

of sources of seven specified pollutants to assure that sources 

accounting for not less than 90 percent of the aggregate 

emissions of each such pollutant are subject to standards under 

CAA section 112(d)(2) or 112(d)(4). EPA has identified 

“Industrial Coal Combustion,” “Industrial Oil Combustion,” 

Industrial Wood/Wood Residue Combustion,” “Commercial Coal 

Combustion,” “Commercial Oil Combustion,” and “Commercial 

Wood/Wood Residue Combustion” as source categories that emit two

of the seven CAA section 112(c)(6) pollutants: POM and mercury. 
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(The POM emitted is composed of 16 polyaromatic hydrocarbons 

(PAH).) In the Federal Register notice, Source Category Listing 

for Section 112(d)(2) Rulemaking Pursuant to Section 112(c)(6) 

Requirements, 63 FR 17838, 17849, Table 2 (April 10, 1998), EPA 

identified “Industrial Coal Combustion,” “Industrial Oil 

Combustion,” Industrial Wood/Wood Residue Combustion,” 

“Commercial Coal Combustion,” “Commercial Oil Combustion,” and 

“Commercial Wood/Wood Residue Combustion” as source categories

“subject to regulation” for purposes of CAA section 112(c)(6) 

with respect to the CAA section 112(c)(6) pollutants that these 

units emit.

Specifically, as by-products of combustion, the formation 

of POM is effectively reduced by the combustion and postcombustion practices required to comply with the CAA section 112 

standards. Any POM that does form during combustion is further 

controlled by the various post-combustion controls. The add-on 

PM control systems (fabric filter) used to reduce mercury and/or 

PM emissions further reduce emissions of these organic

pollutants, as is evidenced by performance data. Specifically, 

the emission tests obtained at currently operating major source 

boilers show that the MACT regulations for coal-fired area 

source boilers will reduce Hg emissions by about 86 percent. It 

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is, therefore, reasonable to conclude that POM emissions from 

coal-fired area source boilers will be substantially controlled.

In lieu of establishing numerical emissions limits for 

pollutants such as POM, we regulate surrogate substances. While 

we have not identified specific numerical limits for POM, we 

believe CO serves as an effective surrogate for this HAP, 

because CO, like POM, is formed as a product of incomplete 

combustion. 

Consequently, we have concluded that the emissions limits 

for CO function as a surrogate for control of POM, such that it 

is not necessary to establish numerical emissions limits for POM 

with respect to coal-fired area source boilers to satisfy CAA 

section 112(c)(6).

To further address POM and mercury emissions, this rule 

also includes an energy assessment provision that encourages

modifications to the facility to reduce energy demand that lead 

to these emissions.

VIVII. Summary of the Impacts of this Final Rule

A. What are the air impacts?

Table 3 of this preamble illustrates, for each subcategory, 

the estimated emissions reductions achieved by this rule (i.e., 

the difference in emissions between an area source boiler 
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controlled to the MACT/GACT level of control and boilers at the 

current baseline) for new and existing sources. Nationwide 

emissions of total HAP (HCl, hydrogen fluoride, non-mercury 

metals, mercury, and VOC (for organic HAP) will be reduced by 

about 667 tpy for existing units and 74 tpy for new units. 

Emissions of mercury will be reduced by about 88 pounds per year 

for existing units and by about 9 pounds per year for new units. 

Emissions of filterable PM will be reduced by about 2,300 tpy 

for existing units and 280 tpy for new units. Emissions of nonmercury metals (i.e., antimony, arsenic, beryllium, cadmium, 

chromium, cobalt, lead, manganese, nickel, and selenium) will be 

reduced by about 280 tpy for existing units and will be reduced 

by 40 tpy for new units. Additionally, EPA has estimated that 

conducting an annual tune-up will likely reduce emissions of 

organic HAP as a result of improved combustion and reduced fuel 

use. POM reductions are represented by 7-PAH, a group of 

polycyclic aromatic hydrocarbons. EPA estimates that the energy 

efficient work andpractices, management practices, and CO 

emission limits may reduce emissions of 7-PAH by 8 tpy for 

existing units and that the CO emission limit may reduce 

emissions of 7-PAH by 1 tpy for new units. A discussion of the 

methodology used to estimate baseline emissions and emissions 
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reductions is presented in “Estimation of Impacts for 

Industrial, Commercial, and Institutional Boilers Area Source 

NESHAP” in the docket.

Table 3. Summary of HAP Emissions Reductions for Existing and 

New Sources (tpy)

Source Subcategory PM

Non 

Mercury 

Metalsa Mercury POMb

Existing 

Units

Coal 1,092 4 0.003 0.2

Biomass 815 11 0.003 5

Oil 349 269 0.04 3

New 

Units

Coal 7 0.03 0.0001 0.02

Biomass 121 2 0.0002 0.5

Oil 149 36 0.004 0.5

a Includes antimony, arsenic, beryllium, cadmium, chromium, 

cobalt, lead, manganese, nickel, and selenium.

b POM is represented by total emissions of polycyclic aromatic 

hydrocarbons (7-PAH). It is assumed that compliance with work 

practice standard and management practice will reduce fuel usage 

by 1 percent, which may reduce emissions of 7-PAH by an 

equivalent amount.

B. What are the cost impacts?

To estimate the national cost impacts of this rule for 

existing sources, EPA developed several model boilers and 

determined the cost of control for these model boilers. EPA 

assigned a model boiler to each existing unit based on the fuel, 

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size, and current controls. The analysis considered all air 

pollution control equipment currently in operation at existing 

boilers. Model costs were then assigned to all existing units 

that could not otherwise meet the proposed standards. The 

resulting total national cost impact of this rule for existing 

units is $487 million dollars in total annualized costs. The 

total annualized costs (new and existing) for installing 

controls, conducting biennial tune-ups and an energy assessment, 

and implementing testing and monitoring requirements is $535 

million. Table 4 of this preamble shows the total annualized 

cost impacts for each subcategory.

Table 4. Summary of Annual Costs for New and 

Existing Sources

Source Subcategory

Estimated/

Projected No. of 

Affected Units

Total 

Annualized 

Cost (TAC)

($106/yr)a

Existing 

Units

Coal 3,710 37

Biomass 10,958 24

Oil 168,003 374

Facility 

Energy 

Assessme

nt

All 52

New 

Unitsb

Coal 155 0.4

Biomass 200 2.6

Oil 6,424 45

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a TAC does not include fuel savings from improving combustion 

efficiency. 

b Impacts for new units assume the number of units online in the 

first 3 years of this rule (2010 to 2013).

Using Department of Energy projections on fuel 

expenditures, as well as the history of installation dates of 

area source boilers in the dataset, the number of additional 

boilers that could be potentially constructed was estimated. 

The resulting total national cost impact of this proposed rule 

on new sources by the third year, 2013, is $48 million dollars 

in total annualized costs. When accounting for a 1 percent fuel 

savings resulting from improvements to combustion efficiency, 

the total national cost impact on new sources is -($3.6

million).

A discussion of the methodology used to estimate cost 

impacts is presented in the memorandum, “Estimation of Impacts 

for Industrial, Commercial, and Institutional Boilers Area 

Source NESHAP” in the Docket.

C. What are the economic impacts?

The economic impact analysis (EIA) that is included in the 

RIA shows that the expected prices for industrial sectors could 

be 0.01 percent higher and domestic production may fall by less 

than 0.01 percent. Because of higher domestic prices, imports 

may rise by less than 0.01 percent. Energy prices will not be 
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affected. 

 Social costs are estimated to be also $0.49 billion in 2008 

dollars. This is estimated to made up of a $0.24 billion loss 

in domestic consumer surplus, a $0.24 billion loss in domestic 

producer surplus, a $0.004 billion increase in rest of the world 

surplus, and a $0.0.003 billion net loss associated with new 

source costs and fuel savings not modeled in a way that can be 

used to attribute it to consumers and producers.

 EPA 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 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 this final rule’s small entity impacts. 

It includes key information about key results from the Small 

Business Advocacy Review (SBAR) panel. The IRFA is discussed in 

section 5.2 of the report “Regulatory Impact Analysis: National 

Emission Standards for Hazardous Air Pollutants for Industrial, 

Commercial, and Institutional Boilers and Process Heater” 

located in the docket.

For this RIA employment impacts are modeled based on 
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empirical results from a peer-reviewed study Morgenstern, Pizer 

and Shih (2002) that explores the relationship between 

employment and environmental regulation. 

Morgenstern et al. identify three separate components of 

the employment change in response to a regulation:

 higher production costs raise market prices, higher prices 

reduce consumption (and production) reducing demand for labor 

within the regulated industry (“demand effect”);

 As costs go up, plants add more capital and labor. For 

example, pollution abatement activities require additional labor 

services to produce the same level of output (“cost effect”); 

 Post-regulation production technologies may be more or less 

labor intensive (i.e., more/less labor is required per dollar of 

output) (“factor-shift effect”).

Morgenstern et al. empirically estimate a model for four 

highly polluting, regulated industries to examine the effect of 

higher abatement costs from regulation on employment. They 

conclude that increased abatement expenditures generally do not 

cause a significant change in employment. More specifically, 

their results show that, on average across the four industries, 

each additional $1 million spending on pollution abatement 

results in a (statistically insignificant) net increase of 1.5 

jobs. Furthermore they find that for two of the industries (pulp 

and paper, and steel) additional abatement spending leads to a 

statistically positive, yet quite small, net increase in jobs 
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due to substituting labor for other inputs and relatively 

inelastic estimated demand for their output.8

Finally there are two effects that Morgenstern et al. do not 

consider. The first is the effect regulation has on employment 

in industries that make substitute products. Employment goes up 

in the production of these substitute products as consumers 

respond to changes in prices. For example, more expensive 

virgin paper will cause a shift to more recycled paper. The 

recycled paper industry will employ more workers as sales 

increase. Similarly, employment in industries that are 

complements may decrease. The second is changes in employment 

at firms that make pollution control devices or provide 

consulting services employed in design and installation of 

control devices. For example, a recent study by Industrial 

Economics shows that a $19 million order for a new scrubber will 

immediately fund 77 to 91 new jobs for a year constructing and 

installing the new equipment. It will also create 16 permanent 

jobs to operate the new equipment. [(Memorandum to Ellen 

Kurlansky (EPA) from: Jason Price, Nadav Tanners, and Jim 

 

8 These results are similar to Berman and Bui (2001) who find 

that while sharply increased air quality regulation in Los 

Angeles to reduce NOx emissions resulted in large abatement 

costs they did not result in substantially reduced employment.
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Neumann (IEc) and Roy Oommen (ERG), “Employment Impacts 

Associated with the Manufacture, Installation, and Operation of 

Scrubbers,” January 15, 2010])

Parameters estimated in the Morgenstern et al. paper were 

used to estimate three types of employment effects (“demand,” 

“cost,” and “factor shift”). We believe the transfer of 

parameter estimates from the Morgenstern et al. study to this 

rule seems appropriate, as it is a well-respected, peer-reviewed 

study based on standard micro-economic theory. ”Furthermore, 

the results of the Morgenstern et al. work also allow us to 

estimate the “cost effect” and the “factor-shift effect,” as 

well as the “demand effect” to get a more complete sense of how 

regulation affects employment.

We calculated a “demand effect” estimate that used the 

Morgenstern et al. paper. EPA selected this paper because the 

parameter estimates (expressed in jobs per million ($1987) of 

environmental compliance expenditures) provide a transparent and 

tractable way to transfer estimates for an employment effects 

analysis. Similar estimates were not available from other 

studies. To do this, we multiplied the point estimate for the 

total demand effect (−3.56 jobs per million ($1987) of 

environmental compliance expenditure) by the total environmental 
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compliance expenditures used in the partial equilibrium model. 

For example, the jobs effect estimate for the major source rule 

is estimated to be about 6,000 jobs (−3.56 × $2,700 million × 

0.60).9 Demand effect results are provided in Table 5.10

Table 5. Job Losses/Gains Associated 

with the Rules

Method 1,000 Jobs

Literature-based estimate (net effect [A + B +C 

below])

1

(-1 to 2)

A. Literature-based estimate: Demand effect -1

(-3 to 0)

B. Literature-based estimate: Cost 

effect

1

(0 to 1)

C. Literature-based estimate: Factor 

shift effect

1.0

(-1 to 2)

 

9 Since Morgenstern’s analysis reports environmental expenditures 

in $1987, we make an inflation adjustment the engineering cost 

analysis using GDP implicit price deflator (64.76/108.48) = 

0.60) 

10 For comparison purposes, we also calculated “demand effect” 

employment changes by assuming that the number of jobs declines 

proportionally with the multi-market model’s simulated output 

changes. These results were calculated for all sectors in the 

EPA model that show a change in output. For the selected option 

for Major sources this second way of estimating the “demand 

effect” resulted in an estimate of 4000 jobs lost compared to 

the estimate using the Morgenstern parameters of 6000 jobs 

lost. Similarly, for the selected option for Area sources, this 

second way of estimating the “demand effect” resulted in the 

same estimate of 1000 jobs lost as the estimate using the 

Morgenstern parameters. For the combination of the selected 

options for both Major and Area sources, this second way of 

estimating the “demand effect” resulted in an estimate of 5000 

jobs lost compared to the estimate using the Morgenstern 

parameters of 7000 jobs lost.

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Note: Totals may not add due to independent rounding. 

95 percent confidence

intervals for literature-based 

estimates are shown in parenthesis.

We also present the results of using the Morgenstern et al. 

paper to estimate employment “cost” and “factor-shift” effects. 

Although using the Morgenstern et al. parameters to estimate 

these “cost” and “factor-shift” employment changes is uncertain, 

it is helpful to compare the potential job gains from these 

effects to the job losses associated with the “demand” effect.

Table 5 shows that using the Morgenstern et al. point estimates 

of parameters to estimate the “cost” and “factor shift” 

employment gains may be greater than the employment losses 

estimated for the “demand” employment losses. The 95 percent

confidence intervals are shown for all of the estimates based on 

the Morgenstern et al. parameters. As shown, at the 95 percent

confidence level, we cannot be certain if net employment changes 

are positive or negative.

Although the Morgenstern et al. paper provides information 

about the potential job effects of environmental protection 

programs, there are several qualifications EPA considered as 

part of the analysis. First, EPA has used the weighted average 

parameter estimates for a narrow set of manufacturing industries 

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(pulp and paper, plastics, petroleum, and steel). Absent other 

data and estimates, this is a methodologically sound approach as 

these estimates come from a peer-reviewed source. However, EPA 

acknowledges the current rules cover a broader set of industries 

not considered in the original empirical study. By transferring 

the estimates to other industrial sectors, we make the 

assumption that estimates are similar in size. In addition, EPA 

assumes also that Morgenstern et al.’s estimates derived from 

the 1979–1991 time period are still applicable for policy taking 

place in 2014, over 20 years later. Third, Morgenstern et al. 

identifies the industry average as economically and 

statistically insignificant effect (i.e., the point estimates 

are small, measured imprecisely, and not distinguishable from 

zero). EPA acknowledges this fact and thus has reported the 95 

percent confidence intervals in Figure 4-4. Fourth, Morgenstern 

et al.’s methodology assumes that regulations affect plants in 

proportion to their total costs. In other words, each 

additional dollar of regulatory burden affects a plant by an 

amount equal to that plant's total costs relative to the 

aggregate industry costs. By transferring the estimates, EPA 

assumes a similar distribution of regulatory costs by plant size 

and that the regulatory burden does not disproportionately fall 
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on smaller plants. Fifth, there are two categories of job 

effects which are beyond the scope of Morgenstern et al.’s 

study. One is employment at firms that manufacture pollution 

control equipment or provide consulting services to design 

and/or installation pollution control equipment. Employment in 

these sectors would likely increase as firms purchase more 

pollution control equipment and services to meet the promulgated 

rule’s requirements. The second is the impact on employment in 

industries that make substitute products or complementary 

products. However, EPA does not currently have sufficient 

information to provide estimates of job gains from these sources 

for these particular rules. 

D. What are the benefits?

We estimated the The benefit categories associated with 

the emission reduction anticipated for this rule can be broadly 

categorized as those benefits attributable to reduced exposure 

to hazardous air pollutants (HAPs) and those attributable to 

exposure to other pollutants. Because we were unable to 

monetize the benefits associated with reducing HAPs, all 

monetized benefits reflect improvements in ambient PM2.5 and ozone 

concentrations. This results in an underestimate of the total 

monetized benefits. We estimated the total monetized benefits 
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of this final regulatory action to be $210 million to $520 

million (2008$, 3 percent discount rate) in the implementation 

year (2014). The monetized benefits at a 7 percent discount 

rate are $190 million to $470 million (2008$). 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.11

Table 6. Summary of the Monetized Benefits Estimates for the 

Final Boiler Area Source Rule (millions of 2008$)

 A summary of the monetized benefits estimates at 

discount rates of 3 percent and 7 percent are provided in Table 

6 of this preamble. A summary of the avoided health benefits 

are provided in Table 7 of this preamble. 

Pollutant

Emissions 

Reductions 

(tons)

Total Monetized 

Benefits (at 3% 

discount rate)

Total Monetized 

Benefits (at 7% 

discount rate)

Direct PM2.5 678 $79 to $190 $72 to $180

SO2 3,197 $130 to $320 $120 to $290

Total $210 to $520 $190 to $470 1

All estimates are for the implementation year (2014), and are 

rounded to two significant figures so numbers may not sum across 

rows. All fine particles are assumed to have equivalent health 

effects. Benefits from reducing HAP are not included. These 

estimates do not include energy disbenefits valued at less than 

$1 million. These benefits reflect existing boilers and 6,779 

new boilers anticipated to come online by 2014.

Table 7. Summary of the Avoided Health Incidences for the Final 

 

11 Roman et al, 2008. Expert Judgment Assessment of the 

Mortality Impact of Changes in Ambient Fine Particulate Matter 

in the U.S. Environ. Sci. Technol., 42, 7, 2268 – 2274.

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Boiler MACT

Avoided Health 

Incidences

Avoided Premature Mortality 24 to 61

Avoided Morbidity

Chronic Bronchitis 17

Acute Myocardial Infarction 40

Hospital Admissions, Respiratory 6

Hospital Admissions, Cardiovascular 13

Emergency Room Visits, Respiratory 21

Acute Bronchitis 38

Work Loss Days 3,200

Asthma Exacerbation 420

Minor Restricted Activity Days 19,000

Lower Respiratory Symptoms 460

Upper Respiratory Symptoms 350 1

AllNote: All estimates are for the implementation year (2014), 

and are rounded to two significant figures and whole numbers. 

All fine particles are assumed to have equivalent health 

effects. Benefits from reducing HAP are not included. These 

benefits reflect existing boilers and 6,779 new boilers 

anticipated to come online by 2014.

 These quantified benefits estimates represent the human 

health benefits associated with reducing exposure to PM2.5. The 

PM reductions are the result of emission limits on PM as well as 

emission limits on other pollutants, including HAP. To estimate 

the human health benefits, we used the environmental Benefits 

Mapping and Analysis Program (BenMAP) model to quantify the 

changes in PM2.5-related health impacts and monetized benefits 

based on changes in air quality. This approach is consistent 

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with the recently proposed Transport Rule RIA.12

For this final rule, we have expanded and updated the 

analysis since the proposal in several important ways. Using 

the Comprehensive Air Quality Model with extensions (CAMx) 

model, we are able to provide boiler sector-specific air quality 

impacts attributable to the emission reductions anticipated from 

this final rule. We believe that this modeling provides 

estimates that are more appropriate for characterizing the 

health impacts and monetized benefits from boilers than the 

generic benefit-per-ton estimates used for the proposal 

analysis. 

