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: Proposed rule.

SUMMARY: EPA is proposing national emission standards for 

control of hazardous air pollutants from two area source 

categories: industrial boilers and commercial and institutional

boilers. The proposed emission standards for control of mercury 

emissions from coal-fired area source boilers and the proposed 

emission standards for control of polycyclic organic matter 

emissions from all area source boilers are based on the maximum 

achievable control technology. The proposed emission standards

for control of mercury emissions from biomass-fired or oil-fired 

area source boilers and for other hazardous air pollutants are 

based on EPA’s proposed determination as to what constitutes the 

generally available control technology or management practices.

EPA is also clarifying that gas-fired area source boilers 

are not needed to meet the 90 percent requirement of section 

112(c)(3) of the Clean Air Act.
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DATES: Comments must be received on or before [INSERT DATE 45

DAYS AFTER PUBLICATION IN THE FEDERAL REGISTER]. If a hearing 

is requested on this proposed rule, written comments must be 

received by [INSERT DATE 45 DAYS AFTER PUBLICATION IN THE 

FEDERAL REGISTER]. Under the Paperwork Reduction Act, comments 

on the information collection provisions are best assured of 

having full effect if the Office of Management and Budget (OMB) 

receives a copy of your comments on or before [INSERT DATE 30 

DAYS AFTER PUBLICATION IN THE FEDERAL REGISTER].

ADDRESSES: Submit your comments, identified by Docket ID No. 

EPA-HQ-OAR-2006-0790, by one of the following methods:

• http://www.regulations.gov. Follow the instructions 

for submitting comments.

• http://www.epa.gov/oar/docket.html. Follow the 

instructions for submitting comments on the EPA Air 

and Radiation Docket Web Site.

• E-mail: Comments may be sent by electronic mail (email) to a-and-r-docket@epa.gov, Attention Docket ID 

No. EPA-HQ-OAR-2006-0790.

• Fax

•

: Fax your comments to: (202) 566-9744, Docket ID 

No. EPA-HQ-OAR-2006-0790.

Mail: Send your comments to: EPA Docket Center

(EPA/DC), Environmental Protection Agency, Mailcode:
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2822T, 1200 Pennsylvania Ave., NW, Washington, DC 

20460, Docket ID No. EPA-HQ-OAR-2006-0790. Please 

include a total of two copies. In addition, please 

mail a copy of your comments on the information 

collection provisions to the Office of Information and 

Regulatory Affairs, OMB, Attn: Desk Officer for EPA, 

725 17th St., NW, Washington, DC 20503.

• Hand Delivery or Courier: Deliver your comments to:

EPA Docket Center (EPA/DC), EPA West, Room 3334, 1301 

Constitution Ave., NW, Washington, DC 20460. 

Attention Docket ID No. EPA-HQ-OAR-2006-0790. Such 

deliveries are only accepted during the Docket’s 

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

Monday through Friday, excluding legal holiday), and 

special arrangements should be made for deliveries of 

boxed information.

Instructions: All submissions must include agency name and 

docket number or Regulatory Information Number (RIN) for this 

rulemaking. All comments will be posted without change and may 

be made available online at http://www.regulations.gov, 

including any personal information provided, unless the comment 

includes information claimed to be confidential business 

information (CBI) or other information whose disclosure is 

restricted by statute. Do not submit information that you 
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consider to be CBI or otherwise protected through 

http://www.regulations.gov or e-mail. The 

http://www.regulations.gov Web site is an “anonymous access” 

system, which means EPA will not know your identity or contact 

information unless you provide it in the body of your comment. 

If you send an e-mail comment directly to EPA without going 

through http://www.regulations.gov, your e-mail address will be 

automatically captured and included as part of the comment that 

is placed in the public docket and made available on the 

Internet. If you submit an electronic comment, EPA recommends 

that you include your name and other contact information in the 

body of your comment and with any disk or CD-ROM you submit. If 

EPA cannot read your comment due to technical difficulties and 

cannot contact you for clarification, EPA may not be able to 

consider your comment. Electronic files should avoid the use of 

special characters, any form of encryption, and be free of any 

defects or viruses.

Docket: All documents in the docket are listed in the 

http://www.regulations.gov index. Although listed in the index,

some information is not publicly available, e.g., CBI or other 

information whose disclosure is restricted by statute. Certain 

other material, such as copyrighted material, will be publicly 

available only in hard copy form. Publicly available docket 

materials are available either electronically in
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http://www.regulations.gov or in hard copy at the EPA Docket

Center, Room 3334, 1301 Constitution Ave., NW, Washington, DC. 

The Public Reading Room is open from 8:30 a.m. to 4:30 p.m., 

Monday through Friday, excluding legal holidays. The telephone 

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

telephone number for the Air Docket is (202) 566-1742.

FOR FURTHER INFORMATION CONTACT: Ms. Mary Johnson, Energy 

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

01), Office of Air Quality Planning and Standards, U.S. 

Environmental Protection Agency, Research Triangle Park, North 

Carolina 27711; Telephone number: (919) 541-5025; Fax number 

(919) 541-5450; E-mail address: johnson.mary@epa.gov. 

SUPPLEMENTARY INFORMATION:

Outline. The information in this preamble is organized as 

follows:

I. General Information

A. Does this action apply to me?

B. What should I consider as I prepare my comments to EPA?

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

D. When would a public hearing occur?

II. Background Information

A. What is the statutory authority and regulatory approach for 

this proposed rule?

B. What source categories are affected by the proposed 

standards?

C. What is the relationship between this proposed rule and 

other related national emission standards?

D. How did we gather information for this proposed rule?

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

proposed rule?

III. Clarification of the Source Category List

IV. Summary of this Proposed Rule
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A. Do the proposed standards apply to my source?

B. What is the affected source? 

C. When must I comply with the proposed standards?

D. What are the proposed MACT and GACT standards?

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

requirements?

F. What are the proposed initial compliance requirements?

G. What are the proposed continuous compliance requirements?

H. What are the proposed notification, recordkeeping and 

reporting requirements?

I. Submission of Emissions Test Results to EPA 

V. Rationale of this Proposed Rule

A. How did EPA determine which pollution sources would be 

regulated under this proposed rule?

B. How did EPA determine the subcategories for this proposed 

rule?

C. What surrogates are we using?

D. How did EPA determine the proposed standards for existing 

units?

1. MACT Analysis for Mercury from Coal-fired Boilers and POM

2. GACT Determination for Existing Area Source Boilers

E. How did EPA determine the proposed standards for new units?

1. MACT Analysis for Mercury from Coal-fired Boilers and POM

2. GACT Determination for New Area Source Boilers

F. How did we select the compliance requirements?

G. Alternative MACT Standards for Consideration

H. How did we decide to exempt these area source categories 

from title V permitting requirements?

VI. Summary of the Impacts of this Proposed Rule

A. What are the air impacts?

B. What are the cost impacts?

C. What are the economic impacts?

D. What are the social costs and benefits of this proposed 

rule?

E. What are the water and solid waste impacts?

F. What are the energy impacts?

VII. Relationship of this Proposed Action to CAA Section 

112(c)(6)

VIII. Statutory and Executive Order Review

A. Executive Order 12866: Regulatory Planning and Review

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 
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Environmental Health Risks and Safety Risks

H. Executive Order 13211: Actions Concerning Regulations That 

Significantly Affect Energy Supply, Distribution, or Use

I. National Technology Transfer and Advancement Act

J. Executive Order 12898: Federal Actions to Address 

Environmental Justice in Minority Populations and Low-Income 

Populations

I. General Information

A. Does this action apply to me? 

The regulated categories and entities potentially affected 

by the proposed standards include:

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.

422 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 
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affected by this action. To determine whether your facility, 

company, business, organization, etc., would be regulated by 

this action, you should examine the applicability criteria in 40 

CFR 63.11193 of subpart JJJJJJ (National Emission Standards for 

Hazardous Air Pollutants for Industrial, Commercial, and 

Institution Boilers Area Sources). If you have any questions 

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. What should I consider as I prepare my comments to EPA?

Do not submit information containing CBI to EPA through 

http://www.regulations.gov or e-mail. Send or deliver 

information identified as CBI only to the following address: 

Roberto Morales, OAQPS Document Control Officer (C404-02), 

Office of Air Quality Planning and Standards, U.S. Environmental 

Protection Agency, Research Triangle Park, North Carolina 27711, 

Attention: Docket ID EPA-HQ-OAR-2006-0790. Clearly mark the 

part or all of the information that you claim to be CBI. For 

CBI information in a disk or CD-ROM that you mail to EPA, mark 

the outside of the disk or CD-ROM as CBI and then identify 

electronically within the disk or CD-ROM the specific 

information that is claimed as CBI. In addition to one complete 

version of the comment that includes information claimed as CBI, 
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a copy of the comment that does not contain the information 

claimed as CBI must be submitted for inclusion in the public 

docket. Information so marked will not be disclosed except in 

accordance with procedures set forth in 40 CFR part 2. 

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

In addition to being available in the docket, an electronic 

copy of this proposed action will also be available on the 

Worldwide Web (WWW) through the Technology Transfer Network 

(TTN). Following signature, a copy of the proposed 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.

D. When would a public hearing occur?

We will hold a public hearing concerning this proposed rule 

on [INSERT DATE 15 DAYS AFTER PUBLICATION IN THE FEDERAL

REGISTER]. Persons interested in presenting oral testimony at 

the hearing should contact Ms. Pamela Garrett, Energy Strategies

Group, at (919) 541-7966 at least 2 days in advance of the 

hearing. The public hearing will be held in Washington DC at a 

location and time that will be posted at the following web site: 

http://www.epa.gov/airquality/combustion. Please refer to this 

website to confirm the date of the public hearing as well.

II. Background Information
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A. What is the statutory authority and regulatory approach for 

this proposed rule?

Section 112(d) of the Clean Air Act (CAA) requires us to 

establish NESHAP for both major and area sources of hazardous 

air pollutants (HAP) that are listed for regulation under CAA 

section 112(c). A major source emits or has the potential to 

emit 10 tons per year (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.

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 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 or 

management practices (“GACT”) 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 

whether such technologies and practices could be considered
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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 the seven specified hazardous air 

pollutants (HAP) are subject to standards under section 

112(d)(2) or (d)(4). The seven HAP specified in section 

112(c)(6) are as follows: alkylated lead compounds, polycyclic 

organic matter, hexachlorobenzene, mercury, polychlorinated 

biphenyls, 2,3,7,9-tetrachlorodibenzofurans, and 2,3,7,8-

tetrachloridibenzo-p-dioxin. 

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 

combustion. See 63 FR 17849. We listed these source categories 

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

contribution of mercury and polycyclic organic matter (POM). In 

the documentation for the CAA section 112(c)(6) listing, the 
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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 greater detail below, we re-examine the emission inventory 

and the need to address categories under CAA section 112(c)(6) 

during the rule development process. Based on this reexamination, we now believe we will only need to address the 

coal-fueled portion of these categories under CAA section 

112(c)(6).

With this proposed rule and the major source boilers rule, 

we currently believe that we have subjected to regulation or 

proposed to regulate at least 90 percent of the 1990 section 

112(c)(6) emissions inventory for mercury. Coal-fired area 

source boilers represent approximately 4.3 percent of the 1990 

section 112(c)(6) emissions inventory for mercury. In contrast, 

biomass- and oil-fired boilers represent approximately 0.34 

percent. Consequently, we are proposing to regulate coal-fired 

boilers under MACT because we need these sources to meet the 90 

percent requirement for mercury in section 112(c)(6). We are 

proposing to regulate biomass-fired and oil-fired types of 

boilers under GACT to meet the 90 percent requirement for 

mercury in section 112(c)(3).

We solicit comment on whether we should nevertheless 

establish MACT-based mercury emission standards for all boilers 
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in this category. In your comments, please explain the basis 

for your position and provide any supporting documentation.

The “maximum achievable control technology” or “MACT” 

regulation required by CAA section 112(d)(2) or (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 

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 
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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. 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) 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 

measurement methodology to a particular class of sources is not 

practicable due to technological and economic limitations. 

As noted above, we listed industrial coal combustion, 

industrial oil combustion, industrial wood combustion, 

commercial coal combustion, commercial oil combustion, and 
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commercial wood combustion under CAA section 112(c)(6) based on 

the source categories’ contribution of mercury and polycyclic 

organic matter (POM). We listed these same categories under 

section 112(c)(3) for their contribution of mercury, arsenic, 

beryllium, cadmium, lead, chromium, manganese, nickel, 

polycyclic organic matter (POM) (as 7-PAH (polynuclear aromatic 

hydrocarbons)), ethylene dioxide, and polychlorinated biphenyls 

(PCB).

We have developed proposed standards to reflect the 

application of MACT for mercury from coal-fired area source 

boilers and POM from all area source boilers under section 

112(c)(6) and have applied GACT for the other pollutants noted 

above.

B. What source categories are affected by the proposed

standards?

The source categories affected by the proposed 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 

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 the pollutants that formed the basis of the listings.

This proposed rule would apply to all existing and new 
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industrial boilers, institutional boilers, and commercial 

boilers located at 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, 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. 

C. What is the relationship between this proposed rule and 

other related national emission standards?

This proposed rule regulates industrial boilers and 

institutional/commercial boilers that are area sources of HAP. 

Today, in a parallel action, a NESHAP for industrial, 

commercial, and institutional boilers located at major sources 

is being proposed reflecting application of MACT. The major 

source NESHAP regulates emissions of particulate matter (PM) (as 

a surrogate for non-mercury metals), mercury, hydrogen chloride 

(HCl)(as a surrogate for acid gases), dioxins/furans, and carbon 
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monoxide (CO) (as a surrogate for non-dioxin organic HAP) from 

existing and new major source boilers. 

This proposed rule covers boilers located at area source 

facilities. In addition to the major source MACT for boilers 

being issued today and this rule, 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 proposing 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 unit located at an area source 

combusts secondary materials that are “solid waste,” as that 

term is defined by the Administrator under RCRA, those units 

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, 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 
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129(g)(1)].” NRDC v. EPA, 489 F.3d at 1257–58.

Based on the information available to the Agency, we 

believe that the boilers that are subject to this area source 

rule combust coal, oil, and biomass. EPA does not believe that 

the boilers subject to this rule combust any non-hazardous 

secondary materials, whether they are considered a solid waste 

or not. If you are aware of such materials being combusted at 

these boilers, please provide specific information as to the 

type of secondary material being combusted and at what type of 

facilities and in what quantities. If the final form of the 

solid waste definition results in any secondary materials being 

considered solid waste it will be important to know whether 

units are burning those materials, because that would result in 

those units becoming incinerators subject to regulation under 

section 129 and no longer being considered boilers.

There is also another CAA regulation that is relevant in 

that they apply to some of the affected sources in this rule. 

For example, in 1986, EPA codified new source performance 

standards (NSPS) for industrial, commercial, and institutional

boilers (40 CFR part 60, subparts Db and Dc) and revised 

portions of them in 1999 and 2006. The NSPS regulates emissions 

of PM, sulfur dioxide (SO2), and nitrogen oxides from boilers 

constructed after June 19, 1984. Sources subject to the NSPS 

that are located at area source facilities are also subject to 
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this proposed rule because this proposed rule regulates HAP. In 

developing this proposal, we have streamlined the monitoring and 

recordkeeping requirements to avoid duplicating requirements in 

the NSPS.

D. How did we gather information for this proposed rule?

We gathered information for this proposed rule from States’ 

boiler inspection lists, company Web sites, published 

literature, State permits, current State and Federal 

regulations, and from an Information Collection Request (ICR) 

conducted for the major source NESHAP.

We developed an initial nationwide population of area

source boilers based on boiler inspector databases from 13 

states. The boiler inspector databases 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 

database could not be readily assigned to an NAICS code. 

We reviewed state and other federal 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, 

commercial, and institutional boilers in 40 CFR part 60, subpart 

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

for boilers at area sources.

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

proposed rule?

As explained above, 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 112(c)(3) pollutants, we used 

surrogates because, as explained below, it was not practical to 

establish individual standards for each specific HAP. We 

grouped the 112(c)(3) pollutants, which formed the basis for the 

listing of these two source categories, into three common 

groupings: mercury, non-mercury metallic HAP (arsenic, 
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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 

surrogate for these HAP and for their control. 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 metal HAP. Furthermore, establishing separate 

standards for each individual HAP would impose costly and 

significantly more complex compliance and monitoring 
23

requirements and achieve little, if any, HAP emissions 

reductions beyond what would be achieved using the surrogate 

pollutant approach. 

For organic 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 an indicator of 

incomplete combustion and, thus, a potential indication of 

elevated organic HAP emissions. 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 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 proposing GACT 

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

HAP), CO (as a surrogate pollutant for the individual urban 

organic HAP), and mercury from biomass-fired and oil-fired 

boilers. We are proposing MACT standards for mercury from coalfired boilers and for POM from all boilers.
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III. Clarification of the Source Category List

The Industrial Boilers and the Institutional/Commercial 

Boilers area source categories were listed under section 

112(c)(3) of the CAA. EPA needs to establish emission standards 

for area source boilers for the following urban HAP in order to 

meet the section 112(c)(3) 90 percent requirement for these HAP: 

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

nickel, POM (as 7-PAH), ethylene dioxide, and PCB. Natural gasfired area source boilers do not emit any of the urban HAP 

identified above. Therefore, regulation of gas-fired area 

source boilers is not necessary to meet the 90 percent 

requirement under section 112(c)(3) for these HAP. For the 

reason stated above, pursuant to section 112(c)(3) of the CAA, 

we are proposing emission standards for the above mentioned HAP 

for area source boilers fired by coal, oil, and wood, but not 

standards for boilers fired by natural gas. 

IV. Summary of this Proposed Rule

A. Do the proposed standards apply to my source?

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

boiler combusting coal, biomass, or oil 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 standard 

developed under CAA section 129.

This proposed rule applies to you if you own or operate a 
25

boiler combusting natural gas, located at an area source, which

switches to combusting coal, biomass, or oil after the date of 

proposal.

B. What is the affected source? 

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 the proposed standards?

The owner or operator of an existing source would be required 

to comply with the rule no later than 3 years after the date of 

publication of the final rule in the Federal Register. The 

owner or operator of a new source would be required to comply 

upon the date of publication of the final rule in the Federal 

Register or startup of the facility, whichever is later. 

D. What are the proposed MACT and GACT standards?

Emission standards expressed in the form of emission limits 

are being proposed for new and existing area source boilers. 

The proposed MACT emission limits for mercury and CO (as a 

surrogate for POM) are presented, along with the proposed GACT 

standards for PM (as a surrogate for urban metals), in Table 1

of this preamble.

