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 

and polycyclic organic matter emissions are based on the maximum 

achievable control technology. The proposed emission standards

for the control of 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 partneeded to meet the 90 percent requirement of the 

area source categories of industrial boilers and commercial and 

institutional boilers.section 112(c)(3).

DATES: Comments must be received on or before [INSERT DATE 45

DAYS AFTER PUBLICATION IN THE FEDERAL REGISTER]. If a hearing 
2

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:

2822T, 1200 Pennsylvania Ave., NW, Washington, DC 

20460, Docket ID No. EPA-HQ-OAR-2006-0790. Please 
3

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 

consider to be CBI or otherwise protected through 

http://www.regulations.gov or e-mail. The 
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http://www.regulations.gov Web site is an “anonymous access” 

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

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

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

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

automatically captured and included as part of the comment that 

is placed in the public docket and made available on the 

Internet. If you submit an electronic comment, EPA recommends 

that you include your name and other contact information in the 

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

EPA cannot read your comment due to technical difficulties and 

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

consider your comment. Electronic files should avoid the use of 

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

defects or viruses.

Docket: All documents in the docket are listed in the 

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

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

information whose disclosure is restricted by statute. Certain 

other material, such as copyrighted material, will be publicly 

available only in hard copy form. Publicly available docket 

materials are available either electronically in

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

Center, Room 3334, 1301 Constitution Ave., NW, Washington, DC. 
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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 this 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 standard?

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

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?
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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. How did we ensure that the listed HAP are addressed by this 

ruleWhat 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 for HAP 

other than Mercury and POM

E. How did EPA determine the proposed emission 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)

VII. 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 

Environmental Health Risks and Safety Risks
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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 
8

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 (NESHAP) for Area Sources: Industrial, 

commercial, and Institution Boilers). If you have any questions 

regarding the applicability of this action to a particular 

entity, consult either the air permittingdelegated 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 confidential business 

information (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 
9

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

information claimed as CBI must be submitted for inclusion in 

the public docket. Information so marked will not be disclosed 

except in accordance with procedures set forth in 40 CFR part 2. 

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?

If anyone contacts EPA requesting to speak at a public 

hearing concerning this proposed rule by [INSERT DATE 10 DAYS 

AFTER PUBLICATION IN THE FEDERAL REGISTER], we will hold a 

public hearing on [INSERT DATE 15 DAYS AFTER PUBLICATION IN THE 

FEDERAL REGISTER]. Persons interested in presenting oral 

testimony at the hearing, or inquiring as to whether a hearing 

will be held, should contact Ms. Pamela Garrett, Energy 

Strategies Group, at (919) 541-7966 at least two days in advance 

of the hearing. If a public hearing is held, it will be held at 

10 a.m. at the EPA’s Campus located at 109 T.W. Alexander Drive 
10

in Research Triangle Park, NC, or at an alternate site nearby.

II. Background Information

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 
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to HAP emitted from stationary sources.

Under CAA section 112(d)(5), we may elect to promulgate 

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 
12

at area and major sources in similar categories to determine 

whether such technologies and practices could be considered

generally available for the area source categories at issue. 

Finally, as noted above, in determining GACT for a particular 

area source category, we consider the costs and economic impacts 

of available control technologies and management practices on 

that category.

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

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

requires that source EPA list categories and subcategories of 

sources assuring that sources accounting for emissionsnot less 

than 90 percent of the aggregate emissions of each of the seven 

specified hazardous air pollutants (HAP listed in CAA section 

112(c)(6) be) are subject to standards under CAA sectionssection

112(d)(2) for the listed pollutants. Thus, CAA or (d)(4). The 

seven HAP specified in section 112(c)(6) requires that emissions 

of each listed HAP for the listed categories be subject to 

maximum achievable control technology (MACT) regulation. The 

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 
13

combustion, industrial wood combustion, commercial coal 

combustion, commercial oil combustion, and commercial wood 

combustion. See 63 FR 17849. All ofWe listed these source 

categories are on the under CAA section 112(c)(6) list forbased 

on the source categories’ contribution of mercury and polycyclic 

organic matter (POM). In the documentation for the CAA section 

112(c)(6) listing, the commercial fuel combustion categories 

included institutional fuel combustion (See “1990 Emissions 

Inventory of Section 112(c)(6) Pollutants, Final Report,” April 

1998). As discussed in 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 re-examination, 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 

Formatted: Highlight
14

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 

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 The 

MACT based regulation 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 
15

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 

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 
16

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 

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 the proposed standards to reflect the 

application of MACT for the listed 112(c)(6) pollutants (

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 urban HAP which formed the basis for the 

listing of these two area source categoriespollutants noted 

above.

We are proposing these national emission standards in 

response to a court-ordered deadline that requires EPA to issue 
17

standards for source categories listed pursuant to CAA section 

112(c)(6) by December 16, 2010 if no later than April 15, 2010

EPA signs notice of proposed rulemaking (Sierra Club v. U.S. 

Environmental Protection Agency, no. 01-1537, D.D.C).

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. Both source 

categories were listed as contributing a percentage of the total 

area source emissions for the following “urban” HAP: polycyclic 

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

hydrocarbons)), acetaldehyde, acrolein, arsenic, beryllium, 

cadmium, chromium, dioxins, formaldehyde, lead, manganese, 

mercury, polychlorinated biphenyls (PCB), and nickelWe describe 

above the pollutants that formed the basis of the listings.

In addition, both industrial boilers and 

institutional/commercial boilers are on the list of CAA section 

112(c)(6) source categories published on April 10, 1998 (63 FR 

17830). CAA section 112(c)(6) requires EPA to list, and subject 
18

to standards pursuant to CAA section 112(d)(2) or (d)(4), 

categories of sources accounting for not less than 90 percent of 

emissions of each of seven specific HAP. Within these two

source categories, coal combustion, oil combustion, and wood 

combustion are on the 112(c)(6) list because of emissions of 

mercury and POM.

This proposed rule would apply to all existing and new 

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. Combustion units are not subject to this

proposed rule simply by virtue of having a waste heat boiler. A 

waste heat boiler (or heat recovery steam generator) is a device 

that recovers normally unused energy (e.g., hot exhaust gases) 

Formatted: Tab stops: 0", Left + 0.5", Left +

1", Left + 1.5", Left + 2", Left + 2.5", Left +

3", Left + 3.5", Left + 4", Left + 4.5", Left +

5", Left + 5.5", Left
19

and converts it to usable heat. Emissions from a combustion 

unit with a waste heat boiler are regulated by the applicable 

standards for the particular type of combustion unit. For 

example, emissions from a medical waste incineration unit with a 

waste heat boiler are regulated by standards established under 

CAA section 129. 

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 (as a 

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

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

monoxide (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. Thus, this proposed rule may potentially include 

boilers that are regulatedIn 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. 