To generate the boiler sector-specific benefit-per-ton 

estimates, we used CAMx to convert emissions of direct PM2.5 and 

PM2.5 precursors into changes in ambient PM2.5 levels and BenMAP 

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 boiler 

sector-specific benefit-per-ton estimates. These models assume 

that all fine particles, regardless of their chemical 

composition, are equally potent in causing premature mortality 

 

12 U.S. Environmental Protection Agency, 2010. RIA for the 

Proposed Federal Transport Rule. Prepared by Office of Air and 

Radiation. June. Available on the Internet at 

http://www.epa.gov/ttn/ecas/regdata/RIAs/proposaltrria_final.pdf
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because there is no clear scientific evidence that would support 

the development of differential effects estimates by particle 

type. Directly emitted PM2.5 and SO2 are the dominant PM2.5

precursors affected by this rule. 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, SO2 has a lower benefit-per-ton estimate than direct 

PM2.5 because it does not directly transform into PM2.5, and 

because sulfate particles formed from SO2 emissions can 

transport many miles, including over areas with low populations. 

Direct PM2.5 emissions convert directly into ambient PM2.5, 

thus, to the extent that emissions occur in population areas, 

exposures to direct PM2.5 will tend to be higher, and monetized 

health benefits will be higher than for SO2 emissions. 

Furthermore, CAMx modeling allows us to model the reduced 

mercury deposition that would occur as a result of the estimated 

reductions of mercury emissions. Although we are unable to 

model mercury methylation and human consumption of mercurycontaminated fish, the mercury deposition maps provide an 

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improved qualitative characterization of the mercury benefits 

associated with this final rulemaking. 

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 on 

both empirical (epidemiological) studies and judgments elicited 

from scientific experts, to characterize the uncertainty in the 

relationship between PM2.5 concentrations and premature 

mortality. For this rule, we cite two key empirical studies, 

one based on the American Cancer Society cohort study13and the 

extended Six Cities cohort study.14

EPA strives to use the best available science to support 

our benefits analyses. We recognize that interpretation of the 

science regarding air pollution and health is dynamic and 

evolving. After reviewing the scientific literature and recent 

 In the RIA for this rule, 

which is available in the docket, we also include benefits 

estimates derived from expert judgments and other assumptions.

 

13

Pope et al, 2002. “Lung Cancer, Cardiopulmonary Mortality, 

and Long-term Exposure to Fine Particulate Air Pollution.” 

Journal of the American Medical Association 287:1132-1141. 14

Laden et al, 2006. “Reduction in Fine Particulate Air 

Pollution and Mortality.” American Journal of Respiratory and 

Critical Care Medicine. 173: 667-672.

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scientific advice, we have determined that the no-threshold 

model is the most appropriate model for assessing the mortality 

benefits associated with reducing PM2.5 exposure. Consistent 

with this recent advice, we are replacing the previous threshold 

sensitivity analysis with a new LML assessment. While an LML 

assessment 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. 

Most of the estimated PM-related benefits in this rule 

would accrue to populations exposed to higher levels of PM2.5. 

Using the Pope, et al., (2002) study, 79 percent of the 

population is exposed at or above the LML of 7.5 μg/m3. Using 

the Laden, et al., (2006) study, 34 percent of the population is 

exposed above the LML of 10 μg/m3. It is important to emphasize 

that we have high confidence in PM2.5-related effects down to the 

lowest LML of the major cohort studies. This fact is important, 

because as we estimate PM-related mortality among populations 

exposed to levels of PM2.5 that are successively lower, our 

confidence in the results diminishes. However, our analysis 

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shows that the great majority of the impacts occur at higher 

exposures. 

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 other pollutants have not been monetized 

in this analysis, including reducing 1,100 tons of CO, 340 tons 

of HCl, 8 tons of HF, 90 pounds of mercury, and 320 tons of 

other metals each year. Specifically, we were unable to 

estimate the benefits associated with HAPs that would be reduced 

as a result of this rule due to data, resource, and methodology 

limitations. Challenges in quantifying the HAP benefits include 

a lack of exposure-response functions, uncertainties in 

emissions inventories and background levels, the difficulty of 

extrapolating risk estimates to low doses, and the challenges of 

tracking health progress for diseases with long latency periods. 

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 rule, which is available in 

the docket.
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In addition, the monetized benefits estimates provided in 

Table 6 do not reflect the disbenefits associated with increased 

electricity usage from operation of the control devices. We 

estimate that the increases in emissions of CO2 would have 

disbenefits valued at less than $1 million at a 3 percent

discount rate (average). CO2-related disbenefits were calculated 

using the social cost of carbon, which is discussed further in 

the RIA. However, these disbenefits do not change the rounded 

total monetized benefits. In the RIA, we also provide the 

monetized CO2 disbenefits using discount rates of 5 percent 

(average), 2.5 percent (average), and 3 percent (95th 

percentile).

This analysis does not include the type of detailed 

uncertainty assessment found in the 2006 PM2.5 NAAQS RIA or 2008 

Ozone NAAQS RIA. However, the benefits analyses in these RIAs 

provide an indication of the sensitivity of our results to 

various assumptions, including the use of alternative 

concentration-response functions and the fraction of the 

population exposed to low PM2.5 levels. 

For more information on the benefits analysis, please refer 

to the RIA for this final rule that is available in the docket.

E. What are the water and solid waste impacts?
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EPA estimated that no additional water usage would result 

from the MACT floor level of control or GACT requirement. The 

fabric filter, multiclone, or combustion control devices used to 

meet the standards of this rule do not require any water to 

operate, nor do they generate any wastewater.

EPA estimated the additional solid waste that would result 

from this rule to be 1,800 tpy for existing sources due to the 

dust and fly ash captured by mercury and PM control devices. 

The cost of handling the additional solid waste generated from 

existing sources is $75,700 per year. For new sources installed 

by 2013, the EPA estimated the additional solid waste that would 

result from this rule to be 540 tpy for new sources due to the 

dust and fly ash captured by mercury and PM control devices. 

The cost of handling the additional solid waste generated from 

new sources is $22,900 per year. These costs are also accounted 

for in the control costs estimates.

A discussion of the methodology used to estimate impacts is 

presented in “Estimation of Impacts for Industrial, Commercial, 

and Institutional Boilers Area Source NESHAP” in the Docket.

F. What are the energy impacts?

EPA expects an increase of approximately 25 million kWh in 

national annual energy usage from existing sources as a result 
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of this rule. The increase results from the electricity 

required to operate control devices installed to meet this rule, 

such as fabric filters. Additionally, for new sources installed 

by 2013, EPA expects an increase of approximately 8 million kWh 

in national annual energy usage in order to operate the control 

devices.

The Department of Energy has conducted energy assessments 

at selected manufacturing facilities and reports that facilities 

can reduce fuel/energy use by 10 to 15 percent by using best 

practices to increase their energy efficiency. Additionally, 

the EPA expects work practice standards, such as boilers tuneups, and combustion controls such as new replacement burners,

will improve the efficiency of boilers. EPA estimates existing 

area source facilities can save 20 trillion Btu of fuel each 

year. For new sources online by 2013, the EPA estimates 2.3 

trillion BTU per year of fuel can be conserved. This fuel 

savings estimate includes only those fuel savings resulting from 

liquid and coal fuels and it is based on the assumption that the 

work practice standards will achieve 1 percent improvement in 

efficiency.

VII. Relationship of this Action to CAA Section 112(c)(6)

CAA section 112(c)(6) requires EPA to identify categories 
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of sources of seven specified pollutants to assure that sources 

accounting for not less than 90 percent of the aggregate 

emissions of each such pollutant are subject to standards under 

CAA section 112(d)(2) or 112(d)(4). EPA has identified 

“Industrial Coal Combustion,” “Industrial Oil Combustion,” 

Industrial Wood/Wood Residue Combustion,” “Commercial Coal 

Combustion,” “Commercial Oil Combustion,” and “Commercial 

Wood/Wood Residue Combustion” as source categories that emit two

of the seven CAA section 112(c)(6) pollutants: POM and mercury. 

(The POM emitted is composed of 16 polyaromatic hydrocarbons 

(PAH).) In the Federal Register notice, Source Category Listing 

for Section 112(d)(2) Rulemaking Pursuant to Section 112(c)(6) 

Requirements, 63 FR 17838, 17849, Table 2 (April 10, 1998), EPA 

identified “Industrial Coal Combustion,” “Industrial Oil 

Combustion,” Industrial Wood/Wood Residue Combustion,” 

“Commercial Coal Combustion,” “Commercial Oil Combustion,” and 

“Commercial Wood/Wood Residue Combustion” as source categories

“subject to regulation” for purposes of CAA section 112(c)(6) 

with respect to the CAA section 112(c)(6) pollutants that these 

units emit.

Specifically, as by-products of combustion, the formation 

of POM is effectively reduced by the combustion and postFormatted: Font: Not Italic, Underline
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combustion practices required to comply with the CAA section 112 

standards. Any POM that does form during combustion is further 

controlled by the various post-combustion controls. The add-on 

PM control systems (fabric filter) used to reduce mercury and/or 

PM emissions further reduce emissions of these organic

pollutants, as is evidenced by performance data. Specifically, 

the emission tests obtained at currently operating major source 

boilers show that the MACT regulations for coal-fired area 

source boilers will reduce Hg emissions by about 86 percent. It 

is, therefore, reasonable to conclude that POM emissions from 

coal-fired area source boilers will be substantially controlled.

In lieu of establishing numerical emissions limits for 

pollutants such as POM, we regulate surrogate substances. While 

we have not identified specific numerical limits for POM, we 

believe CO serves as an effective surrogate for this HAP, 

because CO, like POM, is formed as a product of incomplete 

combustion. 

Consequently, we have concluded that the emissions limits 

for CO function as a surrogate for control of POM, such that it 

is not necessary to establish numerical emissions limits for POM 

with respect to coal-fired area source boilers to satisfy CAA 

section 112(c)(6).
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To further address POM and mercury emissions, this rule 

also includes an energy assessment provision that encourages

modifications to the facility to reduce energy demand that lead 

to these emissions.

VIII. Statutory And Executive Order Review

A. Executive Order 12866: Regulatory Planning and Review

Under section 3(f)(1) of Executive Order 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 Statestate, local, or tribal 

governments or communities. Accordingly, EPA submitted this 

action to OMB for review under EO 12866 and any changes in 

response to OMB recommendations have been documented in the 

docket for this action. 

In addition, EPA prepared an analysis of the potential 

costs and benefits associated with this action. This analysis 

is contained in the Regulatory Impact Analysis (RIA) report. 

For more information on the costs and benefits for this rule, 

please refer to Section VI.C of this preamblesee the following table.

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Summary of the Monetized Benefits, Social Costs, and Net 

Benefits for the Boiler Area Source Rule in 2014 (millions of 

2008$)1

3% Discount Rate 7% Discount Rate

Final MACT/GACT Approach: Selected

Total Monetized 

Benefits2 $210 to $520 $190 to $470

Total Social Costs3 $490 $490

Net Benefits −$280 to $30 −$300 to −$20

Non-monetized Benefits

1,100 tons of carbon monoxide

340 tons of HCl

8 tons of HF 

90 pounds of mercury 

320 tons of other metals

<1 gram of dioxins/furans (TEQ)

Health effects from SO2 exposure

Ecosystem effects 

Visibility impairment 

Proposed MACT Approach: Alternative

Total Monetized 

Benefits2 $200 to $490 $180 to $440

Total Social Costs3 $850 $850

Net Benefits −$650 to −$360 −$670 to −$410

Non-monetized Benefits 1,100 tons of carbon monoxide

340 tons of HCl

8 tons of HF 

90 pounds of mercury 

320 tons of other metals

<1 gram of dioxins/furans (TEQ)

Health effects from SO2 exposure

Ecosystem effects 

Visibility impairment 1 All estimates are for the implementation year (2014), and are 

rounded to two significant figures. These results include units 

anticipated to come online and the lowest cost disposal 

assumption. 

2

The total monetized benefits reflect the human health benefits 

associated with reducing exposure to PM2.5 through reductions of 

directly emitted PM2.5 and PM2.5 precursors such as SO2. It is 

important to note that the monetized benefits include many but 
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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. These estimates include 

energy disbenefits valued at less than $1 million. 3 The methodology used to estimate social costs for one year in 

the multimarket model using surplus changes results in the same 

social costs for both discount rates.

B. Paperwork Reduction Act

The information collection requirements in this rule have 

been submitted for approval to OMB under the Paperwork Reduction 

Act, 44 U.S.C. 3501 et seq. The information collection 

requirements are not enforceable until OMB approves them. The 

ICR document prepared by EPA has been assigned EPA ICR number 

2253.01. The recordkeeping and reporting requirements in this 

rule are based on the information collection requirements in 

EPA’s NESHAP General Provisions (40 CFR part 63, subpart A). 

The recordkeeping and reporting requirements in the General 

Provisions are mandatory pursuant to CAA section 114 (42 U.S.C. 

7414). All information other than emissions data submitted to 

EPA pursuant to the information collection requirements for 

which a claim of confidentiality is made is safeguarded 

according to CAA section 114(c) and EPA’s implementing 

regulations at 40 CFR part 2, subpart B.
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This NESHAP would require applicable one-time notifications 

according to the NESHAP General Provisions. Facility owners or 

operators are required to include compliance certifications for 

the work practices and management practices in their 

Notifications of Compliance Status. Recordkeeping is required 

to demonstrate compliance with emission limits, work practices, 

management practices, monitoring, and applicability provisions. 

New affected facilities are required to comply with the 

requirements for startup, shutdown, and malfunction reports and 

to submit a compliance report if a deviation occurred during the 

semiannual reporting period.

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 $407 

million. This includes 2.7 million labor hours per year at a 

cost of $254 million and total non-labor capital costs of $153 

million per year. This estimate includes initial and annual 

performance tests, conducting and documenting an energy 

assessment, conducting and documenting a tune-up, semiannual 

excess emission reports, maintenance inspections, developing a 

monitoring plan, notifications, and recordkeeping. Monitoring, 

testing, tune-up and energy assessment costs were also included 
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in the cost estimates presented in the control cost impacts 

estimates in Section VII.B of this preamble. The total burden 

for the Federalfederal government (averaged over the first 3 

years after the effective date of the standard) is estimated to 

be 286,000 hours per year at a total labor cost of $13 million 

per year. Burden is defined at 5 CFR 1320.3(b).

An agency may not conduct or sponsor, and a person is not 

required to respond to, a collection of information unless the 

collection displays a currently valid OMB control number. The 

OMB control numbers for EPA’s regulations in 40 CFR part 63 are 

listed in 40 CFR part 9. When this ICR is approved by OMB, the 

Agency will publish a technical amendment to 40 CFR part 9 in 

the Federal Register to display the OMB control number for the 

approved information collection requirements contained in this 

final rule.

C. Regulatory Flexibility Act (RFA), as Amended by the 

Small Business Regulatory Enforcement Fairness Act of 1996, 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 

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that this finalthe rule will not have a significant economic 

impact on a substantial number of small entities. Small 

entities include small businesses, small organizations, and 

small governmental jurisdictions.

For purposes of assessing the impacts of today’s rule 

on small entities, small entity is defined as: (1) a small 

business according to Small Business Administration (SBA) size 

standards by the North American Industry Classification System 

category of the owning entity. The range of small business size 

standards for the affected industries ranges from 500 to 1,000 

employees, except for petroleum refining and electric utilities. 

In these latter two industries, the size standard is 1,500 

employees and a mass throughput of 75,000 barrels/day or less, 

and 4 million kilowatt-hours of production or less, 

respectively; (2) a small governmental jurisdiction that is a 

government of a city, county, town, school district or special 

district with a population of less than 50,000; and (3) a small 

organization that is any not-for-profit enterprise which is 

independently owned and operated and is not dominant in its 

field. 

Pursuant to section 603 of the RFA, EPA prepared an initial 

regulatory flexibility analysis (IRFA) for the proposed rule (see 

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75 FR 31896 (June 4, 2010)). Pursuant to section 609(b) of the RFA, EPAand convened a 

Small Business Advocacy Review Panel to obtain advice and 

recommendations fromof representatives of the regulated small 

entities that would potentially be regulated by this final rule.. A detailed 

discussion of the Panel’s advice and recommendations is found in 

the final Panel Report located in the docket.(Docket ID No. EPA-HQ-OAR2002-0058-0797). A summary of the Panel’s recommendations is 

also presented in detail in the preamble to the proposed rule. See 75

FR 31918-31918 at 75 FR 32044-32045 (June 4, 2010). In the 

proposed rule, EPA included provisions consistent with four of 

the Panel’s recommendations. As required by section 604 of the 

RFA, we also prepared a final regulatory flexibility analysis

(FRFA) the final rule. 

This final rule will not have a significant economic impact 

on a substantial number of small entities as a result of several 

decisions EPA made regarding the development of this final rule,

which resulted in limiting the impact of this final rule on 

small entities. First, as mentioned earlier in this preamble, 

EPA determined that coal-fired area source boilers need only to 

be address under CAA section 112(c)(6). Therefore, the final 

standards for biomass-fired boilers and oil-fired boilers are 

based on GACT, as opposed to the proposed MACT-based emission 
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limits. As also discussed earlier, EPA determined that for new 

small coal-fired boilers (heat input of less than 10 MMBtu/h), 

it is appropriate to promulgate work practice standards, as 

allowed under CAA section 112(h), instead of the MACT-based 

emission limits. Many small coal-fired boilers, biomass-fired 

boilers, and oil-fired boilers are located at small entities. 

Consequently, this final rule contains no emission limits, only 

work practice standards or management practice, for new and 

existing small coal-fired boilers, existing biomass-fired 

boilers, and existing oil-fired boilers.

After considering the economic impacts of today’s final 

rule on small entities, I certify that this action will not have 

a significant economic impact on a substantial number of small 

entities. The small entities directly regulated by this final 

rule are small businesses, small governmental jurisdictions and 

small non-profits.

D.The rule is intended to reduce emissions of HAP as 

required under section 112 of the CAA. Section II.A of the 

final rule’s preamble describes the reasons that EPA is 

finalizing this action. Many significant issues were raised 

during the public comment period, and EPA’s responses to those 

comments are presented in section V of this preamble or in the 
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response to comments document contained in the docket. 

Significant changes to the rule that resulted from the public 

comments are described in section IV of this preamble.

The primary comments on the IRFA were provided by SBA, with 

the remainder of the comments generally supporting SBA’s 

comments. Those comments applicable to the proposal regarding 

area source boilers included the following: EPA should have 

adopted additional subcategories, including the following: unit 

design type (e.g. fluidized bed, stoker, fuel cell, suspension 

burner), duty cycle, geographic location, boiler size, burner 

type (with and without low-NOx burners), and hours of use 

(limited use); EPA should have minimized facility monitoring and 

reporting requirements; EPA should not have proposed the energy 

audit requirement; and EPA’s proposed emissions standards are 

too stringent.

In response to the comments on the IRFA and other public 

comments, EPA made the following changes to the final rule. EPA 

is promulgating management practice standards requiring the 

implementation of a boiler tune-up program for area source 

boilers in the biomass and oil subcategories instead of the 

proposed CO emission limits. This change will significantly 

reduce the monitoring and testing costs for existing and new 
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biomass-fired and oil-fired area source boilers. EPA also 

decreased monitoring and testing costs for coal-fired area 

source boilers by eliminating the CO CEMS requirement for 

boilers greater than 100 MMBtu/h. The final rule also includes 

work practice standards or management practice standards, 

instead of emission limits, for new area source boilers less 

than 10 MMBtu/h. Finally, EPA is finalizing emission limits 

that are less stringent than the proposed limits. The emission 

limit changes are largely due to the changes in data corrections 

and incorporation of new data into the floor calculations. 

Additional details on the changes discussed in this paragraph 

are included in sections IV and V of the final rule’s preamble.

