31896 Federal Register / Vol. 75, No. 107 / Friday, June 4, 2010 / Proposed Rules 

ENVIRONMENTAL PROTECTION 

AGENCY 

40 CFR Part 63 

[EPA–HQ–OAR–2006–0790; FRL–9148–3] 

RIN 2060–AM44 

National Emission Standards for 

Hazardous Air Pollutants for Area 

Sources: Industrial, Commercial, and 

Institutional Boilers 

AGENCY: Environmental Protection 

Agency (EPA). 

ACTION: Proposed rule. 

SUMMARY: EPA is proposing national 

emission standards for control of 

hazardous air pollutants from two area 

source categories: Industrial boilers and 

commercial and institutional boilers. 

The proposed emission standards for 

control of mercury emissions from coalfired area source boilers and the 

proposed emission standards for control 

of polycyclic organic matter emissions 

from all area source boilers are based on 

the maximum achievable control 

technology. The proposed emission 

standards for control of mercury 

emissions from biomass-fired and oilfired area source boilers and for other 

hazardous air pollutants are based on 

EPA’s proposed determination as to 

what constitutes the generally available 

control technology or management 

practices. 

EPA is also clarifying that gas-fired 

area source boilers are not needed to 

meet the 90 percent requirement of 

section 112(c)(3) of the Clean Air Act. 

Finally, we are also proposing that 

existing area source facilities with an 

affected boiler with a designed heat 

input capacity of 10 million Btu per 

hour or greater undergo an energy 

assessment on the boiler system to 

identify cost-effective energy 

conservation measures. 

DATES: Comments must be received on 

or before July 19, 2010. 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 July 6, 2010. 

Public Hearing. We will hold a public 

hearing concerning this proposed rule 

and the interrelated proposed Boiler 

major source, CISWI, and RCRA rules, 

discussed in this proposal and 

published in the proposed rules section 

of today’s Federal Register, on June 21, 

2010. Persons requesting to speak at a 

public hearing must contact EPA by 

June 14, 2010. 

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 (e-mail) to a-and-rdocket@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 

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 

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. 

Public Hearing: We will hold a public 

hearing concerning this proposed rule 

on June 21, 2010. Persons interested in 

presenting oral testimony at the hearing 

should contact Ms. Pamela Garrett, 

Energy Strategies Group, at (919) 541– 

7966 by June 14, 2010. The public 

hearing will be held in the Washington, 

DC area at a location and time that will 

be posted at the following Web site: 

http://www.epa.gov/airquality/ 

combustion. Please refer to this Web site 

to confirm the date of the public hearing 

as well. If no one requests to speak at 

the public hearing by June 14, 2010 then 

the public hearing will be cancelled and 

a notification of cancellation posted on 

the following Web site: http:// 

www.epa.gov/airquality/combustion. 

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. 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; email address: johnson.mary@epa.gov. 

SUPPLEMENTARY INFORMATION: 


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Outline. The information in this 

preamble is organized as follows: 

I. General Information 

A. Does this action apply to me? 

B. What should I consider as I prepare my 

comments to EPA? 

C. Where can I get a copy of this 

document? 

D. When would a public hearing occur? 

II. Background Information 

A. What is the statutory authority and 

regulatory approach for this proposed 

rule? 

B. What source categories are affected by 

the proposed standards? 

C. What is the relationship between this 

proposed rule and other related national 

emission standards? 

D. How did we gather information for this 

proposed rule? 

E. How are the area source boiler HAP 

addressed by this proposed rule? 

III. Clarification of the Source Category List 

IV. Summary of This Proposed Rule 

A. Do the proposed standards apply to my 

source? 

B. What is the affected source? 

C. When must I comply with the proposed 

standards? 

D. What are the proposed MACT and 

GACT standards? 

E. What are the Startup, Shutdown, and 

Malfunction (SSM) requirements? 

F. What are the proposed initial 

compliance requirements? 

G. What are the proposed continuous 

compliance requirements? 

H. What are the proposed notification, 

recordkeeping and reporting 

requirements? 

I. Submission of Emissions Test Results to 

EPA 

V. Rationale of This Proposed Rule 

A. How did EPA determine which 

pollution sources would be regulated 

under this proposed rule? 

B. How did EPA determine the 

subcategories for this proposed rule? 

C. What surrogates are we using? 

D. How did EPA determine the proposed 

standards for existing units? 

1. MACT Analysis for Mercury From CoalFired Boilers and POM 

2. GACT Determination for Existing Area 

Source Boilers 

E. How did EPA determine the proposed 

standards for new units? 

1. MACT Analysis for Mercury From CoalFired Boilers and POM 

2. GACT Determination for New Area 

Source Boilers 

F. How did we select the compliance 

requirements? 

G. Alternative MACT Standards for 

Consideration 

H. How did we decide to exempt these area 

source categories from title V permitting 

requirements? 

VI. Summary of the Impacts of This Proposed 

Rule 

A. What are the air impacts? 

B. What are the cost impacts? 

C. What are the economic impacts? 

D. What are the social costs and benefits 

of this proposed rule? 

E. What are the water and solid waste 

impacts? 

F. What are the energy impacts? 

VII. Relationship of This Proposed Action to 

CAA Section 112(c)(6) 

VIII. Statutory and Executive Order Review 

A. Executive Order 12866: Regulatory 

Planning and Review 

B. Paperwork Reduction Act 

C. Regulatory Flexibility Act (RFA) 

D. Unfunded Mandates Reform Act of 1995 

E. Executive Order 13132: Federalism 

F. Executive Order 13175: Consultation 

and Coordination With Indian Tribal 

Governments 

G. Executive Order 13045: Protection of 

Children From Environmental Health 

Risks and Safety Risks 

H. Executive Order 13211: Actions 

Concerning Regulations That 

Significantly Affect Energy Supply, 

Distribution, or Use 

I. National Technology Transfer and 

Advancement Act 

J. Executive Order 12898: Federal Actions 

To Address Environmental Justice in 

Minority Populations and Low-Income 

Populations 

I. General Information 

A. Does this action apply to me? 

The regulated categories and entities 

potentially affected by the proposed 

standards include: 

Category NAICS Code 1 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 

affected by this action. To determine 

whether your facility, company, 

business, organization, etc., would be 

regulated by this action, you should 

examine the applicability criteria in 40 

CFR 63.11193 of subpart JJJJJJ (National 

Emission Standards for Hazardous Air 

Pollutants for Industrial, Commercial, 

and Institutional Boilers Area Sources). 

If you have any questions regarding the 

applicability of this action to a 

particular entity, consult either the 

delegated regulatory authority for the 

entity or your EPA regional 

representative as listed in 40 CFR 63.13 

of subpart A (General Provisions). 

B. What should I consider as I prepare 

my comments to EPA? 

Do not submit information containing 

CBI to EPA through http:// 

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

deliver information identified as CBI 

only to the following address: Roberto 

Morales, OAQPS Document Control 

Officer (C404–02), Office of Air Quality 

Planning and Standards, U.S. 

Environmental Protection Agency, 

Research Triangle Park, North Carolina 

27711, Attention: Docket ID EPA–HQ– 

OAR–2006–0790. Clearly mark the part 

or all of the information that you claim 

to be CBI. For CBI information in a disk 

or CD–ROM that you mail to EPA, mark 

the outside of the disk or CD–ROM as 

CBI and then identify electronically 

within the disk or CD–ROM the specific 

information that is claimed as CBI. In 

addition to one complete version of the 

comment that includes information 

claimed as CBI, 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. 


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C. Where can I get a copy of this 

document? 

In addition to being available in the 

docket, an electronic copy of this 

proposed action will also be available 

on the Worldwide Web (WWW) through 

the Technology Transfer Network 

(TTN). Following signature, a copy of 

the proposed action will be posted on 

the TTN’s policy and guidance page for 

newly proposed or promulgated rules at 

the following address: http:// 

www.epa.gov/ttn/oarpg/. The TTN 

provides information and technology 

exchange in various areas of air 

pollution control. 

D. When would a public hearing occur? 

We will hold a public hearing 

concerning this proposed rule on June 

21, 2010. Persons interested in 

presenting oral testimony at the hearing 

should contact Ms. Pamela Garrett, 

Energy Strategies Group, at (919) 541– 

7966 by June 14, 2010. The public 

hearing will be held in the Washington, 

DC area at a location and time that will 

be posted at the following Web site: 

http://www.epa.gov/airquality/ 

combustion. Please refer to this Web site 

to confirm the date of the public hearing 

as well. If no one requests to speak at 

the public hearing by June 14, 2010 then 

the public hearing will be cancelled and 

a notification of cancellation posted on 

the following Web site: http:// 

www.epa.gov/airquality/combustion. 