TABLE 1. Emission Limits for Area Source Boilers

(Pounds per million British thermal units heat input)

Source Subcategory Particulate 

Matter (PM)

Mercury Carbon 

Monoxide 

(CO) (ppm)
26

New 

Boiler

Coal 0.03 3.0E-06 310 (@ 7% 

oxygen)

Biomass 0.03 100 (@ 7% 

oxygen)

Oil 0.03 1 (@ 3% 

oxygen)

Existing 

Boiler

Coal 0.3 3.0E-06 310 (@ 7% 

oxygen)

Biomass 170 (@ 7% 

oxygen)

Oil 2 (@ 3% 

oxygen)

The emission limits for existing area source boilers are 

only applicable to area source boilers that have a designed heat 

input capacity of 10 million British thermal units per hour

(MMBtu/h) or greater. If your boiler burns at least 10 percent 

coal on a total fuel annual heat input basis, the boiler is in 

the coal fuel subcategory. If your boiler burns biomass or 

biomass in combination with a liquid or gaseous fuel, the unit 

is in the biomass subcategory. If your boiler burns oil, or oil

in combination with a gaseous fuel, 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 proposed for existing area source boilers that 

are units with designed heat input capacity of less than 10

MMBtu/h. The work practice standard for existing small area 

source boilers requires the implementation of a tune-up program.

An additional standard is being proposed for existing area 
27

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 the facility 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, 2010 

U.S. LEXIS 2265 (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,” that EPA promulgated under section 

112 of the CAA. When incorporated into CAA Section 112(d) 

regulations for specific source categories, these two provisions 

exempt sources from the requirement to comply with the otherwise 

applicable CAA section 112(d) emission standard during periods 

of SSM.

Consistent with Sierra Club 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 proposed 
28

regulatory language any provisions that are inappropriate, 

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

We are specifically seeking comment on whether there are any 

such provisions that we have inadvertently incorporated or 

overlooked. We also request comment on whether there are 

additional provisions that should be added to regulatory text in 

light of the absence of an SSM exemption and provisions related 

to the SSM exemption (such as the SSM plan requirement and SSM 

recordkeeping and reporting provisions).

In establishing the standards in this rule, EPA has taken 

into account startup and shutdown periods and, for the reasons

explained below, has not established different standards for 

those periods. The standards that we are proposing are daily or 

monthly averages. Based upon continuous emission monitoring 

data, obtained as part of the information collection effort for 

the major source boiler and process heater rulemaking, which 

included periods of startup and shutdown, over long averaging 

periods, startups and shutdowns will not affect the 

achievability of the standard. Boilers, especially solid fuelfired boilers, do not normally startup and shutdown more than

once per day. Thus, we are not establishing a separate emission

standard for these periods because startup and shutdown are part 

of their routine operations and, therefore, are already 

addressed by the standards.
29

Periods of startup, normal operations, and shutdown are all 

predictable and routine aspects of a source’s operations. 

However, by contrast, malfunction is defined as a “sudden, 

infrequent, and not reasonably preventable failure of air 

pollution control and monitoring equipment, process equipment or 

a process to operate in a normal or usual manner * * * “(40 CFR 

63.2). EPA has determined that malfunctions should not be 

viewed as a distinct operating mode and, therefore, any 

emissions that occur at such times do not need to be factored 

into development of CAA section 112(d) standards, which, once 

promulgated, apply at all times. It is reasonable to interpret 

section 112(d) as not requiring EPA to account for malfunctions 

in setting emissions standards. For example, we note that CAA 

section 112 uses the concept of “best performing” sources in 

defining MACT, the level of stringency that major source 

standards must meet. Applying the concept of “best performing” 

to a source that is malfunctioning presents significant 

difficulties. The goal of best performing sources is to operate 

in such a way as to avoid malfunctions of their units. 

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 
30

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, EPA would determine an appropriate response 

based on, among other things, the good faith efforts of the 

source to minimize emissions during malfunction periods, 

including preventative and corrective actions, as well as root 

cause analyses to ascertain and rectify excess emissions. EPA 

would also consider whether the source's failure to comply with 

the CAA section 112(d) standard was, in fact, “sudden, 

infrequent, not reasonably preventable” and was not instead 

“caused in part by poor maintenance or careless operation.” 40 

C.F.R. § 63.2 (definition of malfunction).

F. What are the proposed initial compliance requirements?

For new and existing area source boilers with applicable 

emission limits, we are proposing that you must conduct initial 
31

stack tests or fuel analysis (for mercury) to determine 

compliance with the PM, mercury, and CO emission limits. 

As part of the initial compliance demonstration, we are 

proposing that you must monitor specified operating parameters 

during the initial performance tests that demonstrate compliance 

with the PM and mercury emission limits for area source boilers 

with wet or dry scrubbers. The test average establishes your 

site-specific operating levels.

For owners or operators of existing area source boilers

having a heat input capacity of less than 10 MMBtu/h, we are 

proposing that 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, we are proposing that you 

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 proposed continuous compliance requirements?

If you demonstrate initial compliance with the emission 

limits by performance (stack) tests, we are proposing that you 

conduct stack tests on an annual basis. Furthermore, to 

demonstrate continuous compliance with the PM and mercury 

emission limits, we are proposing that you must monitor and 
32

comply with the applicable site-specific operating limits.

For area source boilers without wet scrubbers that must 

comply with the PM and mercury emission limits, we are proposing 

that you must continuously monitor opacity and maintain the 

opacity at or below ten percent (daily block average). Or, if 

the unit is controlled with a fabric filter, instead of 

continuously monitoring opacity, we are proposing that the 

fabric filter may be continuously operated such that the bag 

leak detection system alarm does not sound more than 5 percent 

of the operating time during any 6-month period. 

For boilers with wet scrubbers that must comply with the PM

and mercury emission limits, we are proposing that 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.

If you elected to demonstrate initial compliance with the 

mercury emission limit by fuel analysis, we are proposing that 

you 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, we propose 

that you must maintain monthly fuel records that demonstrate 

that you burned no new fuel type or new mixture (monthly 
33

average) as set during the performance test. If you plan to 

burn a new fuel type or new mixture than what was burned during 

the initial performance test, then we are proposing that you 

must conduct a new performance test to demonstrate continuous 

compliance with the PM emission limit and mercury emission 

limit.

For boilers with heat input capacities equal to or greater 

than 100 MMBtu/hr, we propose that you must continuously monitor 

CO and maintain the daily average CO emissions at or below the 

limits indicated in Table 1 to demonstrate compliance with the 

CO emission limits at all times.

H. What are the proposed notification, recordkeeping and 

reporting requirements?

All new and existing sources would be required to comply 

with some requirements of the General Provisions (40 CFR part 

63, subpart A), which are identified in Table 6 of this proposed 

rule. The General Provisions include specific requirements for 

notifications, recordkeeping, and reporting. If performance 

tests are required under this proposed rule, then the 

notification and reporting requirements for performance tests in 

the General Provisions would also apply.

Each owner or operator would be required to submit a 

notification of compliance status report, as required by 40 CFR 

63.9(h) of the General Provisions. This proposed rule requires 
34

the owner or operator to include in the notification of 

compliance status report certifications of compliance with rule

requirements.

Semiannual compliance reports, as required by 40 CFR 

63.10(e)(3) of subpart A, would be required only for semiannual

reporting periods when a deviation from any of the requirements 

in the rule occurred, or any process changes occurred and

compliance certifications were reevaluated.

This proposed rule would require records to demonstrate 

compliance with each emission limit, work practice standard, or 

management 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 of either continuously monitored parameter data for 

a control device if a device is used to control the emissions or

continuous emission monitoring system (CEMS) data would be 

required.

Each owner and operator would be required to keep the 

following records:

(1) All reports and notifications submitted to comply with 

the rule;

(2) Continuous monitoring data as required in the rule;
35

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

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

deviations from the 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 

assessments, opacity observations, performance evaluations, or 

other compliance demonstrations conducted to demonstrate initial 

or continuous compliance with the rule; and

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

for the rule, if applicable.

Typically, records would be retained for at least 5 years. 

In addition, monitoring plans, operating and maintenance plans, 

and other plans would 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.
36

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 would be required to 

submit to WebFIRE (an EPA electronic database) 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 proposed requirement to submit source 

test data electronically to EPA would not require any additional

performance testing. In addition, when a facility submits

performance test data to WebFIRE, there would be no additional 

requirements for data compilation; instead, we believe industry 

would greatly benefit from improved emissions factors, fewer

information requests, and better regulation development as 

discussed below. Because the information that would be reported 

is already required in the existing test methods and is

necessary to evaluate the conformance to the test methods, 

facilities would already be collecting and compiling these data. 

One major advantage of submitting source test data through the 

Electronic Reporting Tool (ERT), which was developed with input
37

from stack testing companies (who already collect and compile

performance test data electronically), is that it would provide 

a standardized method to compile and store all the documentation 

required by this proposed rule. Another important benefit of 

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 
38

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

money.

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 conducting of stack 

tests data for various pollutants including PM, mercury,

dioxin/furan, and HCl. Presently, the ERT does not accept 

opacity data or CEMS data.

EPA specifically requests comment on the utility of this 

electronic reporting requirement and the burden that owners and

operators of boiler area source facilities estimate would be 

associated with this requirement.

V. Rationale of this Proposed Rule
39

A. How did EPA determine which pollution sources would be 

regulated under this proposed rule?

This proposed rule regulates industrial boilers (fired by 

coal, biomass, or oil) and institutional and commercial boilers

(fired by coal, biomass, or oil) that are located at area 

sources of HAP. 

Boilers that are used specifically for research and 

development are not regulated. However, boilers that only 

provide steam to a process or for heating at a research and 

development facility are still subject to this proposed rule.

B. How did EPA determine the subcategories for this proposed 

rule?

The CAA allows EPA to divide source categories into 

subcategories when differences between given types of units lead 

to corresponding differences in the nature of emissions or the 

technical feasibility of applying emission control techniques. 

The design, operating, and emissions information that EPA 

reviewed during the major source rulemaking indicates the need 

to subcategorize boilers based on the boiler type.

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. Most boilers can only achieve full load on the fuel or 

fuels for which they were specifically designed. Changes to the 
40

fuel type would often require extensive changes to the fuel 

handling and feeding system. Additionally, the burners and 

combustion chamber would need to be redesigned and modified to 

handle different fuel types and account for increases or 

decreases in the fuel volume and shape. In some cases, the 

changes may reduce the capacity and efficiency of the boiler. 

An additional effect of these changes would be extensive 

retrofit costs.

Emissions from boilers burning coal, biomass, and oil will 

also differ. Boilers emit a number of urban HAP. In general, 

HAP formation is dependent upon the composition of the fuel. 

The combustion quality and temperature also play an important 

role. The fuel dependent urban HAP emissions from boilers are 

metals, including mercury. These fuel dependent HAP emissions 

generally can be controlled by either changing the fuel property 

before combustion or by removing the HAP from the flue gas after 

combustion. Organic HAP, on the other hand, are formed from 

incomplete combustion and are much less influenced by the 

characteristics of the fuel being burned. The degree of 

combustion may be greatly influenced by three general factors: 

time, turbulence, and temperature. These factors are a function 

of the design of the boiler which is dependent in part on the 

type of fuel being burned.

Because these different types of boilers have different 
41

emission characteristics which may influence the feasibility and

effectiveness of emission control, we are proposing to 

subcategorize them as follows: boilers designed to fire coal,

boilers designed to fire biomass, and boilers designed to fire 

oil in order to account for these differences in emissions. The 

coal-fired subcategory includes boilers burning greater than 10 

percent coal on an annual fuel heat input basis. The biomass 

fuel subcategory includes units burning any biomass but not more 

than 10 percent coal on an annual fuel heat input basis. The 

oil subcategory includes all remaining boilers. 

In summary, we have identified three subcategories of 

boilers located at area sources: (1) boilers designed for coal 

firing, (2) boilers designed for biomass firing, and (3) boilers

designed for oil firing.

C. What surrogates are we using?

As explained above, EPA is proposing emission standards for 

the two source categories in this proposed rule. For mercury 

from coal-fired area source boilers and POM from all area source 

boilers, EPA is proposing these standards under CAA sections

112(d)(2) and 112(h). For the other urban HAP which formed the 

basis of the CAA section 112(c)(3) listing, EPA is proposing 

standards pursuant to CAA section 112(d)(5). 

In selecting the proposed emission standards, we are using 

PM as a surrogate for the non-mercury metallic urban HAP 
42

(arsenic, beryllium, cadmium, chromium, lead, manganese, and 

nickel). The inherent variability and unpredictability of the 

non-mercury metal HAP compositions and amounts in fuel have 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 

surrogate for these HAP and for their control. 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 metal HAP. Consequently, we used PM as a 

surrogate for the non-mercury metal urban HAP in establishing 

emissions limits. The use of PM as a surrogate will also 

eliminate the cost of performance testing to comply with 

numerous standards for individual non-mercury metals. 

We looked at mercury separately from other metallic urban 

HAP due to its different chemical characteristics and applicable 
43

controls.

For the organic urban HAP listed for these source 

categories (POM, acetaldehyde, acrolein, dioxins, PCB, and 

formaldehyde), we used CO as a surrogate to represent the 

organic urban HAP emitted from the boilers. The presence of CO 

is an indicator of incomplete combustion. A high level of CO in 

emissions is an indicator of incomplete combustion and, thus, a 

potential indication of elevated organic HAP emissions. 

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 CO emissions than to 

measure and monitor emissions of each individual organic HAP. 

We considered other surrogates, such as 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. 

D. How did EPA determine the proposed standards for existing 

units?

Both industrial boilers and institutional/commercial 

boilers have been on the list of CAA section 112(c)(6) source 

categories for mercury and POM. That section requires MACT 

standards for each of the pollutants needed to achieve 

regulation of 90 percent of the emissions of the relevant 
44

pollutant. As previously noted, the CAA allows EPA to establish 

standards under GACT instead of MACT for urban HAP we propose to 

regulate to fulfill CAA section 112(c)(3). 

As discussed previously, CAA section 112(h) allows the 

Administrator to promulgate a design, equipment, work practice, 

or operational standard, or combination thereof, in certain

cases where, in the judgment of the Administrator, it is not 

feasible to prescribe or enforce an emission standard under CAA 

section 112(d). These cases include the situation in which the 

application of measurement methodology to a particular class of 

sources is not practicable due to technical and economic 

limitations.

As we establish emission standards for each source category 

listed pursuant to CAA section 112(c)(6), we learn more about 

the source category. As part of our analysis, we examine the 

available information about the source category, and we reexamine the inventory associated with the original listing. We 

continue to believe that we must regulate POM from coal-fired, 

biomass-fired, and oil-fired area source boilers in order to 

meet the requirement in section 112(c)(6), and propose below 

MACT-based limits for POM for all categories. However, based on 

the information we have learned to date as we are developing 

standards for various source categories, such as major source 

boilers, gold mines, commercial and industrial solid waste 
45

incinerators, and other categories, we believe that we only need 

coal-fired area source boilers to meet the 90 percent 

requirement set forth in section 112(c)(6) for mercury. 

Therefore, we propose as our primary option MACT-based controls 

for mercury only for coal-fired boilers. 

With respect to mercury 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 proposed standards that 

reflect GACT for these two area source categories.

1. MACT Analysis for Mercury from Coal-Fired Boilers and POM

All standards established pursuant to CAA section 112(d)(2) 

must reflect MACT, the maximum degree of reduction in emissions 

of air pollutants that the Administrator, taking into 

consideration the cost of achieving such emissions reductions, 

and any non-air quality health and environmental impacts and 

energy requirements, determined is achievable for each category

or subcategory. For existing sources, MACT 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 categories or subcategories with 30 or more 

sources. This requirement constitutes the “MACT floor” for 

existing area source boilers. EPA may not consider cost in 

determining the MACT floor. EPA must consider cost, non-air 

quality health and environmental impacts, and energy 
46

requirements in evaluating whether it is appropriate to set a

standard more stringent than the MACT floor (beyond-the-floor 

controls).

a. MACT Floor Analysis for Mercury and POM 

The approach selected for determining the MACT floors is 

based on estimating the emissions levels achieved on average by 

the best 12 percent of existing sources, for which we have 

information. In terms of developing MACT emission limits for 

area source boilers, we have:

- no emission data for POM,

- limited emission data (nine coal-fired boilers) for 

mercury,

- no State regulations applicable for mercury or POM,

- no State permits specific for mercury or POM,

- no surrogate for mercury, but CO as a surrogate for POM,

- emission data on four coal-fired area source boilers 

using add-on control technology for mercury,

- limited emission data for CO (5 coal-fired boilers, 30 

wood-fired boilers, 68 oil-fired boilers),

- a few State permits with CO limits for coal, oil, and 

wood-fired area source boilers,

The MACT floor limits for each of the HAP and HAP 

surrogates (mercury and CO) are calculated based on the

performance of the lowest emitting (best performing) sources in 
47

each of the subcategories. We ranked all of the sources for 

which we had data based on their emissions and identified the

lowest emitting 12 percent of the sources for each HAP.

We first considered whether fuel switching would be an 

appropriate control option for sources in each subcategory. We 

considered 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. A second consideration was whether 

fuel switching could be technically achieved by boilers in the

subcategory considering the existing design of boilers. We also 

considered 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 of control for any

subcategory. This decision was based on the overall effect of 

fuel switching on HAP emissions, technical and design

considerations discussed previously in this preamble, 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.
48

We used the emissions data for those best performing 

affected sources to determine the emission limits to be 

proposed, with an accounting for variability. EPA must exercise 

its judgment, based on an evaluation of the relevant factors and 

available data, to determine the level of emissions control that 

has been achieved by the best performing sources under variable 

conditions. The Court has recognized that EPA may consider 

variability in estimating the degree of emission reduction 

achieved by best-performing sources and in setting MACT floors. 

See Mossville Envt’l Action Now v. EPA, 370 F.3d 1232, 1241–42 

(D.C. Cir 2004) (holding EPA may consider emission variability 

in estimating performance achieved by best-performing sources 

and may set the floor at level that best-performing source can 

expect to meet “every day and under all operating conditions”). 

To calculate the achieved emission limit, including 

variability, we used the equation:

Where:

n = the number of test runs

m = the number of test runs in the compliance average

s = standard deviation of emission data

t(0.99, n-1) = the t-statistic

x = emissions data average

Specifically, the MACT floor limit is an upper prediction limit 

(UPL) calculated with the Student’s t-test using the TINV 
49

function in Microsoft Excel. The Student’s t-test has also been 

used in other EPA rulemakings in accounting for variability. 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. Given this definition, 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 an independent sample from the same population. That 

is, if we were to randomly select a future test condition from 

any of these sources (i.e., average of 3 runs), we can be 99

percent confident that the reported level will fall at or below 

the UPL value. To calculate the UPL, we used the average (or 

sample mean) and sample standard deviation (SD), which are two 

statistical measures calculated from the sample data. The 

average is the central value of a data set, and the SD is the 

common measure of the dispersion of the data set around the 

average.

Based on this limited available information, the MACT floor 

analyses for the three subcategories (coal, biomass, and oil) 

are discussed below. 

1. Existing area source boilers designed for coal firing:
50

Mercury – The total number of coal-fired area source 

boilers for which we have actual mercury emission data is 9. 

Thus, the top 12 percent is based on emissions from two boilers. 

The average mercury emission level of the top 12 percent is 1.3

pounds per trillion Btu (lb/TBtu). The SD of test runs in the 

top 12 percent boilers is 0.322. Therefore, the 99 percent UPL

level is 2.5 lb/TBtu. The resulting MACT floor mercury limit 

for existing coal-fired area source boilers is 2.5 lb/T Btu

(rounded to 0.000003 lb/million Btu). No fuel analysis data 

from boilers in the top 12 percent were available for assessing 

the impact of fuel variability on mercury emissions.