EPA does not have sufficient information to estimate the 

number of small entities expected to be covered by the area 

source rule. As discussed in section 5.1 of the RIA for this 

rule, using these cost data and the Census estimates of average 

establishment receipts, a substantial number of SUSB 

NAICS/enterprise categories have ratios over 3%. The following 

types of representative small area source public facilities 

would have cost-to-revenue ratios exceeding 1 percent but below 

3 percent: other public facilities (ratio > 1.7 percent) and 

churches (ratio = 1.5 percent).
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The information collection activities in this ICR include 

initial and annual stack tests, fuel analyses, operating 

parameter monitoring, continuous O2 monitoring for all coal-fired 

area source boilers greater than 10 MMBtu/h, certified energy 

assessments for area source facilities having a boiler greater 

than 10 MMBtu/h, biennial tune-ups, preparation of a startup, 

shutdown, malfunction plan (SSMP), preparation of a sitespecific monitoring plan and a site-specific fuel monitoring 

plan, one-time and periodic reports, and the maintenance of 

records. Based on 13 states’ inventories of boilers, there are 

an estimated 92,000 existing facilities with affected boilers. 

It is estimated that 53 percent are located in the private 

sector and the remaining 47 percent are located in the public 

sector. Of these, only about 0.3 percent of the area source 

facilities are subject to emission limits and the testing and 

monitoring requirements in the final rule. A table included in 

the FRFA summarizes the types and number of each type of small 

entities expected to be affected by the area source rule.

The Agency expects that persons with knowledge of .pdf 

software, spreadsheet and relational database programs will be 

necessary in order to prepare the report or record. Based on 

experience with previous emission stack testing, we expect most 
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facilities to contract out preparation of the reports associated 

with emission stack testing, including creation of the 

Electronic Reporting Tool submittal which will minimize the need 

for in depth knowledge of databases or spreadsheet software at 

the source. We also expect affected sources will need to work 

with web-based applicability tools and flowcharts to determine 

the requirements applicable to them, knowledge of the heat input 

capacity and fuel use of the combustion units at each facility 

will be necessary in order to develop the reports and determine 

initial applicability to the rule. Affected facilities will 

also need skills associated with vendor selection in order to 

identify service providers that can help them complete their 

compliance requirements, as necessary.

While EPA did make significant changes based on public 

comment, EPA is maintaining, but clarifying, the energy 

assessment requirement. Some changes to the energy assessment 

requirement that will reduce costs for small entities include a 

the following provisions: the energy assessment for facilities 

with affected boilers using less than 0.3 trillion Btu per year 

heat input will be one day in length maximum. The boiler system 

and energy use system accounting for at least 50 percent of the 

energy output will be evaluated to identify energy savings 
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opportunities, within the limit of performing a one-day energy 

assessment; and the energy assessment for facilities with 

affected boilers using 0.3 to 1.0 trillion Btu per year will be 

3 days in length maximum. The boiler system and any energy use 

system accounting for at least 33 percent of the energy output 

will be evaluated to identify energy savings opportunities, 

within the limit of performing a 3-day energy assessment. In 

addition, the final rule allows facilities to use a previously 

completed energy assessment to satisfy the energy assessment 

requirement.

As required by section 212 of SBREFA, EPA also is preparing 

a Small Entity Compliance Guide to help small entities comply 

with this rule. Small entities will be able to obtain a copy of 

the Small Entity Compliance guide at the following web site: 

http://www.epa.gov/ttn/atw/boiler/boilerpg.html.

D. Unfunded Mandates Reform Act of 1995

Title II of the Unfunded Mandates Reform Act of 1995 

(UMRA), Public Law 104-4, establishes requirements for 

Federalfederal agencies to assess the effects of their 

regulatory actions on Statestate, local, and tribal governments 

and the private sector. Under section 202 of the UMRA, we 

generally must prepare a written statement, including a cost-
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benefit analysis, for proposed and final rules with 

“Federalfederal mandates” that may result in expenditures to 

Statestate, 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, section 205 of the UMRA 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 

this final rule. The provisions of section 205 do not apply 

when they are inconsistent with applicable law. Moreover, 

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 this 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 section 203 

of the UMRA. 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 
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Federalfederal intergovernmental mandates, and informing, 

educating, and advising small governments on compliance with the 

regulatory requirements.

We have determined that this rule contains a Federalfederal

mandate that may result in expenditures of $100 million or more 

for Statestate, local, and Tribaltribal 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 Boiler Area Source NESHAP" under 

section 202 of the UMRA which is summarized below.

1. Statutory Authority

As discussed in Section I of this preamble, the statutory 

authority for this rulemaking is CAA section 112. Title III of 

the CAA was enacted to reduce nationwide air toxic emissions. 

Section 112(b) of the CAA 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.

Section 112(d) of the CAA requires us to establish NESHAP 

for both major and area sources of HAP that are listed for 

regulation under CAA section 112(c). CAA section 112(k)(3)(B) 

calls for EPA to identify at least 30 HAP which, as the result 

of emissions from area sources, pose the greatest threat to 
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public health in the largest number of urban areas. CAA section 

112(c)(3) requires EPA to list sufficient categories or 

subcategories of area sources to ensure that area sources

representing 90 percent of the emissions of the 30 urban HAP are 

subject to regulation.

Under CAA section 112(d)(5), we may elect to promulgate 

standards or requirements for area sources based on GACT used by 

those sources to reduce emissions of HAP. 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 analogous source 

category and, as appropriate, the control technologies and 

management practices at area and major sources in similar 

categories, to determine if the standards, technologies, and/or

practices are transferable and generally available to area 

sources. 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.

While GACT may be a basis for standards for most types of 

HAP emitted from area source, CAA section 112(c)(6) requires 
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that source categories accounting for emissions of the HAP 

listed in CAA section 112(c)(6) be subject to standards under 

CAA section 112(d)(2) for the listed pollutants. Thus, CAA 

section 112(c)(6) requires that emissions of each listed HAP for 

the listed categories be subject to MACT regulation. The CAA 

section 112(c)(6) list of source categories includes industrial 

boilers and institutional/commercial boilers. Within these two 

source categories, coal combustion, oil combustion, and wood 

combustion have been on the CAA section 112(c)(6) list because 

of emissions of mercury and POM. We currently believe that 

regulation of coal-fired boilers will ensure that we fulfill our 

obligation under CAA section 112(c)(6) with respect to mercury 

and POM reductions. Consequently, we deem it reasonable to 

regulate the coal-fired boilers under MACT, rather than the 

biomass and oil-fired boilers, to obtain additional mercury and 

POM reductions towards achieving the CAA section 112(c)(6) 

obligation. We are regulating biomass-fired and oil-fired 

boilers under GACT. 

This NESHAP will apply to all existing and new industrial 

boilers, institutional boilers, and commercial boilers located 

at area sources. In compliance with section 205(a) of the UMRA, 

we identified and considered a reasonable number of regulatory 
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alternatives. Additional information on the costs and 

environmental impacts of these regulatory alternatives is 

presented in the docket.

The emission limits for existing area source boilers are 

only applicable to area source boilers that have a designed heat 

input capacity of 10 MMBtu/h or greater. The regulatory 

alternative upon which the standards are based represents the 

MACT floor for the listed CAA section 112(c)(6) pollutants 

(mercury and POM) for coal-fired units and GACT for the other 

urban HAP which formed the basis for the listing of these two 

area source categories. The standards will require new coalfired boilers to meet MACT-based emission limits for mercury and 

CO (as a surrogate for POM) and GACT-based emission limits for 

PM (as a surrogate for urban metals). New biomass and oil-fired 

boilers will be required to meet GACT for CO, which are tuneups, and GACT-based emission limits for PM. Existing large 

coal-fired boilers will be required to meet MACT-based emission 

limits for mercury and CO for coal-fired units, and existing 

large biomass and oil-fired boilers will be subject to GACT, 

which is a tune-up. As allowed under CAA section 112(h), a work 

practice standard requiring the implementation of a tune-up 

program is being established for existing and new area source 
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boilers with a designed heat input capacity of less than 10 

MMBtu/h. An additional “beyond-the-floor” standard is being 

established for existing area source facilities having an 

affected boiler with a heat input capacity of 10 MMBtu/h or 

greater that requires the performance of an energy assessment on 

the boiler and the facility to identify cost-effective energy 

conservation measures. 

2. Social Costs and Benefits

The regulatory impact analysis prepared for this final rule

including the Agency’s assessment of costs and benefits, is 

detailed in the “Regulatory Impact Analysis: National Emission 

Standards for Hazardous Air Pollutants for Industrial, 

Commercial, and Institutional Boilers and Process Heaters” in 

the docket. Based on estimated compliance costs associated with 

this final rule and the predicted change in prices and 

production in the affected industries, the estimated social 

costs of this final rule are $[0.49] billion (2008 dollars).

 It is estimated that 3 years after implementation of this 

final rule, HAP will be reduced by hundreds of tons, including 

reductions in metallic HAP including mercury, hydrochloric acid, 

hydrogen fluoride, and several other organic HAP from area 

source boilers. Studies have determined a relationship between 
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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 reductions in 

PM2.5 and in SO2 that will occur, including 678 tons of PM2.5 and 

3,197 tons of SO2. These reductions occur within 3 years after 

the implementation of the regulation 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). While we are unable to monetize the benefits 

associated with the HAP emissions reductions, we are able to 

monetize the benefits associated with the PM2.5 and SO2

emissions reductions. For SO2.5 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 2013 associated with the 

implementation of this final rule range from $0.21 billion (2008 

dollars) to $0.52 billion (2008 dollars) when using a 3 percent 
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discount rate (or from $0.19 billion (2008 dollars) to $0.47

billion (2008 dollars) when using a 7 percent discount rate. 

The general approach used to value benefits is discussed in more 

detail in Section VII.D of this preamble. For more detailed 

information on the benefits estimated for the rulemaking, refer 

to the RIA in the docket.

3. Future and Disproportionate Costs

The Unfunded Mandates Reform Act requires that we estimate, 

where accurate estimation is reasonably feasible, future 

compliance costs imposed by this final rule and any 

disproportionate budgetary effects. Our estimates of the future 

compliance costs of this final rule are discussed in Section 

VII.C of this preamble.

We do not believe that there will be any disproportionate 

budgetary effects of this final rule on any particular areas of 

the country, Statestate or local governments, types of 

communities (e.g., urban, rural), or particular industry 

segments. See the results of the “Economic Impact Analysis of 

the Proposed Industrial Boilers and Process Heaters NESHAP,” the 

results of which are discussed in Section VII.C of this 

preamble.

4. Effects on the National Economy
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The Unfunded Mandates Reform Act requires that we estimate 

the effect of the 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 final rule is 

presented in the Economic Impact Analysis chapter (Section 4) of 

the RIA in the docket. This analysis provides estimates of the 

effect of this final rule on some of the categories mentioned 

above. The results of the economic impact analysis are 

summarized in Section VII.C of this preamble. The results show 

that there will be a small impact on prices and output (less 

than 0.01 percent). In addition, there should be little impact 

on energy markets (in this case, coal, natural gas, petroleum 

products, and electricity). Hence, the potential impacts on the 

categories mentioned above should be small.

5. Consultation with Government Officials

The Unfunded Mandates Reform Act requires that we describe 

the extent of the Agency’s prior consultation with affected 

Statestate, local, and tribal officials, summarize the 
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officials’ comments or concerns, and summarize our response to 

those comments or concerns. In addition, section 203 of the 

UMRA 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 section 204 of the UMRA, EPA has 

initiated consultations with governmental entities affected by 

this rule. EPA invited the following 10 national organizations 

representing Statestate and local elected officials to a meeting 

held on March 24, 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 Statestate 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 provide 

general background on the proposal, answer questions, and 

solicit input from Statestate/local governments. During the 
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meeting, officials expressed uncertainty with regard to how 

boilers owned/operated by Statestate and local entities would be 

impacted, as well as with regard to the potential burden 

associated with implementing this final rule on Statestate and 

local entities. To that end, officials requested and EPA 

provided (1) model boiler costs, (2) inventory of area source 

boilers (coal, oil, biomass only) for the 13 Statesstates for 

which we have an inventory, and (3) information on potential 

size of boilers used for various facility types and sizes. EPA 

has not received additional questions or requests from 

Statestate or local officials.

Consistent with section 205, EPA identified and considered 

a reasonable number of regulatory alternatives. Because an 

initial screening analysis for impact on small entities 

indicated a likely significant impact for substantial numbers,

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 final rule. As part of that 

process, EPA considered several options. Those options included 

establishing emission limits, establishing work practice 

standards, and establishing work practice standards and 

requiring an energy assessment. The regulatory alternative 
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selected is a combination of the options considered and includes 

provisions regarding each of the SBAR Panel’s recommendations

for area source boilers. The recommendations regard the use of 

subcategories, work practice standards, and compliance costs 

(see section IX.C of this preamble for more detail on the RFA).

EPA determined subcategories based on boiler type to be 

appropriate because different types of units have different 

emission characteristics which may affect the feasibility and 

effectiveness of emission control. Thus, this final rule

identifies three subcategories of area source boilers: (1) 

boilers designed for coal firing, (2) boilers designed for 

biomass firing, and (3) boilers designed for oil firing.

The emission limits for existing and new area source 

boilers are only applicable to area source boilers that have a 

designed heat input capacity of 10 MMBtu/h or greater. A work 

practice standard (for mercury from coal-fired boilers and for 

POM from all boilers) or management practice (for all other HAP, 

including mercury from biomass-fired and oil-fired boilers) 

requiring the implementation of a tune-up program is being 

established for existing area source boilers with a designed 

heat input capacity of less than 10 MMBtu/h. The regulatory 

alternative upon which the standards are based represents the 
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MACT floor for mercury and POM (CO is used as a surrogate for 

POM) for coal-fired boilers, and GACT for the other urban HAP 

(PM is used as a surrogate for urban HAP metals and CO is used 

as a surrogate for urban organic pollutants) for new coal, 

biomass, and oil-fired boilers. An additional “beyond-thefloor” standard is being established for existing area source 

facilities having an affected boiler with a heat input capacity 

of 10 MMBtu/h or greater that requires the performance of an 

energy assessment on the boiler and the facility to identify 

cost-effective energy conservation measures.

The use of surrogate pollutants will result in reduced

compliance costs because testing is only be required for the 

surrogate pollutants (i.e., CO and PM) versus for the HAP (i.e., 

POM and metals). The work practice standard/management practice

also will result in reduced compliance costs with respect to 

monitoring/testing for the smaller existing area source boilers. 

EPA’s exemption of most area source facilities from title V 

permit requirements also will reduce burden on area source 

boiler facilities.

This rule is not subject to the requirements of section 203 

of the UMRA because it contains no regulatory requirements that 

might significantly or uniquely affect small governments. While 
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some small governments may have boilers that will be affected by 

this final rule, EPA’s analysis shows that other public 

facilities that are located at area source facilities owned by 

small entities will not have cost-to-revenue ratios exceeding 10

percent. Hospitals’ and schools’ revenue tests fall below 1

percent. Because this final rule’s requirements apply equally 

to boilers owned and/or operated by governments and to boilers 

owned and/or operated by private entities, there will be no 

requirements that uniquely apply to such governments or impose 

any disproportionate impacts on them.

E. Executive Order 13132: Federalism

Under Executive Order 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 Federalfederal government provides the funds 

necessary to pay the direct compliance costs incurred by 

Statestate and local governments, or EPA consults with 

Statestate 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 Statestate or local governments, and the 
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Federalfederal 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 Executive Order 13132.

Based on the estimates in EPA’s RIA for today’s action, the 

regulatory option may have federalism implications because the 

action may impose approximately $276 million in annual direct 

compliance costs on an estimated 57,000 Statestate or local 

governments. Boiler inventories for the health services, 

educational services, and government-owned buildings sectors 

from 13 States were used to estimate the nationwide number of 

potentially impacted Statestate or local governments. Because 

the inventories for these sectors include privately owned and 

Federalfederal government owned facilities, the estimate may 

include many facilities that are not Statestate or local 

government owned. Table 8 of this preamble presents estimates 

of the number of potentially impacted Statestate and local 

governments and their potential annual compliance costs for each 

of the three sectors. In addition to an estimate of the total 

number of potentially impacted facilities, estimates for 

facilities with small boilers and for facilities with large 

boilers are presented. Small boilers (boilers with heat input 
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capacity of less than 10 MMBtu/h) will be subject to a work 

practice standard or management practice that requires a boiler 

tune-up every 2 years. Large coal-fired boilers (boilers with 

heat input capacity of 10 MMBtu/h or greater) will be subject to 

emission limits for mercury and CO. Large biomass and oil-fired 

boilers will be subject to a biennial boiler tune-up requirement

for CO. All facilities with large boilers will be required to 

conduct a one-time energy assessment.

Table 8. State and local governments potentially impacted by 

the standards for boilers at area source facilities

Sector

Number of potentially 

impacted facilities

Annual compliance 

costs to meet 

Total Small Large standards

Health 

Services

17,206 15,293 1,913 $84 million

Educational 

Services

34,052 33,303 749 $159 million

GovernmentOwned 

Buildings

5,796 5,098 698 $33 million

Total 57,054 53,694 3,360 $276 million

EPA consulted with Statestate and local officials in the 

process of developing the action to permit them to have 

meaningful and timely input into its development. EPA met with 

10 national organizations representing Statestate and local 

elected officials to provide general background on the proposed 

rule, answer questions, and solicit input from Statestate/local 

governments. The UMRA discussion in Section IX.D this preamble 

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includes a description of the consultation. As required by 

section 8(a) of Executive Order 13132, EPA included a 

certification from its Federalism Official stating that EPA had 

met the Executive Order’s requirements in a meaningful and 

timely manner, when it sent the draft of this final action to 

OMB for review pursuant to Executive Order 12866. A copy of 

this certification has been included in the public version of 

the official record for this final action.

F. Executive Order 13175: Consultation and Coordination with 

Indian Tribal Governments

This action does not have tribal implications, as specified 

in Executive Order 13175 (65 FR 67249, November 9, 2000). This 

final rule imposes requirements on owners and operators of 

specified area sources and not tribal governments. We do not 

know of any industrial, commercial, or institutional boilers 

owned or operated by Indian tribal governments. However, if 

there are any, the effect of this final rule on communities of 

tribal governments would not be unique or disproportionate to 

the effect on other communities. Thus, Executive Order 13175 

does not apply to this action.

G. Executive Order 13045: Protection of Children from 

Environmental Health Risks and Safety Risks
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This action is not subject to Executive Order 13045 

because the Agency does not believe the environmental health 

risks or safety risks addressed by this action present a 

disproportionate risk to children. In addition, this action is 

not subject to Executive Order 13045 because this final rule is 

based solely on technology performance.

H. Executive Order 13211: Actions Concerning Regulations That 

Significantly Affect Energy Supply, Distribution, or Use

This action is not a “significant energy action” as defined 

in Executive Order 13211 (66 FR 28355 (May 22, 2001)) because it 

is not likely to have a significant adverse effect on the 

supply, distribution, or use of energy. We estimate no 

significant changes for the energy sector for price, production, 

or imports. For more information on the estimated energy 

effects, please refer to Section VI of this preamble. The 

analysis is available in the public docket. 

I. National Technology Transfer and Advancement Act

Section 12(d) of the National Technology Transfer and 

Advancement Act (NTTAA) of 1995 (Public Law No. 104-113, Section 

12(d), 15 U.S.C. 272 note) directs EPA to use voluntary consensus 

standards (VCS) in its regulatory activities, unless to do so 

would be inconsistent with applicable law or otherwise 
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impractical. The VCS are technical standards (e.g., materials 

specifications, test methods, sampling procedures, and business 

practices) that are developed or adopted by VCS bodies. The 

NTTAA directs EPA to provide Congress, through OMB, explanations 

when the Agency does not use available and applicable VCS.