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 HAP-emitting stationary 

source that is not a major source. 

CAA section 112(k)(3)(B) calls for 

EPA to identify at least 30 HAP which, 

as the result of emissions from area 

sources, pose the greatest threat to 

public health in the largest number of 

urban areas. EPA implemented this 

provision in 1999 in the Integrated 

Urban Air Toxics Strategy (Strategy), (64 

FR 38715, July 19, 1999). Specifically, 

in the Strategy, EPA identified 30 HAP 

that pose the greatest potential health 

threat in urban areas, and these HAP are 

referred to as the ‘‘30 urban HAP.’’ CAA 

section 112(c)(3) requires EPA to list 

sufficient categories or subcategories of 

area sources to ensure that area sources 

representing 90 percent of the emissions 

of the 30 urban HAP are subject to 

regulation. A primary goal of the 

Strategy is to achieve a 75 percent 

reduction in cancer incidence 

attributable to HAP emitted from 

stationary sources. 

Under CAA section 112(d)(5), we may 

elect to promulgate standards or 

requirements for area sources ‘‘which 

provide for the use of generally 

available control technologies or 

management practices (‘GACT’) by such 

sources to reduce emissions of 

hazardous air pollutants.’’ Additional 

information on GACT is found in the 

Senate report on the legislation (Senate 

Report Number 101–228, December 20, 

1989), which describes GACT as: 

* * * methods, practices and techniques 

which are commercially available and 

appropriate for application by the sources in 

the category considering economic impacts 

and the technical capabilities of the firms to 

operate and maintain the emissions control 

systems. 

Consistent with the legislative history, 

we can consider costs and economic 

impacts in determining GACT, which is 

particularly important when developing 

regulations for source categories that 

may have many small businesses such 

as these. 

Determining what constitutes GACT 

involves considering the control 

technologies and management practices 

that are generally available to the area 

sources in the source category. We also 

consider the standards applicable to 

major sources in the analogous source 

category to determine if the control 

technologies and management practices 

are transferable and generally available 

to area sources. In appropriate 

circumstances, we may also consider 

technologies and practices at area and 

major sources in similar categories to 

determine whether such technologies 

and practices could be considered 

generally available for the area source 

categories at issue. Finally, as noted 

above, in determining GACT for a 

particular area source category, we 

consider the costs and economic 

impacts of available control 

technologies and management practices 

on that category. 

While GACT may be a basis for 

standards for most types of HAP emitted 

from area sources, CAA section 

112(c)(6) requires that EPA list 

categories and subcategories of sources 

assuring that sources accounting for not 

less than 90 percent of the aggregate 

emissions of each of the seven specified 

hazardous air pollutants (HAP) are 

subject to standards under section 

112(d)(2) or (d)(4). The seven HAP 

specified in section 112(c)(6) are as 

follows: alkylated lead compounds, 

polycyclic organic matter, 

hexachlorobenzene, mercury, 

polychlorinated biphenyls, 2,3,7,9- 

tetrachlorodibenzofurans, and 2,3,7,8- 

tetrachloridibenzo-p-dioxin. 

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

source categories currently includes 

industrial coal combustion, industrial 

oil combustion, industrial wood 

combustion, commercial coal 

combustion, commercial oil 

combustion, and commercial wood 

combustion. See 63 FR 17849. We listed 

these source categories under CAA 

section 112(c)(6) based on the source 

categories’ contribution of mercury and 

polycyclic organic matter (POM). In the 

documentation for the CAA section 

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

combustion categories included 

institutional fuel combustion (see ‘‘1990 

Emissions Inventory of Section 112(c)(6) 

Pollutants, Final Report,’’ April 1998). 

As discussed in greater detail below, we 

re-examine the emission inventory and 

the need to address categories under 

CAA section 112(c)(6) during the rule 

development process. Based on this reexamination, we now believe we will 

only need to address the coal-fueled 

portion of these categories under CAA 

section 112(c)(6). 

With this proposed rule and the major 

source boilers rule, we currently believe 

that we have subjected to regulation or 

proposed to regulate at least 90 percent 

of the 1990 section 112(c)(6) emissions 

inventory for mercury. Coal-fired area 

source boilers represent approximately 

4.3 percent of the 1990 section 112(c)(6) 

emissions inventory for mercury. In 

contrast, biomass- and oil-fired boilers 

represent approximately 0.34 percent. 

Consequently, we are proposing to 

regulate coal-fired boilers under MACT 

because we need these sources to meet 

the 90 percent requirement for mercury 

in section 112(c)(6). We are proposing to 

regulate biomass-fired and oil-fired 

types of boilers under GACT to meet the 

90 percent requirement for mercury in 

section 112(c)(3). 

We solicit comment on whether we 

should nevertheless establish MACTbased 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 of measures, processes, 

methods, systems, or techniques 

including, but not limited to: (1) 


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Reducing the volume of, or eliminating 

emissions of, such pollutants through 

process changes, substitutions of 

materials, or other modifications; (2) 

enclosing systems or processes to 

eliminate emissions; (3) collecting, 

capturing, or treating such pollutants 

when released from a process, stack, 

storage or fugitive emission point; (4) 

design, equipment, work practices, or 

operational standards as provided in 

CAA section 112(h); or (5) a 

combination of the above. 

The MACT floor is the minimum 

control level allowed for NESHAP and 

is defined under CAA section 112(d)(3). 

For new sources, MACT based 

standards cannot be less stringent than 

the emission control achieved in 

practice by the best-controlled similar 

source, as determined by the 

Administrator. The MACT based 

standards for existing sources can be 

less stringent than standards for new 

sources, but they cannot be less 

stringent than the average emission 

limitation achieved by the best 

performing 12 percent of existing 

sources in the category or subcategory 

(for which the Administrator has 

emission information) for source 

categories and subcategories with 30 or 

more sources, or the best performing 5 

sources for categories and subcategories 

with fewer than 30 sources (CAA 

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

Although emission standards are 

often structured in terms of numerical 

emissions limits, alternative approaches 

are sometimes necessary and authorized 

pursuant to CAA section 112. For 

example, in some cases, physically 

measuring emissions from a source may 

be not practicable due to technological 

and economic limitations. CAA section 

112(h) authorizes the Administrator to 

promulgate a design, equipment, work 

practice, or operational standard, or 

combination thereof, consistent with the 

provisions of CAA sections 112(d) or (f), 

in those cases where, in the judgment of 

the Administrator, it is not feasible to 

prescribe or enforce an emission 

standard. CAA section 112(h)(2) 

provides that the phrase ‘‘not feasible to 

prescribe or enforce an emission 

standard’’ includes the situation in 

which the Administrator determines 

that * * * the application of 

measurement methodology to a 

particular class of sources is not 

practicable due to technological and 

economic limitations. 

As noted above, we listed industrial 

coal combustion, industrial oil 

combustion, industrial wood 

combustion, commercial coal 

combustion, commercial oil 

combustion, and commercial wood 

combustion under CAA section 

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

contribution of mercury and polycyclic 

organic matter (POM). We listed these 

same categories under section 112(c)(3) 

for their contribution of mercury, 

arsenic, beryllium, cadmium, lead, 

chromium, manganese, nickel, 

polycyclic organic matter (POM) (as 7– 

PAH (polynuclear aromatic 

hydrocarbons)), ethylene dioxide, and 

polychlorinated biphenyls (PCB). 

We have developed proposed 

standards to reflect the application of 

MACT for mercury from coal-fired area 

source boilers and POM from all area 

source boilers under section 112(c)(6) 

and have applied GACT for the other 

pollutants noted above. 

B. What source categories are affected 

by the proposed standards? 

The source categories affected by the 

proposed standards are industrial 

boilers and commercial and 

institutional boilers. Both source 

categories were included in the area 

source list published on July 19, 1999 

(64 FR 38721). The inclusion of these 

two source categories on the CAA 

section 112(c)(3) area source category 

list is based on 1990 emissions data, as 

EPA used 1990 as the baseline year for 

that listing. We describe above the 

pollutants that formed the basis of the 

listings. 

This proposed rule would apply to all 

existing and new industrial boilers, 

institutional boilers, and commercial 

boilers located at area sources. The 

industrial boiler source category 

includes boilers used in manufacturing, 

processing, mining, refining, or any 

other industry. The commercial boiler 

source category includes boilers used in 

commercial establishments such as 

stores/malls, laundries, apartments, 

restaurants, and hotels/motels. The 

institutional boiler source category 

includes boilers used in medical centers 

(e.g., hospitals, clinics, nursing homes), 

educational and religious facilities (e.g., 

schools, universities, churches), and 

municipal buildings (e.g., courthouses, 

prisons). 