POM – None of the States for which we have an inventory 

have an applicable emission limit specifically for POM or CO. 

However, one State (New Jersey) does have standards for CO, but 

for boilers the size of coal-fired area source boilers, the 

requirement is actually a work practice standard for CO (i.e.,

boiler tune-up). For small (less than 50 MMBtu/h) boilers, the 

New Jersey requirement is to maintain and operate the source in 

accordance with manufacturer specifications. 

The available State permits obtained for coal-fired area 

source boilers limiting CO emissions were for 12 units located 

in Ohio (3 units), California (1 unit), and Illinois (8 units). 

We also obtained CO emission data from 5 coal-fired area source 

boilers as part of the information collection effort for the 
51

major source NESHAP. Therefore, the top 12 percent is made up 

of three boilers. The average CO level of the top 12 percent is 

162 parts per million (ppm) at 3 percent oxygen. The SD of the

run data in top 12 percent boilers is 92.1 ppm. Therefore, the 

99 percent UPL level is 390 ppm at 3 percent oxygen. The 

resulting MACT floor CO limit for existing coal-fired area 

source boilers is 310 ppm at 7 percent oxygen. We correct to 7

percent oxygen because that is typically in the oxygen range 

that coal-fired boilers operate and we rounded up to the nearest 

10 ppm.

2. Existing area source boilers designed for biomass firing:

POM – None of the States for which we have an inventory 

have an applicable emission limit specifically for POM or CO. 

Actual CO emission data were available from the National Forest 

Service’s Fuels for Schools program for 14 wood-fired boilers. 

Also, State permits limiting CO emissions from biomass boilers 

were obtained on another 24 biomass-fired area source boilers. 

We also obtained CO emission test data from 26 biomass-fired 

area source boilers as part of the major source ICR survey.

The top 12 percent is made up of 8 boilers. The average CO 

level of the top 12 percent is 75.5 ppm at 3 percent oxygen. 

The SD of the top 12 percent boilers is 81.3 ppm. The 99

percent UPL is 202 ppm at 3 percent oxygen, rounded up to 210 

ppm. Biomass-fired boilers typically operate at around 7
52

percent oxygen. Therefore, the MACT floor level is 170 ppm CO 

at 7 percent oxygen.

3. Existing area source boilers designed for oil firing:

POM – None of the States for which we have an inventory 

have an applicable emission limit specifically for POM or CO. 

Actual CO emission data were available from 68 oil-fired area 

source boilers responding to the Boiler MACT ICR. State permits 

limiting CO emissions from oil-fired area source boilers were 

obtained on 56 oil-fired area source boilers. 

The top 12 percent is made up of 15 boilers. The average 

CO level of the top 12 percent is 1 ppm at 3 percent oxygen. 

Based on the test runs from these 15 best performing units, the 

99 percent UPL level is 2 ppm at 3 percent oxygen. Therefore, 

the MACT floor level is 2 ppm CO at 3 percent oxygen. Because 

oil-fired boilers typically operate at around 3 percent oxygen, 

additional oxygen content correction was not necessary.

4. Work Practice Standards for Smaller Boilers

As previously discussed, CAA section 112(h)(1) states that 

the Administrator may prescribe a work practice standard or 

other requirements, consistent with the provisions of CAA 

sections 112(d) or (f), in those cases where, in the judgment of 

the Administrator, it is not feasible to enforce an emission 

standard. CAA section 112(h)(2)(B) further defines the term 

“not feasible” to mean when “the application of measurement 
53

technology to a particular class of sources is not practicable 

due to technological and economic limitations.” 

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 EPA Methods 29, 10, and 5 of 40 

CFR part 60 appendices A-8, A-4, and A-3, respectively. These 

methods are reliable and relatively inexpensive. However, the 

methods are not applicable for sampling small diameter (less 

than 12 inches) stacks. For example, in these small diameter 

stacks, the conventional Method 5 stack assembly blocks a 

significant portion of the cross-section of the duct and causes 

inaccurate measurements. Many existing area source boilers have 

stacks with diameters less than 12 inches. The stack diameter 

is generally related to the size of the boiler. Boilers that 

have a capacity below 10 MMBtu/h generally have stacks with 

diameters less than 12 inches. Also, many area source boilers 

do not currently have sampling ports or a platform for accessing 

the exhaust stack which would require an expensive modification 

to install sampling ports and a platform.

We conducted a cost-to-sales analysis to evaluate the 

economic impact of the testing and monitoring costs that area 

source boiler facilities would incur to demonstrate compliance 

with the proposed emission limits. The annual compliance costs 

imposed on each source is for the costs of a stack test for 
54

mercury and PM emissions and a continuous emission monitor (CEM) 

for CO emissions. We assumed that each establishment in each 

industry, commercial, or institutional sector would be 

associated with a single boiler. The financial impacts of 

potential compliance costs are assessed for representative 

entities in each entity sector using the ratio of compliance 

costs to the average representative entity revenue (cost-tosales ratio or CSR).

The results of the analysis indicate that total compliance 

costs exceed 3 percent (and can reach as high as 19 percent) of 

the average firm revenues for 79 percent of the facilities. 

This indicates that the annual costs for testing and monitoring 

alone would have a significant adverse economic impact on these 

facilities. The severity of the economic impact would depend on 

the size of the facility. For small institutional (schools) and 

commercial (farms) facilities the costs would be prohibitive. 

This analysis is discussed in the memorandum “Cost-to-Sales 

Analysis of Testing and Monitoring Costs” located in the docket.

Based on this analysis, pursuant to CAA section 112(h), EPA 

is proposing that it is not feasible to enforce emission 

standards for area source boilers having a heat input capacity 

of less than 10 MMBtu/h because of the technological and 

economic limitations described above. Thus, a work practice, as 

discussed below, is being proposed to limit the emissions of 
55

mercury and CO (as a surrogate for POM) for existing area source 

boilers having a heat input capacity of less than 10 MMBTU/h. 

We are specifically requesting comment on whether a threshold 

higher than 10 MMBtu/h meets the technical and economic 

limitations as specified in section 112(h). 

For existing area source boilers, the only work practice 

being used that potentially controls mercury and POM emissions 

is a boiler tune-up. Mercury is a fuel dependent HAP. That is, 

the amount of mercury emitted from the boiler depends on the 

amount of mercury contained in the fuel. Fuel usage can be 

reduced by improving the combustion efficiency of the boiler. 

At best, boilers may be 85 percent efficient and untuned boilers 

may have combustion efficiencies of 60 percent or lower. As 

combustion efficiency decreases, fuel usage increases to 

maintain energy output resulting in increased emissions. 

On the other hand, POM is formed from incomplete combustion 

of the fuel. The objective of good combustion is to release all 

the energy in the fuel while minimizing losses from combustion 

imperfections and excess air. The combination of the fuel with 

the oxygen requires temperature (high enough to ignite the fuel 

constituents), mixing or turbulence (to provide intimate oxygenfuel contact), and sufficient time (to complete the process), 

sometimes referred to as the three Ts of combustion. Good 

combustion practice (GCP), in terms of boilers, could be defined 
56

as the system design and work practices expected to minimize 

organic HAP emissions.

We have obtained information on area source boilers 

reported using GCP, as part of the information collection effort 

for the major source NESHAP. The data that we have suggests 

that area source boilers typically conduct boiler tune-ups. We 

also reviewed State regulations and permits applicable to area 

source boilers. The work practices listed in State regulations 

includes tune-ups (10 States), operator training (1 State), 

periodic inspections (2 States), and operation in accordance 

with manufacturer specifications (1 State). Of the 44 area 

source boilers with a capacity of less than 10 MMBtu/h that 

responded to EPA’s information collection effort for major 

source NESHAP, 28 (or 64 percent) reported conducting a boiler 

tune-up program. Ultimately, we determined that at least 6

percent of the boilers in each of the subcategories are subject 

to a tune-up requirement. Therefore, the work practice of a 

tune-up does establish the MACT floor for mercury and POM 

emissions from existing area source boilers with a heat input 

capacity of less than 10 MMBtu/h.

A detailed discussion of the MACT floor methodology is 

presented in the memorandum “MACT Floor Analysis for the 

Industrial, Commercial, and Institutional Area Source Boilers” 

in the docket.
57

b. Beyond-the-Floor Determination for Mercury and POM.

We considered the pollution prevention and energy 

conservation measure of an energy assessment as a beyond-thefloor option for mercury and POM emissions. An energy 

assessment provides valuable information on improving energy 

efficiency. An energy assessment, or energy audit, is an indepth energy study identifying all energy conservation measures 

appropriate for a facility given its operating parameters. 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 emissions of 

pollutants through process changes and other efficiency 

modifications. Besides reducing operating and maintenance 

costs, improving energy efficiency reduces negative impacts on 

the environment. Improvement in energy efficiency results in 

decreased fuel use which results in a corresponding decrease in 

emissions (both HAP and non-HAP) from the boiler, but not 

necessarily all those present. The Department of Energy (DOE) 

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. Many best practices are considered 

pollution prevention because they reduce the amount of fuel 
58

combusted which results in a corresponding reduction in 

emissions from the fuel combustion. The most common best 

practice is simply tuning the boiler to the manufacturer’s 

specification. 

If a facility elected to implement the cost-effective 

energy conservation measures identified in the energy 

assessment, it would potentially result in greater mercury and 

POM reduction than achieved by a boiler tune-up alone. In 

addition, 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 will be offset by 

the cost savings in lower fuel costs. Therefore, we decided to 

go beyond the MACT floor for this proposed rule for the existing 

area source boilers. The proposed standards for existing area 

source facilities with a boiler that has a capacity equal to or 

greater than 10 MMBtu/h for mercury and POM include the 

requirement of a performance of an energy assessment to identify 

energy conservation measures. Since there was insufficient 

information to determine if requiring implementation of costeffective measures were economically feasible, we are seeking

comment on this point. 

In this proposed rule, we are defining a cost-effective 

energy conservation measure to be any measure that has a payback 
59

(return of investment) period of two years or less. This 

payback period was selected based on section 325(o)(2)(B)(iii) 

of the Energy Policy and Conservation Act which states that 

there is a presumption that an energy conservation standard is 

economically justified if the increased installed cost for a 

measure is less than three times the value of the first-year 

energy savings resulting from the measure.

A detailed description of the beyond-the-floor 

consideration is in the memorandum “Methodology for Estimating 

Cost and Emissions Impacts for Industrial, Commercial, 

Institutional Area Source Boilers” in the docket.

2. GACT Determination for Existing Area Source Boilers 

As provided in CAA section 112(d)(5), we are proposing 

standards representing GACT for these area source boilers.

For existing coal and biomass-fired area source boilers, 

the add-on control technology generally being used is 

multiclones. We found that this technology is minimally 

effective in controlling urban metal HAP and has no effect on 

urban organic HAP.

Multiclones are mechanical separators that use velocity 

differential across the cyclones to separate particles. A 

multiclone uses several smaller diameter cyclones to improve 

efficiency. Multiclones have a control efficiency for PM 

emissions of about 75 percent. Multiclones are more efficient 
60

in collecting larger particles and their collection efficiency 

falls off at small particle sizes. This is a disadvantage 

because non-mercury metallic HAP tend to be on small size 

particles (i.e., fine particle enrichment). Based on emission 

data obtained during the major source NESHAP development, 

multiclones have a control efficiency for non-mercury metallic 

HAP of only about 10 percent and have no effect on reducing 

mercury emissions. The cost of using multiclones (capital, 

testing, and monitoring) is estimated to be between $50,000 and 

$100,000 depending on the size of the boiler.

We also considered various pollution prevention and energy

conservation options as the potential basis for GACT for the 

urban metal HAP and the organic urban HAP. The most common 

options, and generally available, are simply tuning the boiler 

to the manufacturer’s specification. A boiler tune-up provides 

potential savings from energy efficiency improvements and

pollution prevention. Besides reducing operating and 

maintenance costs, improving energy efficiency reduces negative 

impacts on the environment. Improvement in energy efficiency 

results in decreased fuel use which results in a corresponding 

decrease in emissions (both HAP and non-HAP) from the boiler. A 

boiler tune-up requirement would potentially result in the same 

non-mercury metallic HAP reduction as a PM emission limit based 

on performance of multiclones but would also reduce emissions of 
61

organic HAP. In addition, the cost of a boiler tune-up appears 

minimal compared to the cost for testing and monitoring to 

demonstrate compliance with an emission limit.

For existing oil-fired area source boilers, we found no 

add-on control technology being used.

Therefore, we determined that GACT for existing area source 

boilers with heat input capacities of 10 MMBtu/hour or greater

is a management practice requiring the implementation of a

boiler tune-up program. Thus, for existing area source boilers, 

we are proposing GACT for HAP other than mercury and POM to be a 

management practice requiring the implementation of a boiler 

tune-up program.

If we conclude that our obligations under section 112(c)(6) 

for mercury can be met without mercury emissions from biomassfired or oil-fired area source boilers, we believe that several 

requirements of this proposed rule would be generally available 

to the regulated community and would provide some control of 

mercury and other fuel-bound pollutants at existing sources with 

larger boilers. For example, the requirements to optimize 

combustion, conduct an energy audit, and conduct biennial tuneups would decrease emissions of mercury because less fuel would 

be burned. In contrast, we do not believe that fabric filters

are widely used now, would be expensive to install for small 

businesses, and therefore would not be considered GACT. 
62

Therefore, we seek comment on whether the various measures 

discussed in this preamble to reduce fuel consumption in 

connection with POM control and control of urban metal HAP and 

organic urban HAP would represent GACT for mercury emitted from 

biomass-fired and oil-fired area source boilers. 

E. How did EPA determine the proposed standards for new units?

As noted above, we have developed the proposed standards to 

reflect the application of MACT for mercury and POM, and GACT 

for arsenic, beryllium, cadmium, lead, chromium, manganese, 

nickel, ethylene dioxide, and polychlorinated biphenyls (PCB).1

1. MACT Analysis for Mercury from Coal-fired Boilers and POM.

The CAA specifies that MACT for new boilers shall not be 

less stringent than the emission control that is achieved in 

practice by the best-controlled similar source, as determined by 

the Administrator. This minimum level of stringency is the MACT 

floor for new units. EPA may not consider costs or other 

impacts in determining the MACT floor. However, EPA must 

consider cost, non-air quality health and environmental impacts, 

and energy requirements in evaluating whether it is appropriate 

to set a standard that is more stringent than the MACT floor 

(beyond-the-floor controls). 

 

1 The proposed emission standards will also reduce emissions of 

other urban HAP, which did not form the basis of the listing. 

Those urban HAP include benzene, acetaldehyde, acrolein, dioxins, 

and formaldehyde. 
63

a. MACT Floor Analysis for Mercury and POM. Similar to the 

MACT floor process used for existing area source boilers, the 

approach used for determining the MACT floors for new units is 

based on estimating the emissions levels achieved by the bestcontrolled similar source, for which we have information.

1. New area source boilers designed for coal firing:

Mercury – We determined in the context of the major source 

rulemaking for boilers that fabric filters are the most 

effective technology employed by coal-fired industrial, 

commercial, and institutional boilers for controlling mercury 

emissions. Five coal-fired area source boilers have been 

identified as having a fabric filter. Based on available 

emission data, the best performing unit (i.e., the unit having 

the reported lowest mercury level based on a three run test) is 

an area source coal-fired boiler equipped with an electrostatic 

precipitator (ESP). The boiler had a test average for mercury 

of 1.4 lb/TBtu with a SD of 0.307 to account for variability. 

Therefore, the resulting MACT floor mercury limit for new coalfired area source boilers is determined to be 3.2 lb/T Btu. 

Since this calculated value is less stringent than the MACT 

floor for mercury at existing boilers designed for coal firing, 

the MACT floor for new sources was established to be equal to 

the floor for existing sources (0.000003 lb/million Btu).

POM – For POM emissions, the only control technology 
64

identified as being used on area source boilers is monitoring 

and maintaining CO emission levels which is associated with 

minimizing emissions of organic HAP (including POM). Carbon 

monoxide is generally an indicator of incomplete combustion 

because CO will oxidize to carbon dioxide if adequate oxygen is 

available. Therefore, controlling CO emissions can be a 

mechanism for ensuring combustion efficiency and may be viewed 

as a GCP. As discussed previously in this preamble, CO is 

considered a surrogate for organic HAP (including POM) emissions 

in this proposed rule. 

None of the States for which we have an inventory have an 

applicable emission limit specifically for POM or CO. However, 

one State (New Jersey) does have standards for CO, but for 

boilers the size of coal-fired area source boilers, it is 

actually a work practice standard for CO (i.e., tune-up). For 

small (less than 50 MMBtu/h) boilers, New Jersey’s requirement 

is to maintain and operate the source in accordance with 

manufacturers’ specifications.

Considering available State permit data and emission test 

data for coal-fired area source boilers the best controlled 

similar source is a coal-fired area source boiler having an 

average three run CO test emission level of 216 ppm at 3 percent

oxygen. The calculated 99 percent UPL, to account for 

variability, is 640 ppm at 3 percent oxygen. Since this 
65

calculated value is less stringent than the MACT floor for CO at 

existing boilers designed for coal firing, the MACT floor for 

new sources was established to be equal to the floor for 

existing sources (300 ppm at 7 percent oxygen).

2. New area source boilers designed for biomass firing:

POM – None of the States for which we have an inventory 

have an applicable emission limit specifically for POM or CO. 

Actual CO emission data were available from the Fuels for 

Schools program for 14 biomass-fired boilers and from 29 

biomass-fired area source boilers as part of the major source 

ICR survey. Also, State permits limiting CO emissions from 

biomass boilers were obtained on another 27 biomass-fired area 

source boilers. Therefore, the MACT floor for POM achieved by 

the best controlled similar source is based on actual CO 

emission data. 

The average 3-run test CO level of the best controlled 

similar source is 38.6 ppm at 3 percent oxygen. The SD for the 

test runs is 14 ppm. Therefore, the 99 percent UPL is 120 ppm 

at 3 percent oxygen, rounded up to the nearest 10 ppm. Thus, 

the proposed MACT floor level is 100 ppm CO at 7 percent oxygen.

3. New area source boilers designed for oil firing:

POM – None of the States for which we have an inventory 

have an applicable emission limit specifically for POM or CO. 

Actual CO emission data were available on 66 oil-fired area 
66

source boilers. State permits limiting CO emissions from oilfired area source boilers were obtained on 46 oil-fired area 

source boilers. Therefore, the proposed MACT floor for POM 

achieved by the best controlled similar source would be based on 

the boilers reporting the lowest CO emission level. 

The CO emission level of the best performing similar source

is 0.6 ppm at 3 percent oxygen. The SD of the test runs is 0.04 

ppm. Therefore, the 99 percent UPL and the proposed MACT floor 

level is 1 ppm CO at 3 percent oxygen, rounded up to the nearest 

whole ppm.

A detailed description of the MACT floor determination is 

in the memorandum, “MACT Floor Analysis for Industrial, 

Commercial, and Institutional Area Source Boilers” in the 

docket.