This final rule involves technical standards. EPA cites 

the following standards in this final rule: EPA Methods 1, 2, 

2F, 2G, 3A, 3B, 4, 5, 5D, 10, 10A, 10B, 17, 19, 29 of 40 CFR 

part 60; 101A of 40 CFR part 61; and voluntary consensus 

standards: American Society of Mechanical Engineers (ASME) PTC 

19 (manual methods only), American Society for Testing and 

Materials (ASTM) D6522-00, ASTM D6784-02, ASTM D2234/D2234M–10, 

ASTM D6323-98, ASTM D2013-04, ASTM D5198-92, ASTM D5865-04, ASTM 

E711-87, ASTM D3173-03, ASTM E871-82, and ASTM D6722-01.

Consistent with the NTTAA, EPA conducted searches to 

identify voluntary consensus standards in addition to these EPA 

methods. No applicable voluntary consensus standards were 

identified as alternatives for EPA Methods 2F, 2G, 5D, and 19. 

The search and review results are in the docket for this rule.

The search for emissions measurement procedures identified 

16 other voluntary consensus standards. EPA determined that 

these 16 standards identified for measuring emissions of the HAP 
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or surrogates subject to emission standards in this rule were 

impractical alternatives to EPA test methods for the purposes of 

this rule. Therefore, EPA did not adopt these standards for 

this purpose. The reasons for the determinations for the 16

methods can be found in the docket to this rule.

Table 4 to subpart JJJJJJ of this rule lists the testing 

methods included in the regulation. Under 40 CFR 63.7(f) and 

63.8(f) of the General Provisions, a source may apply to EPA for 

permission to use alternative test methods or alternative 

monitoring requirements in place of any required testing 

methods, performance specifications, or procedures.

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 Federalfederal executive policy on environmental 

justice (EJ). Its main provision directs Federalfederal

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, low-income, 
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and Tribaltribal populations in the United States.

This action establishes national emission standards for 

industrial, commercial, and institutional boilers that are area 

sources. The industrial boiler source category includes boilers 

used in manufacturing, processing, mining, refining, or any 

other industry. The commercial boiler source category includes 

boilers used in commercial establishments such as stores/malls, 

laundries, apartments, restaurants, theatres, and hotels/motels. 

The institutional boiler source category includes boilers used 

in medical centers (e.g., hospitals, clinics, nursing homes), 

educational and religious facilities (e.g., schools, 

universities, places of worship), and municipal buildings (e.g., 

courthouses, arts centers, prisons). There are approximately 

92,000 facilities affected by this final rule, most of which are 

small entities. By the defined nature of the category, many of 

these sources are located in close proximity to residential 

areas, commercial centers, and other locations where large 

numbers of people live and work.

Due to the large number of these sources, their nation-wide 

dispersal, and the absence of site specific coordinates, EPA is 

unable to examine the distributions of exposures and health 

risks attributable to these sources among different socio-
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demographic groups for this rule, or to relate the locations of 

expected emission reductions to the locations of current poor 

air quality. However, this final rule is anticipated to have 

substantial emissions reductions of toxic air pollutants (see 

Table 2 of this preamble), some of which are potential 

carcinogens, neurotoxins, and respiratory irritants. This final 

rule will also result in reductions in criteria pollutants such 

as CO, PM, SO2, as well as ozone precursors.

Because of the close proximity of these source categories 

to people, the substantial emission reductions of air toxics 

resulting from the implementation of this rule is anticipated to 

have health benefits for all persons living or going near these 

types of sources. (Please refer to the RIA for this rulemaking, 

which is available in the docket.) For example, there will be 

reductions of mercury emissions which will reduce potential 

exposures due to the atmospheric deposition of mercury for 

populations such as subsistence fisherman. In addition, there 

will be reductions in other air toxics which can cause adverse 

health effects such as ozone precursors that contribute to 

“smog.” EPA has determined that this rule will not have 

disproportionately high and adverse human health or 

environmental effects on minority or low-income populations 
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because it increases the level of environmental protection for 

all affected populations without having any disproportionately 

high and adverse human health or environmental effects on any 

population, including any minority, low-income, or Tribaltribal

populations. 

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 an EJ communication strategy to ensure that 

interested communities have access to this rule, are aware of 

its content, and have an opportunity to comment. In addition, 

Statestate and Federalfederal permitting requirements will 

provide Statestate and local governments and communities the 

opportunity to provide their comments on the permit conditions 

associated with permitting these sources.

K. 

The Congressional Review Act, 5 U.S.C. 801 et seq., as 

added by the Small Business Regulatory Enforcement Fairness Act 

of 1996, generally provides that before a rule may take effect, 

the agency promulgating this final rule must submit a rule 

Congressional Review Act
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report, which includes a copy of this final rule, to each House 

of the Congress and to the Comptroller General of the United 

States. EPA will submit a report containing this rule and other 

required information to the U.S. Senate, the U.S. House of 

Representatives, and the Comptroller General of the United 

States prior to publication of this final rule in the Federal 

Register. A major rule cannot take effect until 60 days after 

it is published in the Federal Register. This action is a 

“major rule” as defined by 5 U.S.C. 804(2). This rule will be 

effective [INSERT THE DATE 60 DAYS FOLLOWING PUBLICATION OF THIS 

FINAL RULE IN THE FEDERAL REGISTER].

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List of Subjects in 40 CFR part 63

Environmental protection, Administrative practice and 

procedure, Air pollution control, Hazardous substances, 

Intergovernmental relations, Incorporation by reference, 

Reporting and recordkeeping requirements.

______________________

Dated:

_______________________

Lisa P. Jackson,

Administrator.
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For the reasons stated in the preamble, title 40, chapter 

I, part 63 of the Code of Federal Regulations is proposed to be 

amended as follows:

PART 63—-[AMENDED]

1. The authority citation for part 63 continues to read as 

follows:

Authority: 42 U.S.C. 7401 et seq.

Subpart A—[AMENDED]

2. Section 63.14 is amended by revising:

a. Revising paragraphs (b)(27), (b)(35), (b)(39) through 

(44), (b)(47), (b)(49), (b)(50), (b)() through (52), (b)(55), 

(b)(56), (b)(5857), (b)(61), (b)(6264), and (i)(1) to read as 

follows:).

b. Removing and reserving paragraphs (b)(45), (b)(46), 

(b)(55), (b)(56), (b)(58) through (60), and (b)(62).

c. Adding paragraphs (b)(66) through (68).

d. Adding paragraphs (o) and (p).

§63.14 Incorporation by reference.

* * * * *

(b) * * *

(27) ASTM D6522–00, Standard Test Method for 

Determination of Nitrogen Oxides, Carbon Monoxide, and Oxygen 

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Concentrations in Emissions from Natural Gas Fired Reciprocating 

Engines, Combustion Turbines, Boilers, and Process Heaters Using 

Portable Analyzers, IBR approved for §63.9307(c)(2).

* * * * *

(35) ASTM D6784-02 (Reapproved 2008) Standard Test Method 

for Elemental, Oxidized, Particle-Bound and Total Mercury in 

Flue Gas Generated from Coal-Fired Stationary Sources (Ontario 

Hydro Method), approved April 1, 2008, IBR approved for table 1 

to subpart DDDDD of this part, table 2 to subpart DDDDD of this 

part, table 5 to subpart DDDDD, table 12 to subpart DDDDD of 

this part, and table 4 to subpart JJJJJJ of this part.

* * * * *

(39) ASTM Method D388-05, Standard Classification of Coals 

by Rank1Rank, approved September 15, 2005, IBR approved for 

§63.7575 and §63.11237.

* * * * *

(40) ASTM D396-10 Standard Specification for Fuel Oils, 

approved October 1, 2010, IBR approved for §63.7575.

(41) ASTM Method D1835–05, Standard Specification for 

Liquefied Petroleum (LP) Gases,1 approved April 1, 2005, IBR 

approved for §63.7575 and §63.11237 .

* * * * *

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(58(42) ASTM D2013/D2013M-09 Standard Practice for 

Preparing Coal Samples for Analysis, approved November 1, 2009, 

IBR approved for table 6 to subpart DDDDD of this part and table 

5 to subpart JJJJJJ of this part. 

(43) ASTM D2234/D2234M-10 Standard Practice for Collection 

of a Gross Sample of Coal, approved January 1, 2010, IBR 

approved for table 6 to subpart DDDDD of this part and table 5 

to subpart JJJJJJ of this part.

(44) ASTM D3173–03 (Reapproved 2008),) Standard Test 

Method for Moisture in the Analysis Sample of Coal and Coke, 

approved February 1, 2008, IBR approved for Tabletable 6 to 

subpart DDDDD of this part and Tabletable 5 to subpart JJJJJJ of 

this part.

* * * * *

(47) ASTM D5198-09 Standard Practice for Nitric Acid 

Digestion of Solid Waste, approved February 1, 2009, IBR 

approved for table 6 to subpart DDDDD of this part and table 5 

to subpart JJJJJJ of this part.

(48) ASTM D5865–10a Standard Test Method for Gross 

Calorific Value of Coal and Coke, approved May 1, 2010, IBR 

approved for table 6 to subpart DDDDD of this part and table 5 

to subpart JJJJJJ of this part.

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(49) ASTM D6323–98 (Reapproved 2003), Standard Guide for 

Laboratory Subsampling of Media Related to Waste Management 

Activities, approved August 10, 2003, IBR approved for table 6 

to subpart DDDDD of this part and table 5 to subpart JJJJJJ of 

this part.

(50) ASTM E711-87 (Reapproved 2004) Standard Test Method 

for Gross Calorific Value of Refuse-Derived Fuel by the Bomb 

Calorimeter, approved August 28, 1987, IBR approved for table 6 

to subpart DDDDD of this part and table 5 to subpart JJJJJJ of 

this part.

(51) ASTM E776-87 (Reapproved 2009) Standard Test Method 

for Forms of Chlorine in Refuse-Derived Fuel, approved July 1, 

2009, IBR approved for table 6 to subpart DDDDD of this part.

(52) ASTM E871-82 (Reapproved 2006) Standard Test Method 

for Moisture Analysis of Particulate Wood Fuels, approved 

November 1, 2006, IBR approved for table 6 to subpart DDDDD of 

this part and table 5 to subpart JJJJJJ of this part.

* * * * *

(57) ASTM D6721-01 (Reapproved 2006) Standard Test Method 

for Determination of Chlorine in Coal by Oxidative Hydrolysis 

Microcoulometry, approved April 1, 2006, IBR approved for table 

6 to subpart DDDDD of this part.
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* * * * *

(61) ASTM D6722–01 (2006),) Standard Test Method for Total 

Mercury in Coal and Coal Combustion Residues by the Direct 

Combustion Analysis, approved April 1, 2006, IBR approved for 

Table 6 to subpart DDDDD and Table 5 to subpart JJJJJJ of this 

part.

(62* * * * *

(64) ASTM D5865–10a,D6522–00 (Reapproved 2005), Standard 

Test Method for Gross Calorific ValueDetermination of 

CoalNitrogen Oxides, Carbon Monoxide, and CokeOxygen 

Concentrations in Emissions from Natural Gas Fired Reciprocating 

Engines, Combustion Turbines, Boilers, and Process Heaters Using 

Portable Analyzers, approved October 1, 2005, IBR approved for 

Table 6table 4 to subpart DDDDD and TableZZZZ of this part, 

table 5 to subpart DDDDD of this part, and table 4 to subpart 

JJJJJJ of this part.

* * * * * * * *

(66) ASTM D4084–07 Standard Test Method for Analysis of 

Hydrogen Sulfide in Gaseous Fuels (Lead Acetate Reaction Rate 

Method), approved June 1, 2007, IBR approved for table 6 to 

subpart DDDDD of this part. 

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(67) ASTM D5954-98 (Reapproved 2006), Test Method for 

Mercury Sampling and Measurement in Natural Gas by Atomic 

Absorption Spectroscopy, approved December 1, 2006, IBR approved 

for table 6 to subpart DDDDD of this part.

(68) ASTM D6350-98 (Reapproved 2003) Standard Test Method 

for Mercury Sampling and Analysis in Natural Gas by Atomic 

Fluorescence Spectroscopy, approved May 10, 2003, IBR approved 

for table 6 to subpart DDDDD of this part.

(i) * * *

(1) ANSI/ASME PTC 19.10–1981, “Flue and Exhaust Gas 

Analyses [Part 10, Instruments and Apparatus],” IBR approved for 

§§63.309(k)(1)(iii), 63.865(b), 63.3166(a)(3), 

63.3360(e)(1)(iii), 63.3545(a)(3), 63.3555(a)(3), 63.4166(a)(3), 

63.4362(a)(3), 63.4766(a)(3), 63.4965(a)(3), 63.5160(d)(1)(iii), 

63.9307(c)(2), 63.9323(a)(3), 63.11148(e)(3)(iii), 

63.11155(e)(3), 63.11162(f)(3)(iii) and (f)(4), 

63.11163(g)(1)(iii) and (g)(2), 63.11410(j)(1)(iii), 

63.11551(a)(2)(i)(C), table 5 to subpart DDDDD of this part, 

table 1 to subpart ZZZZZ of this part, and table 4 to subpart 

JJJJJJ of this part.

* * * * *
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(o) The following material is available from the U.S. 

Environmental Protection Agency, 1200 Pennsylvania Avenue, NW., 

Washington, DC 20460, (202) 272–0167, http://www.epa.gov. 

(1) National Emission Standards for Hazardous Air 

Pollutants (NESHAP) for Integrated Iron and Steel Plants—

Background Information for Proposed Standards, Final Report, 

EPA–453/R–01–005, January 2001, IBR approved for §63.7491(g).

(2) Office Of Air Quality Planning And Standards (OAQPS), 

Fabric Filter Bag Leak Detection Guidance, EPA–454/R–98–015, 

September 1997, IBR approved for §63.7525(j)(2) and 

§63.11224(f)(2).

(3) SW–846–3020A, Acid Digestion of Aqueous Samples And 

Extracts For Total Metals For Analysis By GFAA Spectroscopy, 

Revision 1, July 1992, in EPA Publication No. SW–846, Test 

Methods for Evaluating Solid Waste, Physical/Chemical Methods, 

Third Edition, IBR approved for table 6 to subpart DDDDD of this 

part and table 5 to subpart JJJJJJ of this part.

(4) SW–846–3050B, Acid Digestion of Sediments, Sludges, 

And Soils, Revision 2, December 1996, in EPA Publication No. SW–

846, Test Methods for Evaluating Solid Waste, Physical/Chemical 

Methods, Third Edition, IBR approved for table 6 to subpart 

DDDDD of this part and table 5 to subpart JJJJJJ of this part. 
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(5) SW-846-7470A, Mercury In Liquid Waste (Manual ColdVapor Technique), Revision 1, September 1994, in EPA Publication 

No. SW–846, Test Methods for Evaluating Solid Waste, 

Physical/Chemical Methods, Third Edition, IBR approved for table 

6 to subpart DDDDD of this part and table 5 to subpart JJJJJJ of 

this part.

(6) SW-846-7471B, Mercury In Solid Or Semisolid Waste 

(Manual Cold-Vapor Technique), Revision 2, February 2007, in EPA 

Publication No. SW–846, Test Methods for Evaluating Solid Waste, 

Physical/Chemical Methods, Third Edition, IBR approved for table 

6 to subpart DDDDD of this part and table 5 to subpart JJJJJJ of 

this part.

(7) SW-846-9250, Chloride (Colorimetric, Automated 

Ferricyanide AAI), Revision 0, September 1986, in EPA 

Publication No. SW–846, Test Methods for Evaluating Solid Waste, 

Physical/Chemical Methods, Third Edition, IBR approved for table 

6 to subpart DDDDD of this part.

(p) The following material is available for purchase from 

the International Standards Organization (ISO), 1, ch. de la 

Voie-Creuse, Case postale 56, CH–1211 Geneva 20, Switzerland, 

+41 22 749 01 11, http://www.iso.org/iso/home.htm.
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(1) ISO 6978-1:2003(E), Natural Gas – Determination of 

Mercury - Part 1: Sampling of Mercury by Chemisorption on 

Iodine, First edition, October 15, 2003, IBR approved for table 

6 to subpart DDDDD of this part.

(2) ISO 6978-2:2003(E), Natural gas - Determination of 

Mercury - Part 2: Sampling of Mercury by Amalgamation on 

Gold/Platinum Alloy, First edition, October 15, 2003, IBR 

approved for table 6 to subpart DDDDD of this part.

3. Part 63 is amended by adding subpart JJJJJJ to read as 

follows:

Subpart JJJJJJ--National Emission Standards for Hazardous Air 

Pollutants for Industrial, Commercial, and Institutional Boilers 

Area Sources

Sec.

What this Subpart Covers

63.11193 Am I subject to this subpart?

63.11194 What is the affected source of this subpart?

63.11195 Are any boilers not subject to this subpart?

63.11196 What are my compliance dates?

Emission Limits, Work Practice Standards, Emission Reduction 

Measures, and Management Practices

63.11200 What are the subcategories of boilers?

63.11201 What standards must I meet?

InitialGeneral Compliance Requirements

63.11205 What are my general requirements for complying with 

this subpart?

Initial Compliance Requirements
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63.11210 What are my initial compliance requirements and by 

what date must I conduct them?

63.11211 How do I demonstrate initial compliance with the 

emission limits?

63.11212 What stack tests and procedures must I use for the 

performance tests?

63.11213 What fuel analyses and procedures must I use for the 

performance tests?

63.11214 How do I demonstrate initial compliance with the work 

practice standard, emission reduction measures, 

and management practice?

Continuous Compliance Requirements

63.11220 When must I conduct subsequent performance tests?

63.11221 How do I monitor and collect data to demonstrate 

continuous compliance?

63.11222 How do I demonstrate continuous compliance with the 

emission limits?

63.11223 How do I demonstrate continuous compliance with the 

work practice standards and management practices?

63.11224 What are my monitoring, installation, operation, and 

maintenance requirements?

63.11225 What are my notification, reporting, and recordkeeping 

requirements?

§63.11226 How can I assert an affirmative defense if I exceed

an emission limit during a malfunction?

Other Requirements and Information

63.11235 What parts of the General Provisions apply to me?

63.11236 Who implements and enforces this subpart?

63.11237 What definitions apply to this subpart?

Table 1 to Subpart JJJJJJ of Part 63. Emission Limits

Table 2 to Subpart JJJJJJ of Part 63. Work Practice Standards

Table 3 to Subpart JJJJJJ of Part 63. Operating Limits for 

Boilers With Emission Limits

Table 4 to Subpart JJJJJJ of Part 63. Performance (Stack) 

Testing Requirements

Table 5 to Subpart JJJJJJ of Part 63. Fuel Analysis 

Requirements

Table 6 to Subpart JJJJJJ of Part 63—Establishing Operating 

Limit
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Table 7 to Subpart JJJJJJ of Part 63. Applicability of General 

Provisions to Subpart JJJJJJ

Subpart JJJJJJ--National Emission Standards for Hazardous Air 

Pollutants for Industrial, Commercial, and Institutional Boilers 

Area Sources

What this Subpart Covers

§63.11193 Am I subject to this subpart? 

You are subject to this subpart if you own or operate an 

industrial, commercial, or institutional boiler as defined in 

§63.11237 that is located at, or is part of, an area source of 

hazardous air pollutants (HAP), as defined in §63.2, except as 

specified in §63.11195.

§63.11194 What is the affected source of this subpart?

(a) This subpart applies to each new, reconstructed, or 

existing affected source as defined in paragraphs (a)(1) and (2) 

of this section.

(1) The affected source is the collection of all 

existing industrial, commercial, and institutional boilers 

within a subcategory, (coal, biomass, oil), as listed in 

§63.11200 and defined in §63.11237, located at an area source.

(2) The affected source of this subpart is each new 

or reconstructed industrial, commercial, or institutional boiler 

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within a subcategory, as listed in §63.11200 and as defined in 

§63.11237, located at an area source.