Boiler means an enclosed combustion 

device having the primary purpose of 

recovering thermal energy in the form of 

steam or hot water. 

C. What is the relationship between this 

proposed rule and other related 

national emission standards? 

This proposed rule regulates 

industrial boilers and institutional/ 

commercial boilers that are area sources 

of HAP. Today, in a parallel action, a 

NESHAP for industrial, commercial, 

and institutional boilers located at major 

sources is being proposed reflecting 

application of MACT. The major source 

NESHAP regulates emissions of 

particulate matter (PM) (as a surrogate 

for non-mercury metals), mercury, 

hydrogen chloride (HCl)(as a surrogate 

for acid gases), dioxins/furans, and 

carbon monoxide (CO) (as a surrogate 

for non-dioxin organic HAP) from 

existing and new major source boilers. 

This proposed rule covers boilers 

located at area source facilities. In 

addition to the major source MACT for 

boilers being issued today and this rule, 

the Agency is also issuing emission 

standards today pursuant to CAA 

section 129 for commercial and 

industrial solid waste incineration 

units. In a parallel action, EPA is 

proposing a solid waste definition 

rulemaking pursuant to Subtitle D of 

RCRA. That action is relevant to this 

proceeding because if an industrial, 

commercial, or institutional unit located 

at an area source combusts secondary 

materials that are ‘‘solid waste,’’ as that 

term is defined by the Administrator 

under RCRA, those units would be 

subject to section 129 of the CAA, not 

section 112. 

As background, in 2007, the United 

States Court of Appeals for the District 

of Columbia Circuit (DC Circuit) vacated 

the CISWI Definitions Rule, which EPA 

issued pursuant to CAA section 129. 

The court found that the definitions in 

that rule were inconsistent with the 

CAA. Specifically, the Court held that 

the term ‘‘solid waste incineration unit’’ 

in CAA Section 129(g)(1) 

‘‘unambiguously include[s] among the 

incineration units subject to its 

standards any facility that combusts any 

commercial or industrial solid waste 

material at all—subject to the four 

statutory exceptions identified [in CAA 

Section 129(g)(1)].’’ NRDC v. EPA, 489 

F.3d at 1257–58. 

Based on the information available to 

the Agency, we believe that the boilers 

that are subject to this area source rule 

combust coal, oil, and biomass. EPA 

does not believe that the boilers subject 

to this rule combust any non-hazardous 

secondary materials, whether they are 

considered a solid waste or not. If you 

are aware of such materials being 

combusted at these boilers, please 

provide specific information as to the 

type of secondary material being 

combusted and at what type of facilities 

and in what quantities. If the final form 

of the solid waste definition results in 

any secondary materials being 

considered solid waste it will be 

important to know whether units are 

burning those materials, because that 

would result in those units becoming 

incinerators subject to regulation under 


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section 129 and no longer being 

considered boilers. 

There is also another CAA regulation 

that is relevant in that they apply to 

some of the affected sources in this rule. 

For example, in 1986, EPA codified new 

source performance standards (NSPS) 

for industrial, commercial, and 

institutional boilers (40 CFR part 60, 

subparts Db and Dc) and revised 

portions of them in 1999 and 2006. The 

NSPS regulates emissions of PM, sulfur 

dioxide (SO2), and nitrogen oxides from 

boilers constructed after June 19, 1984. 

Sources subject to the NSPS that are 

located at area source facilities are also 

subject to this proposed rule because 

this proposed rule regulates HAP. In 

developing this proposal, we have 

streamlined the monitoring and 

recordkeeping requirements to avoid 

duplicating requirements in the NSPS. 

D. How did we gather information for 

this proposed rule? 

We gathered information for this 

proposed rule from States’ boiler 

inspection lists, company Web sites, 

published literature, State permits, 

current State and Federal regulations, 

and from an Information Collection 

Request (ICR) conducted for the major 

source NESHAP. 

We developed an initial nationwide 

population of area source boilers based 

on boiler inspector databases from 13 

States. The boiler inspector databases 

include steam boilers that are required 

to be inspected for safety or insurance 

purposes. We classified the area source 

boilers to NAICS codes based on the 

‘‘name’’ of the facility at which the boiler 

was located. However, many of the 

boilers in the boiler inspector database 

could not be readily assigned to an 

NAICS code. 

We reviewed State and other Federal 

regulations that apply to the area 

sources in the source categories for 

information concerning existing HAP 

emission control approaches. For 

example, as noted above, the NSPS for 

small industrial, commercial, and 

institutional boilers in 40 CFR part 60, 

subpart Dc apply to boilers at some area 

sources. Similarly, permit requirements 

established by the Ohio, Illinois, 

Vermont, New Hampshire, and Maine 

air regulatory agencies apply to some 

area sources. We also reviewed 

standards for boilers at major sources 

that would be appropriate for and 

transferable to boilers at area sources. 

For example, we determined that 

management practices, such as, annual 

tune-ups and operator training 

applicable to major source boilers are 

equally feasible for boilers at area 

sources. 

E. How are the area source boiler HAP 

addressed by this proposed rule? 

As explained above, industrial coal 

combustion, industrial oil combustion, 

industrial wood combustion, 

commercial coal combustion, 

commercial oil combustion, and 

commercial wood combustion are listed 

under CAA section 112(c)(6) due to 

contributions of mercury and POM and 

these same categories are listed under 

CAA section 112(c)(3) for their 

contribution of mercury, arsenic, 

beryllium, cadmium, lead, chromium, 

manganese, nickel, POM, ethylene 

dioxide, and PCB. 

With respect to the 112(c)(3) 

pollutants, we used surrogates because, 

as explained below, it was not practical 

to establish individual standards for 

each specific HAP. We grouped the 

112(c)(3) pollutants, which formed the 

basis for the listing of these two source 

categories, into three common 

groupings: mercury, non-mercury 

metallic HAP (arsenic, beryllium, 

cadmium, chromium, lead, manganese, 

and nickel), and organic HAP (POM, 

ethylene dichloride, and PCB). In 

general, the pollutants within each 

group have similar characteristics and 

can be controlled with the same 

techniques. 

For the non-mercury metallic HAP, 

we selected PM as a surrogate. The 

inherent variability and unpredictability 

of the non-mercury metal HAP 

compositions and amounts in fuel has a 

material effect on the composition and 

amount of non-mercury metal HAP in 

the emissions from the boiler. As a 

result, establishing individual 

numerical emissions limits for each 

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 nonmercury metal HAP. Furthermore, 

establishing separate standards for each 

individual HAP would impose costly 

and significantly more complex 

compliance and monitoring 

requirements and achieve little, if any, 

HAP emissions reductions beyond what 

would be achieved using the surrogate 

pollutant approach. 

For organic HAP, we selected CO as 

a surrogate for organic compounds, 

including POM, emitted from the 

various fuels burned in boilers. The 

presence of CO is an indicator of 

incomplete combustion. A high level of 

CO in emissions is an indicator of 

incomplete combustion and, thus, a 

potential indication of elevated organic 

HAP emissions. Monitoring equipment 

for CO is readily available, which is not 

the case for organic HAP. Also, it is 

significantly easier and less expensive 

to measure and monitor CO emissions 

than to measure and monitor emissions 

of each individual organic HAP. We 

considered other surrogates, such as 

total hydrocarbon (THC), but lacked 

data on emissions and permit limits for 

area source boilers. Therefore, using CO 

as a surrogate for organic urban HAP is 

a reasonable approach because 

minimizing CO emissions will result in 

minimizing organic urban HAP 

emissions. 

Based on these considerations, we are 

proposing GACT standards for PM (as a 

surrogate for the individual urban metal 

HAP), CO (as a surrogate pollutant for 

the individual urban organic HAP), and 

mercury from biomass-fired and oilfired 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 

The Industrial Boilers and the 

Institutional/Commercial Boilers area 

source categories were listed under 

section 112(c)(3) of the CAA. EPA needs 

to establish emission standards for area 

source boilers for the following urban 

HAP in order to meet the section 

112(c)(3) 90 percent requirement for 

these HAP: mercury, arsenic, beryllium, 

cadmium, lead, chromium, manganese, 

nickel, POM (as 7–PAH), ethylene 

dioxide, and PCB. Natural gas-fired area 

source boilers do not emit any of the 

urban HAP identified above. Therefore, 

regulation of gas-fired area source 

boilers is not necessary to meet the 90 

percent requirement under section 

112(c)(3) for these HAP. For the reason 

stated above, pursuant to section 

112(c)(3) of the CAA, we are proposing 

emission standards for the above 

mentioned HAP for area source boilers 

fired by coal, oil, and wood, but not 

standards for boilers fired by natural 

gas. 