CAA section 129(h) states that no unit subject to standards 
20

under CAA section 129 shall be subject to standards under CAA 

section 112(d). Therefore, we are excluding from this proposed 

rule, as is being done for the major source NESHAP, any boiler

that is subject to regulation under CAA section 129. A 

rulemaking under CAA section 129 is being proposed in for 

commercial and industrial solid waste incineration units. In a 

parallel action and , EPA is proposing a solid waste definition 

rulemaking pursuant to Subtitle D of RCRA. That action is 

relevant to this action proceeding because it would apply to 

boilers if an industrial, commercial, or institutional unit

located at an area source that combust any solid waste. 

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.

InAs 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 

Formatted: Font color: Black

Formatted: Font color: Black
21

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

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 had 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 particulate matter (PM), sulfur dioxide, 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 this proposed rule because this proposed rule 

regulates HAP. However, inIn 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 standard?

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 both steam 

boilers and heater units that are required to be inspected for 
22

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 to 

establish subcategories andconcerning existing HAP emission

control requirements.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 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?

Area source bAs explained above, oilers can emit a 

varietyindustrial coal combustion, industrial oil combustion,

industrial wood combustion, commercial coal combustion, 
23

commercial oil combustion, and commercial wood combustion are 

listed under CAA section 112(c)(6) due to contributions of urban 

HAP, depending onmercury 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 fuel combusted. Because of the number 

of urban HAP potentially present in emissions112(c)(3) 

pollutants, we used surrogates because, as explained below, it 

was not practical to establish individual standards for each

specific HAP that could be present in the various fuels. 

Furthermore, establishing separate standards for each individual 

HAP would impose costly and significantly more complex 

compliance and monitoring requirements and achieve little, if 

any, HAP emissions reductions beyond what would be achieved 

using the surrogate pollutant approach. Therefore, we used

surrogates in developing standards for the HAP described in this

proposed rule. 

. We grouped the urban HAP112(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, beryllium, cadmium, chromium, lead, manganese, and 

nickel), and organic HAP (POM, acetaldehyde, acrolein, dioxins, 

ethylene dichloride, formaldehyde, and PCB). In general, the 

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24

pollutants within each group have similar characteristics and 

can be controlled with the same techniques. 

Next, as explained in more detail in section V.C of this 

preamble, we identified compounds that could be used as 

surrogates for all the compounds in each pollutant category. 

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 non-mercury 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 fly-ash 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 
25

compliance and monitoring requirements and achieve little, if 

any, HAP emissions reductions beyond what would be achieved 

using the surrogate pollutant approach. 

For organic HAP, we selected carbon monoxide (CO) as a 

surrogate to represent the variety offor 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 area source boilers based on control of mercury, 

PM (as a surrogate for the individual non-mercuryurban metal

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

organic HAP).urban organic HAP), and mercury from biomass-fired 

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and oil-fired boilers. We are proposing MACT standards for 

mercury from coal-fired boilers and for POM from all boilers.

III. Clarification of the Source Category List

This proposed rule announces a clarification of the area 

source category list developed under our Integrated Urban Air 

Toxics Strategy pursuant to CAA section 112(c)(3), which is that

theThe Industrial Boilers and the Institutional/Commercial 

Boilers area source categories do not include boilers combusting 

only gaseous fuels.

Specifically, we are clarifying that the source categories 

do not include all types of boilers. This is simply a 

clarification and does not change the universe of sources that 

were the basis for listing the source categories under CAA 

section 112(c)(3).

In the initial listing of source categories contributing to 

emissions of the 30 area source HAP, industrial boilers and 

institutional/commercial boilers were, as a whole, selected as 

source categories whose emissions, when subject to regulation, 

can be counted towards the 90-percent goal for each of the area 

source HAP. Industrial boilers and institutional/commercial 

boilers were listed, in 1999, as contributing to under section 

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

for area source boilers for the following urban HAP: 7-PAH, 

acetaldehyde, acrolein in order to meet the section 112(c)(3) 

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90% requirement for these HAP: mercury, arsenic, beryllium, 

cadmium, lead, chromium, dioxins, formaldehyde, lead, manganese, 

mercury, nickel, POM (as 7-PAH), ethylene dioxide, and PCB. We 

stated in the Integrated Urban Strategy (64 FR 38720) that EPA 

chose to complete this list in stages, adding to, deleting from, 

or shuffling the list as we gather more and improved data. 

Since the initial listing of these two source categories, we 

have reexamined the HAP emissions from Natural gas-fired area 

source boilers do not emit any of the urban HAP identified 

above. Therefore, regulation of gas-fired area source boilers 

and have determined that the initial listings were based on HAP 

emissions from area source boilers combusting coal, wood, or 

oil. Area source boilers fired by gas were determined to 

contribute only to the urban HAP formaldehyde, with its 

percentage contribution being only 0.01. Furthermore, through 

other regulatory actions, we have met our requirement to subject 

categories to standards is not necessary to meet the 90 percent%

requirement for formaldehyde. Therefore, industrial boilers 

fired by natural gas and institutional/commercial boilers fired 

by natural gas were determined to be categories not needed to 

reach the 90 percent requirement.

Thus, to meet our CAAunder section 112(c)(3) for these HAP. 

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

obligationof the CAA, we need to promulgateare proposing

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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 

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 

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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)

New 

Boiler

Coal 0.02 0.0000033.0E06310 (@ 7% 

oxygen)

Biomass 0.02 0.0000004 100 (@ 7% 

oxygen)

Oil 0.06 0.0000003 1 (@ 3% 

oxygen)

Existing 

Boiler

Coal 0.3 0.0000033.0E06310 (@ 7% 

oxygen)

Biomass 0.3 0.0000004 170 (@ 7% 

oxygen)

Oil 0.3 0.000009 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 (Btu) per 

hour (MMBtu/h) or greater. If your boiler burns, or is 

permitted to burn, at least 10 percent coal (either ason a 

primarytotal fuel or a backup fuel), or any combination of coal
30

with other fuelsannual 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 a particular class of existing 

area source boilers (that are units with designed heat input 

capacity of less than 10 million Btu per hour).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 

source facilities having an affected boiler with a designed heat 

input capacity of 10 million Btu per hourMMBtu/h or greater that 

require the performance of an energy assessment, by qualified 

personnel, on the boiler and the facility to identify costeffective 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 

Sectionsection 112 regulations governing the emissions of HAP 

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

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

In light of Consistent with Sierra Club v. EPA, 40 CFR 

63.6(f)(1) and (h)(1) do not apply. As such, the proposed 

emission EPA has established standards summarized in section 

IV.D of this preamble rule that apply at all times. EPA has 

attempted to ensure that we have not incorporated into proposed 

regulatory language any provisions that are inappropriate, 

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

We are not proposing a separate emission standard for the source 

categories at issue here that applies during periods of startup 

and shutdown. Periods of startup, normal operations, and 

shutdown are all predictable and routine aspects of a source’s 

operation. We have evaluatedspecifically seeking comment on

whether it is appropriate to there are any such provisions that 
32

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 same standards apply 

during startup and shutdownSSM exemption (such as applied to 

normal operationsthe 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. Based upon continuous emission

monitoring data, obtained as part of the information collection 

effort for the major source boiler and process heater 

rulemaking, which include periodsincluded periods of startup and 

shutdown, over long averaging periods, startups and shutdowns 

will not affect the achievability of startup and shutdown.the 

standard. Boilers, especially solid fuel-fired boilers, do not 

normally startup and shutdown more the than once per day. Thus, 

we are not establishing a separate emission standard for these 

periods because startup and shutdown are part of their 

normalroutine operations and, therefore, are already addressed 

by the standards.