(b) An affected source is an existing source if you 

commenced construction or reconstruction of the affected source 

on or before June 4, 2010.

(c) An affected source is a new source if you commenced 

construction or reconstruction of the affected source after June 

4, 2010 and you meet the applicability criteria at the time you 

commence construction.

(d) A boiler is a new affected source if you commenced 

fuel switching from natural gas to solid fossil fuel, biomass, 

or liquid fuel after June 4, 2010.

(e) Any source that was a major source and installed a 

control device on a boiler after November 15, 1990, and, as a 

result, became an area source under 40 CFR part 63 is required 

to obtain a permit under 40 CFR part 70 or 40 CFR part 71. 

Otherwise, you are exempt from the obligation to obtain a permit 

under 40 CFR part 70 or 40 CFR part 71, provided you are not 

otherwise required by law to obtain a permit under 40 CFR 

§70.3(a) or 40 CFR §71.3(a). Notwithstanding the previous 

sentence, you must continue to comply with the provisions of 

this subpart.
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§63.11195 Are any boilers not subject to this subpart? 

The types of boilers listed in paragraphs (a) through (eg) 

of this section are not subject to this subpart and to any 

requirements in this subpart.

(a) Any boiler specifically listed as, or included in the 

definition of, an affected source in another standard(s) under 

this part.

(b) Any boiler specifically listed as an affected source 

in another standard(s) established under section 129 of the 

Clean Air Act (CAA)..

(c) A boiler required to have a permit under section 3005 

of the Solid Waste Disposal Act or covered by subpart EEE of 

this part (e.g., hazardous waste boilers).

(d) A boiler that is used specifically for research and 

development. This exemption does not include unitsboilers that 

solely or primarily provide steam (or heat) to a process or for 

heating at a research and development facility. This exemption 

does not prohibit the use of the steam (or heat) generated from 

the boiler during research and development, however, the boiler 

must be concurrently and primarily engaged in research and 

development for the exemption to apply. 

(e) A gas-fired boiler as defined in this subpart.
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(f) A hot water heater as defined in this subpart.

(g) Any boiler that is used as a control device to comply 

with another subpart of this part, provided that at least 50 

percent of the heat input to the boiler is provided by the gas 

stream that is regulated under another subpart.

§63.11196 What are my compliance dates? 

(a) If you own or operate an existing affected 

sourceboiler, you must achieve compliance with the applicable 

provisions in this subpart as specified in paragraphs (a)(1) 

through (a)(3) of this section.

(1) If the existing affected boiler is subject to a work 

practice or management practice standard of a tune-up, you must 

achieve compliance with the work practice or management standard 

no later than [INSERT THE DATE 1 YEARSYEAR AFTER PUBLICATION OF 

THIS FINAL RULE IN THE FEDERAL REGISTER].

(2) If the existing affected boiler is subject to emission 

limits, you must achieve compliance with the emission limits no 

later than [INSERT THE DATE 3 YEARS AFTER PUBLICATION OF THIS 

FINAL RULE IN THE FEDERAL REGISTER].

(3) If the existing affected boiler is subject to the 

energy assessment requirement, you must achieve compliance with 

the energy assessment requirement no later than [INSERT THE DATE 
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3 YEARS AFTER PUBLICATION OF THIS FINAL RULE IN THE FEDERAL 

REGISTER].

(b) If you start up a new affected source on or before 

[INSERT THE DATE 60 DAYS AFTER THE DATE OF PUBLICATION OF THIS 

FINAL RULE IN THE FEDERAL REGISTER], you must achieve compliance 

with the provisions of this subpart no later than [INSERT THE 

DATE 60 DAYS AFTER THE DATE OF PUBLICATION OF THIS FINAL RULE IN 

THE FEDERAL REGISTER].

(c) If you start up a new affected source after [INSERT 

THE DATE 60 DAYS AFTER THE DATE OF PUBLICATION OF THIS FINAL 

RULE IN THE FEDERAL REGISTER], you must achieve compliance with 

the provisions of this subpart upon startup of your affected 

source.

(d) If you own or operate an industrial, commercial, or 

institutional boiler and would be subject to this subpart except 

for the exemption in §63.11195(b) for commercial and industrial 

solid waste incineration units covered by 40 CFR part 60, 

subpart CCCC or subpart DDDD, and you cease combusting solid 

waste, you must be in compliance with this subpart on the 

effective date of the waste to fuel switch, if the effective 

date of that switch is after the applicable compliance date in 

paragraphs (a)-(c) of this section. The effective date of the 
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waste to fuel switch is a date selected by you consistent with 

part 60, subpart CCCC or subpart DDDD that must be at least 12 

months from the date that you ceased combusting solid waste.

Emission Limits, Work Practice Standards, Emission Reduction 

Measures, and Management Practices

§63.11200 What are the subcategories of boilers?

The subcategories of boilers are coal, biomass, and liquid 

fueloil. Each subcategory is defined in §63.11237.

§63.11201 What standards must I meet? 

(a) You must comply with each emission limit specified in 

Table 1 ofto this subpart that applies to your boiler. 

(b) You must comply with each work practice standard, 

emission reduction measure, and management practice specified in 

Table 2 ofto this subpart that applies to your boiler. An 

energy assessment completed on or after January 1, 2008 that 

meets the requirements in Table 2 shall satisfyto this subpart

satisfies the energy assessment portion of this requirement.

(c) You must comply with each operating limit specified in 

Table 3 ofto this subpart that applies to your boiler.

(d) These standards apply at all times.

General Compliance Requirements

§63.11205 What are my general requirements for complying with 

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this subpart?

(a) 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. The general duty to minimize emissions does not 

require you to make any further efforts to reduce emissions if 

levels required by this standard have been achieved. 

Determination of whether such operation and maintenance 

procedures are being used will be based on information available 

to the Administrator whichthat 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.

(b) You can demonstrate compliance with any applicable 

mercury emission limit using fuel analysis if the emission rate 

calculated according to §63.11211(b) is less than the applicable 

emission limit. Otherwise, you must demonstrate compliance 

using stack testing.

(c) If you demonstrate compliance with any applicable 

emission limit through performance stack testing and subsequent 

compliance with operating limits (including the use of 
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continuous parameter monitoring system), or with a CEMS, or 

COMS, you must develop a site-specific monitoring plan according 

to the requirements in paragraphs (c)(1) through (4) of this 

section for the use of any CEMS, COMS, or continuous parameter 

monitoring system. This requirement also applies to you if you 

petition the EPA Administrator for alternative monitoring 

parameters under §63.8(f).

(1) For each CMS required in this section (including CEMS, 

COMS, or continuous parameter monitoring system), you must 

develop, and submit to the delegated authority for approval upon 

request, a site-specific monitoring plan that addresses 

paragraphs (c)(1)(i) through (iii) of this section. You must 

submit this site-specific monitoring plan, if requested, at 

least 60 days before your initial performance evaluation of your 

CMS. 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 COMS prepared under 

Appendix B to part 60 of this chapter and which meet the 

requirements of §63.11224.

(i) Installation of the CMS sampling probe or other 

interface at a measurement location relative to each affected 

process unit such that the measurement is representative of 
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control of the exhaust emissions (e.g., on or downstream of the 

last control device);

(ii) Performance and equipment specifications for the 

sample interface, the pollutant concentration or parametric 

signal analyzer, and the data collection and reduction systems; 

and

(iii) Performance evaluation procedures and acceptance 

criteria (e.g., calibrations).

(2) In your site-specific monitoring plan, you must also 

address paragraphs (c)(2)(i) through (iii) of this section.

(i) Ongoing operation and maintenance procedures in 

accordance with the general requirements of §63.8(c)(1)(ii),

(c)(3), and (c)(4)(ii);

(ii) Ongoing data quality assurance procedures in 

accordance with the general requirements of §63.8(d); and

(iii) Ongoing recordkeeping and reporting procedures in 

accordance with the general requirements of §63.10(c) (as 

applicable in Table 10 to this subpart), (e)(1), and (e)(2)(i).

(3) You must conduct a performance evaluation of each CMS 

in accordance with your site-specific monitoring plan.

(4) You must operate and maintain the CMS in continuous 

operation according to the site-specific monitoring plan.
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Initial Compliance Requirements

§63.11210 What are my initial compliance requirements and by 

what date must I conduct them?

(a) You must demonstrate initial compliance with each 

emission limit specified in Table 1 ofto this subpart that 

applies to you by either conducting performance (stack) tests, 

as applicable, according to §63.11212 and Table 4 ofto this 

subpart or, for mercury, conducting fuel analyses, as 

applicable, according to §63.11213 and Table 5 to this subpart. 

(b) For existing affected sourcesboilers that have 

applicable emission limits, you must demonstrate initial 

compliance no later than 180 days after the compliance date that 

is specified in §63.11196 and according to the applicable 

provisions in §63.7(a)(2).

(c) For existing affected sourcesboilers that have 

applicable work practice standards, management practices, or 

emission reduction measures, you must demonstrate initial 

compliance no later than the compliance date that is specified 

in §63.11196 and according to the applicable provisions in 

§63.7(a)(2).

(d) For new or reconstructed affected sources, you must 

demonstrate initial compliance no later than 180 calendar days 
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after [INSERT THE DATE OF PUBLICATION OF THIS FINAL RULE IN THE 

FEDERAL REGISTER] or within 180 calendar days after startup of 

the source, whichever is later, according to §63.7(a)(2)(ix).

(e) For affected sourcesboilers that ceased burning solid 

waste consistent with §63.11196(d), you must demonstrate 

compliance within 60 days of the effective date of the waste -to

-fuel switch. You If you have not conducted your compliance 

demonstration for this subpart within the previous 12 months,

you must complete all initial compliance demonstrations before 

you commence or recommence combustion of solid waste. 

§63.11211 How do I demonstrate initial compliance with the 

emission limits? 

(a) For affected sourcesboilers that demonstrate 

compliance with any of the emission limits of this subpart 

through performance (stack) testing, your initial compliance 

requirements include conducting performance tests according to 

§63.11212 and Table 4 to this subpart, conducting a fuel 

analysis for each type of fuel burned in your boiler according 

to §63.11213 and Table 5 to this subpart, establishing operating 

limits according to §63.11222 , Table 6 to this subpart and 

paragraph (b) of this section, as applicable, and conducting 

continuous monitoring system (CMS) performance evaluations 
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according to §63.11223. For affected boilers that burn a single 

type of fuel, you are exempted from the compliance requirements 

of conducting a fuel analysis for each type of fuel burned in 

your boiler. For purposes of this subpart, boilers that use a 

supplemental fuel only for startup, unit shutdown, and transient 

flame stability purposes still qualify as affected boilers that 

burn a single type of fuel, and the supplemental fuel is not 

subject to the fuel analysis requirements under §63.11213 and 

Table 5 to this subpart.

(b(b) You must establish parameter operating limits 

according to paragraphs (b)(1) through (4) of this section.

(1) For a wet scrubber, you must establish the minimum 

liquid flowrate and pressure drop as defined in §63.11237, as 

your operating limits during the three-run performance stack 

test. If you use a wet scrubber and you conduct separate 

performance stack tests for particulate matter and mercury 

emissions, you must establish one set of minimum scrubber liquid 

flowrate and pressure drop operating limits. If you conduct 

multiple performance stack tests, you must set the minimum 

liquid flowrate and pressure drop operating limits at the 

highest minimum values established during the performance stack 

tests.

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(2) For an electrostatic precipitator operated with a wet 

scrubber, you must establish the minimum voltage and secondary 

amperage (or total power input), as defined in §63.11237, as 

your operating limits during the three-run performance stack 

test. (These operating limits do not apply to electrostatic 

precipitators that are operated as dry controls without a wet 

scrubber.)

(3) For activated carbon injection, you must establish the 

minimum activated carbon injection rate, as defined in 

§63.11237, as your operating limit during the three-run 

performance stack test.

(4) The operating limit for boilers with fabric filters 

that demonstrate continuous compliance through bag leak 

detection systems is that a bag leak detection system be 

installed according to the requirements in §63.11224, and that 

each fabric filter must be operated such that the bag leak 

detection system alarm does not sound more than 5 percent of the 

operating time during a 6-month period.

(c) If you elect to demonstrate compliance with an 

applicable mercury emission limit through fuel analysis, you 

must conduct fuel analyses according to §63.11213 and Table 5 to 

this subpart and follow the procedures in paragraphs (bc)(1) 
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through (3) of this section. 

(1) If you burn more than one fuel type, you must 

determine the fuel type, or mixture, you could burn in your 

boiler that would result in the maximum emission rates of 

mercury.

(2) You must determine the 90th percentile confidence 

level fuel mercury concentration of the composite samples 

analyzed for each fuel type using Equation 1 of this section. 

P90 = mean + (SD * t) (Eq. 1)

Where:

P90 = 90th percentile confidence level mercury 

concentration, in pounds per million Btu;.

mean = Arithmetic average of the fuel mercury 

concentration in the fuel samples analyzed 

according to §63.11213, in units of pounds 

per million Btu;.

SD = Standard deviation of the mercury 

concentration in the fuel samples analyzed 

according to §63.11213, in units of pounds 

per million Btu;.

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 mercury 

emission limit, the emission rate that you calculate for your 

boiler using Equation 1 of this section must be less than the 

applicable mercury emission limit.
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§63.11212 What stack tests and 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 stack test according to the 

requirements in Table 4 to this subpart.

(c) You must conduct performance stack tests at the maximum 

normalrepresentative operating load conditions while burning the 

type of fuel or mixture of fuels that have the highest emissions 

potential for each regulated pollutant, and you must demonstrate 

initial compliance and establish your operating limits based on 

these performance stack tests. For subcategories with more than 

one emission limit, these requirements could result in the need 

to conduct more than one performance stack test. Following each 

performance stack test and until the next performance stack 

test, you must comply with the operating limit for operating 

load conditions specified in Table 3 to this subpart.

(d) You must conduct a minimum of three separate test runs 

for each performance stack test required in this section, as 

specified in §63.7(e)(3). The sampling time for each test run 

must last at least 1 hour except that the sampling time for the 

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test runs conducted for mercury emissions must last at least 2 

hours.

(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 of appendix A-7 to part 60 of this 

chapter to convert the measured PMparticulate matter

concentrations and the measured mercury concentrations that 

result from the initial performance test to pounds per million 

Btu heat input emission rates. 

§63.11213 What fuel analyses and procedures must I use for the 

performance tests?

(a) You must conduct fuel analyses according to the 

procedures in paragraphs (b) and (c) of this section and Table 5 

to this subpart, as applicable. You are not required to conduct 

fuel analyses for fuels used for only startup, unit shutdown, 

and transient flame stability purposes. You are required to 

conduct fuel analyses only for fuels and units that are subject 

to emission limits for mercury in Table 1 of this subpart.

(b) At a minimum, you must obtain three composite fuel 

samples for each fuel type according to the procedures in Table 

5 ofto this subpart. Each composite sample willmust consist of 

a minimum of three samples collected at approximately equal 
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intervals during a test run period. 

(c) Determine the concentration of mercury in the fuel in 

units of pounds per million Btu of each composite sample for 

each fuel type according to the procedures in Table 5 to this 

subpart.

§63.11214 How do I demonstrate initial compliance with the 

work practice standard, emission reduction measures, and 

management practice?

(a) If you own or operate an existing or new coal-fired 

boiler with a heat input capacity of less than 10 million Btu 

per hour, you must conduct a performance tune-up according to 

§63.11223(b) and you must submit a signed statement in the 

Notification of Compliance Status report that indicates that you 

conducted a tune-up of the boiler.

(b) If you own or operate an existing or new biomass-fired 

boiler or an existing or new liquid fueloil-fired boiler, you 

must conduct a performance tune-up according to §63.11223(b) and 

you must submit a signed statement in the Notification of 

Compliance Status report that indicates that you conducted a 

tune-up of the boiler.

(c) If you own or operate an existing affected boiler with 

a heat input capacity of 10 million Btu per hour or greater, you 
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must submit the energy assessment report, along with a signed 

certification that the assessment is an accurate depiction of 

your facility.

(d) If you own or operate a boiler subject to emission 

limits in Table 1 of this subpart, you must minimize the 

boiler’s startup and shutdown periods following the 

manufacturer’s recommended procedures, if available. If 

manufacturer’s recommended procedures are not available, you 

must follow recommended procedures for a unit of similar design 

for which manufacturer’s recommended procedures are available. 

You must submit a signed statement in the Notification of 

Compliance Status report that indicates that you conducted 

startups and shutdowns according to the manufacturer’s 

recommended procedures or procedures specified for a boiler of 

similar design if manufacturer’s recommended procedures are not 

available.

Continuous Compliance Requirements

§63.11220 When must I conduct subsequent performance tests?

(a) If your boiler has a heat input capacity of 10 million 

Btu per hour or greater, you must conduct all applicable 

performance (stack) tests according to §63.11212 on an annual 

basis, unless you follow the requirements listed in paragraphs 
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(b) through (d) of this section. Annual performance tests must 

be completed between 11 andno more than 13 months after the 

previous performance test, unless you follow the requirements 

listed in paragraphs (b) through (d) of this section. 

(b) You can conduct performance stack tests less often for 

particulate matter or mercury if your performance stack tests 

for the pollutant for at least 3 consecutive years show that 

your emissions are at or below 75 percent of 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. In this case, you do not have to conduct a 

performance stack test for that pollutant for the next 2 years. 

You must conduct a performance stack test during the third year 

and no more than 37 months after the previous performance stack 

test. 

(c) If your boiler continues to meet the emission limit 

for particulate matter or mercury, you may choose to conduct 

performance stack tests for the pollutant every third year if 

your emissions are at or below 75 percent of 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 stack test must be 
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conducted no more than 3637 months after the previous 

performance test.

(d) If a performance stack test shows emissions exceeded 

75 percent of the emission limit, you must conduct annual 

performance stack tests for that pollutant until all performance 

stack tests over a consecutive 3-year period show compliance at 

or below 75 percent of the limit.

(e) If you have an applicable CO emission limit, you must 

conduct annual performance tests for CO according to §63.11211. 

Each annual performance test must be conducted between 11 andno 

more than 13 months after the previous performance test. 

(f) If you demonstrate compliance with the mercury 

emission limit based on fuel analysis, you must conduct a fuel 

analysis according to §63.11213 for each type of fuel burned 

monthly. If you plan to burn a new type of fuel or fuel 

mixture, you must conduct a fuel analysis before burning the new 

type of fuel or mixture in your boiler. You must recalculate 

the mercury emission rate using Equation 1 of §63.11211. The 

recalculated mercury emission rate must be less than the 

applicable emission limit.

§63.11221 How do I monitor and collect data to demonstrate 

continuous compliance? 
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(a) You must monitor and collect data according to this 

section. 

(b) You must operate the monitoring system and collect 

data at all required intervals at all times the affected source 

is operating except for periods of monitoring system 

malfunctions or out-of-control periods, repairs associated with 

monitoring system malfunctions or out-of-control periods (see 

section 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 effect monitoring system 

repairs in response to monitoring system malfunctions or out-ofcontrol periods 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 

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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 out-of-control periods, and required 

monitoring system quality assurance or quality control 

activities including, as applicable, calibration checks and 

required zero and span adjustments, failure to collect required 

data is a deviation of the monitoring requirements.

§63.11222 How do I demonstrate continuous compliance with the 

emission limits? 

(a) You must demonstrate continuous compliance with each 

emission limit and operating limit in Tables 1 and 3 to this 

subpart that applies to you according to paragraphs (a)(1) 

through (54) of this section.

(1) Following the date on which the initial compliance 

demonstration is completed or is required to be completed under 

§§63.7 and 63.11196, 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 
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Table 3 to this subpart. Operation above the established 

maximum or below the established minimum operating limits shall 

constituteconstitutes a deviation of established operating 

limits. Operating limits are confirmed or reestablished during 

performance tests.