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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 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 ............................................ 0.03 3.0E–06 310 (@ 7% oxygen). 

Biomass ..................................... 0.03 .............................. 100 (@ 7% oxygen). 

Oil ............................................... 0.03 .............................. 1 (@ 3% oxygen). 

Existing Boiler ............................. Coal ............................................ .............................. 3.0E–06 310 (@ 7% oxygen). 

Biomass ..................................... .............................. .............................. 160 (@ 7% oxygen). 

Oil ............................................... .............................. .............................. 2 (@ 3% oxygen). 

The emission limits for existing area 

source boilers are only applicable to 

area source boilers that have a designed 

heat input capacity of 10 million British 

thermal units per hour (MMBtu/h) or 

greater. If your boiler burns at least 10 

percent coal on a total fuel annual heat 

input basis, the boiler is in the coal fuel 

subcategory. If your boiler burns 

biomass or biomass in combination with 

a liquid or gaseous fuel, the unit is in 

the biomass subcategory. If your boiler 

burns oil, or oil in combination with a 

gaseous fuel, the unit is in the oil 

subcategory, except if the unit burns oil 

only during periods of gas curtailment. 

As allowed under CAA section 

112(h), a work practice standard is being 

proposed for existing area source boilers 

that are units with designed heat input 

capacity of less than 10 MMBtu/h. The 

work practice standard for existing 

small area source boilers requires the 

implementation of a tune-up program. 

An additional standard is being 

proposed for existing area source 

facilities having an affected boiler with 

a designed heat input capacity of 10 

MMBtu/h or greater that requires the 

performance of an energy assessment, 

by qualified personnel, on the boiler 

and the facility to identify cost-effective 

energy conservation measures. 

E. What are the Startup, Shutdown, and 

Malfunction (SSM) requirements? 

The United States Court of Appeals 

for the District of Columbia Circuit 

vacated portions of two provisions in 

EPA’s CAA section 112 regulations 

governing the emissions of HAP during 

periods of startup, shutdown, and 

malfunction (SSM). Sierra Club v. EPA, 

551 F.3d 1019 (D.C. Cir. 2008), cert. 

denied, 2010 U.S. LEXIS 2265 (2010). 

Specifically, the Court vacated the SSM 

exemption contained in 40 CFR 

63.6(f)(1) and 40 CFR 63.6(h)(1), that are 

part of a regulation, commonly referred 

to as the ‘‘General Provisions Rule,’’ that 

EPA promulgated under section 112 of 

the CAA. When incorporated into CAA 

Section 112(d) regulations for specific 

source categories, these two provisions 

exempt sources from the requirement to 

comply with the otherwise applicable 

CAA section 112(d) emission standard 

during periods of SSM. 

Consistent with Sierra Club v. EPA, 

EPA has established standards in this 

rule that apply at all times. EPA has 

attempted to ensure that we have not 

incorporated into proposed regulatory 

language any provisions that are 

inappropriate, unnecessary, or 

redundant in the absence of an SSM 

exemption. We are specifically seeking 

comment on whether there are any such 

provisions that we have inadvertently 

incorporated or overlooked. We also 

request comment on whether there are 

additional provisions that should be 

added to regulatory text in light of the 

absence of an SSM exemption and 

provisions related to the SSM 

exemption (such as the SSM plan 

requirement and SSM recordkeeping 

and reporting provisions). 

In establishing the standards in this 

rule, EPA has taken into account startup 

and shutdown periods and, for the 

reasons explained below, has not 

established different standards for those 

periods. The standards that we are 

proposing are daily or monthly 

averages. Based upon continuous 

emission monitoring data, obtained as 

part of the information collection effort 

for the major source boiler and process 

heater rulemaking, which included 

periods of startup and shutdown, over 

long averaging periods, startups and 

shutdowns will not affect the 

achievability of the standard. Boilers, 

especially solid fuel-fired boilers, do not 

normally startup and shutdown more 

than once per day. Thus, we are not 

establishing a separate emission 

standard for these periods because 

startup and shutdown are part of their 

routine operations and, therefore, are 

already addressed by the standards. 

Periods of startup, normal operations, 

and shutdown are all predictable and 

routine aspects of a source’s operations. 

However, by contrast, malfunction is 


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defined as a ‘‘sudden, infrequent, and 

not reasonably preventable failure of air 

pollution control and monitoring 

equipment, process equipment or a 

process to operate in a normal or usual 

manner * * *’’ (40 CFR 63.2). EPA has 

determined that malfunctions should 

not be viewed as a distinct operating 

mode and, therefore, any emissions that 

occur at such times do not need to be 

factored into development of CAA 

section 112(d) standards, which, once 

promulgated, apply at all times. It is 

reasonable to interpret section 112(d) as 

not requiring EPA to account for 

malfunctions in setting emissions 

standards. For example, we note that 

CAA section 112 uses the concept of 

‘‘best performing’’ sources in defining 

MACT, the level of stringency that 

major source standards must meet. 

Applying the concept of ‘‘best 

performing’’ to a source that is 

malfunctioning presents significant 

difficulties. The goal of best performing 

sources is to operate in such a way as 

to avoid malfunctions of their units. 

Similarly, although standards for area 

sources are generally not required to be 

set based on ‘‘best performers,’’ we 

believe that what is ‘‘generally available’’ 

should not be based on periods in 

which there is a ‘‘failure to operate.’’ 

Moreover, even if malfunctions were 

considered a distinct operating mode, 

we believe it would be impracticable to 

take malfunctions into account in 

setting CAA section 112(d) standards for 

area source boilers. As noted above, by 

definition, malfunctions are sudden and 

unexpected events and it would be 

difficult to set a standard that takes into 

account the myriad different types of 

malfunctions that can occur across all 

sources in the category. Moreover, 

malfunctions can vary in frequency, 

degree, and duration, further 

complicating standard setting. 

In the event that a source fails to 

comply with the applicable CAA section 

112(d) standards as a result of a 

malfunction event, EPA would 

determine an appropriate response 

based on, among other things, the good 

faith efforts of the source to minimize 

emissions during malfunction periods, 

including preventative and corrective 

actions, as well as root cause analyses 

to ascertain and rectify excess 

emissions. EPA would also consider 

whether the source’s failure to comply 

with the CAA section 112(d) standard 

was, in fact, ‘‘sudden, infrequent, not 

reasonably preventable’’ and was not 

instead ‘‘caused in part by poor 

maintenance or careless operation.’’ 40 

CFR 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 MMBtu/h, we 

are proposing that you must submit to 

the delegated authority or EPA, as 

appropriate, documentation that a tuneup was conducted. 

For owners or operators of existing 

area source facilities having a boiler 

with a heat input capacity of 10 

MMBtu/h or greater and subject to this 

rule, we are proposing that you submit 

to the delegated authority or EPA, as 

appropriate, documentation that the 

energy assessment was performed and 

the cost-effective energy conservation 

measures identified. 

G. What are the proposed continuous 

compliance requirements? 

If you demonstrate initial compliance 

with the emission limits by performance 

(stack) tests, we are proposing that you 

conduct stack tests on an annual basis. 

Furthermore, to demonstrate continuous 

compliance with the PM and mercury 

emission limits, we are proposing that 

you must monitor and comply with the 

applicable site-specific operating limits. 

For area source boilers without wet 

scrubbers that must comply with the PM 

and mercury emission limits, we are 

proposing that you must continuously 

monitor opacity and maintain the 

opacity at or below ten percent (daily 

block average). Or, if the unit is 

controlled with a fabric filter, instead of 

continuously monitoring opacity, we are 

proposing that the fabric filter may be 

continuously operated such that the bag 

leak detection system alarm does not 

sound more than 5 percent of the 

operating time during any 6-month 

period. 

For boilers with wet scrubbers that 

must comply with the PM and mercury 

emission limits, we are proposing that 

you must monitor pressure drop and 

liquid flow rate of the scrubber and 

maintain the daily block averages at or 

above the minimum operating limits 

established during the performance test. 

If you elected to demonstrate initial 

compliance with the mercury emission 

limit by fuel analysis, we are proposing 

that you conduct a monthly fuel 

analysis and maintain the annual 

average at or below the limit indicated 

in Table 1 of this preamble. 

For boilers that demonstrate 

compliance with the PM and mercury 

emission limits by performance (stack) 

tests, we propose that you must 

maintain monthly fuel records that 

demonstrate that you burned no new 

fuel type or new mixture (monthly 

average) as set during the performance 

test. If you plan to burn a new fuel type 

or new mixture than what was burned 

during the initial performance test, then 

we are proposing that you must conduct 

a new performance test to demonstrate 

continuous compliance with the PM 

emission limit and mercury emission 

limit. 