Periods of startup, normal operations, and shutdown 

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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 

SectionCAA 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 

operating mode, we believe it would be impracticable to take 

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34

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. 

For a source that fails to comply with the applicable 

Section 112(d) standards during malfunction events, EPA will 

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. 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 

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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 

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 million Btu per 

hour (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 million Btu per 

hourMMBtu/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 
36

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 

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 
37

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 

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 

or equal tothan 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 
38

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 

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 applicable for 

all boilers must be maintained. Specifically, the owner or

operator must keep records of the dates and the results of each 

boiler tune-up.
39

Records of either continuously monitored parameter data for 

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

CEMScontinupous emission monitoring system (CEMS) data would be 

required.

Each owner and operator would be required to keep the 

following recordrecords:

(1) All reports and notifications submitted to comply with 

the rule;

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

(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 boilersboiler 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, 
40

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.

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 
41

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

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 will substantiallyshould 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
42

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 out-dated or not representative of a

particular source category. Receiving recent performance test 

results would ensure that emissions factors are updated and more 

accurate. In summary, receiving these test data already 

collected for other purposes and using them in the emissions 

factors development program will save industry, 

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 (TTN). 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.
43

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 currently

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

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. These area source categories potentially 

include boilers that are already regulated under CAA section 

129. Since CAA section 129(h) states that no unit subject to 

standards under CAA section 129 shall be subject to standards 

under CAA section 112(d), we are excluding from this proposed 

rule any boilers that are subject to regulation under CAA 

section 129.

Boilers that are used specifically for research and 

development are also not regulated. However, boilers that only 

provide steam to a process or for heating at a research and 
44

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 

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 
45

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 unitsboilers have 

different emission characteristics which may influence the 

feasibility and effectiveness of emission control, they should 

be regulated separately (i.e., subcategorized). Thus, these 

subcategories appropriately identify distinctly different types 

of units subject to regulation.

Accordingly, we are proposing to subcategorize area source 

boilers by boiler type (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 
46

in emissions. The coal-fired subcategory includes boilers 

burning any amount ofgreater than 10 percent coal. on an annual 

fuel heat input basis. The biomass fuel subcategory includes 

units burning any biomass but nonot 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. How did we ensure that the listed HAP are addressed by this 

rule?

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 

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

nickel). The inherent variability and unpredictability of the 
47

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. 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 non-mercury 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 
48

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 fly-ash 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 

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 
49

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. 

D. How did EPA determine the proposed standards for existing 

units?

As discussed previously, CAA section 112(d)(5) allows EPA 

to establish standards or requirements for area sources based on 

GACT, instead of MACT. However, bothBoth industrial boilers and 

institutional/commercial boilers arehave been on the list of CAA 

section 112(c)(6) source categories. CAA for mercury and POM. 

That section 112(c)(6) requires that source categories emitting 

the HAP listed in CAA section 112(c)(6) be subject to standards 

under CAA sections 112(d)(2) or (d)(4). Thus, CAA section 

112(c)(6) requires that emissions of MACT standards for each 

listed HAP forof the listed categories be subjectpollutants 

needed to MACTachieve regulation. However, as of 90 percent of 

the emissions of the relevant 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). 
50

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. Thus, we have developed the proposed standards to 

reflect the application of MACT for the listed 112(c)(6) 

pollutants (mercury and POM) and GACT for the other urban HAP 

listed for these two area source categories.

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 
51

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. However, EPA may, under CAA section 

112(h), consider cost (of demonstrating compliance), as well as 
52

technical feasibility, in evaluating whether the emission 

standards are feasible to enforce and, thus, appropriate to set 

work practice standards. EPA must consider cost, non-air 

quality health and environmental impacts, and energy 

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 for Existing 

Units.

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 (9nine coal, 2 biomass-fired 

boilers) for mercury

- no stateState regulations applicable for mercury or POM,

- no stateState permits specific for mercury or POM,

- no surrogate for Hgmercury, but CO as a surrogate for 

POM,

- few (7- emission data on four coal, 2 biomass)-fired area 

source boilers using add-on control technology for mercury,

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

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53

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

- a few stateState 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 (PM, mercury, and CO) are calculated based on the

performance of the lowest emitting (best performing) sources in 

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.

The MACT floor limit is calculatedWe 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 a statistical formula designed to estimate aother 

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 that is achievable by the 

average of the of control for any subcategory. This decision 

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54

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.

We used the emissions data for those best performing sources 

ifaffected 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 were able to 

replicateunder 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 bestperforming sources and may set the floor at level that bestperforming source can expect to meet “every day and under all 

operating conditions”). 

Formatted: Font: Courier New, Font color:

Black

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Black
55

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 tests in our data 

base. 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 

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 aan independent sample from the same population. In 

other wordsThat 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% confident that the reported level will fall at or 
56

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 standard 

deviationSD 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:

Mercury – The total number of coal-fired area source 

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

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

average mercury emission level of the top 12% is 1.3 pounds per 

trillion Btu (lb/TBtu). The standard deviationSD of test runs 

in the top 12% boilers is 0.322. Therefore, the 99% 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.

Based on test information on utility boilers, we have 

concluded that fabric filters are the most effective technology 

for controlling mercury emissions from coal-fired area source 
57

boilers.

POM – None of the statesStates for which we have an 

inventory have an applicable emission limit specifically for POM 

or CO. However, one stateState (New Jersey) does have standards 

for CO, but for boilers at the size of coal-fired area source 

boilers it, the requirement is actually a work practice standard 

for CO (i.e., boiler tune-up). For small (less than 50 MM 

BtuMMBtu/h) boilers, the New Jersey requirement is to maintain 

and operate the source in accordance with manufacturer 

specifications. 

The available statesState 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 major source NESHAP. Therefore, the top 12% is made up 

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

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

data in top 12% boilers is 92.1 ppm. Therefore, the 99% UPL

level is 390 ppm at 3% oxygen. The resulting MACT floor CO

limit for existing coal-fired area source boilers is 310 ppm at 

7% oxygen. We correct to 7% oxygen because that is typically in 

the oxygen range that coal-fired boilers operate and we rounded 

up to the nearest 10 ppm.
58

Based on available information, we have concluded that good 

combustion practices (GCP), beyond annual tune-ups, such as, 

computer controls, improved combustion air system (fans), 

operator training, or new burners are the most effective 

technology for controlling CO emissions (as a surrogate for 

POM).