4. Appropriateness of Work Practice Standards for New Area 

Source Boilers:

As previously discussed, CAA section 112(h) states that the 

Administrator may prescribe a work practice standard or other 

requirements, consistent with the provisions of CAA sections 

112(d) or (f), in those cases where, in the judgment of the 

Administrator, it is not feasible to enforce an emission 

standard due to technical and economic limitations.

As was the case for existing small area source boilers, 

total compliance costs would likely exceed 3 percent of the 
67

average firm revenues for some new facilities. This indicates 

that the annual costs for testing and monitoring alone may have 

a significant adverse economic impact on some new facilities.

As discussed previously, 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 EPA Methods 

29, 10, and 5 and are not applicable for sampling small diameter 

stacks. We solicit comment on whether it would be technically 

infeasible to design sampling ports adequate for the test 

methods in boilers that are below a certain size. 

Based on this analysis and the reason discussed below, we 

are not proposing a work practice under CAA section 112(h) for 

new area source boilers. New facilities, as opposed to existing 

facilities, have the added flexibility of including compliance 

costs into their design and planning. This would include the 

design and cost to provide a performance testing facility that 

has sampling ports adequate for the test methods and 

constructing the exhaust stack such that HAP emission rates can 

be accurately determined. In addition, a new facility has the 

option of fuel selection in minimizing their compliance costs. 

A detailed discussion of the MACT floor methodology is 

presented in the memorandum “MACT Floor Analysis for the 

Industrial, Commercial, and Institutional Area Source Boilers” 

in the docket.
68

b. Beyond-the-floor Analysis for Mercury and POM for New 

Area Source Boilers. The MACT floor level of control for new 

units is based on the emission control that is achieved in 

practice by the best controlled similar source within each of 

the subcategories. No technologies or other HAP emission 

reduction approaches were identified that would achieve mercury 

or POM reduction greater than the new source floors for each of 

the subcategories.

Therefore, we decided to not go beyond the MACT floor level 

of control for mercury and POM emissions for new area source

boilers in this proposed rule. A detailed description of the 

beyond-the-floor consideration is in the memorandum “Methodology 

for Estimating Cost and Emissions Impacts for Industrial, 

Commercial, Institutional Area Source Boilers” in the docket.

2. GACT Determination for New Area Source Boilers

The control technologies currently used by facilities in 

the source categories that reduce non-mercury metallic HAP and 

PM are fabric filters and ESP. We determined that these

controls are generally available and cost effective for new area 

source boilers. New area source boilers with heat input 

capacity of 10 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 
69

require a PM control device to comply with the proposed mercury 

MACT standard.

The emissions database contains PM test data for 82 area 

source boilers obtained from the ICR survey conducted for major 

sources. All of the boilers were greater than 10 million Btu 

per hour in size. In order to develop PM (as a surrogate for 

non-mercury metallic HAP) emission limits for the three

subcategories, we compared the PM limits in NSPS subpart Dc with 

the obtained PM emission data. We considered this to be an 

appropriate methodology because many new area source boilers

will be subject to NSPS subpart Dc. Consequently, we determined 

that the PM limits in the NSPS could be used to establish the PM 

GACT emission limit for area source boilers.

The proposed GACT PM emission level based on NSPS subpart 

Dc for new area source boilers is 0.03 lb/million Btu. Of the 

82 area source boilers for which we have PM emission data, 11 

had reported PM emission levels below 0.03 lb/million Btu.

For the organic urban HAP (acetaldehyde, acrolein, dioxins, 

and formaldehyde), the most effective control technology 

identified is minimizing CO emissions and we determined that 

this control is generally available and cost effective for new 

area source boilers. This determination is based on the fact 

there is no additional costs associated with proposing a CO 

emission limit (as a surrogate for the urban organic HAP) as 
70

GACT because it is the same as the MACT standard being proposed 

for these subcategories for POM.

F. How did we select the compliance requirements?

We are proposing testing, monitoring, notification, and 

recordkeeping requirements that are adequate to assure 

continuous compliance with the requirement of the rule. Those 

requirements are described in detail in sections IV.F to IV.H. 

We selected these requirements based upon our determination of 

the information necessary to ensure that the emission standards, 

work practices, and management practices are being followed and 

that emission control devices and equipment are maintained and 

operated properly. The proposed requirements ensure compliance 

with this proposed rule without proposing a significant 

additional burden for facilities that must implement them.

We are proposing that compliance with the PM and mercury 

emission limits be demonstrated by an initial performance test. 

To ensure continuous compliance with the proposed PM and mercury 

emission limits, this proposed rule would require continuous 

parameter monitoring of control devices and recordkeeping. 

Additionally, this proposed rule requires annual performance 

tests to ensure, on an ongoing basis, that the air pollution 

control device is operating properly and its performance has not 

deteriorated. If initial compliance with the mercury emission 

limit is demonstrated by a fuel analysis performance test, this
71

proposed rule requires fuel analyses monthly, with compliance 

determined based on an annual average.

We evaluated the cost of applying PM CEMS to area source 

boilers. For PM CEM monitoring, capital costs were estimated to 

be $88,000 per unit and annualized costs were estimated to be 

$33,000 per unit. The estimated national annual cost would be 

$4.5 billion. We determined the costs would make them an 

unreasonable monitoring option.

We reviewed the cost information for CO CEMS provided by 

commenters on the NESHAP for major source boilers to make the 

determination on whether to require CO CEMS or conducting annual 

CO testing to demonstrate continuous compliance with the CO 

emission limit. In evaluating the available cost information, 

we determined that requiring CO CEMS for units with heat input 

capacities greater or equal to 100 MMBtu/hr is reasonable. This

proposed rule requires units with heat input capacities less 

than 100 MMBtu/hr to conduct initial and annual performance 

(stack) tests.

G. Alternative MACT Standards for Consideration

Our analysis of the inventory for mercury under CAA section 

112(c)(6) has led us to believe that we do not need to regulate 

biomass-fired and oil-fired boilers under MACT in order to meet 

our statutory obligations under this provision. We solicit 

comment on whether we should require the MACT-based emission 
72

limits on mercury emissions from larger boilers in this category 

if we conclude that such controls are unnecessary to meet our 

obligations under section 112(c)(6).

We also solicit comment on MACT-based requirements for 

mercury emitted from biomass-fired and oil-fired area source 

boilers in the event comment and further analysis of the 

inventory demonstrates such regulation is necessary to fulfill 

the 90 percent requirement under CAA section 112(c)(6) or is 

otherwise appropriate. We present what would be MACT below.

1. Existing area source boilers designed for biomass firing:

Mercury – We obtained mercury emission data from two 

biomass-fired area source boilers as part of the information 

collection effort for the major source NESHAP. Thus, the top 12

percent would be comprised of one boiler. The average mercury

level of the top 12 percent is 0.36 lb/TBtu. All 3 test runs 

results were nondetect. The standard deviation for the three 

detection limits, when converted to lb/mmBtu using the heat 

input rates during each run, was 1.82E-09. Therefore, the 

resulting MACT floor mercury limit for existing biomass-fired 

area source boilers would be 0.37 lb/TBtu (rounded to 0.0000004 

lb/MMBtu).

2. Existing area source boilers designed for oil firing:

Mercury – There are no available emission data, State 

regulations, or State permits regarding mercury emissions from 
73

oil-fired area source boilers. Available emission factors are 

generally the average of available data and would not reasonably 

represent the average of the top 12 percent best performing 

units. However, we have obtained mercury emission data on major 

source oil-fired boilers as part of the major source rulemaking. 

Since major source oil-fired boilers are similar in design and 

controls as compared to area source oil-fired boilers, we are 

applying the major source MACT limit of 4 lb/TBtu (0.000004 

lb/MMBtu) to existing oil-fired area source boilers. 

3. New area source boilers designed for biomass firing:

Mercury – We determined in the context of the major source 

rulemaking for boilers that fabric filters are the most 

effective technology employed by biomass-fired boilers for 

controlling mercury emissions. However, there is no test 

information on biomass-fired boilers equipped with fabric 

filters in which to determine control efficiency. 

The average mercury level of the “best controlled” unit for 

which we have emission data is 0.36 lb/TBtu. All 3 test runs 

results were nondetect. The standard deviation for the three 

detection limits, when converted to lb/MMBtu using the heat 

input rates during each run, was 1.82E-09. Therefore, the 

resulting MACT floor mercury limit for existing biomass-fired 

area source boilers would be 0.36 lb/TBtu (0.0000004 lb/MMBtu).

4. New area source boilers designed for oil firing:
74

Mercury – There are no available emission data, State 

regulations, or State permits regarding mercury emissions from 

oil-fired area source boilers. Available emission factors are 

generally the average of available data and would not reasonably 

represent the best performing unit. However, we have obtained 

mercury emission data on major source oil-fired boilers as part 

of the major source rulemaking. Since major source oil-fired 

boilers are similar in design and controls as compared to area 

source oil-fired boilers, we are applying the major source MACT 

limit for new oil-fired boilers of 0.3 lb/TBtu (0.0000003 

lb/MMBtu) to new oil-fired area source boilers. 

H. How did we decide to exempt these area source categories 

from title V permitting requirements?

For the reasons described below, we are proposing to exempt 

from title V permitting requirements affected sources in the 

industrial boiler and the institutional/commercial boiler area 

source categories that are not certain synthetic area sources. 

We estimate that at least 48 synthetic area sources reduced 

their HAP emissions to below the major source thresholds by 

installing air pollution control devices. We are not proposing 

to exempt from title V those synthetic area sources that have 

reduced their HAP emissions to below the major source thresholds

by installing air pollution control devices. 

CAA section 502(a) provides that the Administrator may 
75

exempt an area source category (in whole or in part) from title 

V if the Administrator determines that compliance with title V

requirements is “impracticable, infeasible, or unnecessarily 

burdensome” on an area source category. See CAA section 502(a). 

In December 2005, in a national rulemaking, EPA interpreted the 

term “unnecessarily burdensome” in CAA section 502 and developed 

a four-factor balancing test for determining whether title V is 

unnecessarily burdensome for a particular area source category, 

such that an exemption from title V is appropriate. See 70 FR 

75320, December 19, 2005 (Exemption Rule).

The four factors that EPA identified in the Exemption Rule 

for determining whether title V is “unnecessarily

burdensome” on a particular area source category include: (1) 

whether title V would result in significant improvements to the 

compliance requirements, including monitoring, recordkeeping, 

and reporting, that are proposed for an area source category (70

FR 75323); (2) whether title V permitting would impose 

significant burdens on the area source category and whether the 

burdens would be aggravated by any difficulty the sources may 

have in obtaining assistance from permitting agencies (70 FR 

75324); (3) whether the costs of title V permitting for the area 

source category would be justified, taking into consideration 

any potential gains in compliance likely to occur for such 

sources (70 FR 75325); and (4) whether there are implementation 
76

and enforcement programs in place that are sufficient to assure 

compliance with the NESHAP for the area source category, without 

relying on title V permits (70 FR 75326).

In discussing these factors in the Exemption Rule, we 

further explained that we considered on “a case-by-case basis 

the extent to which one or more of the four factors supported 

title V exemptions for a given source category, and then we 

assessed whether considered together those factors demonstrated 

that compliance with title V requirements would be 

‘unnecessarily burdensome’ on the category, consistent with 

section 502(a) of the Act.” See 70 FR 75323. Thus, in the 

Exemption Rule, we explained that not all of the four factors 

must weigh in favor of exemption for EPA to determine that title 

V is unnecessarily burdensome for a particular area source 

category. Instead, the factors are to be considered in 

combination, and EPA determines whether the factors, taken 

together, support an exemption from title V for a particular 

source category.

In the Exemption Rule, in addition to determining whether 

compliance with title V requirements would be unnecessarily 

burdensome on an area source category, we considered, consistent 

with the guidance provided by the legislative history of CAA 

section 502(a), whether exempting the area source category would 

adversely affect public health, welfare, or the environment. 
77

See 70 FR 15254–15255, March 25, 2005. As explained below, we 

propose that title V permitting is unnecessarily burdensome for 

a majority of the area sources at issue in this proposed rule. 

We have also determined that the proposed exemptions from title

V would not adversely affect public health, welfare, and the 

environment. Our rationale for this decision follows here.

In considering the exemption from title V requirements for 

sources in the categories affected by this proposed rule, we 

first compared the title V monitoring, recordkeeping, and

reporting requirements (factor one) to the requirements in the

proposed NESHAP for the boiler area source categories. This 

proposed rule requires facilities to comply with either emission 

limits using add-on controls or process changes or 

implementation of certain work or management practices. This 

proposed rule would require direct monitoring of emissions or 

control device parameters, both continuous and periodic,

recordkeeping that also may serve as monitoring, and deviation 

and other semi-annual reporting to assure compliance with this 

NESHAP.

The monitoring component of the first factor favors title V 

exemption. For the work and management practices, this proposed 

standard provides monitoring in the form of recordkeeping that 

would assure compliance with the requirements of this proposed 

rule. Monitoring by means other than recordkeeping for the work 
78

and management practices is not practical or appropriate. 

Records are required to ensure that the work and management 

practices are followed. This proposed rule requires continuous 

parameter monitoring, with periodic recording of the parameter 

for the required control device, to assure compliance. The 

records are required to be maintained in a form suitable and 

readily available for expeditious review, and that they are kept 

for at least five years, the first two of which must be onsite.

As part of the first factor, in addition to monitoring, we 

have considered the extent to which title V could potentially

enhance compliance for area sources covered by this proposed 

rule through recordkeeping or reporting requirements. We have 

considered the various title V recordkeeping and reporting 

requirements, including requirements for a 6-month monitoring

report, deviation reports, and an annual certification in 40 CFR 

70.6 and 71.6.

For any boiler area source, this proposed NESHAP requires 

an Initial Notification and a Notification of Compliance Status. 

This proposed rule also requires facilities to certify 

compliance with the emission limits, work practices, and 

management practices. In addition, facilities must maintain 

records showing compliance through the required parameter 

monitoring and deviation requirements. The information required 

in the deviation reports is similar to the information that must 
79

be provided in the deviation reports required under 40 CFR 

70.6(a)(3) and 40 CFR 71.6(a)(3).

We acknowledge that title V might require additional 

compliance requirements on these categories, but we have 

determined that the monitoring, recordkeeping and reporting

requirements of the proposed NESHAP are sufficient to assure 

compliance with the provisions of the NESHAP. Given the nature 

of the operations at most area sources and the types of 

requirements in this rule, title V would not significantly 

improve those compliance requirements.

For the second factor, we determine whether title V 

permitting would impose a significant burden on the area sources 

in the categories and whether that burden would be aggravated by 

any difficulty the source may have in obtaining assistance from 

the permitting agency. Subjecting any source to title V

permitting imposes certain burdens and costs that do not exist 

outside of the title V program. EPA estimated that the average 

cost of obtaining and complying with a title V permit was 

$65,700 per source for a 5-year permit period, including fees. 

See Information Collection Request for Part 70 Operating

Permit Regulations, January 2007, EPA ICR Number 1587.07. EPA 

does not have specific estimates for the burdens and costs of 

permitting industrial, commercial, and institutional boiler area 

sources; however, there are certain activities associated with 
80

the part 70 and 71 rules. These activities are mandatory and

impose burdens on the any facility subject to title V. They 

include reading and understanding permit program guidance and 

regulations; obtaining and understanding permit application 

forms; answering follow-up questions from permitting authorities 

after the application is submitted; reviewing and understanding 

the permit; collecting records; preparing and submitting

monitoring reports on a 6-month or more frequent basis; 

preparing and submitting prompt deviation reports, as defined by 

the State, which may include a combination of written, verbal, 

and other communications methods; collecting information, 

preparing, and submitting the annual compliance certification; 

preparing applications for permit revisions every 5 years; and, 

as needed, preparing and submitting applications for permit 

revisions. In addition, although not required by the permit 

rules, many sources obtain the contractual services of 

consultants to help them understand and meet the permitting 

program’s requirements. The ICR for part 70 provides additional

information on the overall burdens and costs, as well as the 

relative burdens of each activity described here. Also, for a

more comprehensive list of requirements imposed on part 70

sources (hence, burden on sources), see the requirements of 40 

CFR 70.3, 70.5, 70.6, and 70.7.

In assessing the second factor for facilities affected by 
81

this proposal, we found that most of the facilities that would 

be affected by this proposed rule are small entities. These 

small sources lack the technical resources that would be needed 

to comply with permitting requirements and the financial

resources that would be needed to hire the necessary staff or 

outside consultants. As discussed above, title V permitting 

would impose significant costs on these area sources, and,

accordingly, we conclude that title V is a significant burden 

for the sources in these categories that we propose to exempt. 

Furthermore, given the estimated 91,300 area source facilities

(including schools, hospitals, and churches) in the categories, 

it would likely be difficult for them to obtain sufficient 

assistance from the permitting authority. Thus, we conclude 

that factor two supports title V exemption for the sources in 

these categories that we propose to exempt.

The third factor, which is closely related to the second 

factor, is whether the costs of title V permitting for these

area sources would be justified, taking into consideration any 

potential gains in compliance likely to occur for such sources. 

We explained above under the second factor that the costs of

compliance with title V would impose a significant burden on 

many of the approximately 137,000 facilities affected by this

proposed rule. We also concluded in considering the first 

factor that, while title V might impose additional requirements, 
82

the monitoring, recordkeeping and reporting requirements in this

proposed NESHAP assure compliance with the emission standards, 

work practices, and management practices imposed in the NESHAP. 

In addition, below in our consideration of the fourth factor, we 

find that there are adequate implementation and enforcement 

programs in place to assure compliance with the NESHAP. Because 

the costs, both economic and non-economic, of compliance with 

title V are high, and the potential for gains in compliance is 

low, title V permitting is not justified for the sources we 

propose to exempt. Accordingly, the third factor supports title

V exemptions for these area source categories, except as 

discussed below.

The fourth factor we considered in determining if title V 

is unnecessarily burdensome is whether there are implementation 

and enforcement programs in place that are sufficient to assure 

compliance with the NESHAP without relying on title V permits. 

EPA has implemented regulations that provide States the 

opportunity to take delegation of area source NESHAP, and we 

believe that State delegated programs are sufficient to assure 

compliance with this NESHAP. See 40 CFR part 63, subpart E 

(States must have adequate programs to enforce the CAA section 

112 regulations and provide assurances that they will enforce 

the NESHP before EPA will delegate the program).

We also note that EPA retains authority to enforce this 
83

NESHAP anytime under CAA sections 112, 113, and 114. Also, 

States and EPA often conduct voluntary compliance assistance, 

outreach, and education programs (compliance assistance 

programs), which are not required by statute. We determined 

that these additional programs will supplement and enhance the 

success of compliance with these proposed standards. We believe 

that the statutory requirements for implementation and 

enforcement of this NESHAP by the delegated States and EPA and 

the additional assistance programs described above together are 

sufficient to assure compliance with these proposed standards 

without relying on title V permitting.

In light of all the information presented here, we believe 

that there are implementation and enforcement programs in place 

that are sufficient to assure compliance with the proposed 

standards without relying on title V permitting for the sources 

we are proposing to exempt.

Balancing the four factors for these area source categories 

strongly supports the proposed finding that title V is

unnecessarily burdensome for the sources we propose to exempt. 