For boilers with heat input capacities 

equal to or greater than 100 MMBtu/hr, 

we propose that you must continuously 

monitor CO and maintain the daily 

average CO emissions at or below the 

limits indicated in Table 1 to 

demonstrate compliance with the CO 

emission limits at all times. 

H. What are the proposed notification, 

recordkeeping and reporting 

requirements? 

All new and existing sources would 

be required to comply with some 

requirements of the General Provisions 

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

identified in Table 6 of this proposed 

rule. The General Provisions include 

specific requirements for notifications, 

recordkeeping, and reporting. If 

performance tests are required under 

this proposed rule, then the notification 

and reporting requirements for 

performance tests in the General 

Provisions would also apply. 

Each owner or operator would be 

required to submit a notification of 

compliance status report, as required by 

40 CFR 63.9(h) of the General 

Provisions. This proposed rule requires 

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. 


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This proposed rule would require 

records to demonstrate compliance with 

each emission limit, work practice 

standard, or management practice. 

These recordkeeping requirements are 

specified directly in the General 

Provisions to 40 CFR part 63. 

Records for applicable management 

practices must be maintained. 

Specifically, the owner or operator must 

keep records of the dates and the results 

of each boiler tune-up. 

Records of either continuously 

monitored parameter data for a control 

device if a device is used to control the 

emissions or continuous emission 

monitoring system (CEMS) data would 

be required. 

Each owner and operator would be 

required to keep the following records: 

(1) All reports and notifications 

submitted to comply with the rule; 

(2) Continuous monitoring data as 

required in the rule; 

(3) Each instance in which you did 

not meet each emission limit, work/ 

management practice, and operating 

limit (i.e., deviations from the rule); 

(4) Monthly fuel use by each boiler 

including a description of the type(s) of 

fuel(s) burned, amount of each fuel type 

burned, and units of measure; 

(5) A copy of the results of all 

performance tests, energy assessments, 

opacity observations, performance 

evaluations, or other compliance 

demonstrations conducted to 

demonstrate initial or continuous 

compliance with the rule; and 

(6) A copy of your site-specific 

monitoring plan developed for the rule, 

if applicable. 

Typically, records would be retained 

for at least 5 years. In addition, 

monitoring plans, operating and 

maintenance plans, and other plans 

would be updated as necessary and kept 

for as long as they are still current. 

I. Submission of Emissions Test Results 

to EPA 

Compliance test data are necessary for 

many purposes including compliance 

determinations, development of 

emission factors, and determining 

annual emission rates. EPA has found it 

burdensome and time consuming to 

collect emission test data because of 

varied locations for data storage and 

varied data storage methods. 

One improvement that has occurred 

in recent years is the availability of 

stack test reports in electronic format as 

a replacement for bulky paper copies. 

In this action, we are taking a step to 

improve data accessibility for stack tests 

(and in the future continuous 

monitoring data). Boiler area sources 

would be required to submit to 

WebFIRE (an EPA electronic database) 

an electronic copy of stack test reports 

as well as process data. Data entry 

requires only access to the Internet and 

is expected to be completed by the stack 

testing company as part of the work that 

it is contracted to perform. 

Please note that the proposed 

requirement to submit source test data 

electronically to EPA would not require 

any additional performance testing. In 

addition, when a facility submits 

performance test data to WebFIRE, there 

would be no additional requirements for 

data compilation; instead, we believe 

industry would greatly benefit from 

improved emissions factors, fewer 

information requests, and better 

regulation development as discussed 

below. Because the information that 

would be reported is already required in 

the existing test methods and is 

necessary to evaluate the conformance 

to the test methods, facilities would 

already be collecting and compiling 

these data. One major advantage of 

submitting source test data through the 

Electronic Reporting Tool (ERT), which 

was developed with input from stack 

testing companies (who already collect 

and compile performance test data 

electronically), is that it would provide 

a standardized method to compile and 

store all the documentation required by 

this proposed rule. Another important 

benefit of submitting these data to EPA 

at the time the source test is conducted 

is that these data should reduce the 

effort involved in data collection 

activities in the future for these source 

categories. This results in a reduced 

burden on both affected facilities (in 

terms of reduced manpower to respond 

to data collection requests) and EPA (in 

terms of preparing and distributing data 

collection requests). Finally, another 

benefit of submitting these data to 

WebFIRE electronically is that these 

data will greatly improve the overall 

quality of the existing and new 

emissions factors by supplementing the 

pool of emissions test data upon which 

emissions factors are based and by 

ensuring that data are more 

representative of current industry 

operational procedures. A common 

complaint we hear from industry and 

regulators is that emissions factors are 

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). The WebFIRE Web site was 

constructed to store emissions test data 

for use in developing emission factors. 

A description of the WebFIRE data base 

can be found at http://cfpub.epa.gov/ 

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

The ERT will be able to transmit the 

electronic report through EPA’s Central 

Data Exchange (CDX) network for 

storage in the WebFIRE data base. 

Although ERT is not the only electronic 

interface that can be used to submit 

source test data to the CDX for entry 

into WebFIRE, it makes submittal of 

data very straightforward and easy. A 

description of the ERT can be found at 

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

ert_tool.html. 

The ERT can be used to document the 

conducting of stack tests data for 

various pollutants including PM, 

mercury, dioxin/furan, and HCl. 

Presently, the ERT does not accept 

opacity data or CEMS data. 

EPA specifically requests comment on 

the utility of this electronic reporting 

requirement and the burden that owners 

and operators of boiler area source 

facilities estimate would be associated 

with this requirement. 

V. Rationale of This Proposed Rule 

A. How did EPA determine which 

pollution sources would be regulated 

under this proposed rule? 

This proposed rule regulates 

industrial boilers (fired by coal, 

biomass, or oil) and institutional and 

commercial boilers (fired by coal, 

biomass, or oil) that are located at area 

sources of HAP. 

Boilers that are used specifically for 

research and development are not 

regulated. However, boilers that only 

provide steam to a process or for heating 

at a research and development facility 

are still subject to this proposed rule. 

B. How did EPA determine the 

subcategories for this proposed rule? 

The CAA allows EPA to divide source 

categories into subcategories when 

differences between given types of units 

lead to corresponding differences in the 

nature of emissions or the technical 

feasibility of applying emission control 

techniques. The design, operating, and 

emissions information that EPA 

reviewed during the major source 

rulemaking indicates the need to 

subcategorize boilers based on the boiler 

type. 


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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 also differ. Boilers 

emit a number of urban HAP. In general, 

HAP formation is dependent upon the 

composition of the fuel. The combustion 

quality and temperature also play an 

important role. The fuel dependent 

urban HAP emissions from boilers are 

metals, including mercury. These fuel 

dependent HAP emissions generally can 

be controlled by either changing the fuel 

property before combustion or by 

removing the HAP from the flue gas 

after combustion. Organic HAP, on the 

other hand, are formed from incomplete 

combustion and are much less 

influenced by the characteristics of the 

fuel being burned. The degree of 

combustion may be greatly influenced 

by three general factors: time, 

turbulence, and temperature. These 

factors are a function of the design of 

the boiler which is dependent in part on 

the type of fuel being burned. 

Because these different types of 

boilers have different emission 

characteristics which may influence the 

feasibility and effectiveness of emission 

control, we are proposing to 

subcategorize them as follows: boilers 

designed to fire coal, boilers designed to 

fire biomass, and boilers designed to fire 

oil in order to account for these 

differences in emissions. The coal-fired 

subcategory includes boilers burning 

greater than 10 percent coal on an 

annual fuel heat input basis. The 

biomass fuel subcategory includes units 

burning any biomass but not more than 

10 percent coal on an annual fuel heat 

input basis. The oil subcategory 

includes all remaining boilers. 

In summary, we have identified three 

subcategories of boilers located at area 

sources: (1) Boilers designed for coal 

firing, (2) boilers designed for biomass 

firing, and (3) boilers designed for oil 

firing. 

C. What surrogates are we using? 

As explained above, EPA is proposing 

emission standards for the two source 

categories in this proposed rule. For 

mercury from coal-fired area source 

boilers and POM from all area source 

boilers, EPA is proposing these 

standards under CAA sections 112(d)(2) 

and 112(h). For the other urban HAP 

which formed the basis of the CAA 

section 112(c)(3) listing, EPA is 

proposing standards pursuant to CAA 

section 112(d)(5). 