2. Existing area source boilers designed for biomass firing:

Mercury – We obtained mercury emission data from 2 biomassfired area source boilers as part of the information collection 

effort for the major source NESHAP. Thus, the top 12% would be 

comprised of one boiler. The average mercury level of the top 

12% 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/million Btu).

POM – None of the statesStates 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, stateState 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 
59

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

ICR survey.

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

of the top 12% is 75.5 ppm at 3% oxygen. The SD of the top 12% 

boilers is 81.3 ppm. The 99% UPL is 202 ppm at 3% oxygen, 

rounded up to 210 ppm. Biomass-fired boilers typically operate 

at around 7 % oxygen. Therefore, the MACT floor level is 170

ppm CO at 7% oxygen.

In light of this analysis, we determined that, in general, 

the combination of a fabric filter and GCP forms the basis for 

the MACT floor level of control for existing area source boilers 

in the biomass subcategory.

3. Existing area source boilers designed for oil firing:

Mercury – There are no available emission data, state 

regulations, or state permits regarding mercury emissions from 

oil-fired area source boilers. Available emission factors (EF) 

are generally the average of available data and would not 

reasonably represent the average of the top 12% 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 8 lb/TBtu (0.000008 

lb/million Btu) to existing oil-fired area source boilers. 
60

POM – None of the statesStates 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% is made up of 1415 boilers. The average CO 

level of the top 12% is 1 ppm at 3% oxygen. Based on the test 

runs from these 15 best performing units, the 99% UPL level is 2 

ppm at 3% oxygen. Therefore, the MACT floor level is 2 ppm CO 

at 3% oxygen. Because oil-fired boilers typically operate at 

around 3% oxygen, additional oxygen content correction was not 

necessary.

In light of this analysis, we determined that, in general, 

the combination of a fabric filter and GCP forms the basis for 

the MACT floor level of control for existing area source boilers 

in the oil subcategory.

However, as4. 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 
61

“not feasible” in this context to applymean when “the 

application of measurement 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 million Btu per hourMMBtu/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 
62

with the proposed emission limits. The annual compliance costs 

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

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% (and can reach as high as 19%) of the average 

firm revenues for 79% of the facilities. This indicates that

the annual costs for testing and monitoring costs 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, the Administrator has determined, 

as allowed under pursuant to CAA section 112(h), EPA is 

proposing that it is not feasible to enforce emission standards

for a particular class of existing area source boilers having a 
63

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 emissionemissions of mercury and CO (as a surrogate for POM) 

for existing area source boilers having a heat input capacity of 

less than 10 MMBtu/h.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 dependent HAP are 

typically controlled by removing them from the flue gas after 

combustion. The only work practices expected to minimize 

mercury emissions are fuel switching to a fuel type with a lower 

mercury content or reducing the fuel usage. As previously 

discussed, we determined that fuel switching was not an 

appropriate emission reduction approach for purposes of 

determining the MACT floor. Fuel usage can be reduced by 

improving the combustion efficiency of the boiler. At best, 

boilers may be 85% efficient and untuned boilers may have 

combustion efficiencies of 60% or lower. As combustion 
64

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 the three Ts of combustion. Good 

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

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 or less

that responded to EPA’s information collection effort for major 
65

source NESHAP, 28 (or 64%) reported conducting a boiler tune-up 

program. Ultimately, we determinedetermined that at least 6

percent% of the boilers in each of the subcategorysubcategories

are subject to an annuala tune-up requirement. Therefore, the 

work practice of an annuala 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 or 

less.

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.

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

POM.

We analyzed two beyond-the-floor options: fuel switching 

and a requirement of an energy assessment for all existing area 

source facilities. Based on the analysis, EPA decided to go 

beyond the MACT floor for this proposed rule for existing area 

source boilers. 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.

For each subcategory, fuel switching to natural gas is a 

regulatory option more stringent than the MACT floor level of 
66

control that would reduce mercury emissions. We determined that 

fuel switching was not an appropriate beyond-the-floor option. 

For example, natural gas supplies are not available in some 

areas, and supplies to industrial customers can be limited 

during periods when natural gas demand exceeds supply. 

Additionally, the estimated emissions reductions that would be 

achieved if solid and liquid fuel boilers switched to natural 

gas were compared with the estimated cost of converting existing 

solid and liquid fuel boilers to fire natural gas. It was 

determined that the costs would be too high to consider it a 

feasible beyond-the-floor option. The EPA estimates the capital 

costs associated with fuel switching to be $258 billion dollars. 

The Energy Information Administration published cost data for 

industrial and commercial sector consumption in 2008. According 

to the EIA, natural gas costs $11.66 per million Btu while 

residual fuel oil and distillate fuel oil costs $12.96 and 

$22.66 per million Btu, respectively. Based on these fuel costs, 

and the relatively large number of area source boilers firing 

distillate fuel oil, the EPA estimates the total annualized 

costs of fuel switching to natural gas be a net savings of $1 

billion per year. However, EPA recognizes the price volatility 

of fuel oil and natural gas over time, and given the high 

capital costs involved to replace or retrofit boilers to fire 

natural gas, EPA concluded this is not a feasible alternative. 
67

Additional detail on the calculation procedures is provided in 

the memorandum “Development (2010) of Fuel Switching Costs and 

Emissions Reductions for Industrial, Commercial, and 

Institutional Boilers” in the docket.

We also 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 

decreasedecreased 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 
68

use by 10 to 15 percent by using best practices to increase 

their energy efficiency. Many best practices are considered 

pollution prevention (P2) because they reduce the amount of fuel 

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
69

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 

(return of investment) period of 3two 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 for HAP 

other than Mercury and POM

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 for removing

HAP other than Mercury and POM is multiclones. We found that 

this technology is minimally effective in controlling suchurban 

metal HAP and has no effect on urban organic HAP.

Multiclones are mechanical separators that use velocity 
70

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 

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 

non-mercury metallic urban metal HAP and the organic urban HAP

(acetaldehyde, acrolein, dioxins, and formaldehyde).. The most 

common options, and generally available, are simply tuning the 

boiler to the manufacturer’s specification. An annualA 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 
71

energy efficiency results in decreasedecreased 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 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 HAP other than 

mercury and POM for existing area source boilers with heat input 

capacities of 10 MMBtu/hour or greater is a management practice 

requiring the implementation of an annuala 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 an annuala

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 
72

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. 

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 emission standards for 

new units?

As discussed previously, CAA section 112(d)(5) allows EPA 

to establish standards or requirements for area sources based on 

GACT, instead of MACT. However, CAA section 112(c)(6) requires 

that source categories accounting for emissions of the HAP 

listed in CAA section 112(c)(6) be subject to MACT regulation. 