While title V might add additional compliance requirements if 

imposed, we believe that there would not be significant

improvements to the compliance requirements in this proposed 

rule because the proposed rule requirements are specifically 

designed to assure compliance with the emission standards
84

imposed on the area sources we propose to exempt. We further 

maintain that the economic and non-economic costs of compliance 

with title V would impose a significant burden on the sources we 

propose to exempt. We determined that the high relative costs 

would not be justified given that there is likely to be little 

or no potential gain in compliance if title V were required. 

And, finally, there are adequate implementation and enforcement 

programs in place to assure compliance with these proposed 

standards. Thus, we propose that title V permitting is 

“unnecessarily burdensome” for these area source categories, 

except as discussed below.

In addition to evaluating whether compliance with title V 

requirements is “unnecessarily burdensome”, EPA also considered, 

consistent with guidance provided by the legislative history of

CAA section 502(a), whether exempting these area source 

categories from title V requirements would adversely affect

public health, welfare, or the environment. Exemption of these

area source categories from title V requirements would not 

adversely affect public health, welfare, or the environment 

because the level of control would remain the same if a permit 

were required. The title V permit program does not impose new

substantive air quality control requirements on sources, but 

instead requires that certain procedural measures be followed, 

particularly with respect to determining compliance with
85

applicable requirements. As stated in our consideration of 

factor one for this category, title V would not lead to

significant improvements in the compliance requirements 

applicable to existing or new area sources that we propose to 

exempt.

Furthermore, we explained in the Exemption Rule that 

requiring permits for the large number of area sources could, at 

least in the first few years of implementation, potentially 

adversely affect public health, welfare, or the environment by 

shifting State agencies resources away from assuring compliance 

for major sources with existing permits to issuing new permits 

for these area sources, potentially reducing overall air program 

effectiveness. Based on the above analysis, we conclude that 

title V exemptions for these area sources would not adversely 

affect public health, welfare, or the environment for all of the 

reasons explained above. 

For the reasons stated here, we are proposing to exempt 

these area source categories, except for certain synthetic area 

sources, as explained below, from title V permitting 

requirements.

We have determined that it is not appropriate to exempt

from Title V requirements those synthetic area sources that 

installed air pollution controls. Unlike many other area source 

categories that we have exempted from title V while implementing 
86

the requirements of CAA sections 112(c)(3) and 112(k)(3)(B), the 

boiler area source categories include a number of synthetic area 

sources that installed air pollution controls to become area 

sources. Synthetic area sources that installed controls 

represent less than one percent of the total number of sources 

that will be subject to the final rule. In fact, these sources 

are much more like the major sources of HAP that will be subject 

to the Boiler MACT. In addition, many of these sources are 

located in cities, and often in close proximity to residential 

and commercial centers where large numbers of people live and 

work. The record also indicates that many of these synthetic 

area sources have significantly higher emissions potential when 

uncontrolled than the other sources in the boiler area source 

categories, even those that are synthetic minor sources that 

took operational limits to attain area source status. 

For these reasons, we believe that the additional public 

participation and compliance benefits of additional 

informational, monitoring, reporting, certification, and 

enforcement requirements that exist in title V should be the 

same for a major source that installed a control device after 

1990 to become an area source as for a source that is major and 

installed a control device to comply with an applicable major 

source NESHAP, and thereby reduced emissions below major source 

levels (10 tpy of a single HAP or 25 tpy of total HAP). Many of 
87

the synthetic area sources that became area sources by virtue of 

installing add-on controls are large facilities with 

comprehensive compliance programs in place because their 

uncontrolled emissions would far exceed the major source 

threshold. We maintain that requiring additional public 

involvement and compliance assurance requirements through title 

V is important to ensure that these sources are maintaining 

their emissions at the area source level.

For these reasons above, this proposed rule requires title 

V permits for major sources of HAP emissions that installed 

controls after 1990 to become area sources of HAP emissions. We 

estimate that approximately 170 sources that will be subject to 

this rule are either required to have title V permits because of 

criteria pollutants or the proposed rule will require the

affected area sources to obtain title V permits. 

We are not requiring title V permits for sources that 

reduced their emissions to area source levels by taking 

operational restrictions, such as restricting hours of operation 

or production, or for natural area sources, for the reasons set 

forth above.

VI. Summary of the Impacts of this Proposed Rule

A. What are the air impacts?

Table 2 of this preamble illustrates, for each subcategory, 

the estimated emissions reductions achieved by this proposed 
88

rule (i.e., the difference in emissions between an area source 

boiler controlled to the MACT/GACT level of control and boilers 

at the current baseline) for new and existing sources. 

Nationwide emissions of total HAP (hydrogen chloride, hydrogen 

fluoride, non-mercury metals, mercury, and VOC (for organic HAP) 

will be reduced by about 1,200 tpy for existing units and 340 

tpy for new units. Emissions of mercury will be reduced by 

about 0.7 tpy per year for existing units and by 0.1 tpy for new 

units. Emissions of filterable PM will be reduced by about 

6,300 tpy for existing units and 1,300 tpy for new units. 

Emissions of non-mercury metals (i.e., antimony, arsenic, 

beryllium, cadmium, chromium, cobalt, lead, manganese, nickel, 

and selenium) will be reduced by about 210 tpy for existing 

units and will be reduced by 40 tpy for new units. 

Additionally, EPA has estimated that conducting an annual tuneup could potentially 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 and 

management practices 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 

reductions is presented in “Estimation of Impacts for 
89

Industrial, Commercial, and Institutional Boilers Area Source 

NESHAP” in the docket.

Table 2. Summary of HAP Emissions Reductions for Existing and 

New Sources (tpy)

Source Subcategory PM Non 

Mercury 

Metalsa

Mercury

POMb

Existing 

Units

Coal 5,350 24 0.6 0.2

Biomass 760 10 0.003 5

Oil 230 175 0.03 3

New 

Units

Coal 510 3 0.09 0.02

Biomass 690 8 0.0003 0.5

Oil 100 28 0.005 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 proposed rule 

for existing sources, EPA developed several model boilers and 

determined the cost of control for these model boilers. The EPA 

assigned a model boiler to each existing unit based on the fuel, 

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 
90

that could not otherwise meet the proposed standards. The 

resulting total national cost impact of this proposed rule for 

existing units is $696 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 $1.0 billion. Table 3 of this preamble shows 

the total annualized cost impacts for each subcategory.

Table 3. Summary of Annual Costs for New and 

Existing Sources

Source Subcategory Estimated/

Projected No. of 

Affected Units

Total 

Annualized 

Cost (106$/yr)a

Existing 

Units

Coal 3,710 160

Biomass 10,958 48

Oil 168,003 436

Facility 

Energy

Audit

All 52

New 

Unitsb

Coal 155 54

Biomass 200 13

Oil 6,424 244 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 DOE 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 
91

national cost impact of this proposed rule on new sources by the 

3rd year, 2013, is $311 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 $260 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 

affected. 

 Social costs are estimated to also be $0.5 billion in 2008 

dollars. This is estimated to made up of a $0.3 billion loss in 

domestic consumer surplus, a $0.3 billion loss in domestic 

producer surplus, a $0.1 billion increase in rest of the world 

surplus, and a $0.1 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.
92

 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 than 3 percent for small entities included in 

the screening analysis. EPA has prepared an Initial Regulatory 

Flexibility Analysis (IRFA) that discusses alternative 

regulatory or policy options that minimize the rule’s small 

entity impacts. It includes key information about key results 

from the Small Business Advocacy Review (SBAR) panel.

Precise job effect estimates cannot be estimated with 

certainty. Morgenstern et al. (2002) identify three economic 

mechanisms by which pollution abatement activities can 

indirectly influence jobs:

 higher production costs raise market prices, higher 

prices reduce consumption, and employment within an 

industry falls (“demand effect”); 

 pollution abatement activities require additional labor 

services to produce the same level of output (“cost 

effect”); and 

 post regulation production technologies may be more or 

less labor intensive (i.e., more/less labor is required 

per dollar of output) (“factor-shift effect”).

Several empirical studies, including Morgenstern et al. 

(2002), suggest the net employment decline is zero or 
93

economically small (e.g., Cole and Elliot, 2007; Berman and Bui, 

2001). However, others show the question has not been resolved 

in the literature (Henderson, 1996; Greenstone, 2002). 

Morgenstern’s paper uses a six-year panel (U.S. Census data for 

plant-level prices, inputs (including labor), outputs, and 

environmental expenditures) to econometrically estimate the 

production technologies and industry-level demand elasticities. 

Their identification strategy leverages repeat plant-level 

observations over time and uses plant-level and year fixed 

effects (e.g., plant and time dummy variables). After 

estimating their model, Morgenstern show and compute the change 

in employment associated with an additional $1 million ($1987) 

in environmental spending. Their estimates covers four 

manufacturing industries (pulp and paper, plastics, petroleum, 

and steel) and Morgenstern, et al. present results separately 

for the cost, factor shift, and demand effects, as well as the 

net effect. They also estimate and report an industry-wide 

average parameter that combines the four industry-wide estimates 

and weighting them by each industry’s share of environmental 

expenditures. 

EPA has most often estimated employment changes associated 

with plant closures due to environmental regulation or changes 

in output for the regulated industry (EPA, 1999a; EPA, 2000). 

This analysis goes beyond what EPA has typically done in two 
94

ways. First, because the multimarket model provides estimates 

for changes in output for sectors not directly regulated, we 

were able to estimate a more comprehensive “demand effect.” 

Secondly, parameters estimated in the Morgenstern paper were 

used to estimate all three effects (“demand,” “cost,” and 

“factor shift”). This transfer of results from the Morgenstern 

study is uncertain but avoids ignoring the “cost effect” and the 

“factor-shift effect.” 

We calculated “demand effect” employment changes by 

assuming that the number of jobs changes proportionally with 

multi-market model’s simulated output changes. These results 

were calculated for all sectors in the EPA model that show a 

change in output. The total job losses are estimated to be 

approximately 1,000.

We also calculated a similar “demand effect” estimate that 

used the Morgenstern paper. 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 compliance expenditures used in the partial 

equilibrium model. For example, the job loss estimate is 

approximately 1,000 jobs (−3.56× $0.5 billion × 0.60)1

 

1 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) 

. 
95

We also present the results of using the Morgenstern paper 

to estimate employment “cost” and “factor-shift” effects (Table 

1). Although using the Morgenstern 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 1 

shows that using the Morgenstern point estimates of parameters 

to estimate the “cost” and “factor shift” employment gains may 

be greater than the employment losses using either of the two 

ways of estimating “demand” employment losses. The 95 percent

confidence intervals are shown for all of the estimates based on 

the Morgenstern parameters. As shown, at the 95 percent

confidence level, we cannot be certain if net employment changes 

are positive or negative. 

Although the Morgenstern paper provides additional 

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 (pulp and paper, plastics, petroleum, 

and steel). Absent other data and estimates, this approach 

seems reasonable and the estimates come from a respected peerreviewed source. However, EPA acknowledges the proposed rule 

covers a broader set of industries not considered in original 
96

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 still applicable 

for policy taking place in 2013, almost 20 years later. Second, 

the multi-market model only considers near term employment 

effects in a U.S. economy where production technologies are 

fixed. As a result, the modeling system places more emphasis on 

the short term “demand effect” whereas the Morgenstern paper 

emphasizes other important long term responses. For example, 

positive job gains associated with “factor shift effects” are 

more plausible when production choices become more flexible over 

time and industries can substitute labor for other production 

inputs. Third, the Morgenstern paper estimates rely on sector 

demand elasticities that are different from the demand 

elasticity parameters used in the multi-market model. As a 

result, the demand effects are not directly comparable with the 

demand effects estimated by the multi-market model. Fourth, 

Morgenstern 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 has reported the 95 

percent confidence intervals in Table 1. Fifth, Morgenstern’s 

methodology assumes large plants bear most of the regulatory 
97

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 on smaller 

plants.

Table 4. Employment Changes: 2013

Estimation Method 1,000 Jobs

Partial equilibrium model (multiple markets) 

(demand effect only) −1

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 +2)

C. Literature-based estimate: Factor 

shift effect

+1

(0 to +2)

Note: Totals may not add due to independent rounding. 95 

percent confidence intervals for literature-based estimates are 

shown in parenthesis.

D. 

We estimated the monetized benefits of this proposed 

regulatory action to be $1.0 billion to $2.4 billion (2008$, 3 

percent discount rate) in the implementation year (2013). The 

monetized benefits of this proposed regulatory action at a 7 

percent discount rate are $910 million to $2.2 billion (2008$). 

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 

What are the social costs and benefits of this proposed 

rule?
98

fall between these two estimates.1

Table 5. Summary of the Monetized Benefits, Social Costs, and 

Net Benefits for the Boiler Area Source Rule in 2013 (billions 

of 2008$)1

 A summary of the monetized 

benefits estimates at discount rates of 3 percent and 7 percent 

is in Table 5 of this preamble. 

3% Discount Rate 7% Discount Rate

Proposed Option

Total Monetized 

Benefits2 $1.0 to $2.4 $0.91 to $2.2

Total Social Costs3 $0.50 $0.5

Net Benefits $0.5 to $1.9 $0.4 to $1.7

Non-monetized Benefits

39,000 tons of carbon monoxide

130 tons of HCl

5 tons of HF

0.75 tons of mercury 

250 tons of other metals

470 grams of dioxins/furans 

Health effects from NO2 and SO2

exposure

Ecosystem effects 

Visibility impairment 

1

All estimates are for the implementation year (2015), and are 

rounded to two significant figures. 

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 NOx and SO2. It 

is important to note that the monetized benefits include many 

but not all health effects associated with PM2.5 exposure. 

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.

These benefits estimates represent the total monetized 

 

1 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.
99

human health benefits for populations exposed to less PM2.5 in 

2013 from controls installed to reduce air pollutants in order 

to meet these standards. These estimates are calculated as the 

sum of the monetized value of avoided premature mortality and 

morbidity associated with reducing a ton of PM2.5 and PM2.5

precursor emissions. To estimate of human health benefits 

derived from reducing PM2.5 and PM2.5 precursor emissions, we 

utilized the general approach and methodology on the laid out in 

Fann et al. (2009)1

To generate the benefit-per-ton estimates, we used a model 

to convert emissions of direct PM2.5 and PM2.5 precursors into 

changes in ambient PM2.5 levels and another model to estimate the 

changes in human health associated with that change in air 

quality. Finally, the monetized health benefits were divided by 

the emission reductions to create the benefit-per-ton estimates. 

Even though we assume that all fine particles have equivalent 

health effects, the benefit-per-ton estimates vary between 

precursors because each ton of precursor reduced has a different 

propensity to form PM2.5. For example, SOX has a lower benefitper-ton estimate than direct PM2.5 because it does not form as 

much PM2.5, thus the exposure would be lower, and the monetized 

health benefits would be lower. 

. 

 

1 Fann, N., C.M. Fulcher, B.J. Hubbell. 2009. “The influence of location, 

source, and emission type in estimates of the human health benefits of 

reducing a ton of air pollution.” Air Qual Atmos Health (2009) 2:169–176.
100

For context, it is important to note that the magnitude of 

the PM benefits is largely driven by the concentration response 

function for premature mortality. Experts have advised EPA to 

consider a variety of assumptions, including estimates based 

both on empirical (epidemiological) studies and judgments 

elicited from scientific experts, to characterize the 

uncertainty in the relationship between PM2.5 concentrations and 

premature mortality. For this proposed rule we cite two key 

empirical studies, one based on the American Cancer Society 

cohort study1 and the extended Six Cities cohort study2

This analysis does not include the type of detailed 

uncertainty assessment found in the 2006 PM2.5 NAAQS RIA because 

we lack the necessary air quality input and monitoring data to 

run the benefits model. However, the 2006 PM2.5 NAAQS benefits 

analysis

. In the 

RIA for this proposed rule, which is available in the docket, we 

also include benefits estimates derived from expert judgments 

and other assumptions.

3

 

1 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

provides an indication of the sensitivity of our 

results to various assumptions. 

2 Laden et al, 2006. “Reduction in Fine Particulate Air 

Pollution and Mortality.” American Journal of Respiratory and 

Critical Care Medicine. 173: 667-672 3 U.S. Environmental Protection Agency, 2006. Final Regulatory Impact 

Analysis: PM2.5 NAAQS. Prepared by Office of Air and Radiation. October. 

Available on the Internet at http://www.epa.gov/ttn/ecas/ria.html
101

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 carbon monoxide and hazardous air 

pollutants have not been monetized in this analysis, including 

reducing 39,000 tons of carbon monoxide, 0.75 ton of mercury, 

and 130 tons of HCl, 5 tons of HF, and 460 grams of 

dioxins/furans each year. Although we do not have sufficient 

information or modeling available to provide monetized estimates 

for this rulemaking, we include a qualitative assessment of the 

health effects of these air pollutants in the Regulatory Impact 

Analysis (RIA) for this proposed rule, which is available in the 

docket.

The social costs of this proposed rulemaking are estimated 

to be $0.5 billion (2008$) in the implementation year, and the 

monetized benefits are $1.0 billion to $2.4 billion (2008$, 3 

percent discount rate) for that same year. The benefits at a 7 

percent discount rate are $910 million to $2.2 billion (2008$). 

Thus, net benefits of this rulemaking are estimated at $500 

million to $1.9 billion (2008$, 3 percent discount rate) and 

$400 million to $1.7 billion (2008$, 7 percent discount rate). 

A summary of the monetized benefits, social costs, and net 

benefits at discount rates of 3 percent and 7 percent is in 
102

Table 6 of this preamble. 

Table 6. Summary of the Monetized Benefits, Social Costs, and 

Net Benefits for the Boiler Area Source Rule in 2013 (millions 

of 2008$)1

Proposed Option

3% Discount Rate 7% Discount Rate

Total Monetized 

Benefits $1,000 to $2,4002 $910 to $2,2002

Total Social 

Costs $5003 $500

Net Benefits $500 to $1,900 $400 to $1,700

1

All estimates are for the implementation year (2013), and are 

rounded to two significant figures. 

2 The total monetized benefits reflect the human health benefits 

associated with reducing exposure to PM2.5 through reductions of 

29,000 tons of directly emitted PM2.5 and PM2.5 precursors such as 

1,700 tons of VOC and 360,000 tons of SO2. The monetized 

benefits from reducing 330,000 tons of carbon monoxide, 42,000 

tons of hydrochloric acid, 1,200 tons of HF, and 7.9 tons of 

mercury, and 730 grams of dioxins/furans each year are not 

included in these estimates. In addition, the monetized 

benefits from reducing ecosystem effects and visibility 

impairment are not included. 

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.

For more information on the benefits analysis, please refer 

to the RIA for this rulemaking, which is available in the 

docket.

E. What are the water and solid waste impacts?

The 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 proposed rule do not require any 

water to operate, nor do they generate any wastewater.
103

The EPA estimated the additional solid waste that would 

result from this proposed rule to be 14,300 tpy for existing

sources due to the dust and flyash captured by mercury and PM 

control devices. The cost of handling the additional solid 

waste generated from existing sources is $602,000 per year. For 

new sources installed by 2013, the EPA estimated the additional 

solid waste that would result from this proposed rule to be 

1,800 tpy for new sources due to the dust and flyash captured by 

mercury and PM control devices. The cost of handling the 

additional solid waste generated from existing sources is 

$75,900 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?