In selecting the proposed emission 

standards, we are using PM as a 

surrogate for the non-mercury metallic 

urban HAP (arsenic, beryllium, 

cadmium, chromium, lead, manganese, 

and nickel). The inherent variability and 

unpredictability of the non-mercury 

metal HAP compositions and amounts 

in fuel have a material effect on the 

composition and amount of nonmercury 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 nonmercury 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. 

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 less expensive 

to measure and monitor CO emissions 

than to measure and monitor emissions 

of each individual organic HAP. We 

considered other surrogates, such as 

THC, but lacked data on emissions and 

permit limits for area source boilers. 

Therefore, using CO as a surrogate for 

organic urban HAP is a reasonable 

approach because minimizing CO 

emissions will result in minimizing 

organic urban HAP emissions. 

D. How did EPA determine the proposed 

standards for existing units? 

Both industrial boilers and 

institutional/commercial boilers have 

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

source categories for mercury and POM. 

That section requires MACT standards 

for each of the pollutants needed to 

achieve regulation of 90 percent of the 

emissions of the relevant pollutant. As 

previously noted, the CAA allows EPA 

to establish standards under GACT 

instead of MACT for urban HAP we 

propose to regulate to fulfill CAA 

section 112(c)(3). 

As discussed previously, CAA section 

112(h) allows the Administrator to 

promulgate a design, equipment, work 

practice, or operational standard, or 

combination thereof, in certain cases 

where, in the judgment of the 

Administrator, it is not feasible to 

prescribe or enforce an emission 

standard under CAA section 112(d). 

These cases include the situation in 

which the application of measurement 

methodology to a particular class of 

sources is not practicable due to 

technical and economic limitations. 

As we establish emission standards 

for each source category listed pursuant 

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

about the source category. As part of our 

analysis, we examine the available 

information about the source category, 

and we re-examine the inventory 

associated with the original listing. We 

continue to believe that we must 

regulate POM from coal-fired, biomassfired, and oil-fired area source boilers in 

order to meet the requirement in section 

112(c)(6), and propose below MACTbased 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 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, 


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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 biomassfired or oil-fired, as well as with respect 

to other urban HAP besides POM, we 

have developed proposed standards that 

reflect GACT for these two area source 

categories. 

1. MACT Analysis for Mercury From 

Coal-Fired Boilers and POM 

All standards established pursuant to 

CAA section 112(d)(2) must reflect 

MACT, the maximum degree of 

reduction in emissions of air pollutants 

that the Administrator, taking into 

consideration the cost of achieving such 

emissions reductions, and any non-air 

quality health and environmental 

impacts and energy requirements, 

determined is achievable for each 

category or subcategory. For existing 

sources, MACT cannot be less stringent 

than the average emission limitation 

achieved by the best performing 12 

percent of existing sources in the 

category or subcategory for categories or 

subcategories with 30 or more sources. 

This requirement constitutes the ‘‘MACT 

floor’’ for existing area source boilers. 

EPA may not consider cost in 

determining the MACT floor. EPA must 

consider cost, non-air quality health and 

environmental impacts, and energy 

requirements in evaluating whether it is 

appropriate to set a standard more 

stringent than the MACT floor (beyondthe-floor controls). 

a. MACT Floor Analysis for Mercury 

and POM 

The approach selected for 

determining the MACT floors is based 

on estimating the emissions levels 

achieved on average by the best 12 

percent of existing sources, for which 

we have information. In terms of 

developing MACT emission limits for 

area source boilers, we have: 

—No emission data for POM, 

—Limited emission data (nine coal-fired 

boilers) for mercury, 

—No State regulations applicable for 

mercury or POM, 

—No State permits specific for mercury 

or POM, 

—No surrogate for mercury, but CO as 

a surrogate for POM, 

—Emission data on four coal-fired area 

source boilers using add-on control 

technology for mercury, 

—Limited emission data for CO (5 coalfired boilers, 30 wood-fired boilers, 68 

oil-fired boilers), 

—A few State permits with CO limits for 

coal, oil, and wood-fired area source 

boilers, 

The MACT floor limits for each of the 

HAP and HAP surrogates (mercury and 

CO) are calculated based on the 

performance of the lowest emitting (best 

performing) sources in each of the 

subcategories. We ranked all of the 

sources for which we had data based on 

their emissions and identified the 

lowest emitting 12 percent of the 

sources for each HAP. 

We first considered whether fuel 

switching would be an appropriate 

control option for sources in each 

subcategory. We considered the 

feasibility of fuel switching to other 

fuels used in the subcategory and to 

fuels from other subcategories. This 

consideration included determining 

whether switching fuels would achieve 

lower HAP emissions. A second 

consideration was whether fuel 

switching could be technically achieved 

by boilers in the subcategory 

considering the existing design of 

boilers. We also considered the 

availability of various types of fuel. 

After considering these factors, we 

determined that fuel switching was not 

an appropriate control technology for 

purposes of determining the MACT 

floor level of control for any 

subcategory. This decision was based on 

the overall effect of fuel switching on 

HAP emissions, technical and design 

considerations discussed previously in 

this preamble, and concerns about fuel 

availability. This determination is 

discussed in the memorandum 

‘‘Development of Fuel Switching Costs 

and Emission Reductions for Industrial, 

Commercial, and Institutional Boilers 

and Process Heaters National Emission 

Standards for Hazardous Air 

Pollutants—Area Source’’ located in the 

docket. 

We used the emissions data for those 

best performing affected sources to 

determine the emission limits to be 

proposed, with an accounting for 

variability. EPA must exercise its 

judgment, based on an evaluation of the 

relevant factors and available data, to 

determine the level of emissions control 

that has been achieved by the best 

performing sources under variable 

conditions. The Court has recognized 

that EPA may consider variability in 

estimating the degree of emission 

reduction achieved by best-performing 

sources and in setting MACT floors. See 

Mossville Envt’l Action Now v. EPA, 370 

F.3d 1232, 1241–42 (DC Cir 2004) 

(holding EPA may consider emission 

variability in estimating performance 

achieved by best-performing sources 

and may set the floor at level that bestperforming source can expect to meet 

‘‘every day and under all operating 

conditions’’). 

To calculate the achieved emission 

limit, including variability, we used the 

equation: 

UPL x +t ,n s

n m

= −× × + ⎛

⎝

⎜ ⎞

⎠

⎟ (0.99 2 1 1 1 )

Where: 

n = the number of test runs 

m = the number of test runs in the 

compliance average 

s = standard deviation of emission data 

t(0.99, n¥1) = the t-statistic 

x = emissions data average 

Specifically, the MACT floor limit is an 

upper prediction limit (UPL) calculated 

with the Student’s t-test using the TINV 

function in Microsoft Excel. The 

Student’s t-test has also been used in 

other EPA rulemakings in accounting 

for variability. A prediction interval for 

a future observation is an interval that 

will, with a specified degree of 

confidence, contain the next (or some 

other pre-specified) randomly selected 

observation from a population. In other 

words, the prediction interval estimates 

what future values will be, based upon 

present or past background samples 

taken. Given this definition, the UPL 

represents the value which we can 

expect the mean of 3 future observations 

(3-run average) to fall below, based 

upon the results of an independent 

sample from the same population. That 

is, if we were to randomly select a 

future test condition from any of these 

sources (i.e., average of 3 runs), we can 

be 99 percent confident that the 

reported level will fall at or below the 

UPL value. To calculate the UPL, we 

used the average (or sample mean) and 

sample standard deviation (SD), which 

are two statistical measures calculated 

from the sample data. The average is the 

central value of a data set, and the SD 

is the common measure of the 

dispersion of the data set around the 

average. 

Based on this limited available 

information, the MACT floor analyses 

for the three subcategories (coal, 

biomass, and oil) are discussed below. 

1. Existing area source boilers 

designed for coal firing: 

Mercury—The total number of coalfired area source boilers for which we 

have actual mercury emission data is 9. 

Thus, the top 12 percent is based on 

emissions from two boilers. The average 

mercury emission level of the top 12 

percent is 1.3 pounds per trillion Btu 

(lb/TBtu). The SD of test runs in the top 

12 percent boilers is 0.322. Therefore, 

the 99 percent UPL level is 2.5 lb/TBtu. 

The resulting MACT floor mercury limit 

for existing coal-fired area source boilers 

is 2.5 lb/T Btu (rounded to 0.000003 lb/ 


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million Btu). No fuel analysis data from 

boilers in the top 12 percent were 

available for assessing the impact of fuel 

variability on mercury emissions. 