Both industrial boilers and institutional/commercial boilers are 

on the list of CAA section 112(c)(6) source categories. 

Thusnoted above, we have developed the proposed standards to 

reflect the application of MACT for the listed 112(c)(6) 

pollutants (mercury and POM), and GACT for HAP other than 

Formatted: Tab stops: 0", Left + 0.5", Left +

1", Left + 1.5", Left + 2", Left + 2.5", Left +

3", Left + 3.5", Left + 4", Left + 4.5", Left +

5", Left + 5.5", Left
73

mercury ormercury and POM which form the basis, and GACT for the 

listing of these two area source categories.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). 

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.:

 

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. 
74

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 and, based. Based on 

available emission data, the best performing unit for mercury is 

a boiler equipped with a fabric filter. However, the mercury 

level (1 lb/TBtu) for this fabric filter equipped unit is based 

on a single test run which is insufficient to determine 

variability. Therefore, the MACT floor emission level was 

determined by using the mercury emission result from(i.e., the 

unit having the reported lowest mercury level based on a three 

run test. This “best performing unit”) is an area source coalfired boiler equipped with an electrostatic precipitator (ESP.). 

The boiler had a three run test average for mercury isof 1.4 

lb/TBtu with a standard deviation (SD) of 0.307 to account for 

variability. Therefore, the resulting MACT floor mercury limit 

for new coal-fired 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 (0.0000025000003

lb/million Btu).

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75

POM – For POM emissions, the only control technology 

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 statesStates for which we have an inventory 

have an applicable emission limit specifically for POM or CO. 

However, one stateState (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 MM BtuMMBtu/h) boilers, the New Jersey’s

requirement is to maintain and operate the source in accordance 

with manufacturers’ specifications.

Considering available stateState 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% 

oxygen. The calculated 99% UPL, to account for variability, is 
76

640 ppm at 3% oxygen. Since this 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 

(310300 ppm at 7% oxygen).

2. 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 wood-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/million 

Btu).

POM – None of the statesStates 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 woodbiomass-fired boilers and from 29 
77

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

ICR survey. Also, stateState 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% UPL is 120 ppm at 3% 

oxygen, rounded up to the nearest 10 ppm. Thus, the proposed 

MACT floor level is 100 ppm CO at 7% oxygen.

3. Existing area source boilers designed for oil firing:

Mercury – There are no available emission data, state 

regulations, or state permits regarding mercury emissions from 

oil-fired area source boilers. Available emission factors (EF) 

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 oilfired 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/million Btu) to new oil-firedNew area source boilers. 

designed for oil firing:
78

POM – None of the statesStates 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 source boilers. State permits limiting CO emissions from 

oil-fired 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 three top performing CO tests from boilers designed to 

burn liquid did not have three test runs. Therefore, the CO 

emission level of the fourth best controlled performing similar 

source is 0.76 ppm at 3 percent oxygen. The SD of the test runs

is 0.04 ppm. Therefore, the 99% UPL and the proposed MACT floor 

level is 1 ppm CO at 3% 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:

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 
79

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% of the average 

firm revenues for some new facilities. This indicates that the 

annual costs for testing and monitoring costs 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, the 

Administrator has determinedwe are not to proposeproposing a 

work practice, as allowed under CAA section 112(h), instead of 

an emission standard) 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 
80

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.

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 
81

PM are fabric filters and electrostatic precipitators (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 million Btu/hrMMBtu/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 and biomass

area source boilers will likely 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 levelslevel 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 
82

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 

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 workmanagement 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 
83

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

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
84

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 ConsiderationHow did we 

decide to exempt these area source categories from title V 

permit requirements?

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 

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% 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 

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85

12% would be comprised of one boiler. The average mercury level 

of the top 12% 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 

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% 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 
86

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:

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 permit requirements?

For the reasons described below, we are proposing to exempt 
87

from title V permitting requirements for 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 

thatto 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 obtain

title V permitting requirements..

CAA section 502(a) provides that the Administrator may 

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

Burdensomeburdensome” on a particular area source category 
88

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 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 
89

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. 

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

propose that title V permitting is unreasonablyunnecessarily

burdensome for a majority of the area source categoriessources

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 
90

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 

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 
91

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 

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 imposerequire 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, and. 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 
92

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 

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, 
93

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 

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 number of sourcesestimated 91,300 area 

source facilities (including schools, hospitals, and churches)
94

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, 

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 these source 

categories.the sources we propose to exempt. Accordingly, the 

third factor supports title V exemptions for these area source 
95

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 

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.
96

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

imposed on thesethe area source categories.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.
97

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

applicable requirements. As stated in our consideration of the

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 
98

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.

Our determinationWe have determined that exemptionit is not 

appropriate to exempt from Title V requirements for thethose

synthetic area sources that installed air pollution controls is 

not appropriate is based on the facts set forth below. We do 

not believe title V is unnecessarily burdensome on these area 

sources.. Unlike many other area source categories that we have 

exempted from title V while implementing 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, 
99

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 

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 and, while there is 
100

some burden on the affected facilities, we think that the burden 

is not significant because these facilities are generally larger 

and more sophisticated than the natural area sources and sources 

that took operational limits to become area sources.

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. We conclude that 

our analysis that title V is unnecessarily burdensome for 

sources in the boiler area source categories is accurate for the 

sources we are exempting, 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 

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

boiler controlled to the MACT/GACT level of control and boilers 
101

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 11,0001,200 tpy for existing units and 

2000340 tpy for new units. Emissions of mercury will be reduced 

by about 20.7 tpy per year for existing units and by 0.1 tpy for 

new units. Emissions of filterable PM will be reduced by about 

60,2006,300 tpy for existing units and 5,0001,300 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 10,500210 tpy for 

existing units and will be reduced by 1,96040 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 

Industrial, Commercial, and Institutional Boilers Area Source 

NESHAP” in the docket.
102

Table 2. Summary of HAP Emissions Reductions for Existing and 

New Sources (tpy)

Source Subcategory PM Non 

Mercury 

Metalsa

Mercuryb

POMCPO

Mb

Existing 

Units

Coal 7,1605,3

50

3524 1,7500.6 0.2

Biomass 41,11076

0

52010 2800.003 5

Oil 11,92023

0

9,930175 1,4300.0

3

3

New 

Units

Coal 546510 3 1340.09 0.02

Biomass 1,900690 138 270.0003 0.5

Oil 2,550100 194628 1,9600.0

05

0.5

a Includes antimony, arsenic, beryllium, cadmium, chromium, 

cobalt, lead, manganese, nickel, and selenium. b Emission reductions for mercury are presented in units of 

pounds per year.

cb 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 
103

boilers. Model costs were then assigned to all existing units 

that could not otherwise meet the proposed standards. The 

resulting total national cost impact of this proposed rule for 

existing units is $4.8 billion696 million dollars in total 

annualized costs after considering fuel savings from efficiency 

improvements.. The total annualized costs (new and existing) 

for installing controls, conducting an annualbiennial tune-upups

and an energy assessment, and implementing testing and 

monitoring requirements, is $5.51.0 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 107160

Biomass 10,958 2,39948

Oil 168,003 2,818436

Facility 

Energy 

Audit

All 14552

New 

Unitsb

Coal 155 10554

Biomass 200 5313

Oil 6,424 1,988244 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 
104

history of installation dates of area source boilers in the 

dataset, the number of additional boilers that could be 

potentially constructed was estimated. The resulting total 

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

3rd year, 2013, is $2.2 billion311 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 $2.1 billion260 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% higher and domestic production may fall by less than 

0.01%. Because of higher domestic prices imports may rise by 

less than 0.01%. Energy prices will not be affected. 