(2) If you have an applicable mercury or PM emission 

limit, you must keep records of the type and amount of all fuels 

burned in each boiler during the reporting period to demonstrate 

that all fuel types and mixtures of fuels burned would result in 

lower emissions of mercury than the applicable emission limit.

(if you demonstrate compliance through fuel analysis), or result 

in lower fuel input of mercury than the maximum values 

calculated during the last performance stack test (if you 

demonstrate compliance through performance stack testing).

(3) If you have an applicable mercury emission limit and 

you plan to burn a new type of fuel, you must determine the 

mercury concentration for any new fuel type in units of pounds 

per million Btu, using the procedures in Equation 1 of §63.11211

based on supplier data or your own fuel analysis, and meet the 

requirements in paragraphs (a)(3)(i) or (ii) of this section.

(i) The recalculated mercury emission rate must be less 

than the applicable emission limit.
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(ii) If the mercury concentration is higher than mercury 

fuel input 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 

§63.11212 to demonstrate that the mercury emissions do not 

exceed the emission limit.

(4) 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 operate and maintain the 

fabric filter system such that the alarm does not sound more 

than 5 percent of the 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 beis counted as a minimum 

of 1 hour. If you take longer than 1 hour to initiate 
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corrective action, the alarm time shall beis counted as the 

actual amount of time taken to initiate corrective action.

(b) You must report each instance in which you did not 

meet each emission limit and operating limit in Tables 1 and 3 

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 

§63.11225.

§63.11223 How do I demonstrate continuous compliance with the 

work practice and management practice standards?

(a) For affected sources subject to the work practice 

standard or the management practices of a tune-up, you must 

conduct a biennial performance tune-up according to 

§63.11223(b)paragraphs (b) of this section and keep records as 

required in §63.11225(c) to demonstrate continuous compliance.

Each biennial tune-up must be conducted between 23 andno more 

than 25 months after the previous tune-up.

(b) You must conduct a tune-up of the boiler biennially to 

demonstrate continuous compliance as specified in paragraphs 

(b)(1) through (67) of this section.

(1) InspectAs applicable, inspect the burner, and clean or 

replace any components of the burner as necessary; (you may 
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delay the burner inspection until the next scheduled unit 

shutdown, but you must inspect each burner at least once every 

36 months).

(2) Inspect the flame pattern, as applicable, and make any 

adjustments toadjust the burner as 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 COcarbon monoxide. This 

optimization should be consistent with the manufacturer’s 

specifications;, if available.

(5) Measure the concentration concentrations in the 

effluent stream of COcarbon monoxide in parts per million, by 

volume, and oxygen in volume percent, before and after the 

adjustments are made (measurements may be either on a dry or wet 

basis (ppmvd),, as long as it is the same basis before and after 

the adjustments are made; and).

(6) Maintain on-siteonsite and submit, if requested by the 

Administrator, a biennial report containing the information in 

paragraphs (b)(6)(i) through (iii) of this section,.
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(i) The concentrations of CO in the effluent stream in 

ppmvdparts per million, by volume, and oxygen in volume percent

dry basis, measured before and after the tune-up of the boiler

as defined in §63.11222(b) of this section;.

(ii) A description of any corrective actions taken as a 

part of the tune-up of the boiler as defined in §63.11222(b) of 

this section; and.

(iii) The type and amount of fuel used over the 12 months 

prior to the biennial tune-up of the boiler as defined in 

§63.11222(b) of this section.

(7) If the unit is not operating on the required date for 

a tune-up, the tune-up must be conducted within one week of 

startup.

(c) If you own or operate an existing or new coal-fired 

boiler with a heat input capacity of 10 million Btu per hour or 

greater, you must minimize the boiler’s time spent during 

startup and shutdown following the manufacturer’s recommended 

procedures and you must submit a signed statement in the 

Notification of Compliance Status report that indicates that you 

conducted startups and shutdowns according to the manufacturer’s 

recommended procedures.

§63.11224 What are my monitoring, installation, operation, and 
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maintenance requirements? 

(a(a) If your boiler is subject to a carbon monoxide 

emission limit in Table 1 o 2 to this subpart, you must install, 

operate, and maintain a continuous oxygen monitor according to 

the procedures in paragraphs (a)(1) through (6) of this section 

by the compliance date specified in §63.11196. The oxygen level 

shall be monitored at the outlet of the boiler.

(1) Each monitor must be installed, operated, and 

maintained according to the applicable procedures under 

Performance Specification 3 at 40 CFR part 60, appendix B, and 

according to the site-specific monitoring plan developed 

according to paragraph (c) of this section.

(2) You must conduct a performance evaluation of each CEMS 

according to the requirements in §63.8(e) and according to 

Performance Specification 3 at 40 CFR part 60, appendix B.

(3) Each CEMS must complete a minimum of one cycle of 

operation (sampling, analyzing, and data recording) for each 

successive 15-minute period.

(4) The CEMS data must be reduced as specified in 

§63.8(g)(2).

(5) You must calculate and record a 30-day rolling average 

concentration on a daily basis. A new 30-day rolling average 
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concentration is calculated as the average of all of the hourly 

oxygen concentration data for the preceding 30 operating days.

(6) For purposes of calculating data averages, you must 

use all the data collected during all periods in assessing 

compliance, excluding data collected during periods when the 

monitoring system malfunctions or is out of control, during 

associated repairs, and during required quality assurance or 

control activities (including, as applicable, calibration checks 

and required zero and span adjustments). Monitoring failures 

that are caused in part by poor maintenance or careless 

operation are not malfunctions. Any period for which the 

monitoring system malfunctions or is out of control and data are 

not available for a required calculation constitutes a deviation 

from the monitoring requirements. Periods when data are 

unavailable because of required quality assurance or control 

activities (including, as applicable, calibration checks and 

required zero and span adjustments) do not constitute monitoring 

deviations.

(b) If you are using a control device to comply with the 

emission limits specified in Table 1 ofto this subpart, you must 

maintain each operating limit in Table 3 ofto this subpart that 

applies to your boiler. If you use a control device not covered 
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in Table 3 to this subpart, or you wish to establish and monitor 

an alternative operating limit and alternative monitoring 

parameters, you must apply to the United States Environmental 

Protection Agency (EPA) Administrator for approval of 

alternative monitoring under §63.8(f).

(bc) If you demonstrate compliance with any applicable 

emission limit through stack testing and subsequent compliance 

with operating limits, you must develop a site-specific 

monitoring plan according to the requirements in paragraphs 

(bc)(1) through (4) of this section. This requirement also 

applies to you if you petition the EPA Administrator for 

alternative monitoring parameters under §63.8(f).

(1) For each continuous monitoring system (CMS) required 

in this section, you must develop, and submit to the EPA 

Administrator for approval upon request, a site-specific 

monitoring plan that addresses paragraphs (b)(1)(i) through 

(iii) of this section. You must submit this site-specific 

monitoring plan (if requested) at least 60 days before your 

initial performance evaluation of your CMS.

(i) Installation of the CMS sampling probe or other 

interface at a measurement location relative to each affected 

unit such that the measurement is representative of control of 
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the exhaust emissions (e.g., on or downstream of the last 

control device);).

(ii) Performance and equipment specifications for the 

sample interface, the pollutant concentration or parametric 

signal analyzer, and the data collection and reduction systems; 

and.

(iii) Performance evaluation procedures and acceptance 

criteria (e.g., calibrations).

(2) In your site-specific monitoring plan, you must also 

address paragraphs (b)(2)(i) through (iii) of this section.

(i) Ongoing operation and maintenance procedures in 

accordance with the general requirements of §63.8(c)(1), (3), 

and (4)(ii);).

(ii) Ongoing data quality assurance procedures in 

accordance with the general requirements of §63.8(d); and).

(iii) Ongoing recordkeeping and reporting procedures in 

accordance with the general requirements of §63.10(c), (e)(1), 

and (e)(2)(i).

(3) You must conduct a performance evaluation of each CMS in 

accordance with your site-specific monitoring plan.(3) You must conduct 

a performance evaluation of each CMS in accordance with your 

site-specific monitoring plan.

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(4) You must operate and maintain the CMS in continuous 

operation according to the site-specific monitoring plan.

(cd) If you have an operating limit that requires the use 

of a CMS, you must install, operate, and maintain each 

continuous parameter monitoring system (CPMS) according to the 

procedures in paragraphs (cd)(1) through (5) of this section.

(1) The CPMScontinuous parameter monitoring system must 

complete a minimum of one cycle of operation for each successive 

15-minute period. You must have a minimum of four successive 

cycles of operation to have a valid hour of data.

(2) Except for monitoring malfunctions, associated 

repairs, and required quality assurance or control activities 

(including, as applicable, calibration checks and required zero 

and span adjustments), you must conduct all monitoring in 

continuous operation at all times that the unit is operating. A 

monitoring malfunction is any sudden, infrequent, not reasonably 

preventable failure of the monitoring to provide valid data. 

Monitoring failures that are caused in part by poor maintenance 

or careless operation are not malfunctions.

(3) For purposes of calculating data averages, you must 

not use data recorded during monitoring malfunctions, associated 

repairs, out of control periods, or required quality assurance 
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or control activities. You must use all the data collected 

during all other periods in assessing compliance. Any period 

for which the monitoring system is out-of-control and data are 

not available for a required calculation constitutes a deviation 

from the monitoring requirements.

(4) Determine the 4-hour block average of all recorded 

readings, except as provided in paragraph (cd)(3) of this 

section.

(5) Record the results of each inspection, calibration, 

and validation check.

(de) If you have an applicable opacity operating limit

under this rule, you must install, operate, certify and maintain 

each continuous opacity monitoring system (COMS) according to 

the procedures in paragraphs (de)(1) through (7) of this section 

by the compliance date specified in §63.11196.

(1) Each COMS must be installed, operated, and maintained 

according to PSPerformance Specification 1 of 40 CFR part 60, 

appendix B.

(2) You must conduct a performance evaluation of each COMS 

according to the requirements in §63.8 and according to 

PSPerformance Specification 1 of 40 CFR part 60, appendix B.

(3) As specified in §63.8(c)(4)(i), each COMS must 
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complete a minimum of one cycle of sampling and analyzing for 

each successive 10-second period and one cycle of data recording 

for each successive 6-minute period.

(4) The COMS data must be reduced as specified in 

§63.8(g)(2).

(5) You must include in your site-specific monitoring plan 

procedures and acceptance criteria for operating and maintaining 

each COMS according to the requirements in §63.8(d). At a 

minimum, the monitoring plan must include a daily calibration 

drift assessment, a quarterly performance audit, and an annual 

zero alignment audit of each COMS.

(6) You must operate and maintain each COMS according to 

the requirements in the monitoring plan and the requirements of 

§63.8(e). Identify periods the COMS is out of control including 

any periods that the COMS fails to pass a daily calibration 

drift assessment, a quarterly performance audit, or an annual 

zero alignment audit.

(7) You must determine and record all the 1-hour block 

averages collected for periods during which the COMS is not out 

of control.

(ef) If you use a fabric filter bag leak detection system 

to comply with the requirements of this subpart, you must 
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install, calibrate, maintain, and continuously operate the bag 

leak detection system as specified in paragraphs (ef)(1) through 

(8) of this section.

(1) You must install and operate a bag leak detection 

system for each exhaust stack of the fabric filter.

(2) Each bag leak detection system must be installed, 

operated, calibrated, and maintained in a manner consistent with 

the manufacturer's written specifications and recommendations 

and in accordance with EPA Fabric Filter Bag Leak Detection 

Guidance, EPA–454/R–98–015, September 1997 (incorporated by 

reference, see §63.14).

(3) The bag leak detection system must be certified by the 

manufacturer to be capable of detecting particulate matter 

emissions at concentrations of 10 milligrams per actual cubic 

meter or less.

(4) The bag leak detection system sensor must provide 

output of relative or absolute particulate matter loadings.

(5) The bag leak detection system must be equipped with a 

device to continuously record the output signal from the sensor.

(6) The bag leak detection system must be equipped with an

audible or visual alarm system that will activate automatically 

when an increase in relative particulate matter emissions over a 
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preset level is detected. The alarm must be located where it is 

easily heard or seen by plant operating personnel.

(7) For positive pressure fabric filter systems that do 

not duct all compartments of cells to a common stack, a bag leak 

detection system must be installed in each baghouse compartment 

or cell.

(8) Where multiple bag leak detectors are required, the 

system's instrumentation and alarm may be shared among 

detectors.

§63.11225 What are my notification, reporting, and 

recordkeeping, requirements?

(a) You must submit the notifications specified in 

paragraphs (a)(1) through (a)(5) of this section to the 

delegated authority.

(1) You must submit all of the notifications in §§63.7(b): 

63.8(e) and (f); 63.9(b) through (e); and 63.9(g) and (h) that 

apply to you by the dates specified in those sections.

(2) As specified in §63.9(b)(2), you must submit the 

Initial Notification no later than 120 calendar days after 

[INSERT THE DATE 60 DAYS AFTER THE DATE OF PUBLICATION OF THIS 

FINAL RULE IN THE FEDERAL REGISTER] or within 120 days after the 

source becomes subject to the standard.
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(3) If you are required to conduct a performance stack 

test you must submit to the delegated authority a Notification 

of Intent to conduct a performance test at least 60 days before 

the performance stack test is scheduled to begin.

(4) You must submit the Notification of Compliance Status 

in accordance with §63.9(h) no later than 120 days after the 

applicable compliance date specified in §63.11196 unless you 

must conduct a performance stack test. If you must conduct a 

performance stack test, you must submit the Notification of 

Compliance Status within 60 days of completing the performance 

stack test. 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:

(i) “This facility complies with the requirements in 

§63.11214(b) to conduct an initial tune-up of the boiler”..”

(ii) “This facility has had an energy assessment performed 

according to §63.11215.”

(iii) This certification of compliance by theFor an owner 

or operator that installs bag leak detection systems: “This 

facility has prepared a bag leak detection system monitoring 

plan in accordance with §63.11221 and will operate each bag leak 
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detection system according to the plan.” 

(iv) For units that do not qualify for a statutory 

exemption as provided in section 129(g)(1) of the Clean Air Act: 

“No secondary materials that are solid waste were combusted in 

any affected unit.”

(5) If you are using data from a previously conducted 

emission test to serve as documentation of conformance with the 

emission standards and operating limits of this subpart 

consistent with §63.7(e)(2)(iv), you must submit the test data 

in lieu of the initial performance test results with the 

Notification of Compliance Status required under paragraph 

(a)(4) of this section.

(b) You must prepare, by March 1 of each year, and submit 

to the delegated authority upon request, an annual compliance 

certification report for the previous calendar year containing 

the information specified in paragraphs (b)(1) through (b)(4) of 

this section. You must submit the report by March 15 if you had 

any instance described by paragraph (b)(4) of this section3) of 

this section. For boilers that are subject only to a 

requirement to conduct a biennial tune-up according to 

§63.11223(a) and not subject to emission limits or operating 

limits, you may prepare only a biennial compliance report as 
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specified in paragraphs (b)(1) through (4) of this section, 

instead of a semi-annual compliance report.

(1) Company name and address.

(2) Statement by a responsible official, with the 

official’s name, title, phone number, e-mail address, and 

signature, certifying the truth, accuracy and completeness of 

the notification and a statement of whether the source has 

complied with all the relevant standards and other requirements 

of this subpart.

(3) If the source is not in complianceexperiences any 

deviations from the applicable requirements during the reporting 

period, include a description of deviations from the applicable 

requirements, the time periods during which the deviations 

occurred, and the corrective actions taken.

(4) The total fuel use by each affected sourceboiler

subject to an emission limit, for each calendar month within the 

reporting period, including, but not limited to, a description 

of the fuel, including whether the fuel has received a non-waste 

determination by you or EPA through a petition process to be a 

non-waste under §241.3(c), whether the fuel(s) were processed 

from discarded non-hazardous secondary materials within the 

meaning of §241.3, and the total fuel usage amount with units of 
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measure.

(c) You must maintain the records specified in paragraphs 

(c)(1) through (5) of this section.

(1) As required in §63.10(b)(2)(xiv), you must keep a copy 

of each notification and report that you submitted to comply 

with this subpart and all documentation supporting any Initial 

Notification or Notification of Compliance Status that you 

submitted.

(2) You must keep records to document conformance with the 

work practices, emission reduction measures, and management 

practices required by §63.11214 as specified in paragraphs 

(c)(2)(i) and (ii) of this section.

(i) Records must identify each boiler, the date of tuneup, the procedures followed for tune-up, and the manufacturer’s 

specifications to which the boiler was tuned.

(ii) Records documenting the fuel type(s) used monthly 

fuel use by each boiler, including the type(s) of fuel, 

including, but not limited to, a description of the fuel, 

including whether the fuel has received a non-waste 

determination by you or EPA, and the total fuel usage amount 

with units of measure. If you combust non-hazardous secondary 

materials that have been determined not to be solid waste 
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pursuant to §41241.3(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 §241.3(b)(2), you must keep records as to how the 

operations that produced the fuel satisfies the definition of 

processing in §241.2. If the fuel received a non-waste 

determination pursuant to the petition process submitted under 

§241.3(c), you must keep a record that documents how the fuel 

satisfies the requirements of the petition process.

(3) For sources that demonstrate compliance through fuel 

analysis, a copy of all calculations and supporting 

documentation that were done to demonstrate compliance with the 

mercury emission limits. Supporting documentation should 

include results of any fuel analyses. You can use the results 

from one fuel analysis for multiple boilers provided they are 

all burning the same fuel type.

(4) Records of the occurrence and duration of each 

malfunction of the boiler, or of the associated air pollution 

control and monitoring equipment.

(5) Records of actions taken during periods of malfunction 

to minimize emissions in accordance with the general duty to 
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minimize emissions in §63.11205(a), including corrective actions 

to restore the malfunctioning boiler, air pollution control, or 

monitoring equipment to its normal or usual manner of operation.

(6) You must keep the records of all inspection and 

monitoring data required by §§63.11221 and 63.11222, and the 

information identified in paragraphs (c)(6)(i) through (vi) of 

this section for each required inspection or monitoring.

(i) The date, place, and time of the monitoring event;.

(ii) Person conducting the monitoring;.

(iii) Technique or method used;.

(iv) Operating conditions during the activity;.

(v) Results, including the date, time, and duration of the 

period from the time the monitoring indicated a problem to the 

time that monitoring indicated proper operation; and.

(vi) Maintenance or corrective action taken (if 

applicable).

(7) If you use a bag leak detection system, you must keep 

the records specified in paragraphs (c)(7)(i) through (iii) of 

this section.

(i) Records of the bag leak detection system output.

(ii) Records of bag leak detection system adjustments, 

including the date and time of the adjustment, the initial bag 
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leak detection system settings, and the final bag leak detection 

system settings.

(iii) The date and time of all bag leak detection system 

alarms, and for each valid alarm, the time you initiated 

corrective action, the corrective action taken, and the date on 

which corrective action was completed.

(d) Your records must be in a form suitable and readily 

available for expeditious review, according to §63.10(b)(1). As 

specified in §63.10(b)(1), you must keep each record for 5 years 

following the date of each recorded action. You must keep each 

record onsite for at least 2 years after the date of each 

recorded action according to §63.10(b)(1). You may keep the 

records offsiteoff site for the remaining 3 years.

(e) AfterAs of December 31, 2011, and within 60 days after 

the date of completing each performance evaluation or 

performance test, as defined in §63.2, conducted to demonstrate 

compliance with this subpart, the owner or operator of the 

affected facilityyou 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) using the Electronic Reporting 

Tool (ERT) or other compatible electronic spreadsheet. Only 
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data collected using methods compatible with the ERT are subject 

to this requirement to be submitted electronically into EPA’s 

WebFIRE database.