The EPA expects an increase of approximately 206 million 

kilowatt hours (kWh) in national annual energy usage from 

existing sources as a result of this proposed rule. The 

increase results from the electricity required to operate 

control devices installed to meet this proposed rule, such as 

fabric filters. Additionally, for new sources installed by 2013,

EPA expects an increase of approximately 22 million kWh in 

national annual energy usage in order to operate the control 
104

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 tune-ups 

and combustion controls such as new replacement burners and will 

improve the efficiency of boilers. The 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 estimates 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 Proposed 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 
105

Combustion,” “Commercial Oil Combustion,” and “Commercial 

Wood/Wood Residue Combustion” as source categories that emits 

two of the seven CAA Section 112(c)(6) pollutants: POM and 

mercury. (The POM emitted is composed of 16 polyaromatic

hydrocarbons (PAH) and extractable organic matter (EOM).) 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 category “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 byproducts of combustion, the formation of 

POM is effectively reduced by the combustion and post-combustion

practices required to comply with the CAA Section 112 standards. 

Any POM that do form during combustion are 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 proposed MACT regulations for area source boilers will
106

reduce Hg emissions by about 86 percent. It is, therefore, 

reasonable to conclude that POM emissions will be substantially 

controlled. Thus, while this proposed rule does not identify 

specific numerical emission limits for POM, emissions of POM

are, for the reasons noted below, nonetheless “subject to 

regulation” for purposes of CAA section 112(c)(6).

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 propose numerical emissions limits for POM 

with respect to boilers to satisfy CAA Section 112(c)(6).

To further address POM and mercury emissions, this proposed

rule also includes an energy assessment provision that encourage 

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 Executive Order 12866 (58 FR 51735, October 4, 1993), 

this action is an “economically significant regulatory action” 
107

because it is likely to have an annual effect on the economy of 

$100 million or more or adversely affect in a material way the 

economy, a sector of the economy, productivity, competition, 

jobs, the environment, public health or safety, or State, local, 

or tribal governments or communities.

Accordingly, EPA submitted this action to the Office of 

Management and Budget (OMB) for review under EO 12866 and any 

changes in response to OMB recommendations have been documented 

in the docket for this action.

B. Paperwork Reduction Act

The information collection requirements in this proposed 

rule have been submitted for approval to OMB under the Paperwork 

Reduction Act, 44 U.S.C. 3501 et seq. The Information 

Collection Request (ICR) document prepared by EPA has been 

assigned EPA ICR number 2253.01. 

The recordkeeping and reporting requirements in this

proposed rule would be 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 section 114 of the 

CAA (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 
108

implementing regulations at 40 CFR part 2, subpart B.

This proposed NESHAP would require applicable one-time 

notifications according to the NESHAP General Provisions. 

Facility owners or operators would be required to include 

compliance certifications for the work practices and management 

practices in their Notifications of Compliance Status. 

Recordkeeping would be required to demonstrate compliance with

emission limits, work practices, management practices, 

monitoring, and applicability provisions. New affected 

facilities would be required to comply with the requirements for 

startup, shutdown, and malfunction plans/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 $933 

million. This includes 6.8 million labor hours per year at a 

cost of $660 million and total non-labor capital costs of $273 

million per year. This estimate includes initial and annual 

performance test, conducting an documenting an energy audit, 

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 audit costs were also included in the cost estimates 
109

presented in the control costs impacts estimates in section IV.D 

of this preamble. The total burden for the Federal government 

(averaged over the first 3 years after the effective date of the 

standard) is estimated to be 916,912 hours per year at a total 

labor cost of $46.2 million per year.

Burden means the total time, effort, or financial resources 

expended by persons to generate, maintain, retain, or disclose 

or provide information to or for a Federal agency. This 

includes the time needed to review instructions; develop, 

acquire, install, and utilize technology and systems for the 

purposes of collecting, validating, and verifying information, 

processing and maintaining information, and disclosing and 

providing information; adjust the existing ways to comply with 

any previously applicable instructions and requirements; train 

personnel to be able to respond to a collection of information; 

search data sources; complete and review the collection of 

information; and transmit or otherwise disclose the information.

An agency may not conduct or sponsor, and a person is not 

required to respond to, a collection of information unless 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.

To comment on EPA’s need for this information, the accuracy 

of the provided burden estimates, and any suggested methods for 
110

minimizing respondent burden, including the use of automated 

collection techniques, EPA has established a public docket for 

this action, which includes this ICR, under Docket ID number 

EPA-HQ-OAR-2006-0790. Submit any comments related to the ICR to 

EPA and OMB. See ADDRESSES section at the beginning of this 

preamble for where to submit comments to EPA. Send comments to 

OMB at the Office of Information and Regulatory Affairs, Office 

of Management and Budget, 725 17th Street, NW, Washington, DC 

20503, Attention: Desk Office for EPA. Since OMB is required 

to make a decision concerning the ICR between 30 and 60 days 

after [INSERT DATE OF PUBLICATION IN THE FEDERAL REGISTER], a 

comment to OMB is best assured of having its full effect if OMB 

receives it by [INSERT DATE 30 DAYS FROM DATE OF PUBLICATION IN 

THE FEDERAL REGISTER]. The final rule will respond to any OMB 

or public comments on the information collection requirements 

contained in this proposal.

C. Regulatory Flexibility Act (RFA)

The RFA generally requires an agency to prepare a 

regulatory flexibility analysis of any rule subject to notice 

and comment rulemaking requirements under the Administrative 

Procedure Act or any other statute unless the agency certifies 

that the rule will not have a significant economic impact on a 

substantial number of small entities. Small entities include 

small businesses, small organizations, and small governmental 
111

jurisdictions.

For purposes of assessing the impacts of today’s proposed 

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 40 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. 

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 rule.

(1) Panel Process and Panel Outreach

As required by section 609(b) of the RFA, as amended by 
112

SBREFA, EPA also has conducted outreach to small entities and. 

On January 22, 2009 EPA’s Small Business Advocacy Chairperson 

convened a Panel under section 609(b) of the RFA. In addition 

to the Chair, the Panel consisted of the Director of the Sector 

Policies and Programs Division within EPA’s Office of Air and 

Radiation, the Chief Counsel for Advocacy of the Small Business

Administration, and the Administrator of the Office of 

Information and Regulatory Affairs within the Office of

Management and Budget.

As part of the SBAR Panel process we conducted outreach 

with representatives from 14 various small entities that would 

be affected by this rule. The small entity representatives 

(SERs) included associations representing schools, churches, 

hotels/motels, wood product facilities and manufacturers of home 

furnishings. We met with these SERs to discuss the potential 

rulemaking approaches and potential options to decrease the 

impact of the rulemaking on their industries/sectors. We 

distributed outreach materials to the SERs; these materials 

included background on the rulemaking, possible regulatory

approaches, preliminary cost and economic impacts, and possible 

rulemaking alternatives. The Panel met with SERs from the 

industries that will be impacted directly by this rule on

February 10, 2009 to discuss the outreach materials and receive 

feedback on the approaches and alternatives detailed in the 
113

outreach packet. (EPA also met with SERs on November 13, 2008

for an initial outreach meeting.) The Panel received written 

comments from the SERs following the meeting in response to 

discussions at the meeting and the questions posed to the SERs 

by the Agency. The SERs were specifically asked to provide 

comment on regulatory alternatives that could help to minimize

the rule’s impact on small businesses.

(2) Panel Recommendations for Small Business Flexibilities

The Panel recommended that EPA consider and seek comment on 

a wide range of regulatory alternatives to mitigate the impacts 

of the rulemaking on small businesses, including those

flexibility options described below. The following section 

summarizes the SBAR Panel recommendations. EPA has proposed 

provisions consistent with each of the Panel’s recommendations

regarding area source facilities.

Consistent with the RFA/SBREFA requirements, the Panel 

evaluated the assembled materials and small-entity comments on 

issues related to elements of the IRFA. A copy of the Final 

Panel Report (including all comments received from SERs in 

response to the Panel’s outreach meeting as well as summaries of 

both outreach meetings that were held with the SERs is included 

in the docket for this proposed rule. A summary of the Panel 

recommendations is detailed below. As noted above, this 

proposal includes proposed provisions for each of the Panel 
114

recommendations regarding area source facilities.

(a) Work Practice Standards

The panel recommended that EPA consider requiring annual 

tune-ups, including standardized criteria outlining proper tuneup methods targeted at smaller boiler operators. The panel 

further recommended that EPA take comment on the efficacy of 

energy assessments/audits at improving combustion efficiency and 

the cost of performing the audits, especially to smaller boiler 

operators.

A work practice standard, instead of MACT emission limits, 

may be proposed if it can be justified under CAA section 112(h), 

that is, it is impracticable to enforce the emission standards 

due to technical and economic limitations. Work practice 

standards could reduce fuel use and improve combustion 

efficiency which would result in reduced emissions.

In general, SERs commented that a regulatory approach to 

improve combustion efficiency, such as work practice standards, 

would have positive impacts with respect to the environment and 

energy use and save on compliance costs. The SERs were 

concerned with work practice standards that would require energy 

audits and implementation of audit findings. The basis of these 

concerns rested upon the uncertainty that there is no guarantee 

that there are available funds to implement a particular audit’s 

findings.
115

(b) Subcategorization

The Panel recommended that EPA allow subcategorizations 

suggested by the SERs, unless EPA finds that a subcategorization 

is inconsistent with the Clean Air Act. 

SERs commented that subcategorization is a key concept that 

could ensure that like boilers are compared with similar boilers 

so that MACT floors are more reasonable and could be achieved by 

all units within a subcategory using appropriate emission 

reduction strategies. SERs commented that EPA should 

subcategorize based on fuel type, boiler type, duty cycle, and 

location. 

(c) Compliance Costs

The Panel recommended that EPA carefully weigh the 

potential burden of compliance requirements and consider for 

small entities options such as, emission averaging within 

facility, reduced monitoring/testing requirements, or allowing 

more time for compliance. 

SERs noted that recordkeeping activities, as written in the 

vacated boiler MACT, would be especially challenging for small 

entities that do not have a dedicated environmental affairs 

department. 

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 Federal 
116

agencies to assess the effects of their regulatory actions on 

State, local, and tribal governments and the private sector. 

Under section 202 of the UMRA, we generally must prepare a 

written statement, including a cost-benefit analysis, for 

proposed and final rules with “Federal mandates” that may result 

in expenditures to State, local, and tribal governments, in the 

aggregate, or to the private sector, of $100 million or more in 

any 1 year. Before promulgating a rule for which a written 

statement is needed, 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 the 

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 the final rule an explanation why 

that alternative was not adopted. Before we establish any 

regulatory requirements that may significantly or uniquely 

affect small governments, including tribal governments, we must 

develop a small government agency plan under 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 
117

development of regulatory proposals with significant Federal 

intergovernmental mandates, and informing, educating, and 

advising small governments on compliance with the regulatory 

requirements.

We have determined that this proposed rule contains a 

Federal mandate that may result in expenditures of $100 million 

or more for State, local, and Tribal governments, in the 

aggregate, or the private sector in any 1 year. Accordingly, we 

have prepared a written statement entitled “Unfunded Mandates 

Reform Act Analysis for the Proposed Industrial Boilers and 

Process Heaters 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 proposed rulemaking is section 112 of the 

CAA. Title III of the CAA Amendments 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 
118

of emissions from area sources, pose the greatest threat to 

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 

that source categories accounting for emissions of the HAP 
119

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 

reductions. Regulation of biomass and oil-fired boilers for 

mercury would be substantially less cost-effective for mercury 

reduction and would impose substantial technical barriers for 

and economic barriers to numerous small businesses. 

Consequently, we deem it reasonable to propose to regulate the 

coal-fired boilers under MACT, rather than the biomass and oilfired boilers, to obtain additional mercury reductions towards 

achieving the CAA section 112(c)(6) obligation. We propose to 

regulate biomass-fired and oil-fired boilers under GACT. 

This proposed NESHAP would 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 
120

number of regulatory alternatives. Additional information on 

the costs and environmental impacts of these regulatory 

alternatives is presented in the docket.

The regulatory alternative upon which the proposed 

standards are based represents the MACT floor for the listed CAA 

section 112(c)(6) pollutants (mercury and POM) and GACT for the 

other urban HAP which formed the basis for the listing of these 

two area source categories. The proposed standards would 

require new coal-fired boilers to meet MACT-based emission 

limits for mercury and CO (as a surrogate for POM) and GACTbased emission limits for PM (as a surrogate for urban metals). 

New biomass and oil-fired boilers would be required to meet 

MACT-based CO emission limits and GACT-based emission limits for 

PM. The emission limits for existing area source boilers are 

only applicable to area source boilers that have a designed heat 

input capacity of 10 million Btu per hour or greater. Existing 

large coal-fired boilers would be required to meet MACT-based 

emission limits for mercury and CO, and existing large biomass 

and oil-fired boilers would be subject to MACT-based CO emission 

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

standard requiring the implementation of a tune-up program is 

being proposed for existing area source boilers with a designed 

heat input capacity of less than 10 million Btu per hour. An 

additional “beyond-the-floor” standard is being proposed for 
121

existing area source facilities having an affected boiler with a 

heat input capacity of 10 million Btu per hour 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 the proposed 

rule including the Agency’s assessment of costs and benefits, is 

detailed in the “Regulatory Impact Analysis for the Proposed 

Industrial Boilers and Process Heaters MACT” in the docket. 

Based on estimated compliance costs associated with the proposed 

rule and the predicted change in prices and production in the 

affected industries, the estimated social costs of the proposed 

rule are $0.5 billion (2008 dollars).

 It is estimated that 3 years after implementation of the 

proposed rule, HAP would 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 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 would occur, including 

2,700 tons of PM2.5 and 1,500 tons of SO2. These reductions occur 
122

within 3 years after the implementation of the proposed 

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

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 the proposed 

alternative range from $1.0 billion (2008 dollars) to $2.4 

billion (2008 dollars) when using a 3 percent discount rate (or 

from $0.9 billion (2008 dollars)to $2.2 billion (2008 dollars) 

when using a 7 percent discount rate. The general approach used 

to value benefits is discussed in more detail earlier in this 

preamble. For more detailed information on the benefits 

estimated for the proposed rulemaking, refer to the RIA in the 

docket.
123

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 the proposed rule and any 

disproportionate budgetary effects. Our estimates of the future 

compliance costs of the proposed rule are discussed previously 

in this preamble.

We do not believe that there will be any disproportionate 

budgetary effects of the proposed rule on any particular areas 

of the country, State 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 previously in this preamble.

4. Effects on the National Economy

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 the proposed rule is 

presented in the “Economic Impact Analysis for the Industrial 
124

Boilers and Process Heaters MACT” in the docket. This analysis 

provides estimates of the effect of the proposed rule on some of 

the categories mentioned above. The results of the economic 

impact analysis are summarized previously in this preamble. The 

results show that there will be a small impact on prices and 

output (less than 0.02 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 

State, local, and tribal officials, summarize the 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 

proposed rule. EPA invited the following 10 national 

organizations representing State and local elected officials to 

a meeting held on March 24, 2010 in Washington DC: (1) National 

Governors Association; (2) National Conference of State 
125

Legislatures, (3) Council of State Governments, (4) National 

League of Cities, (5) U.S. Conference of Mayors, (6) National 

Association of Counties, (7) International City/County 

Management Association, (8) National Association of Towns and 

Townships, (9) County Executives of America, and (10) 

Environmental Council of States. These 10 organizations of 

elected State and local officials have been identified by EPA as 

the “Big 10” organizations appropriate to contact for purpose of 

consultation with elected officials. The purposes of the 

consultation were to provide general background on the proposal, 

answer questions, and solicit input from State/local 

governments. During the meeting, officials expressed 

uncertainty with regard to how boilers owned/operated by State 

and local entities would be impacted, as well as with regard to 

the potential burden associated with implementing the rule on 

State and local entities. 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 States for 

which we have an inventory, (3) information on potential size of 

boilers used for various facility types and sizes. EPA has not 

received additional questions or requests from State or local 

officials.

Consistent with section 205, EPA has identified and 

considered a reasonable number of regulatory alternatives. 
126

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 the 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 audit. The regulatory alternative selected 

is a combination of the options considered and includes proposed 

provisions regarding each of the SBAR Panel’s recommendations

for area source boilers. The recommendations regard 

subcategorization, work practice standards, and compliance costs 

(see section VIII.C. of this preamble for more detail).

EPA determined subcategorization 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, the proposal 

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 regulatory alternative upon which the proposed 

standards are based represents the MACT floor for mercury for 

coal-fired boilers, the MACT floor for POM (CO is used as a 
127

surrogate for POM) for coal, biomass, and oil-fired boilers, and 

GACT for the other urban HAP (PM is used as a surrogate for 

urban HAP metals) for coal, biomass, and oil-fired boilers. The 

emission limits for existing area source boilers are only 

applicable to area source boilers that have a designed heat 

input capacity of 10 million Btu per hour 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 

proposed for existing area source boilers with a designed heat 

input capacity of less than 10 million Btu per hour. An 

additional “beyond-the-floor” standard is being proposed for 

existing area source facilities having an affected boiler with a 

heat input capacity of 10 million Btu per hour or greater that 

requires the performance of an energy assessment on the boiler 

and the facility to identify cost-effective energy conservation 

measures.

The proposed use of surrogate pollutants would result in

reduced compliance costs because testing would only be required 

for the surrogate pollutants (i.e., CO and PM) versus for the 

HAP (i.e., POM and metals). The proposed work practice 

standard/management practice also would result in reduced 

compliance costs with respect to monitoring/testing for the 
128

smaller existing area source boilers. EPA’s proposed exemption 

of area source facilities from title V permit requirements also 

would reduce burden on area source boiler facilities.

This proposed rule is not subject to the requirements of 

section 203 of UMRA because it contains no regulatory 

requirements that might significantly or uniquely affect small 

governments. While some small governments may have boilers that 

would be affected by the proposed rule, EPA’s analysis shows 

that other public facilities that are located at area source 

facilities owned by small entities would have cost-to-revenue 

ratios exceeding 10 percent. Hospitals’and schools’ revenue 

tests fall below 1 percent. Because the proposed rule’s 

requirements apply equally to boilers owned and/or operated by 

governments and to boilers owned and/or operated by private 

entities, there would 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 Federal government provides the funds necessary to 

pay the direct compliance costs incurred by State and local 

governments, or EPA consults with State and local officials 

early in the process of developing the proposed action. 
129

EPA has concluded that this action may have federalism 

implications, because it may impose substantial direct 

compliance costs on State or local governments, and the Federal 

government will not provide the funds necessary to pay those 

costs. Accordingly, EPA provides the following federalism 

summary impact statement as required by section 6(b) of 

Executive Order 13132.

Based on the estimates in EPA’s RIA for today’s action, the 

proposed regulatory option, if promulgated, may have federalism 

implications because the option may impose approximately $416

million in annual direct compliance costs on an estimated 57,000

State 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 State or local governments. 