 Social costs are estimated to also be $6.90.5 billion in 

2008 dollars. This is estimated to made up of a $20.3 billion 

loss in domestic consumer surplus, a $30.3 billion loss in 

domestic producer surplus, a $0.21 billion increase in rest of 

the world surplus, and a $0.1.5 billion net loss associated with 

new source costs and fuel savings not modeled in a way that can 
105

be used to attribute it to consumers and producers.

 EPA performed a screening analysis for impacts on small 

entities by comparing compliance costs to sales/revenues (e.g., 

sales and revenue tests). EPA’s analysis found the tests were 

typically higher than 3% 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.

 Estimates ofPrecise job changes were developed in two different ways. The first 

is based on assuming job changes proportional to output changes. This approach provides a point 

estimate of 12,000 less jobs; data is not available to estimate uncertainty ranges. This does not 

include job increases associated with pollutanteffect estimates cannot be 

estimated with certainty. Morgenstern et al. (2002) identify 

three economic mechanisms by which pollution abatement 

activities that 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 or changes related 

to (“cost effect”); and 

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 post regulation production technologies. The second approach is 

more comprehensive and looks may be more or less labor intensive 

(i.e., more directly at all three components but is based on a limited set of 

industrial data. This second method showed a point estimate of a /less labor 

is required per dollar of output) (“factor-shift 

effect”).

Several empirical studies, including Morgenstern et al. 

(2002), suggest the net increase of about 8,000 in jobs.employment decline 

is zero or economically small (e.g., Cole and Elliot, 2007; 

Berman and Bui, 2001). However, statistical 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 

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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 of the data indicates goes beyond what EPA has typically 

done in two 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 we can not state whether the net change will be an increase or a decrease 

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 

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108

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

We also present the results of using the second 

method.Morgenstern paper to estimate employment “cost” and 

“factor-shift” effects (Table 1). Although using the 

Morgenstern parameters to estimate these “cost” and “factorshift” 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% confidence intervals are 

shown for all of the estimates based on the Morgenstern 

parameters. As shown, at the 95% 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 

 

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) 

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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 

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 
110

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 

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 $4.21.0 billion to $102.4 billion 

(2008$, 3 percent discount rate) in the implementation year 

What are the social costs and benefits of this proposed 

rule?
111

(2013). The monetized benefits of this proposed regulatory 

action at a 7 percent discount rate are $3.8 billion910 million

to $9.32.2 billion (2008$). 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 fall between these two estimates.1

Table 45. Summary of the Monetized Benefits Estimates for the 

Proposed Boiler MACT and 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 45 of this preamble. 

Estimated 

Emission 

reductions

(tons per year)

Total 

monetized 

benefits

(3% Discount 

Rate)

Total 

monetized 

benefits

(7% Discount 

Rate)

PM2.5

11,5732,682 tons

PM2.5

2,787 tons SO2

50 tons VOC

$4.20.96 to 

$102.4

$3.80.88 to 

$9.32.1

PM2.5 Precursors

SO2 1,539 tons $0.31 to $0.76 $0.28 to $0.68

VOC 1,179 tons $0.01 to $0.04 $0.01 to $0.03

Total $1.0 to $2.4 $0.91 to $2.2 1

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

rounded to two significant figures so numbers may not sum across 

rows. All fine particles are assumed to have equivalent health 

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

precursors because each ton of precursor reduced has a different 

propensity to form PM2.5. Benefits from reducing hazardous air 

pollutants (HAPs)), ecosystem effects, and visibility impairment

are not included. 

 

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.

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112

These benefits estimates represent the total monetized 

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 

. 

 

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.

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113

health benefits would be lower. 

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

the PM benefits is largely driven by the concentration response 

function for premature mortality. Experts have advised EPA to 

consider a variety of assumptions, including estimates based 

both on empirical (epidemiological) studies and judgments 

elicited from scientific experts, to characterize the 

uncertainty in the relationship between PM2.5 concentrations and 

premature mortality. For this proposed rule we cite two key 

empirical studies, one based on the American Cancer Society 

cohort 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 

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
114

results to various assumptions. 

It should be emphasized that the monetized benefits 

estimates provided above do not include benefits from several 

important benefit categories, including reducing other air 

pollutants, ecosystem effects, and visibility impairment. The 

benefits from reducing carbon monoxide and hazardous air 

pollutants have not been monetized in this analysis, including 

reducing 5839,000 tons of carbon monoxide, 4,400 pounds0.75 ton

of mercury, and 450130 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 $4.90.5 billion (2008$) in the implementation year, and 

the monetized benefits are $4.21.0 billion to $102.4 billion 

(2008$, 3 percent discount rate) for that same year. The 

benefits at a 7 percent discount rate are $3.8 billion910

million to $9.32.2 billion (2008$). Thus, net benefits of this 

rulemaking are estimated at $-680$500 million to $5.41.9 billion 

(2008$, 3 percent discount rate) and $-1.1 billion$400 million

to $4.41.7 billion (2008$, 7 percent discount rate). 
115

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

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

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 
116

to meet the standards of this proposed rule do not require any 

water to operate, nor do they generate any wastewater.

The EPA estimated the additional solid waste that would 

result from this proposed rule to be 62,50014,300 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 $2.6 

million602,000 per year. For new sources installed by 2013, the 

EPA estimated the additional solid waste that would result from 

this proposed rule to be 2,1001,800 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 $88,50075,900 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 1.7 billion206 

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,
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EPA expects an increase of approximately 9122 million kWh in 

national annual energy usage in order to operate the control 

devices.