(f) If you intend to commence or recommence combustion of 

solid waste, you must provide 30 days prior notice of the date

upon which you will commence or recommence combustion of solid 

waste. The notification must identify:

(1) The name of the owner or operator of the affected 

source, the location of the source, the boiler(s) or process 

heater(s) that will commence burning solid waste, and the date 

of the notice;.

(2) The currently applicable subcategory under this 

subpart;.

(3) The date on which you became subject to the currently 

applicable emission limits;.

(4) The date upon which you will commence combusting solid 

waste. 

(g) If you intend to switch fuels, and this fuel switch 

may result in the applicability of a different subcategory or a 

switch out of subpart JJJJJJ due to a switch to 100 percent

natural gas, you must provide 30 days prior notice of the date

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upon which you will switch fuels. The notification must 

identify:

(1) The name of the owner or operator of the affected 

source, the location of the source, the boiler(s) that will 

switch fuels, and the date of the notice.

(2) The currently applicable subcategory under this 

subpart.

(3) The date on which you became subject to the currently 

applicable standards.

(4) The date upon which you will commence the fuel switch. 

§63.11226 How can I assert an affirmative defense if I exceed

an emission limit during a malfunction?

In response to an action to enforce the standards set forth 

in paragraph §63.11201 you may assert an affirmative defense to 

a claim for civil penalties for exceedances of numerical 

emission limits that are caused by malfunction, as defined at 40 

CFR §63.2. Appropriate penalties may be assessed, however, if 

you fail to meet your burden of proving all of the requirements 

in the affirmative defense. The affirmative defense shall not 

be available for claims for injunctive relief.

(a) Conditions. To establish the affirmative defense in 

any action to enforce such a limit, you must timely meet the 

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notification requirements in paragraph (b) of this section, and 

must prove by a preponderance of evidence that:

(1) The excess emissions: 

(1) the excess emissions: 

(i) Were caused by a sudden, short, 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. Offshift 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.
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 (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, severe 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; 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 to 

determine, correct, and eliminate the primary causes of the 

malfunction and the excess emissions resulting from the 

malfunction event at issue. The analysis shall also specify, 

using best monitoring methods and engineering judgment, the 

amount of excess emissions that were the result of the 

malfunction. 

(b) Notification. The owner or operator of the facility Formatted: Underline
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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 30 days of 

the initial occurrence of the exceedance of the standard in 

§63.11201 to demonstrate, with all necessary supporting 

documentation, that it has met the requirements set forth in 

paragraph (a) of this section.

Other Requirements and Information

§63.11235 What parts of the General Provisions apply to me?

Table 67 to this subpart shows which parts of the General 

Provisions in §§63.1 through 63.15 apply to you.

§63.11236 Who implements and enforces this subpart? 

(a) This subpart can be implemented and enforced by EPA or 

a delegated authority such as your Statestate, local, or tribal 

agency. If the EPA Administrator has delegated authority to 

your Statestate, local, or tribal agency, then that agency has 

the authority to implement and enforce this subpart. You should 
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contact your EPA Regional Office to find out if implementation 

and enforcement of this subpart is delegated to your Statestate, 

local, or tribal agency. 

(b) In delegating implementation and enforcement authority 

of this subpart to a Statestate, local, or tribal agency under 

40 CFR part 63, subpart E, the authorities contained in 

paragraphs (c) of this section are retained by the EPA 

Administrator and are not transferred to the Statestate, local, 

or tribal agency.

(c) The authorities that cannot be delegated to 

Statestate, local, or tribal agencies are specified in 

paragraphs (c)(1) through (5) of this section.

(1) Approval of an alternative non-opacity emission 

standard and work practice standards in §63.11223(a).

(2) Approval of alternative opacity emission standard 

under §63.6(h)(9).

(3) Approval of major change to test methods under 

§63.7(e)(2)(ii) and (f). A “major change to test method” is 

defined in §63.90.

(4) Approval of a major change to monitoring under 

§63.8(f). A “major change to monitoring” is defined in §63.90. 

(5) Approval of major change to recordkeeping and 
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reporting under §63.10(f). A “major change to 

recordkeeping/reporting” is defined in §63.90.

§63.11237 What definitions apply to this subpart? 

Terms used in this subpart are defined in the CAAClean Air 

Act, 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.

Annual heat input basis means the 12 months preceding the 

compliance demonstration.

Bag leak detection system means an instrumenta group of

instruments that is capable of monitoring particulate matter 

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 

particulate matter loadings.
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Biomass means any biomass-based solid fuel that is not a 

solid waste. This includes, but is not limited to, wood residue 

and wood products (e.g., trees, tree stumps, tree limbs, bark, 

lumber, sawdust, sanderdustsander dust, chips, scraps, slabs, 

millings, and shavings); animal manure, including litter and 

other bedding materials; vegetative agricultural and 

silvicultural materials, such as logging residues (slash), nut 

and grain hulls and chaff (e.g., almond, walnut, peanut, rice, 

and wheat), bagasse, orchard prunings, corn stalks, coffee bean 

hulls and grounds. This definition of biomass is not intended 

to suggest that these materials are or are not solid waste.

Biomass subcategory includes any boiler that burns at least 

15 percent biomass on an annual heat input basis.

Boiler means an enclosed device using controlled flame 

combustion in which water is heated to recover thermal energy in 

the form of steam or hot water. Controlled flame combustion 

refers to a steady-state, or near steady-state, process wherein 

fuel and/or oxidizer feed rates are controlled. Waste heat 

boilers are excluded from this definition. 

Boiler system means the boiler and associated components,

such as, the feedwater system, the combustion air system, the 

boiler fuel system (including burners), blowdown system, 
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combustion control system, steam system, and condensate return 

system. 

Coal means all solid fuels classifiable as anthracite, 

bituminous, sub-bituminous, or lignite by the American Society 

for Testing and Materials in ASTM D388-05, “Standard 

Classification of Coals by Rank1” (incorporated by reference, see 

§63.14(b)),), coal refuse, and petroleum coke. For the purposes 

of this subpart, this definition of “coal” includes synthetic 

fuels derived from coal including, but not limited to, solventrefined coal, coal-oil mixtures, and coal-water mixtures. Coal 

derived gases are excluded from this definition.

Coal subcategory includes any boiler that burns any solid 

fossil fuel and no more than 15 percent biomass on an annual 

heat input basis.

Commercial boiler means a boiler used in commercial 

establishments such as hotels, restaurants, and laundries to 

provide electricity, steam, and/or hot water.

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 
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emission limit, operating limit, or work practice standard;

(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; or 

(2) A deviation is not always a violation. The 

determination of whether a deviation constitutes a violation of 

the standard is up to the discretion of the entity responsible 

for enforcement of the standards.

Dry scrubber

Electrostatic precipitator (ESP) means an add-on air 

pollution control device used to capture particulate matter by 

charging the particles using an electrostatic field, collecting 

the particles using a grounded collecting surface, and 

transporting the particles into a hopper. An electrostatic 

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means an add-on air pollution control 

system that injects dry alkaline sorbent (dry injection) or 

sprays an alkaline sorbent (spray dryer) to react with and 

neutralize acid gas in the exhaust stream forming a dry powder 

material. Sorbent injection systems in fluidized bed boilers 

are included in this definition. A dry scrubber is a dry 

control system.
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precipitator is a dry control system, except when it is operated 

with a wet scrubber.

Energy assessment means an in-depth assessment of the 

boiler system(s) and the energy use system(s) at a facility to 

identify immediate and long-term opportunities to save energy. 

An energy assessment involves a thorough examination of 

potential savings from energy efficiency improvements, waste 

minimization and pollution prevention, and productivity 

improvement. Energy assessment means the following only as this 

term is used in Table 3 to this subpart. :

a. (1) Energy assessment for facilities with affected boilers using less than 0.3 trillion Btu 

(TBtu) per year heat input will be one day in length maximum. The boiler system and 

energy use system accounting for at least 50 percent of the affected 

boiler(s) energy output will be evaluated to identify 

energy savings opportunities, within the limit of 

performing a one day energy assessment.

b. Energy assessment for facilities with affected boilers and 

process heaters using 0.3 to 1 TBtu/year will be three days in length 

maximum. The boiler system(s) and any energy use system(s) accounting for at 

least 33 percent of the affected boiler(s) energy output will be 

evaluated to identify energy savings opportunities, within the 

limit of performing a 3one day energy assessment.

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(2) Energy assessment for facilities with affected boilers 

and process heaters using 0.3 to 1 TBtu/year will be three days 

in length maximum. The boiler system(s) and any energy use 

system(s) accounting for at least 33 percent of the affected 

boiler(s) energy output will be evaluated to identify energy 

savings opportunities, within the limit of performing a 3-day 

energy assessment.

c. (3) Energy assessment for facilities with affected 

boilers and process heaters using greater than 1.0 TBtu/year, 

the boiler system(s) and any energy use system(s) accounting for 

at least 20 percent of the affected boiler(s) energy output will 

be evaluated to identify energy savings opportunities.

Energy use system includes, but not limited to, process 

heating; compressed air systems; machine drive (motors, pumps, 

fans); process cooling; facility heating, ventilation, and airconditioning (HVAC) systems; hot heater systems;, building 

envelop; and lighting.

Equivalent means the following only as this term is used in 

Table 5 to this subpart:

(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 

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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 

mercury using an aliquot of the dried sample, then the drying 

temperature must be modified to prevent vaporizing this metal. 

On the other hand, if metals analysis is done on an "as 
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received" basis, a separate aliquot can be dried to determine 

moisture content and the mercury concentration mathematically 

adjusted to a dry basis.

(6) An equivalent mercury determinative or analytical 

procedure means a published VCS or EPA method that clearly 

states that the standard, practice, or method is appropriate for 

mercury and the fuel matrix and has a published detection limit 

equal or lower than the methods listed in Table 5 to this

subpart for the same purpose.

Fabric filter means an add-on air pollution control device 

used to capture particulate matter by filtering gas streams 

through filter media, also known as a baghouse. A fabric filter 

is a dry control system.

Federally enforceable means all limitations and conditions 

that are enforceable by the EPA Administrator, including the 

requirements of 40 CFR part 60 and 40 CFR part 61, requirements 

within any applicable Statestate implementation plan, and any 

permit requirements established under 40 CFR §§52.21 or under 40 

CFR 51.18 and 40 CFR §51.24.

Fuel type means each category of fuels that share a common 

name or classification. Examples include, but are not limited 

to, bituminous coal, subbituminoussub-bituminous coal, lignite, 

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anthracite, biomass, distillate oil, residual oil. Individual 

fuel types received from different suppliers are not considered 

new fuel types. 

Gaseous fuels includes, but is not limited to, natural gas, 

process gas, landfill gas, coal derived gas, refinery gas, 

hydrogen, and biogas.

Gas-fired boiler includes any boiler that burns gaseous 

fuels not combined with any solid fuels, burns liquid fuel only 

during periods of gas curtailment, gas supply emergencies, or 

periodic testing on liquid fuel. Periodic testing of liquid 

fuel shall not exceed a combined total of 48 hours during any 

calendar year.

Heat input means heat derived from combustion of fuel in a 

boiler and does not include the heat input from preheated 

combustion air, recirculated flue gases, or returned condensate.

Hot water heater means a closed vessel with a capacity of 

no more than 120 U.S. gallons in which water is heated by 

combustion of gaseous or liquid fuel and is withdrawn for use

external to the vessel at pressures not exceeding 160 psig, 

including the apparatus by which the heat is generated and all 

controls and devices necessary to prevent water temperatures

from exceeding 210 degrees Fahrenheit (99 degrees Celsius).
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Industrial boiler means a boiler used in manufacturing, 

processing, mining, and refining or any other industry to 

provide steam, hot water, and/or electricity.

Institutional boiler means a boiler used in institutional 

establishments such as medical centers, research centers, and 

institutions of higher education to provide electricity, steam, 

and/or hot water.

Liquid fuel means, but not limited to, petroleum, 

distillate oil, residual oil, any form of liquid fuel derived 

from petroleum, used oil, liquid biofuels, and biodiesel.

Minimum scrubber pressure drop activated carbon injection rate means 90 

percent of the average scrubber pressure drop measured according 

to Table 3 to this subpart during the most recent performance 

stack test demonstrating compliance with the applicable emission 

limit.

Minimum sorbent flow rate means the boiler load 

fraction (percent) multiplied by 90 percent of the testlowest 1-

hour average sorbent (or activated carbon) injection rate 

measured according to Table 36 to this subpart during the most 

recent performance stack test demonstrating compliance with the 

applicable emission limits.

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Minimum voltage or amperagescrubber pressure drop

means 90 percent of the test lowest 1-hour average voltage or 

amperage to the electrostatic precipitatorscrubber pressure drop

measured according to Table 36 to this subpart during the most 

recent performance stack test demonstrating compliance with the 

applicable emission limit.

Minimum sorbent flow rate means the boiler load (percent) 

multiplied by the lowest 1-hour average sorbent (or activated 

carbon) injection rate measured according to Table 6 to this 

subpart during the most recent performance stack test 

demonstrating compliance with the applicable emission limits.

Minimum voltage or amperage means the lowest 1-hour average 

voltage or amperage to the electrostatic precipitator measured 

according to Table 6 to this subpart during the most recent 

performance stack 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,

including intermediate gas streams generated during processing 

of natural gas at production sites or at gas processing plants; 

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or 

(2) Liquefied petroleum gas, as defined by the American 

Society for Testing and Materials in ASTM D1835-05 (incorporated 

by reference, see §63.14(b); 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); or).

(4) Propane or propane -derived synthetic natural gas. 

Propane means a colorless gas derived from petroleum and natural 

gas, with the molecular structure C3H8.

Oil subcategory includes any boiler that burns any liquid 

fuel and is not in either the biomass or coal subcategories. 

Gas-fired boilers that burn liquid fuel during periods of gas 

curtailment, gas supply emergencies, or for periodic testing, 

not to exceed 48 hours during any calendar year, of liquid fuel 

are not included in this definition.

Opacity means the degree to which emissions reduce the 

transmission of light and obscure the view of an object in the 

background.
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Particulate matter (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.

Performance testing means the collection of data resulting 

from the execution of a test method used (either by stack 

testing or fuel analysis) to demonstrate compliance with a 

relevant emission standard. 

Period of natural gas curtailment or supply interruption

means a period of time during which the supply of natural gas to 

an affected facility is halted for reasons beyond the control of 

the facility. The act of entering into a contractual agreement 

with a supplier of natural gas established for curtailment 

purposes does not constitute a reason that is under the control 

of a facility for the purposes of this definition. An increase 

in the cost or unit price of natural gas does not constitute a 

period of natural gas curtailment or supply interruption.

Qualified Energy Assessor mean a specialist in evaluating 

energy systems, such as, a person who have successfully 

completed the DOEDepartment of Energy Qualified Specialist 

program for all systems, Certified Energy Managers certified by 

the Association of Energy Engineers, or a person who has 
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demonstrated capabilities to perform and evaluate a full 

assessment of energy savings opportunities available for boiler

and energy use systems and technical expertise and tools to 

estimate cost and energy savings.

Steam and energy use systems include, but are not limited 

to:

a. Boiler combustion management.

b. Boiler thermal energy recovery.

1. Conventional feedwater economizer.

2. Conventional combustion air preheater.

3. Condensing economizer.

c. Boiler blowdown thermal energy recovery.

d. Primary energy resource selection.

1. Fuel (primary energy source) switching,.

2. Applied steam energy versus direct fired energy versus 

electricity.

e. Insulation issues.

f. Steam trap and steam leak management.

g. Condensate recovery.

h. Steam end-use management.

Capabilities and knowledge includes, but is not limited to:

a. Background, experience, and recognized abilities to 

perform the assessment activities, data analysis, and 

report preparation.

b. Familiarity with operating and maintenance practices for 

steam or process heating systems.

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1. additionalAdditional potential steam system 

improvement opportunities including improving steam 

turbine operations and reducing steam demand.

2. additionalAdditional process heating system 

opportunities including effective utilization of 

waste heat and use of proper process heating methods.

3. boilerBoiler-steam turbine cogeneration systems,.

4. industryIndustry specific steam end-use systems

4. Qualified personnel mean specialists in evaluating energy systems, such as, 

those who have successfully completed the U.S. Department of Energy 

Qualified Specialist program for all systems, Certified Energy Manager 

certified by the Association of Energy Engineers, or the equivalent.

Responsible official means responsible official as defined 

in 40 CFR §70.2.

Solid fossil fuel includes, but not limited to, coal, 

petroleum coke, and tire derived fuel (TDF)..

Tune-up means adjustments made to a boiler in accordance 

with procedures supplied by the manufacturer (or an approved 

specialist) to optimize the combustion efficiency.

Waste heat boiler means a device that recovers normally 

unused energy and converts it to usable heat. Waste heat 

boilers are also referred to as heat recovery steam generators.

Work practice standard means any design, equipment, work 

practice, or operational standard, or combination thereof, which

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is promulgated pursuant to section 112(h) of the CAA.Clean Air 

Act.

Table 1 to Subpart JJJJJJ of Part 63 — Emission Limits

As stated in §63.11201, you must comply with the following 

applicable emission limits:

If your boiler is 

in this 

subcategory...

For the 

following 

pollutants...

You must achieve less 

than or equal to the 

following emission 

limits, except during 

periods of startup and 

shutdown ...

1. New coal-fired 

boiler with 

heat input 

capacity of 

30 million 

Btu per hour 

or greater

a. Particulate 

Matter

b. Mercury

c. Carbon 

Monoxide

0.03 lb per MMBtu of 

heat input.

0.0000048 lb per MMBtu 

of heat input.

400 ppm by volume on a 

dry basis corrected to 

3 percent oxygen. 

b. Mercury 0.0000048 lb per MMBtu 

of heat input.

c. Carbon 

Monoxide

400 ppm by volume on a 

dry basis corrected to

3 percent oxygen.

2. New coal-fired 

boiler with 

heat input 

capacity of 

between 10 

and 30 

million Btu 

per hour

a. Particulate 

Matter

b. Mercury

c. Carbon 

Monoxide

0.42 lb per MMBtu of 

heat input.

0.0000048 lb per MMBtu 

of heat input.

400 ppm by volume on a 

dry basis corrected to 

3 percent oxygen. 

b. Mercury 0.0000048 lb per MMBtu 

of heat input.

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c. Carbon 

Monoxide

400 ppm by volume on a 

dry basis corrected to 

3 percent oxygen.

3. New biomassfired boiler 

with heat 

input 

capacity of 

30 millionBtu 

per hour or 

greater

a. Particulate 

Matter

0.03 lb per MMBtu of 

heat input.

4. New biomass 

fired boiler 

with heat 

input 

capacity of 

between 10 

and 30 

million Btu 

per hour

a. Particulate 

Matter

0.07 lb per MMBtu of 

heat input.

5. New oil-fired 

boiler with 

heat input 

capacity of 

10 million 

Btu per hour 

or greater

a. Particulate 

Matter

0.03 lb per MMBtu of 

heat input.

6. Existing coal 

(units with heat 

input 

capacity of 

10 million 

Btu per hour 

or greater) 

a. Mercury

b. Carbon 

Monoxide

0.0000048 lb per MMBtu 

of heat input.

400 ppm by volume on a 

dry basis corrected to 

3 percent oxygen. 

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b. Carbon 

Monoxide

400 ppm by volume on a 

dry basis corrected to 

3 percent oxygen.

Table 2 to Subpart JJJJJJ of Part 63 — Work Practice Standards, 

Emission Reduction Measures, and Management Practices

As stated in §63.11201, you must comply with the following 

applicable work practice standards, emission reduction measures, 

and management practices:

If your boiler is in 

this subcategory...

You must meet the following...

1. Existing or new 

coal (units with 

heat input capacity 

of 10 million Btu 

per hour or greater) 

Minimize the boiler’s time spent 

during startup and shutdown 

periods following the 

manufacturer’s recommended 

procedures. If manufacturer’s 

recommended procedures are not 

available, you must follow 

recommended procedures for a unit 

of similar design for which 

manufacturer’s recommended 

procedures are available.