POM—None of the States for which 

we have an inventory have an 

applicable emission limit specifically 

for POM or CO. However, one State 

(New Jersey) does have standards for 

CO, but for boilers the size of coal-fired 

area source boilers, the requirement is 

actually a work practice standard for CO 

(i.e., boiler tune-up). For small (less than 

50 MMBtu/h) boilers, the New Jersey 

requirement is to maintain and operate 

the source in accordance with 

manufacturer specifications. 

The available State permits obtained 

for coal-fired area source boilers 

limiting CO emissions were for 12 units 

located in Ohio (3 units), California (1 

unit), and Illinois (8 units). We also 

obtained CO emission data from 5 coalfired area source boilers as part of the 

information collection effort for the 

major source NESHAP. Therefore, the 

top 12 percent is made up of three 

boilers. The average CO level of the top 

12 percent is 162 parts per million 

(ppm) at 3 percent oxygen. The SD of 

the run data in top 12 percent boilers is 

92.1 ppm. Therefore, the 99 percent 

UPL level is 390 ppm at 3 percent 

oxygen. The resulting MACT floor CO 

limit for existing coal-fired area source 

boilers is 310 ppm at 7 percent oxygen. 

We correct to 7 percent oxygen because 

that is typically in the oxygen range that 

coal-fired boilers operate and we 

rounded up to the nearest 10 ppm. 

2. Existing area source boilers 

designed for biomass firing: 

POM—None of the States for which 

we have an inventory have an 

applicable emission limit specifically 

for POM or CO. Actual CO emission 

data were available from the National 

Forest Service’s Fuels for Schools 

program for 14 wood-fired boilers. Also, 

State permits limiting CO emissions 

from biomass boilers were obtained on 

another 24 biomass-fired area source 

boilers. We also obtained CO emission 

test data from 26 biomass-fired area 

source boilers as part of the major 

source ICR survey. 

The top 12 percent is made up of 8 

boilers. The average CO level of the top 

12 percent is 80.6 ppm at 3 percent 

oxygen. The SD of the top 12 percent 

boilers is 73.5 ppm. The 99 percent UPL 

is 192 ppm at 3 percent oxygen, 

rounded up to 200 ppm. Biomass-fired 

boilers typically operate at around 7 

percent oxygen. Therefore, the MACT 

floor level is 160 ppm CO at 7 percent 

oxygen. 

3. Existing area source boilers 

designed for oil firing: 

POM—None of the States for which 

we have an inventory have an 

applicable emission limit specifically 

for POM or CO. Actual CO emission 

data were available from 68 oil-fired 

area source boilers responding to the 

Boiler MACT ICR. State permits limiting 

CO emissions from oil-fired area source 

boilers were obtained on 56 oil-fired 

area source boilers. 

The top 12 percent is made up of 15 

boilers. The average CO level of the top 

12 percent is 1 ppm at 3 percent oxygen. 

Based on the test runs from these 15 

best performing units, the 99 percent 

UPL level is 2 ppm at 3 percent oxygen. 

Therefore, the MACT floor level is 2 

ppm CO at 3 percent oxygen. Because 

oil-fired boilers typically operate at 

around 3 percent oxygen, additional 

oxygen content correction was not 

necessary. 

4. Work Practice Standards for Smaller 

Boilers 

As previously discussed, CAA section 

112(h)(1) states that the Administrator 

may prescribe a work practice standard 

or other requirements, consistent with 

the provisions of CAA sections 112(d) or 

(f), in those cases where, in the 

judgment of the Administrator, it is not 

feasible to enforce an emission standard. 

CAA section 112(h)(2)(B) further defines 

the term ‘‘not feasible’’ to mean when 

‘‘the application of measurement 

technology to a particular class of 

sources is not practicable due to 

technological and economic 

limitations.’’ 

The standard reference methods for 

measuring emissions of mercury, CO (as 

a surrogate for POM), and PM (as a 

surrogate for urban non-mercury metals) 

are EPA Methods 29, 10, and 5 of 40 

CFR part 60 appendices A–8, A–4, and 

A–3, respectively. These methods are 

reliable and relatively inexpensive. 

However, the methods are not 

applicable for sampling small diameter 

(less than 12 inches) stacks. For 

example, in these small diameter stacks, 

the conventional Method 5 stack 

assembly blocks a significant portion of 

the cross-section of the duct and causes 

inaccurate measurements. Many 

existing area source boilers have stacks 

with diameters less than 12 inches. The 

stack diameter is generally related to the 

size of the boiler. Boilers that have a 

capacity below 10 MMBtu/h generally 

have stacks with diameters less than 12 

inches. Also, many area source boilers 

do not currently have sampling ports or 

a platform for accessing the exhaust 

stack which would require an expensive 

modification to install sampling ports 

and a platform. 

We conducted a cost-to-sales analysis 

to evaluate the economic impact of the 

testing and monitoring costs that area 

source boiler facilities would incur to 

demonstrate compliance with the 

proposed emission limits. The annual 

compliance costs imposed on each 

source is for the costs of a stack test for 

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-to-sales ratio or CSR). 

The results of the analysis indicate 

that total compliance costs exceed 3 

percent (and can reach as high as 19 

percent) of the average firm revenues for 

79 percent of the facilities. This 

indicates that the annual costs for 

testing and monitoring alone would 

have a significant adverse economic 

impact on these facilities. The severity 

of the economic impact would depend 

on the size of the facility. For small 

institutional (schools) and commercial 

(farms) facilities the costs would be 

prohibitive. This analysis is discussed 

in the memorandum ‘‘Cost-to-Sales 

Analysis of Testing and Monitoring 

Costs’’ located in the docket. 

Based on this analysis, pursuant to 

CAA section 112(h), EPA is proposing 

that it is not feasible to enforce emission 

standards for area source boilers having 

a heat input capacity of less than 10 

MMBtu/h because of the technological 

and economic limitations described 

above. Thus, a work practice, as 

discussed below, is being proposed to 

limit the emissions of mercury and CO 

(as a surrogate for POM) for existing area 

source boilers having a heat input 

capacity of less than 10 MMBTU/h. We 

are specifically requesting comment on 

whether a threshold higher than 10 

MMBtu/h meets the technical and 

economic limitations as specified in 

section 112(h). 

For existing area source boilers, the 

only work practice being used that 

potentially controls mercury and POM 

emissions is a boiler tune-up. Mercury 

is a fuel dependent HAP. That is, the 

amount of mercury emitted from the 

boiler depends on the amount of 

mercury contained in the fuel. Fuel 

usage can be reduced by improving the 

combustion efficiency of the boiler. At 

best, boilers may be 85 percent efficient 

and untuned boilers may have 

combustion efficiencies of 60 percent or 

lower. As combustion efficiency 


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decreases, fuel usage increases to 

maintain energy output resulting in 

increased emissions. 

On the other hand, POM is formed 

from incomplete combustion of the fuel. 

The objective of good combustion is to 

release all the energy in the fuel while 

minimizing losses from combustion 

imperfections and excess air. The 

combination of the fuel with the oxygen 

requires temperature (high enough to 

ignite the fuel constituents), mixing or 

turbulence (to provide intimate oxygenfuel contact), and sufficient time (to 

complete the process), sometimes 

referred to as the three Ts of 

combustion. Good combustion practice 

(GCP), in terms of boilers, could be 

defined 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 tuneups. We also reviewed State regulations 

and permits applicable to area source 

boilers. The work practices listed in 

State regulations includes tune-ups (10 

States), operator training (1 State), 

periodic inspections (2 States), and 

operation in accordance with 

manufacturer specifications (1 State). Of 

the 44 area source boilers with a 

capacity of less than 10 MMBtu/h that 

responded to EPA’s information 

collection effort for major source 

NESHAP, 28 (or 64 percent) reported 

conducting a boiler tune-up program. 

Ultimately, we determined that at least 

6 percent of the boilers in each of the 

subcategories are subject to a tune-up 

requirement. Therefore, the work 

practice of a tune-up does establish the 

MACT floor for mercury and POM 

emissions from existing area source 

boilers with a heat input capacity of less 

than 10 MMBtu/h. 

A detailed discussion of the MACT 

floor methodology is presented in the 

memorandum ‘‘MACT Floor Analysis 

for the Industrial, Commercial, and 

Institutional Area Source Boilers’’ in the 

docket. 

b. Beyond-the-Floor Determination for 

Mercury and POM. 