The Department of Energy has conducted energy assessments 

at selected manufacturing facilities and reports that facilities 

can reduce fuel/energy use by 10 to 15 percent by using best 

practices to increase their energy efficiency. Additionally, 

the EPA expects work practice standards such as boilers 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 3320 trillion BTU of fuel each 

year. For new sources online by 2013, the EPA estimates 2.3.9 

million 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% 

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 
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“Industrial Coal Combustion,” “Industrial Oil Combustion,” 

Industrial Wood/Wood Residue Combustion,” “Commercial Coal 

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

Wood/Wood Residue Combustion” as source categories that 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, 

and also reduce Hg emissions, as is evidenced by performance 
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data. Specifically, the emission tests obtained at currently

operating major source boilers show that the proposed MACT

regulations for area source boilers will 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, CAA Section 129(a)(4) allows EPA towe

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 and process heaters 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.
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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” 

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 
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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 

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, 
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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 

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 
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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 

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 
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Procedure Act or any other statute unless the agency certifies 

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

substantial number of small entities. Small entities include 

small businesses, small organizations, and small governmental 

jurisdictions.

For purposes of assessing the impacts of today’s proposed 

rule on small entities, small entity is defined as: (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 
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recommendation of representatives of the small entities that

potentially would be subject to the requirements of this rule.

(a1) Panel Process and Panel Outreach

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

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 
126

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 

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.

(1(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 
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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 

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 orand 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 
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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.

(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 
129

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 

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 

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develop a small government agency plan under section 203 of the 

UMRA. The plan must provide for notifying potentially affected 

small governments, enabling officials of affected small 

governments to have meaningful and timely input in the 

development of regulatory proposals with significant 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.
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Section 112(d) of the CAA directs us to develop NESHAP 

which require existing and new major sources to control 

emissions of HAP using MACT based standards. This NESHAP 

applies to all industrial, commercial, and institutional boilers 

and process heaters located at major sources of HAP emissions.

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

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

for regulation under CAA section 112(c). CAA section 

112(k)(3)(B) calls for EPA to identify at least 30 HAP which, as 

the result of emissions from area sources, pose the greatest 

threat to 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 
132

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 

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. 
133

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 

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 

rule is based represents the MACT floor for industrial boilers 

and process heaters and, as a result, it is the least costly and 

least burdensome alternative.

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). 

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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 

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 

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rule and the predicted change in prices and production in the 

affected industries, the estimated social costs of the proposed 

rule are $6.80.5 billion (2008 dollars).

 It is estimated that 3 years after implementation of the 

proposed rule, HAPs HAP would be reduced by thousandshundreds of 

tons, including reductions in metallic HAP including mercury, 

hydrochloric acid, hydrogen fluoride, metallic HAP including 

mercury, and several other organic HAP from area source boilers

and process heaters.. Studies have determined a relationship 

between exposure to these HAP and the onset of cancer, however, 

the Agency is unable to provide a monetized estimate of the HAP 

benefits at this time. In addition, there are significant 

reductions in PM2.5 and in SO2 that would occur, including 23

thousand2,700 tons of PM2.5 and 384 thousand1,500 tons of SO2. 

These reductions occur 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 worklost 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 

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associated with the PMPM2.5 and SO2 emissions reductions. For SO2

and PMPM2.5, 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 is range from $161.0 billion (2008 dollars) to 

$402.4 billion (2008 dollars) when using a 3 percent discount 

rate (or from $150.9 billion (2008 dollars)to $362.2 billion

(2008 dollars) when using a 7 percent discount rate). This 

estimate, at a 3 percent discount rate, is about $11 billion 

(2008 dollars) to $35 billion (2008 dollars) higher than the 

estimated social costs shown earlier in this section.. 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.

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.

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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 

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, and little impact on communities that may be affected by 

the proposed rule. (less than 0.02%). In addition, there should 
138

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. Although the proposed rule does not affect any 

State, local, or Tribal governments, we have consulted with 

State and local air pollution control officials. We also have 

held meetings on the proposed rule with many of the stakeholders 

from numerous individual companies, environmental groups, 

consultants and vendors, labor unions, and other interested 

parties. We have added materials to the Air Docket to document 

these meetingsConsistent 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 

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139

Governors Association; (2) National Conference of State 

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

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

Association of Counties, (7) International City/County 

Management Association, (8) National Association of Towns and 

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

Environmental Council of States. These 10 organizations of 

elected State and local officials have been identified by EPA as 

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

consultation with elected officials. The purposes of the 

consultation were to 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.

In addition, we have determined that the proposed rule

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Consistent with section 205, EPA has identified and 

considered a reasonable number of regulatory alternatives. 

Because an initial screening analysis for impact on small 

entities indicated a likely significant impact for substantial 

numbers EPA convened a SBAR Panel to obtain advice and 

recommendation of representatives of the small entities that

potentially would be subject to the requirements of 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 
141

standards are based represents the MACT floor for mercury for 

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

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 
142

standard/management practice also would result in reduced 

compliance costs with respect to monitoring/testing for the 

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 some sources 

affected by the proposed rule, the impacts are not expected to 

be significant. Therefore, today's proposed rule is not subject 

to the requirements of section 203 of the UMRAboilers 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%. Hospitals’and schools’ revenue tests fall 

below 1%. 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 (64 FR 43255, August 10, 

1999), requires, EPA to develop an accountable process to ensure 

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143

“meaningful and timely input by State and local officials in the 

development of regulatory policiesmay not issue an action that 

havehas federalism implications.” “Policies, that have 

federalism implications” is defined in the Executive Order to 

include regulations that have “imposes substantial direct 

effects on the States, on the relationship between the 

nationalcompliance costs, and that is not required by statute, 

unless the Federal government and the Statesprovides the funds 

necessary to pay the direct compliance costs incurred by State 

and local governments, or onEPA consults with State and local 

officials early in the distributionprocess of power and 

responsibilities amongdeveloping the various levels of 

government.

The proposed rule does notaction. 

EPA has concluded that this action may have federalism 

implications. It will not have, because it may impose

substantial direct effects on the States, on the relationship 

between the national government and the States,compliance costs 

on State or on the distribution of power and responsibilities 

among the various levels of government,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 specified in required by 

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section 6(b) of Executive Order 13132. Thus, Executive Order 

13132 does not apply to 

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

proposed rule. 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 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 

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145

to emission limits for Hg and CO, while large biomass and oilfired 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 

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 solicitedsolicits

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146

comment on thethis proposed ruleaction 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 

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.

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147

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 

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), 
148

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 

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. 
149

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 

(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 
150

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 

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 
151

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 

(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 
152

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 

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 
153

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 

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 
154

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 155 of 208

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. 

* * * * *

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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 emission limits and operating limits standards

must I meet?

63.11202 What are the work practice standards and management 

practices?

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?

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128

Continuous Compliance Requirements

63.11220 How do I monitor and collect data to demonstrate 

continuous compliance?

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 
129

hazardous air pollutants (HAP), as defined in §63.2.

§63.11194 What is the affected source of this subpart?

(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. 
130

Otherwise, you are exempt from the obligation to obtain a permit 

under 40 CFR part 70 or 40 CFR part 71, provided you are not 

otherwise required by law to obtain a permit under 40 CFR 

70.3(a) or 40 CFR 71.3(a). Notwithstanding the previous 

sentence, you must continue to comply with the provisions of 

this subpart.