Because the inventories for these sectors include privately 

owned and Federal government owned facilities, the estimate may 

include many facilities that are not State or local government 

owned. Table 5 of this preamble presents estimates of the 

number of potentially impacted State 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 
130

presented. Small boilers (boilers with heat input capacity of 

less than 10 million Btu per hour) would be subject to a work 

practice standard that requires a boiler tune-up every 2 years. 

Large coal-fired boilers (boilers with heat input capacity of 10 

million Btu per hour or greater) would be subject to emission 

limits for Hg and CO, while large biomass and oil-fired boilers 

would be subject to emission limits for CO. All facilities with 

large boilers would be required to conduct a one-time energy 

assessment.

Table 7. State and local governments potentially impacted by 

the proposed 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 $143 million

Educational 

Services 34,052 33,303 749 $200 million

GovernmentOwned 

Buildings

5,796 5,098 698 $73 million

Total 57,054 53,694 3,360 $416 million

EPA consulted with State and local officials in the process 

of developing the proposed action to permit them to have 

meaningful and timely input into its development. EPA met with 

10 national organizations representing State and local elected 

officials to provide general background on the proposal, answer 

questions, and solicit input from State/local governments. The 
131

UMRA discussion in this preamble includes a description of the 

consultation.

In the spirit of Executive Order 13132, and consistent with 

EPA policy to promote communications between EPA and State and 

local governments, EPA specifically solicits comment on this 

proposed action from State and local officials.

F. Executive Order 13175: Consultation and Coordination with 

Indian Tribal Governments

Executive Order 13175 (65 FR 67249, November 9, 2000), 

requires EPA to develop an accountable process to ensure 

“meaningful and timely input by tribal officials in the 

development of regulatory policies that have tribal 

implications.” The proposed rule does not have tribal 

implications, as specified in Executive Order 13175 (65 FR 

67249, November 9, 2000). It will not have substantial direct 

effects on tribal governments, on the relationship between the 

Federal government and Indian tribes, or on the distribution of 

power and responsibilities between the Federal government and 

Indian tribes, as specified in Executive Order 13175. The 

proposed 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 the proposed rule on communities of 
132

tribal governments would not be unique or disproportionate to 

the effect on other communities. Thus, Executive Order 13175 

does not apply to the proposed rule. EPA specifically solicits 

additional comment on the proposed rule from tribal officials.

G. Executive Order 13045: Protection of Children from 

Environmental Health Risks and Safety Risks

Executive Order 13045 (62 FR 19885, April 23, 1997) applies 

to any rule that: (1) is determined to be “economically 

significant” as defined under Executive Order 12866, and (2) 

concerns an environmental health or safety risk that EPA has

reason to believe may have a disproportionate effect on 

children. If the regulatory action meets both criteria, the 

Agency must evaluate the environmental health or safety effects 

of the planned rule on children, and explain why the planned 

regulation is preferable to other potentially effective and 

reasonably feasible alternatives considered by the Agency.

The proposed rule 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. The reason for this 

determination is that the proposed rule is based solely on 

technology performance.

The public is invited to submit comments or identify peerreviewed studies and data that assess effects of early life 
133

exposure to the proposed rule. 

H. Executive Order 13211: Actions Concerning Regulations That 

Significantly Affect Energy Supply, Distribution, or Use

Executive Order 13211, (66 FR 28355, May 22, 2001), 

provides that agencies shall prepare and submit to the 

Administrator of the Office of Information and Regulatory 

Affairs, Office of Management and Budget, a Statement of Energy 

Effects for certain actions identified as significant energy 

actions. Section 4(b) of Executive Order 13211 defines 

“significant energy actions” as “any action by an agency 

(normally published in the Federal Register) that promulgates or 

is expected to lead to the promulgation of a final rule or 

regulation, including notices of inquiry, advance notices of 

proposed rulemaking, and notices of proposed rulemaking: (1)(i) 

that is a significant regulatory action under Executive Order 

12866 or any successor order, and (ii) is likely to have a 

significant adverse effect on the supply, distribution, or use 

of energy; or (2) that is designated by the Administrator of the 

Office of Information and Regulatory Affairs as a significant 

energy action.” The proposed rule is not a “significant 

regulatory action” because it is not likely to have a 

significant adverse effect on the supply, distribution, or use 

of energy. The basis for the determination is as follows.

We estimate no significant changes for the energy sector 
134

for price, production, or imports. For more information on the 

estimated energy effects, please refer to the economic impact 

analysis for the proposed rule. The analysis is available in 

the public docket. 

Therefore, we conclude that the proposed rule when 

implemented is not likely to have a significant adverse effect 

on the supply, distribution, or use of energy. 

I. National Technology Transfer and Advancement Act

Section 12(d) of the National Technology Transfer and 

Advancement Act (NTTAA) of 1995 (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 

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.

The proposed rule involves technical standards. The EPA 

cites the following standards in the proposed 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 for Testing and Materials (ASTM) 

D6522-00, American Society of Mechanical Engineers (ASME) PTC 19 
135

(manual methods only), ASTM D6784-02, ASTM D2234-D2234M-03, 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 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. The EPA determined that 

these 16 standards identified for measuring emissions of the HAP 

or surrogates subject to emission standards in this rule were 

impractical alternatives to EPA test methods for the purposes of 

this rule. Therefore, EPA does not intend to 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 proposed rule lists the 

testing methods included in the regulation. Under §63.7(f) and 

§63.8(f) of Subpart A 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.

EPA welcomes comments on this aspect of the proposed 

rulemaking and, specifically, invites the public to identify 
136

potentially-applicable voluntary consensus standards and to 

explain why such standards should be used in this regulation.

J. Executive Order 12898: Federal Actions to Address 

Environmental Justice in Minority Populations and Low-Income 

Populations

Executive Order 12898 (59 FR 7629, February 16, 1994) 

establishes Federal executive policy on environmental justice 

(EJ). Its main provision directs Federal agencies, to the 

greatest extent practicable and permitted by law, to make 

environmental justice 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, 

and Tribal populations in the United States.

This proposed 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 
137

(e.g., schools, universities, places of worship), and municipal 

buildings (e.g., courthouses, arts centers, prisons). There are 

approximately 137,000 facilities affected by the proposed 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 sociodemographic groups for this rule, or to relate the locations of 

expected emission reductions to the locations of current poor 

air quality. However, the rule is anticipated to have 

substantial emissions reductions of toxic air pollutants (See 

Table 2.), some of which are potential carcinogens, neurotoxins, 

and respiratory irritants. The rule will also result in 

substantial 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 proposed rule is 

anticipated to have health benefits for all persons living or 

going near these types of sources. (Please refer to the RIA for 
138

this rulemaking, which is available in the docket.) For 

example, there will be significant 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 substantial 

reductions in other air toxics that can cause adverse health 

effects such as ozone precursors which contribute to “smog.” 

This rule will not cause an increase in any adverse human health 

or environmental effects on any population, including any 

minority, low-income, or Tribal 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 a EJ communication strategy to ensure that 

interested communities have access to this proposed rule, are 

aware of its content, and have an opportunity to comment. 

During the comment period, EPA will publicize the rulemaking via 

EJ newsletters, Tribal newsletters, EJ listserves, and the 

internet, including Office of Policy, Economics, and 

Innovation’s (OPEI) Rulemaking Gateway web site 

(http://yosemite.epa.gov/opei/rulegate.nsf/content/index.html?op

endocument). EPA will also provide general rulemaking fact 
139

sheets (e.g., why is this important for my community) for EJ 

community groups and conduct conference calls with interested 

communities. In addition, state and federal permitting 

requirements will provide state, local governments and 

communities the opportunity to provide their comments on the 

permit conditions associated with permitting these sources.
National Emission Standards for Hazardous Air Pollutants 

for Area Sources: Industrial, Commercial, and 

Institutional Boilers 

Page 140 of 192

List of Subjects in 40 CFR part 63

Environmental protection, Administrative practice and 

procedure, Air pollution control, Hazardous substances, 

Intergovernmental relations, Reporting and recordkeeping 

requirements.

______________________

Dated:

_______________________

Lisa P. Jackson,

Administrator
124

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 paragraphs 

(b)(27), (b)(39), (b)(47), (b)(49), (b)(50), (b)(52), (b)(55), 

(b)(56), (b)(58), (b)(61), (b)(62), and (i)(1) to read as 

follows:

§63.14 Incorporation by reference.

* * * * *

(b) * * *

(27) ASTM D 6522–00, Standard Test Method for Determination 

of Nitrogen Oxides, Carbon Monoxide, and Oxygen Concentrations 

in Emissions from Natural Gas Fired Reciprocating Engines, 

Combustion Turbines, Boilers, and Process Heaters Using Portable 

Analyzers1

, IBR approved for §63.9307(c)(2), Table 4 to subpart 

ZZZZ, Table 5 to subpart DDDDD, and Table 4 to subpart JJJJJJ of 

this part. 

* * * * *
125

(39) ASTM Method D388-99

01

, Standard Classification of 

Coals by Rank1, IBR approved for §63.7575 and §63.11237.

* * * * *

(47) ASTM D5198-92 (Reapproved 2003), Standard Practice 

for Nitric Acid Digestion of Solid Waste1

, IBR approved for Table 

6 to subpart DDDDD and Table 5 to subpart JJJJJJ of this part.

* * * * *

(49) ASTM D6323-98 (Reapproved 2003), Standard Guide for 

Laboratory Subsampling of Media Related to Waste Management 

Activities1, IBR approved for Table 6 to subpart DDDDD and Table 

5 to subpart JJJJJJ of this part.

(50) ASTM E711-87 (Reapproved 1996), Standard Test Method 

for Gross Calorific Value of Refuse-Derived Fuel by the Bomb 

Calorimeter1, IBR approved for Table 6 to subpart DDDDD and Table 

5 to subpart JJJJJJ of this part.

* * * * *

(52) ASTM E871-82 (Reapproved 1998), Standard Method of 

Moisture Analysis of Particulate Wood Fuels1, IBR approved for 

Table 6 to subpart DDDDD and Table 5 to subpart JJJJJJ of this 

part.

* * * * *
126

(55) ASTM D2013–04, Standard Practice for Preparing Coal 

Samples for Analysis, IBR approved for Table 6 to subpart DDDDD 

and Table 5 to subpart JJJJJJ of this part.

(56) ASTM D2234–D2234M–03€1, Standard Practice for 

Collection of a Gross Sample of Coal, IBR approved for Table 6 

to subpart DDDDD and Table 5 to subpart JJJJJJ of this part.

(58) ASTM D3173–03, Standard Test Method for Moisture in 

the Analysis Sample of Coal and Coke, IBR approved for Table 6 

to subpart DDDDD and Table 5 to subpart JJJJJJ of this part.

(61) ASTM D6722–01, Standard Test Method for Total Mercury 

in Coal and Coal Combustion Residues by the Direct Combustion 

Analysis, IBR approved for Table 6 to subpart DDDDD and Table 5 

to subpart JJJJJJ of this part.

(62) ASTM D5865–04, Standard Test Method for Gross 

Calorific Value of Coal and Coke, IBR approved for Table 6 to 

subpart DDDDD and Table 5 to subpart JJJJJJ of this part.

* * * * *

(i) * * *

(1) ANSI/ASME PTC 19.10–1981, “Flue and Exhaust Gas 

Analyses [Part 10, Instruments and Apparatus],” IBR approved for 

§§63.865(b), 63.3166(a), 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), 

Table 5 to subpart DDDDD, and Table 4 to subpart JJJJJJ of this 
127

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 When do I have to comply with this subpart?

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?

Initial Compliance Requirements

63.11205 What are my general requirements for complying with 

this subpart?

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 When must I conduct subsequent performance tests?

63.11215 How do I demonstrate initial compliance with the work 

practice standard, emission reduction measures,

and management practice?

Continuous Compliance Requirements

63.11220 How do I monitor and collect data to demonstrate 

continuous compliance?
128

63.11221 How do I demonstrate continuous compliance with the 

emission limits?

63.11222 How do I demonstrate continuous compliance with the 

work practice standards?

63.11223 What are my monitoring, installation, operation, and 

maintenance requirements?

63.11225 What are my notification, reporting, and 

recordkeeping requirements?

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. 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.

§63.11194 What is the affected source of this subpart?
129

(a) This subpart applies to each new or existing affected 

sources 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 located at an area source.

(2) The affected source of this subpart is each new or 

reconstructed industrial, commercial, or institutional boiler 

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 [INSERT DATE OF PUBLICATION IN THE FEDERAL 

REGISTER].

(c) An affected source is a new source if you commenced 

construction or reconstruction of the affected source after 

[INSERT DATE OF PUBLICATION IN THE FEDERAL REGISTER].

(d) A boiler is a new affected source if you commenced 

fuel switching from natural gas to coal, biomass, or oil after 

[INSERT DATE OF PUBLICATION IN THE FEDERAL REGISTER].

(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 
130

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.

§63.11195 Are any boilers not subject to this subpart? 

The types of boilers listed in paragraphs (a) through (e) 

of this section are not subject to this subpart.

(a) Any boiler specifically listed as 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 does not include boilers that only provide 

steam to a process or for heating at a research and development 

facility.

(e) A gas-fired boiler as defined in this subpart.

§63.11196 What are my compliance dates? 

(a) If you own or operate an existing affected source, you

must achieve compliance with the applicable provisions in this 

subpart no later than [INSERT THE DATE 3 YEARS AFTER PUBLICATION 
131

OF THE FINAL RULE IN THE FEDERAL REGISTER].

(b) If you start up a new affected source on or before 

[INSERT THE DATE OF PUBLICATION OF THE FINAL RULE IN THE FEDERAL 

REGISTER], you must achieve compliance with the provisions of

this subpart no later than [INSERT THE DATE OF PUBLICATION OF 

THE FINAL RULE IN THE FEDERAL REGISTER].

(c) If you start up a new affected source after [INSERT 

THE DATE OF PUBLICATION OF THE FINAL RULE IN THE FEDERAL 

REGISTER], you must achieve compliance with the provisions of 

this subpart upon startup of your affected source.

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 oil. 

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 of 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 of this subpart that applies to your boiler. 

(c) These standards apply at all times.

Initial Compliance Requirements

§63.11205 What are my general requirements for complying with 
132

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 which may include, but is not limited to, 

monitoring results, review of operation and maintenance 

procedures, review of operation and maintenance records, and 

inspection of the source.

(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.

§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 of this subpart that applies 

to you by either conducting performance (stack) tests, as 
133

applicable, according to §63.11212 and Table 4 of this subpart 

or conducting fuel analyses, as applicable, according to 

§63.11213 and Table 5 to this subpart. 

(b) For affected sources that have an applicable carbon 

monoxide (CO) emission limit, your initial compliance 

requirements depend on the rated capacity of your boiler. If 

your boiler has a heat input capacity between 10 and 100 million 

British thermal units (MMBtu) per hour, your initial compliance 

demonstration is conducting a performance test for CO according 

to Table 4 to this subpart. If your boiler has a heat input 

capacity of 100 MMBtu per hour or greater, your initial 

compliance demonstration is conducting a performance evaluation 

of your continuous emission monitoring system (CEMS) for CO

according to §63.11223. 

(c) For existing affected sources 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).

(d) For existing affected sources that have applicable 

work practice standards 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).
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(e) For new affected sources, you must demonstrate initial 

compliance no later than 180 calendar days after [INSERT THE 

DATE OF PUBLICATION OF THE 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).

§63.11211 How do I demonstrate initial compliance with the 

emission limits? 

(a) For affected sources that elect to 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 and conducting CMS 

performance evaluations according to §63.11223.

(b) 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 follow the 

procedures in paragraphs (b)(1) through (3) of this section. 

(1) If you burn more than one fuel type, you must 

determine the fuel mixture you could burn in your boiler that 

would result in the maximum emission rates of mercury that you 

elect to demonstrate compliance through fuel analysis.

(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. 
135

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.

§63.11212 What stack tests and procedures must I use for the 

performance tests? 

(a) You must conduct all performance tests according to 

the requirements in §63.7. 

(b) You must conduct each stack test according to the 

requirements in Table 4 to this subpart.

(c) You must conduct stack tests at the maximum normal 

operating load while burning the type of fuel or mixture of 

fuels that have the highest content of mercury, and you must 

demonstrate initial compliance based on these tests.
136

(d) You must conduct a minimum of three separate test runs

for each performance 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 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 to part 60 of this 

chapter to convert the measured particulate 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.

(b) At a minimum, you must obtain three composite fuel 

samples for each fuel type according to the procedures in Table 

5 of this subpart. Each composite sample will consist of a 

minimum of three samples collected at approximately equal 

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 
137

each fuel type according to the procedures in Table 5 to this 

subpart.

§63.11214 When must I conduct subsequent performance tests?

(a) You must conduct all applicable performance (stack) 

tests according to §63.11212 on an annual basis, unless you 

follow the requirements listed in paragraphs (b) through (d) of 

this section. Annual performance tests must be completed 

between 10 and 12 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 test for that pollutant for the next 2 years. You 

must conduct a performance test during the third year and no 

more than 36 months after the previous performance 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, 
138

and if there are no changes in the operation of the affected 

source or air pollution control equipment that could increase 

emissions, but each such performance test must be conducted no 

more than 36 months after the previous performance test.

(d) If a performance test shows emissions exceeded 75 

percent of the emission limit, you must conduct annual 

performance tests for that pollutant until all performance tests 

over consecutive 3-year period show compliance.

(e) If you have an applicable CO emission limit and your 

boiler has a heat input capacity between 10 and 100 MMBtu per 

hour, you must conduct annual performance tests for CO according 

to §63.11211. Each annual performance test must be conducted 

between 10 and 12 months after the previous performance test. 

(f) If you demonstrate compliance with the mercury 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.

§63.11215 How do I demonstrate initial compliance with the 

work practice standard, emission reduction measures, and 

management practice?
139

(a) If you own or operate an existing boiler with a heat 

input capacity of less than 10 million Btu per hour, 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 affected boiler with 

a heat input capacity of 10 million Btu per hour or greater, you 

must submit the energy assessment report, along with a signed 

certification that the assessment is an accurate depiction of 

your facility.

Continuous Compliance Requirements

§63.11220 How do I monitor and collect data to demonstrate 

continuous compliance? 

(a) You must monitor and collect data according to this 

section and the site-specific monitoring plan required by 

§63.11223. 

(b) Except for monitor malfunctions, associated repairs, 

and required quality assurance or control activities (including, 

as applicable, calibration checks and required zero and span 

adjustments), you must monitor continuously (or collect data at 

all required intervals) at all times that the affected source is 

operating. 

(c) You may not use data recorded during monitoring 

malfunctions, associated repairs, or required quality assurance 
140

or control activities in data averages and calculations used to 

report emission 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. 

§63.11221 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 (5) of this section.

(1) Following the date on which the initial performance 

test is completed or is required to be completed under §§63.7 

and 63.11196, 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 Table 3 

to this subpart at all times. Operation above the established 

maximum or below the established minimum operating limits shall 

constitute a deviation of established operating limits. 

Operating limits are confirmed or reestablished during 

performance tests.

(2) If you have you have an applicable mercury 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 
141

lower emissions of mercury than the applicable emission limit.

(3) If you have 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, 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.