2. Existing or new 

coal (units with 

heat input capacity 

of less than 10 

million Btu per 

hour) 

Conduct a tune-up of the boiler 

biennially as specified in 

§63.11222.

3. Existing or new 

biomass or oil

Conduct a tune-up of the boiler 

biennially as specified in 

§63.11222.

4. Existing coal, 

biomass, or oil 

(units with heat 

input capacity of 10 

million Btu per hour

and greater) 

Must have a one-time energy 

assessment performed by a 

qualified personnel which 

includes: 

(energy assessor. An energy 

assessment completed on or after 

January 1) a, 2008, that meets the 

energy assessment requirements in 

this table satisfies the energy 

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assessment requirement. The energy 

assessment must include: 

(1) A visual inspection of the 

boiler system.

(2) establishAn evaluation of

operating characteristics of the 

facility, energy system 

specifications of energy using 

systems, operating and maintenance 

procedures, and unusual operating 

constraints,

(3) identifyInventory of major 

systems consuming energy from 

affected boiler(s),

(4) aA review of available 

architectural and engineering plans, 

facility operation and maintenance 

procedures and logs, and fuel usage,

(5) aA list of major energy 

conservation measures,

(6) A list of the energy savings 

potential of the energy conservation 

measures identified,

(7) aA comprehensive report 

detailing the ways to improve 

efficiency, the cost of specific 

improvements, benefits, and the time 

frame for recouping those 

investments,

Table 3 to Subpart JJJJJJ of Part 63 — Operating Limits for 

Boilers with Emission Limits

As stated in §63.11201, you must comply with the applicable 

operating limits:

If you demonstrate 

compliance with 

applicable emission 

limits using...

You must meet these operating 

limits...

1. Fabric filter a. Maintain opacity to less than 

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control or equal to 10 percent opacity 

(daily block average); OR

b. Install and operate a bag leak 

detection system according to 

§63.11224 and operate the fabric 

filter such that the bag leak 

detection system alarm does not 

sound more than 5 percent of the 

operating time during each 6-

month period.

2. Electrostatic 

precipitator 

control

a. Maintain opacity to less than 

or equal to 10 percent opacity 

(daily block average); OR

b. Maintain the minimum voltage 

and secondary amperage (or total 

power input) of the electrostatic

precipitator at or above the 

operating limits established 

during the performance test. 

3. Wet scrubber control Maintain the minimum pressure drop 

and liquid flow-rate at or above 

the operating levels established 

during the performance test.

4. Dry sorbent or 

carbon injection 

control

Maintain the minimum sorbent or 

carbon injection rate at or above 

the operating levels established 

during the performance test. When 

your boiler operates at lower 

loads, multiply your sorbent or 

carbon injection rate by the load 

fraction (e.g., actual heat input 

divided by the heat input during 

performance stack test, for 50 

percent load, multiply the 

injection rate operating limit by 

0.5).

5. Any other add-on air 

pollution control type.

This option is for boilers that 

operate dry control systems. 

Boilers must maintain opacity to 

less than or equal to 10 percent 

opacity (daily block average).
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6. Fuel analysis Maintain the fuel type or fuel 

mixture (annual average) such that 

the mercury emission rates 

calculated according to 

§63.11211(b) is less than the 

applicable emission limits for 

mercury.

7. Performance stack 

testing

For boilers that demonstrate 

compliance with a performance 

stack test, maintain the operating 

load of each unit such that is 

does not exceed 110 percent of the 

average operating load recorded 

during the most recent performance 

stack test.

8. Continuous Oxygen 

Monitor 

For boilers that demonstrate 

compliance with an oxygen monitor, 

maintain the oxygen level of the 

stack gas such that it is not 

below 90 percent of the average 

oxygen concentration measured 

during the most recent CO 

performance stack test.

Table 4 to Subpart JJJJJJ of Part 63 — Performance (Stack) 

Testing Requirements

As stated in §63.11212, you must comply with the following 

requirements for performance (stack) test for affected sources:

To conduct a 

performance 

test for the 

following 

pollutant... You must... Using...

1.Particulate 

Matter

a. Select sampling 

ports location and 

the number of 

traverse points.

Method 1 in 

appendix A-1 to 

part 60 of this 

chapter.

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b. Determine velocity 

and volumetric flowrate of the stack 

gas.

Method 2, 2F, or 2G

in appendix A-2 to 

part 60 of this 

chapter.

1. 

Particulate 

Matter

a. Select sampling 

ports location and 

the number of 

traverse points.

b. Determine velocity 

and volumetric flowrate of the stack 

gas.

c. Determine oxygen and 

carbon dioxide 

concentrations of 

the stack gas.

d. Measure the moisture 

content of the stack 

gas

e. Measure the 

particulate matter 

emission 

concentration.

f. Convert emissions 

concentration to lb/ 

MMBtu emission 

rates.

Method 1 in 

appendix A to part 

60 of this chapter.

Method 2, 2F, or 2G 

in appendix A to 

part 60 of this 

chapter.

Method 3A or 3B in 

appendix A-2 to 

part 60 of this 

chapter, or ASTM 

D6522-00 (IBR, see 

§63.14(b)),Reapprov

ed 2005)a, or 

ANSI/ASME PTC 19, 

Part .10(1981)(IBR, 

see §63.14(i)).

Method 4 in 

appendix A to part 

60 of this chapter.

Method 5 or 17 

(positive pressure 

fabric filters must 

use Method 5D) in 

appendix A to part 

60 of this chapter.

Method 19 F-factor 

methodology in 

appendix A to part 

60 of this chapter1981a.

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d. Measure the moisture 

content of the stack 

gas.

Method 4 in 

appendix A-3 to 

part 60 of this 

chapter.

e. Measure the 

particulate matter 

emission 

concentration.

Method 5 or 17 

(positive pressure 

fabric filters must 

use Method 5D) in 

appendix A-3 and A6 to part 60 of 

this chapter.

f. Convert emissions 

concentration to lb/ 

MMBtu emission 

rates.

Method 19 F-factor 

methodology in 

appendix A-7 to 

part 60 of this 

chapter.

2. Mercury a. Select sampling 

ports location and 

the number of 

traverse points.

Method 1 in 

appendix A-1 to 

part 60 of this 

chapter. 

b. Determine velocity 

and volumetric flowrate of the stack gas.

Method 2, 2F, or 2G 

in appendix A-2 to 

part 60 of this 

chapter.

c. Determine oxygen and 

carbon dioxide 

concentrations of 

the stack gas.

Method 3A or 3B in 

appendix A-2 to 

part 60 of this 

chapter, or ASTM 

D6522-00

(Reapproved 2005)a, 

or ANSI/ASME PTC 

19.10-1981a.

d. Measure the moisture 

content of the stack 

gas.

Method 4 in 

appendix A-3 to 

part 60 of this 

chapter.
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2. Mercury a. Select sampling 

ports location and 

the number of 

traverse points.

b. Determine velocity 

and volumetric flowrate of the stack 

gas.

c. Determine oxygen and 

carbon dioxide 

concentrations of 

the stack gas.

d. Measure the moisture 

content of the stack 

gas.

e. Measure the mercury 

emission 

concentration.

f. Convert emissions 

concentration to lb/ 

MMBtu emission 

rates.

Method 129 or 30B

in appendix A to 

part 60 of this 

chapter. 

Method 2, 2F, or 2G 

in appendix A to 

part 60 of this 

chapter.

Method 3A or 3B in 

appendix A to part 

60 of this chapter, 

or ASTM D6522-00 

(IBR, see 

§63.14(b)), or ASME 

PTC 19, Part 

10(1981)(IBR, see 

§63.14(i)).

Method 4 in 

appendix A to part 

60 of this chapter. 

Method 29 in 

appendix A-8 to 

part 60 of this 

chapter or Method 

101A in appendix B 

to part 61 of this 

chapter or ASTM 

Method D6784-02 

(IBR, see 

§63.14(b)).

Method 19 F-factor 

methodology in 

appendix A to part 

60 of this 

chapter02a.

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f. Convert emissions 

concentration to lb/ 

MMBtu emission 

rates.

Method 19 F-factor 

methodology in 

appendix A-7 to 

part 60 of this 

chapter.

3. Carbon 

Monoxide

a. Select the sampling 

ports location and 

the number of 

traverse points

Method 1 in 

appendix A-1 to 

part 60 of this 

chapter.

3. Carbon 

Monoxide a. Select the sampling 

ports location and 

the number of 

traverse points.

b. Determine oxygen and 

carbon dioxide 

concentrations of 

the stack gas.

c. Measure the moisture 

content of the stack 

gas.

d. Measure the carbon 

monoxide emission 

concentration.

Method 1 in 

appendix A to part 

60 of this chapter. 

Method 3A or 3B in 

appendix A-2 to 

part 60 of this 

chapter, or ASTM 

D6522-00 (IBR, see 

§63.14(b)),Reapprov

ed 2005)a, or 

ANSI/ASME PTC 19, 

Part .10(1981)(IBR, 

see §63.14(i)).

Method 4 in 

appendix A to part 

60 of this chapter. 

Method 10, 10A, or 

10 B in appendix A 

to part 60 of this 

chapter or ASTM 

D6522-00 (IBR, see 

§63.14(b). -1981a.

c. Measure the moisture 

content of the stack 

gas.

Method 4 in 

appendix A-3 to 

part 60 of this 

chapter. 

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d. Measure the carbon 

monoxide emission 

concentration.

Method 10, 10A, or 

10B in appendix A-4 

to part 60 of this 

chapter or ASTM 

D6522-00

(Reapproved 2005)a.

a Incorporated by reference, see §63.14

Table 5 to Subpart JJJJJJ of Part 63 — Fuel Analysis 

Requirements

As stated in §63.11213, you must comply with the following 

requirements for fuel analysis testing for affected sources:

To conduct a 

fuel analysis 

for the 

following 

pollutant... You must... Using...

1. Mercury a. Collect fuel 

samples.

Procedure in 

§63.11213(b) or ASTM 

D2234-D2234Ma (for coal) 

or ASTM D6323a (for 

biomass) or equivalent.

b. Compose fuel 

samples.

Procedure in 

§63.11213(b) or 

equivalent.

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1. Mercury a. Collect fuel 

samples.

b. Compose fuel 

samples.

c. Prepare 

composited fuel 

samples.

d. Determine heat 

content of the 

fuel type.

e. Determine 

moisture 

content of the 

fuel type.

f. Measure mercury 

concentration 

in fuel sample.

Procedure in 

§63.11213(c) or ASTM 

D2234-D2234M-03€1 (for 

coal)(IBR, see 

§63.14(b)) or ASTM 

D6323-98 (2003)(for 

biomass)(IBR, see 

§63.14(b)) or 

equivalent.

Procedure in 

§63.11213(c) or 

equivalent.

EPA SW-846-3050B3050Ba

(for solid samples) or 

EPA SW-846-3020A3020Aa

(for liquid samples) or 

ASTM D2013-04/D2013Ma

(for coal)(IBR, see 

§63.14(b))) or ASTM 

D5198-92 (2003)D5198a

(for biomass)(IBR, see 

§63.14(b)) or 

equivalent.

ASTM D5865-10a (for 

coal)(IBR, see 

§63.14(b))a or ASTM 

E711-87 (1996) (for 

biomass)(IBR, see 

§63.14(b)) or 

equivalent.

ASTM D3173-03 (IBR, see 

§63.14(b))b or ASTM 

E871-82 (1998)(IBR, see 

§63.14(b)) or 

equivalent.

ASTM D6722-01 (for 

coal)(IBR, see 

§63.14(b))c or SW-846-

7471A (for solid 

samples) or SW-846 7470A 

(for liquid samples) or 

equivalent.

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d. Determine heat 

content of the 

fuel type.

ASTM D5865a (for coal) 

or ASTM E711a (for 

biomass) or equivalent.

e. Determine 

moisture 

content of the 

fuel type.

ASTM D3173a or ASTM 

E871a or equivalent.

f. Measure mercury 

concentration 

in fuel sample.

ASTM D6722a (for coal) 

or EPA SW-846-7471Ba

(for solid samples) or 

EPA SW-846-7470Aa (for 

liquid samples) or 

equivalent.

g. Convert 

concentrations 

into units of 

lb/MMBtu of 

heat content.

a ASTM D5865–10a, “Standard Test Method for Gross Calorific Value of Coal and 

Coke”

b ASTM D3173–03 (2008), “Standard Test Method for Moisture in the Analysis 

Sample of Coal and Coke”

c ASTM D6722–01 (2006), “Standard Test Method for Total Mercury in Coal and 

Coal Combustion Residues by the Direct Combustion Analysis”

a Incorporated by reference, see §63.14.

Table 6 to Subpart JJJJJJ of Part 63—Establishing Operating 

Limits

As stated in §63.11211, you must comply with the following 

requirements for 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

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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 or 

mercury

a. Wet 

scrubber 

operating 

parameters

i. Establish 

a sitespecific 

minimum 

pressure 

drop and 

minimum flow 

rate 

operating 

limit 

according to 

§63.11211(b)

(1) Data 

from the 

pressure 

drop and 

liquid flow 

rate 

monitors 

and the 

particulate 

matter or 

mercury 

performance

stack test

(a) You must 

collect 

pressure 

drop and 

liquid flowrate data 

every 15 

minutes 

during the 

entire 

period of 

the 

performance 

stack tests;

 (b) 

Determine 

the average 

pressure 

drop and 

liquid flowrate for 

each 

individual 

test run in 

the threerun 

performance 

stack test 

by computing 

the average 

of all the 

15-minute 

readings 

taken during 

each test 

run.
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If you have 

an 

applicable 

emission 

limit for 

. . .

And your 

operating 

limits are 

based on 

. . . You must... Using . . .

According to 

the 

following 

requirements

 b. 

Electrostatic 

precipitator 

operating 

parameters 

(option only 

for units 

that operate 

wet 

scrubbers)

i. Establish 

a sitespecific 

minimum 

voltage and 

secondary 

amperage (or 

total power 

input) 

according to 

§63.11211(b)

(1) Data 

from the 

voltage and 

secondary 

amperage 

monitors 

during the 

particulate 

matter or 

mercury 

performance 

stack test

(a) You must 

collect 

voltage and 

secondary 

amperage or 

total power 

input data 

every 15 

minutes 

during the 

entire 

period of 

the 

performance 

stack tests;

 (b) 

Determine 

the average 

voltage and 

secondary 

amperage or 

total power 

input for 

each 

individual 

test run in 

the threerun 

performance 

stack test 

by computing 

the average 

of all the 

15-minute 

readings 

taken during 

each test 

run.
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If you have 

an 

applicable 

emission 

limit for 

. . .

And your 

operating 

limits are 

based on 

. . . You must... Using . . .

According to 

the 

following 

requirements

2. Mercury a. Activated 

carbon 

injection

i. Establish 

a sitespecific 

minimum 

activated 

carbon 

injection 

rate 

operating 

limit 

according to 

§63.11211(b)

(1) Data 

from the 

activated 

carbon rate 

monitors 

and mercury 

performance 

stack tests

(a) You must 

collect 

activated 

carbon 

injection 

rate data 

every 15 

minutes 

during the 

entire 

period of 

the 

performance 

stack tests;

(b) 

Determine 

the average 

activated 

carbon 

injection 

rate for 

each 

individual 

test run in 

the threerun 

performance 

stack test 

by computing 

the average 

of all the 

15-minute 

readings 

taken during 

each test 

run.
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If you have 

an 

applicable 

emission 

limit for 

. . .

And your 

operating 

limits are 

based on 

. . . You must... Using . . .

According to 

the 

following 

requirements

(c) 

Determine 

the average 

of the three 

test run 

averages 

established 

during the 

performance 

stack test 

as your 

operating 

limit. When 

your unit 

operates at 

lower loads, 

multiply 

your 

activated 

carbon 

injection 

rate by the 

load 

fraction 

(e.g., 

actual heat 

input 

divided by 

heat input 

during 

performance 

stack test, 

for 50 

percent 

load, 

multiply the 

injection 

rate 

operating 

limit by 

0.5) to 

determine 

the required 

injection 
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Table 7 to Subpart JJJJJJ of Part 63 — Applicability of 

General Provisions to Subpart JJJJJJ

As stated in §63.11235, you must comply with the applicable 

General Provisions according to the following:

General 

Provisions Cite

Subject Does it apply?

§63.1 Applicability Yes.

§63.2 Definitions Yes. Additional terms 

defined in §63.11237.

§63.3 Units and 

Abbreviations

Yes.

§63.4 Prohibited 

Activities and 

Circumvention

Yes.

§63.5 Preconstruction 

Review and 

Notification 

Requirements

No

§63.6(a), (b)(1)-

(b)(5), (b)(7), 

(c), (f)(2)-(3), 

(g), (i), (j)

Compliance with 

Standards and 

Maintenance 

Requirements

Yes.

§63.6(e)(1)(i) General Duty to 

minimize emissions

No. See §63.11205 for 

general duty requirement.

§63.6(e)(1)(ii) Requirement to 

correct 

malfunctions ASAP

No.

§63.6(e)(3) SSM Plan No.

§63.6(f)(1) SSM exemption No.

§63.6(h)(1) SSM exemption No.

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§63.6(h)(2) to 

(9)

Determining 

compliance with

opacity emission 

standards

Yes.

§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 §63.11210.

§63.8(a),(b),(c)(

1),(c)(1)(ii),(c)

(2) to 

(c)(9),(d)(1)and(

d)(2), (e),(f), 

and (g)

Monitoring 

Requirements

Yes.

§63.8(c)(1)(i) General duty to 

minimize emissions 

and CMS operation

No.

§63.8(c)(1)(iii) Requirement to 

develop SSM Plan 

for CMS

No.

§63.8(d)(3) Written procedures 

for CMS

Yes, except for the last 

sentence, which refers to 

an SSM plan. SSM plans are 

not required.

§63.9 Notification 

Requirements

Yes.

§63.10(a) and 

(b)(1) 

Recordkeeping and 

Reporting 

Requirements

Yes.

§63.10(b)(2)(i) Recordkeeping of 

occurrence and 

duration of 

startups or 

shutdowns

No.
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§63.10(b)(2)(ii) Recordkeeping of 

malfunctions

No. See §63.11225 for 

recordkeeping of (1) 

occurrence and duration and 

(2) actions taken during 

malfunctions.

§63.10(b)(2)(iii) Maintenance 

records

Yes.

§63.10(b)(2)(iv) 

and (v)

Actions taken to 

minimize emissions 

during SSM

No.

§63.10(b)(2)(vi) Recordkeeping for 

CMS malfunctions

Yes.

§63.10(b)(2)(vii) 

to (xiv)

Other CMS 

requirements

Yes.

§63.10(b)(3) Recordkeeping 

requirements for 

applicability 

determinations

No.

§63.10(c)(1) to 

(9)

Recordkeeping for 

sources with CMS

Yes.

§63.10(c)(10) Recording nature 

and cause of 

malfunctions

No. See §63.11225 for 

malfunction recordkeeping 

requirements.

§63.10(c)(11) Recording 

corrective actions

No. See §63.11225 for 

malfunction recordkeeping 

requirements.

§63.10(c)(12) and 

(13)

Recordkeeping for 

sources with CMS

Yes.

§63.10(c)(15) Allows use of SSM

plan

No.

§63.10(d)(1) and 

(2)

General reporting 

requirements

Yes.
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§63.10(d)(3) Reporting opacity 

or visible 

emission 

observation 

results 

No.

§63.10(d)(4) Progress reports 

under an extension 

of compliance

Yes.

§63.10(d)(5) SSM reports No. See §63.11225 for 

malfunction reporting 

requirements.

§63.10(e) and (f) Yes.

§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.
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