§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 
131

must achieve compliance with the applicable provisions in this 

subpart no later than [INSERT THE DATE 3 YEARS AFTER PUBLICATION 

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.
132

Initial Compliance Requirements

§63.11205 What are my general requirements for complying with 

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 
133

emission limit specified in Table 1 of this subpart that applies 

to you by either conducting performance (stack) tests, as 

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 
134

that is specified in §63.11196 and according to the applicable 

provisions in §63.7(a)(2).

(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 
135

level fuel mercury concentration of the composite samples 

analyzed for each fuel type using Equation 1 of this section. 

P90 = mean + (SD * t) (Eq. 1)

Where:

P90 = 90th percentile confidence level mercury 

concentration, in pounds per million Btu;

mean = Arithmetic average of the fuel mercury 

concentration in the fuel samples analyzed 

according to §63.11213, in units of pounds 

per million Btu;

SD = Standard deviation of the mercury 

concentration in the fuel samples analyzed 

according to §63.11213, in units of pounds 

per million Btu;

t = t distribution critical value for 90th 

percentile (0.1) probability for the 

appropriate degrees of freedom (number of 

samples minus one) as obtained from a 

Distribution Critical Value Table.

(3) To demonstrate compliance with the applicable mercury 

emission limit, the emission rate that you calculate for your 

boiler using Equation 1 of this section must be less than the 

applicable mercury emission limit.

§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 
136

fuels that have the highest content of mercury, and you must 

demonstrate initial compliance based on these tests.

(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. 
137

(c) Determine the concentration of mercury in the fuel in 

units of pounds per million Btu of each composite sample for 

each fuel type according to the procedures in Table 5 to this 

subpart.

§63.11214 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 within 90%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 or process heater continues to meet the 
138

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 within 90%at or below 75 percent of 

the emission limit, and if there are no changes in the operation 

of the affected source or air pollution control equipment that 

could increase emissions, but each such performance test must be 

conducted no more than 36 months after the previous performance 

test.

(d) If a performance test shows emissions exceeded 90%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 
139

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?

(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 
140

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 

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. Boilers that 

have an applicable CO emission limit and are required to install 

and operate a CEMS, may not use data recorded during periods 

when the boiler is operating at less than 50 percent of its 

rated capacity.

§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 
141

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) You (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 lower emissions of mercury than the applicable 

emission limit.

(3) If (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 
142

emission limit.

(4) If your unit is controlled with a fabric filter, and 

you demonstrate continuous compliance using a bag leak detection 

system, you must initiate corrective action within 1 hour of a 

bag leak detection system alarm and operate and maintain the 

fabric filter system such that the alarm does not sound more 

than 5 percent of the operating time during a 6-month period. 

You must also keep records of the date, time, and duration of 

each alarm, the time corrective action was initiated and 

completed, and a brief description of the cause of the alarm and 

the corrective action taken. You must also record the percent 

of the operating time during each 6-month period that the alarm 

sounds. In calculating this operating time percentage, if 

inspection of the fabric filter demonstrates that no corrective 

action is required, no alarm time is counted. If corrective 

action is required, each alarm shall 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 carbon monoxideCO 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 
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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 

required in §63.11224(c) to demonstrate continuous compliance.

(b) You must conduct a tune-up of the boiler 

annuallybiennially 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 
144

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 

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 
145

§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 

(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 
146

criteria (e.g., calibrations).

(2) In your site-specific monitoring plan, you must also 

address paragraphs (b)(2)(i) through (iii) of this section.

(i) Ongoing operation and maintenance procedures in 

accordance with the general requirements of §63.8(c)(1), (3), 

and (4)(ii);

(ii) Ongoing data quality assurance procedures in 

accordance with the general requirements of §63.8(d); and

(iii) Ongoing recordkeeping and reporting procedures in 

accordance with the general requirements of §63.10(c), (e)(1), 

and (e)(2)(i).

(3) You must conduct a performance evaluation of each CMS 

in accordance with your site-specific monitoring plan.

(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 
147

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 

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 
148

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.

(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 
149

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.

(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 
150

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 

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 
151

[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 

compliance, as applicable, and signed by a responsible official:

(i) “This facility complies with the requirements in 

§63.1120211222(b) to conduct an annuala biennial tune-up of the 

boiler”.

(ii) “This facility has had an energy assessment performed

according to §63.1120211215.”

(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 

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152

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.

(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 
153

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 

work practices, emission reduction measures, and management 

practices required by §63.1120211215 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 
154

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;

(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, 
155

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 

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.
156

§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) 

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.
157

(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 

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 littermanure, 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. 

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0" + 0.5" + 1" + 1.5" + 2" + 2.5" + 3" +

3.5" + 4" + 4.5" + 5" + 5.5" + 6" + 6.5"

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158

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 

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 amount 

of coal either 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 

Formatted: Font: Courier New
159

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 

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 
160

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

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
161

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 

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 
162

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.

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, 
163

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.

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 
164

(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 

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 
165

gas does not constitute a period of natural gas curtailment or 

supply interruption.

Qualified personnel mean specialists in evaluating energy 

systems who have successfully completed the DOE Qualified 

Specialist program 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 

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 For the You must meet the 
166

is in this 

subcategory...

following 

pollutants...

following emission limits 

...

1. New coal a. Particulate 

Matter

b. Mercury

c. Carbon 

Monoxide

0.02 lb per MMBtu of heat 

input; or

0.0000025000003 lb per 

MMBtu of heat input

300310 ppm by volume on a 

dry basis corrected to 7 

percent oxygen (daily 

average) 

2. New biomass a. Particulate 

Matter

b. Mercury

c. Carbon

Monoxide

0.02 lb per MMBtu of heat 

input; or

0.0000004 lb per MMBtu of 

heat input

100 ppm by volume on a 

dry basis corrected to 7

percent oxygen (daily

average)

3. New oil a. Particulate 

Matter

b. Mercury

c. Carbon

Monoxide

0.06 lb per MMBtu of heat 

input; or

0.0000003 lb per MMBtu of 

heat input

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

0.0000025000003 lb per 

MMBtu of heat input

300310 ppm by volume on a 

dry basis corrected to 7 

percent oxygen (daily 

average) 

Formatted: Space After: 0 pt

Formatted: Indent: Left: 0", Hanging: 0.88",

Space Before: 0 pt, After: 0 pt
167

5. Existing 

biomass

(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

0.0000004 lb per MMBtu of 

heat input

165170 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) 

a. Particulate 

Matter

b. Mercury

c. Carbon 

Monoxide

0.3 lb per MMBtu of heat 

input; or

0.000008 lb per MMBtu of 

heat input

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 

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 

annuallybiennially 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, 
168

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:

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 Maintain opacity to less than or 

equal to 10 percent opacity (daily
169

precipitator 

control

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:

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.

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 
170

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.

(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.
171

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.
172

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:
173

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.
174

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.
175

§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.
176

§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