(ii) If the results are 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 
142

the corrective action taken. You must also record the percent 

of the operating time during each 6-month period that the alarm 

sounds. In calculating this operating time percentage, if 

inspection of the fabric filter demonstrates that no corrective 

action is required, no alarm time is counted. If corrective 

action is required, each alarm shall be counted as a minimum of 

1 hour. If you take longer than 1 hour to initiate corrective 

action, the alarm time shall be counted as the actual amount of 

time taken to initiate corrective action.

(5) If you have an applicable CO emission limit and you 

are required to install a CEMS according to §63.11223, then you 

must continuously monitor CO according to §§63.11223(a) and 

63.11220 and maintain a CO emission level below your applicable 

CO emission limit in Table 1 to this subpart at all times. 

(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 

§63.11224.

§63.11222 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, you must keep records as 
143

required in §63.11224(c) to demonstrate continuous compliance.

(b) You must conduct a tune-up of the boiler biennially to 

demonstrate continuous compliance as specified in paragraphs 

(b)(1) through (6) of this section.

(1) Inspect the burner, and clean or replace any 

components of the burner as necessary;

(2) Inspect the flame pattern and make any adjustments to 

the burner necessary to optimize the flame pattern consistent 

with the manufacturer’s specifications;

(3) Inspect the system controlling the air-to-fuel ratio, 

and ensure that it is correctly calibrated and functioning 

properly;

(4) Minimize total emissions of CO consistent with the 

manufacturer’s specifications;

(5) Measure the concentration in the effluent stream of CO 

in parts per million, by volume, dry basis (ppmvd), before and 

after the adjustments are made; and

(6) Maintain on-site and submit, if requested by the 

Administrator, an annual report containing the information in 

paragraphs (b)(6)(i) through (iii) of this section,

(i) The concentrations of CO in the effluent stream in 

ppmvd, and oxygen in percent dry basis, measured before and 

after the adjustments of the boiler;

(ii) A description of any corrective actions taken as a 
144

part of the combustion adjustment; and

(iii) The type and amount of fuel used over the 12 months 

prior to the annual adjustment.

§63.11223 What are my monitoring, installation, operation, and 

maintenance requirements? 

(a) If you are using a control device to comply with the 

emission limits specified in Table 1 of this subpart, you must 

maintain each operating limit in Table 3 of this subpart that 

applies to your boiler. If you use a control device not covered 

in Table 3, 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).

(b) If you demonstrate compliance with any applicable 

emission limit through stack testing, you must develop a sitespecific monitoring plan according to the requirements in 

paragraphs (b)(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 
145

(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 

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).
146

(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.

(c) 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 (c)(1) through (5) of this section.

(1) The CPMS 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 
147

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 required calculations constitutes a deviation 

from the monitoring requirements.

(4) Determine the 3-hour block average of all recorded 

readings, except as provided in paragraph (c)(3) of this 

section.

(5) Record the results of each inspection, calibration, 

and validation check.

(d) If you have an applicable opacity operating limit, you 

must install, operate, certify and maintain each continuous 

opacity monitoring system (COMS) according to the procedures in 

paragraphs (d)(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 PS 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 PS 1 of 

40 CFR part 60, appendix B.

(3) As specified in §63.8(c)(4)(i), each COMS must 

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.
148

(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.

(e) If you have an applicable CO emission limit and your 

boiler has a heat input capacity of 100 MMBtu per hour or 

greater, you must install, operate, and maintain a CEMS for CO 

and oxygen according to the procedures in paragraphs (e)(1) 

through (6) of this section by the compliance date specified in 

§63.11196. The CO and oxygen shall be monitored at the same 

location at the outlet of the boiler.
149

(1) Each CEMS must be installed, operated, and maintained 

according to Performance Specification (PS) 4A of 40 CFR part 

60, appendix B, and according to the site-specific monitoring 

plan developed according to §63.11223.

(2) You must conduct a performance evaluation of each CEMS 

according to the requirements in §63.8 and according to PS 4A of 

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 all daily averages. A 

new daily average emission rate is calculated as the average of 

all of the hourly CO emission data for the calendar day.

(6) For purposes of calculating data averages, you must 

not use data recorded during periods of monitoring malfunctions, 

associated repairs, out-of-control periods, required quality 

assurance or control activities, or when your boiler is 

operating at less than 50 percent of its rated capacity. 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 required 

calculations constitutes a deviation from the monitoring 
150

requirements.

(f) You must include in your site-specific monitoring plan 

procedures and acceptance criteria for operating and maintaining

each CEMS according to the requirements in §63.8(d).

§63.11224 What are my notification, reporting, and 

recordkeeping, requirements?

(a) You must submit the notifications specified in 

paragraphs (a)(1) through (a)(4) of this section.

(1) You must submit all of the notifications in §§63.5(b), 

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 OF PUBLICATION OF THE FINAL RULE IN THE FEDERAL 

REGISTER] or within 120 days after the source becomes subject to 

the standard.

(3) 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 test. If you must conduct a 

performance test, you must submit the Notification of Compliance 

Status within 60 days of completing the performance test. In 

addition to the information required in §63.9(h)(2), your 

notification must include the following certification(s) of 
151

compliance, as applicable, and signed by a responsible official:

(i) “This facility complies with the requirements in 

§63.11222(b) to conduct a biennial tune-up of the boiler”.

(ii) “This facility has had an energy assessment performed

according to §63.11215.”

(iii) This certification of compliance by the 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 

detection system according to the plan.” 

(4) 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)(3) of this section.

(b) You must prepare, by March 1 of each year, an annual 

compliance certification report for the previous calendar year 

containing the information specified in paragraphs (b)(1) 

through (b)(3) of this section. You must submit the report by 

March 15 if you had any instance described by paragraph (b)(3) 

of this section.

(1) Company name and address.
152

(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 compliance, 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 source 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, and the total fuel usage amount 

with units of 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 
153

work practices, emission reduction measures, and management 

practices required by §63.11215 as specified in paragraphs 

(c)(2)(i) through (iv) 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 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.

(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) 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)(4)(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;
154

(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).

(5) If you use a bag leak detection system, you must keep 

the records specified in paragraphs (c)(5)(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 

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 
155

recorded action according to §63.10(b)(1). You may keep the 

records offsite for the remaining 3 years.

(e) For affected facilities having applicable emission 

limits, you must submit an electronic copy of stack test reports 

to EPA’s WebFIRE data base, the owner or operator of an affected 

facility shall enter the test data into EPA’s data base using 

the Electronic Reporting Tool located at 

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

Other Requirements and Information

§63.11235 What parts of the General Provisions apply to me?

Table 6 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 State, local, or tribal 

agency. If the EPA Administrator has delegated authority to 

your State, local, or tribal agency, then that agency has the 

authority to implement and enforce this subpart. You should 

contact your EPA Regional Office to find out if implementation 

and enforcement of this subpart is delegated to your State, 

local, or tribal agency. 

(b) In delegating implementation and enforcement authority 

of this subpart to a State, local, or tribal agency under 40 CFR 

part 63, subpart E, the authorities contained in paragraphs (c) 
156

of this section are retained by the EPA Administrator and are 

not transferred to the State, local, or tribal agency.

(c) The authorities that cannot be delegated to State, 

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 

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 CAA, in §63.2 

(the General Provisions), and in this section as follows:

Bag leak detection system means an instrument 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 
157

limited to, an instrument that operates on electrodynamic, 

triboelectric, light scattering, light transmittance, or other 

principle to monitor relative particulate matter loadings.

Biomass means but is not limited to, wood residue, and wood 

products (e.g., trees, tree stumps, tree limbs, bark, lumber, 

sawdust, sanderdust, 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 fuel is not intended to suggest that 

these materials are or not solid waste.

Biomass subcategory includes any boiler that burns any 

amount of biomass, but no coal, either alone or in combination 

with liquid fuels or gaseous fuels.

Boiler means an enclosed combustion device in which water 

is heated to recover thermal energy in the form of steam or hot 

water. A device combusting solid waste, as defined in 40 CFR 

241.3, is not a boiler. Waste heat boilers are excluded from 

this definition. 

Coal means all solid fuels classifiable as anthracite, 

bituminous, sub-bituminous, or lignite by the American Society 

for Testing and Materials in ASTM D388-99e1, “Standard 
158

Specification for Classification of Coals by Rank1” (incorporated 

by reference, see §63.14(b)) and synthetic fuels derived from 

coal including but not limited to, solvent-refined coal, coaloil mixtures, and coal-water mixtures. Coal derived gases are 

excluded from this definition.

Coal subcategory includes any boiler that burns any coal 

alone or at least 10 percent coal on an annual heat input basis

in combination with biomass, liquid fuels, or gaseous fuels.

Commercial boiler means a boiler used in commercial 

establishments such as hotels, restaurants, and laundries to 

provide electricity, steam, and/or hot water that does not 

combust solid waste, as that term is defined by the 

Administrator under RCRA.

Deviation means any instance in which an affected source 

subject to this subpart, or an owner or operator of such a 

source:

(1) Fails to meet any requirement or obligation 

established by this subpart including, but not limited to, any 

emission limit, operating limit, or work practice standard;

(2) 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 

(3) A deviation is not always a violation. The 
159

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 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.

Electrostatic precipitator 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.

Energy assessment means 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.

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
160

EPA method that includes collection of a minimum of three 

composite fuel samples, with each composite consisting of a 

minimum of three increments collected at approximately equal 

intervals over the test period.

(2) An equivalent sample compositing procedure means a 

published VCS or EPA method to systematically mix and

obtain a representative subsample (part) of the composite 

sample.

(3) An equivalent sample preparation procedure means a 

published VCS or EPA method that: Clearly states that the

standard, practice or method is appropriate for the pollutant 

and the fuel matrix; or is cited as an appropriate sample 

preparation standard, practice or method for the pollutant in 

the chosen VCS or EPA determinative or analytical method.

(4) An equivalent procedure for determining heat content 

means a published VCS or EPA method to obtain gross calorific 

(or higher heating) value.

(5) An equivalent procedure for determining fuel moisture 

content means a published VCS or EPA method to obtain moisture 

content. If the sample analysis plan calls for determining

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 

received" basis, a separate aliquot can be dried to determine 
161

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.

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 State 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, subbituminous coal, lignite, anthracite, 

biomass, distillate oil, residual oil.

Gaseous fuels includes, but is not limited to, natural gas, 

process gas, landfill gas, coal derived gas, refinery gas, and 

biogas.
162

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 exhaust gases from 

other sources such as gas turbines, internal combustion engines, 

kilns, etc.

Industrial boiler means a boiler used in manufacturing, 

processing, mining, and refining or any other industry to 

provide steam, hot water, and/or electricity that does not 

combust solid waste, as that term is defined by the 

Administrator under RCRA.

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 that does not combust solid waste, as that term 

is defined by the Administrator under RCRA.

Liquid fuel means petroleum, distillate oil, residual oil,

any form of liquid fuel derived from petroleum, on-spec used 

oil, and biodiesel.
163

Minimum sorbent flow rate means 90 percent of the test 

average sorbent (or activated carbon) flow rate measured 

according to Table 6 to this subpart during the most recent 

performance test demonstrating compliance with the applicable 

emission limits.

Natural gas means: 

(1) A naturally occurring mixture of hydrocarbon and 

nonhydrocarbon gases found in geologic formations beneath the 

earth’s surface, of which the principal constituent is methane; 

or 

(2) Liquid petroleum gas, as defined by the American 

Society for Testing and Materials in ASTM D1835-03a, "Standard 

Specification for Liquid Petroleum Gases" (incorporated by 

reference, see §63.14(b)).

Oil subcategory includes any boiler that does not burn any 

solid fuel and burns any liquid fuel either alone or in 

combination with gaseous fuels. Gas boilers that burn liquid 

fuel during periods of gas curtailment, gas supply emergencies, 

or for periodic testing 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.

Particulate matter means any finely divided solid or liquid 
164

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. An increase in the cost or unit price of natural 

gas does not constitute a period of natural gas curtailment or 

supply interruption.

Qualified personnel mean specialists in evaluating energy 

systems, such as, those who have successfully completed the DOE 

Qualified Specialist program for all systems, Certified Energy 

Managers certified by the Associationof Energy Engineers, or the 

equivalent.

Responsible official means responsible official as defined 

in 40 CFR 70.2.

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 
165

boilers incorporating duct or supplemental burners that are 

designed to supply 50 percent or more of the total rated heat 

input capacity of the waste heat boiler are not considered waste 

heat boilers, but are considered boilers. 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, that 

is promulgated pursuant to section 112(h) of the CAA.

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 meet the 

following emission limits 

...

1. New coal a. Particulate 

Matter

b. Mercury

c. Carbon 

Monoxide

0.03 lb per MMBtu of heat 

input; or

0.000003 lb per MMBtu of 

heat input

310 ppm by volume on a 

dry basis corrected to 7 

percent oxygen (daily 

average) 

2. New biomass a. Particulate 

Matter

b. Carbon

Monoxide

0.03 lb per MMBtu of heat 

input; or

100 ppm by volume on a 

dry basis corrected to 7

percent oxygen (daily

average)
166

3. New oil a. Particulate 

Matter

b. Carbon

Monoxide

0.03 lb per MMBtu of heat 

input; or

1 ppm by volume on a dry 

basis corrected to 3 

percent oxygen (daily 

average)

4. Existing 

coal 

(units with 

heat input 

capacity 

of 10 

million 

Btu per 

hour or 

greater) 

a. Particulate 

Matter

b. Mercury

c. Carbon 

Monoxide

0.3 lb per MMBtu of heat 

input; or

0.000003 lb per MMBtu of 

heat input

310 ppm by volume on a 

dry basis corrected to 7 

percent oxygen (daily 

average) 

5. Existing 

biomass

(units with 

heat input 

capacity 

of 10 

million 

Btu per 

hour or 

greater) 

Carbon Monoxide 170 ppm by volume on a 

dry basis corrected to 7 

percent oxygen (daily 

average)

6. Existing

oil

(units with 

heat input 

capacity 

of 10 

million 

Btu per 

hour or 

greater) 

Carbon Monoxide 2 ppm by volume on a dry 

basis corrected to 3 

percent oxygen (daily 

average)

Table 2 to Subpart JJJJJJ of Part 63 — Work Practice Standards, 

Emission Reduction Measures, and Management Practices

As stated in §§63.11202 and 63.11203, you must comply with the 
167

following applicable work practice standards:

If your boiler is in 

this subcategory...

You must meet the following...

1. Existing coal,

biomass, or oil 

(units with heat 

input capacity of 

less than 10 million 

Btu per hour) 

a. Conduct a tune-up of the boiler 

biennially as specified in 

§63.11222.

2. Existing coal, 

biomass, or oil 

(units with heat 

input capacity of 10 

million Btu per hour

and greater) 

Must have an energy audit performed 

by qualified personnel which 

includes: 

(1) a visual inspection of the 

boiler system.

(2) establish operating 

characteristics of the facility, 

energy system specifications, 

operating and maintenance procedures, 

and unusual operating constraints,

(3) identify major energy 

consuming systems,

(4) a review of available 

architectural and engineering plans, 

facility operation and maintenance 

procedures and logs, and fuel usage,

(5) a list of major energy 

conservation measures,

(6) the energy savings potential 

of the energy conservation measures 

identified,

(7) a 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 Mercury Emission Limits

As stated in §63.11201, you must comply with the applicable 

operating limits:
168

If you demonstrate 

compliance with 

applicable mercury

emission limits 

using...

You must meet these operating 

limits...

1. Fabric filter 

control

a. Maintain opacity to less than 

or equal to 10 percent opacity 

(daily block average); OR

b. Install and operate a bag leak 

detection system according to 

§63.11221 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

Maintain opacity to less than or 

equal to 10 percent opacity (daily

block average). 

3. Dry scrubber or 

carbon injection 

control

Maintain the minimum sorbent or 

carbon injection rate at or above 

the operating levels established 

during the performance test that 

demonstrated compliance with the 

applicable emission limit for 

mercury.

4. Fuel analysis Maintain the fuel type or fuel 

mixture (annual average) such that 

the mercury emission rates 

calculated according to 

§63.11211(c) is less than the 

applicable emission limits for 

mercury.

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 new affected 

sources:
169

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.

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 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 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 chapter.
170

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 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 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 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 chapter.
171

3. Carbon 

Monoxide

a. Select the 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 carbon 

monoxide 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 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 10, 10A, or 

10 B in appendix A 

to part 60 of this 

chapter or ASTM 

D6522-00 (IBR, see 

§63.14(b). 

Method 19 F-factor 

methodology in 

appendix A to part 

60 of this chapter. 

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 new affected sources:
172

To conduct a 

fuel analysis 

for the 

following 

pollutant... You must... Using...

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.

Procedure in 

§63.11213(c) or ASTM 

D2234-D2234M-03

01 (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.

SW-846-3050B (for solid 

samples) or SW-846-3020A 

(for liquid samples) or 

ASTM D2013-04 (for 

coal)(IBR, see 

§63.14(b)) or ASTM 

D5198-92 (2003) (for 

biomass)(IBR, see 

§63.14(b)) or 

equivalent.

ASTM D5865-04 (for 

coal)(IBR, see 

§63.14(b)) or ASTM E711-

87 (1996) (for 

biomass)(IBR, see 

§63.14(b)) or 

equivalent.

ASTM D3173-03 (IBR, see 

§63.14(b)) or ASTM E871-

82 (1998)(IBR, see 

§63.14(b)) or 

equivalent.
173

f. Measure mercury 

concentration 

in fuel sample.

g. Convert 

concentrations 

into units of 

lb/MMBtu of 

heat content.

ASTM D6722-01 (for 

coal)(IBR, see 

§63.14(b)) or SW-846-

7471A (for solid 

samples) or SW-846 7470A 

(for liquid samples) or 

equivalent.

Table 6 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:

Citation Subject Applies to subpart JJJJJJ

§63.1 Applicability Yes.

§63.2 Definitions Yes.

§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.
174

§63.6(e)(1), 

(e)(3), (f)(1), 

and(h)

Startup, shutdown, 

and malfunction 

requirements and 

Opacity/ Visible 

Emission Limits

No. Standards apply at all 

times, including during 

startup, shutdown, and 

malfunction events.

§63.7(a),(b),(c),

(d),(e)(2)-

(e)(9), (f),(g), 

and (h)

Performance 

Testing 

Requirements

Yes.

 

§63.7(e)(1) Conditions for 

conducting 

performance tests

No. Subpart DDDDD 

specifies conditions for 

conducting performance 

tests at §63.11210.

§63.8 Monitoring 

Requirements

Yes.

§63.9 Notification 

Requirements

Yes. Subpart JJJJJJ 

requires submission of 

Notification of Compliance 

Status within 120 days of 

compliance date unless a 

performance test is 

required.

§63.10(a), 

(b)(1), 

(b)(2)(i)-(iii),

(b)(2)(vi)-(xiv),

(c)(1)-(c)(14), 

(d)(1)-(2), and 

(f) 

Recordkeeping and 

Reporting 

Requirements

Yes.

§63.10(b)(2)(iv)-

(v),(b)(3), 

(d)(3)-(5), and 

(e)

No, Subpart JJJJJJ requires 

submission on an annual 

basis. 

§63.10(c)(15) Allows use of SSM 

plan

No.

§63.11 Control Device 

Requirements

No.

§63.12 State Authority 

and Delegation

Yes.
175

§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