We considered the pollution 

prevention and energy conservation 

measure of an energy assessment as a 

beyond-the-floor option for mercury and 

POM emissions. An energy assessment 

provides valuable information on 

improving energy efficiency. An energy 

assessment, or energy audit, is an indepth energy study identifying all 

energy conservation measures 

appropriate for a facility given its 

operating parameters. An energy 

assessment refers to a process which 

involves a thorough examination of 

potential savings from energy efficiency 

improvements, pollution prevention, 

and productivity improvement. It leads 

to the reduction of emissions of 

pollutants through process changes and 

other efficiency modifications. Besides 

reducing operating and maintenance 

costs, improving energy efficiency 

reduces negative impacts on the 

environment. Improvement in energy 

efficiency results in decreased fuel use 

which results in a corresponding 

decrease in emissions (both HAP and 

non-HAP) from the boiler, but not 

necessarily all those present. The 

Department of Energy (DOE) has 

conducted energy assessments at 

selected manufacturing facilities and 

reports that facilities can reduce fuel/ 

energy use by 10 to 15 percent by using 

best practices to increase their energy 

efficiency. Many best practices are 

considered pollution prevention 

because they reduce the amount of fuel 

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. 

The one-time cost of an energy 

assessment ranges from $2500 to 

$55,000 depending on the size of the 

facility. If a facility elected to 

implement the cost-effective energy 

conservation measures identified in the 

energy assessment, it would potentially 

result in greater mercury and POM 

reduction than achieved by a boiler 

tune-up alone. In addition, the cost of 

an energy assessment is minimal, in 

most cases, compared to the cost for 

testing and monitoring to demonstrate 

compliance with an emission limit. 

Furthermore, the costs of any energy 

conservation improvement will be offset 

by the cost savings in lower fuel costs. 

Therefore, we decided to go beyond the 

MACT floor for this proposed rule for 

the existing area source boilers. The 

proposed standards for existing area 

source facilities with a boiler that has a 

capacity equal to or greater than 10 

MMBtu/h for mercury and POM include 

the requirement of a performance of an 

energy assessment to identify energy 

conservation measures. Since there was 

insufficient information to determine if 

requiring implementation of costeffective measures were economically 

feasible, we are seeking comment on 

this point. 

In this proposed rule, we are defining 

a cost-effective energy conservation 

measure to be any measure that has a 

payback (return of investment) period of 

two years or less. This payback period 

was selected based on section 

325(o)(2)(B)(iii) of the Energy Policy and 

Conservation Act which states that there 

is a presumption that an energy 

conservation standard is economically 

justified if the increased installed cost 

for a measure is less than three times the 

value of the first-year energy savings 

resulting from the measure. 

We believe that an energy assessment 

is an appropriate beyond-the-floor 

control technology because it is one of 

the measures identified in CAA section 

112(d)(2). CAA section 112(d)(2) states 

that ‘‘Emission standards promulgated 

* * * and applicable to new or existing 

sources * * * is achievable * * * 

through application of measures, 

processes, methods, systems or 

techniques including, but not limited to 

measures which— 

(A) reduce the volume of, or eliminate 

emissions of, such pollutants through 

process changes, substitution of 

materials or other modifications, 

The purpose of an energy assessment is 

to identify energy conservation 

measures (such as process changes or 

other modifications to the facility) that 

can be implemented to reduce the 

facility energy demand which would 

result in reduced fuel use. Reduced fuel 

use will result in a corresponding 

reduction in HAP, and non-HAP, 

emissions. Thus, an energy assessment, 

in combination with the MACT 

emission limits will result in the 

maximum degree of reduction in 

emissions as required by 112(d)(2). 

Therefore, we are proposing to require 

all existing sources to conduct a onetime energy assessment to identify costeffective energy conservation measures 

on the boiler’s energy consuming 

systems. 

We are proposing that the energy 

assessment be conducted by energy 

professionals and/or engineers that have 

expertise that cover all energy using 

systems, processes, and equipment. We 

are aware of at least two organizations 

that provide certification of specialists 

in evaluating energy systems. We are 

proposing that a qualified specialist is 

someone who has successfully 

completed the Department of Energy’s 

Qualified Specialist Program for all 

systems or a professional engineer 

certified as a Certified Energy Manager 

by the Association of Energy Engineers. 

We are specifically requesting 

comment on: (1) Whether our estimates 

of the assessment costs are correct; (2) 

is there adequate access to certified 

assessors; (3) are there other 

organizations for certifying energy 

engineers; (4) are online tools adequate 


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1The 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. 

to inform the facility’s decision to make 

efficiency upgrades; (5) is the definition 

of ‘‘cost-effective’’ appropriate in this 

context since it refers to payback of 

energy saving investments without 

regard to the impact on HAP reduction; 

and (6) what rate of return should be 

used. 

A detailed description of the beyondthe-floor consideration is in the 

memorandum ‘‘Methodology for 

Estimating Cost and Emissions Impacts 

for Industrial, Commercial, Institutional 

Area Source Boilers’’ in the docket. 

2. GACT Determination for Existing 

Area Source Boilers 

As provided in CAA section 112(d)(5), 

we are proposing standards representing 

GACT for these area source boilers. 

For existing coal and biomass-fired 

area source boilers, the add-on control 

technology generally being used is 

multiclones. We found that this 

technology is minimally effective in 

controlling urban metal HAP and has no 

effect on urban organic HAP. 

Multiclones are mechanical separators 

that use velocity differential across the 

cyclones to separate particles. A 

multiclone uses several smaller 

diameter cyclones to improve efficiency. 

Multiclones have a control efficiency for 

PM emissions of about 75 percent. 

Multiclones are more efficient 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 nonmercury metallic HAP of only about 10 

percent and have no effect on reducing 

mercury emissions. The cost of using 

multiclones (capital, testing, and 

monitoring) is estimated to be between 

$50,000 and $100,000 depending on the 

size of the boiler. 

We also considered various pollution 

prevention and energy conservation 

options as the potential basis for GACT 

for the urban metal HAP and the organic 

urban HAP. The most common options, 

and generally available, are simply 

tuning the boiler to the manufacturer’s 

specification. A boiler tune-up provides 

potential savings from energy efficiency 

improvements and pollution 

prevention. Besides reducing operating 

and maintenance costs, improving 

energy efficiency reduces negative 

impacts on the environment. 

Improvement in energy efficiency 

results in decreased fuel use which 

results in a corresponding decrease in 

emissions (both HAP and non-HAP) 

from the boiler. A boiler tune-up 

requirement would potentially result in 

the same non-mercury metallic HAP 

reduction as a PM emission limit based 

on performance of multiclones but 

would also reduce emissions of organic 

HAP. In addition, the cost of a boiler 

tune-up appears minimal compared to 

the cost for testing and monitoring to 

demonstrate compliance with an 

emission limit. 

For existing oil-fired area source 

boilers, we found no add-on control 

technology being used. 

Therefore, we determined that GACT 

for existing area source boilers with heat 

input capacities of 10 MMBtu/hour or 

greater is a management practice 

requiring the implementation of a boiler 

tune-up program. Thus, for existing area 

source boilers, we are proposing GACT 

for HAP other than mercury and POM 

to be a management practice requiring 

the implementation of a boiler tune-up 

program. 

If we conclude that our obligations 

under section 112(c)(6) for mercury can 

be met without mercury emissions from 

biomass-fired or oil-fired area source 

boilers, we believe that several 

requirements of this proposed rule 

would be generally available to the 

regulated community and would 

provide some control of mercury and 

other fuel-bound pollutants at existing 

sources with larger boilers. For example, 

the requirements to optimize 

combustion, conduct an energy 

assessment, 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 

standards for new units? 

As noted above, we have developed 

the proposed standards to reflect the 

application of MACT for mercury and 

POM, and GACT for arsenic, beryllium, 

cadmium, lead, chromium, manganese, 

nickel, ethylene dioxide, and 

polychlorinated biphenyls (PCB).1

1. MACT Analysis for Mercury From 

Coal-fired Boilers and POM 

The CAA specifies that MACT for 

new boilers shall not be less stringent 

than the emission control that is 

achieved in practice by the bestcontrolled 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: 

Mercury—We determined in the 

context of the major source rulemaking 

for boilers that fabric filters are the most 

effective technology employed by coalfired industrial, commercial, and 

institutional boilers for controlling 

mercury emissions. Five coal-fired area 

source boilers have been identified as 

having a fabric filter. Based on available 

emission data, the best performing unit 

(i.e., the unit having the reported lowest 

mercury level based on a three run test) 

is an area source coal-fired boiler 

equipped with an electrostatic 

precipitator (ESP). The boiler had a test 

average for mercury of 1.4 lb/TBtu with 

a SD of 0.307 to account for variability. 

Therefore, the resulting MACT floor 

mercury limit for new 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 (0.000003 

lb/million Btu). 

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 


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ensuring combustion efficiency and may 

be viewed as a GCP. As discussed 

previously in this preamble, CO is 

considered a surrogate for organic HAP 

(including POM) emissions in this 

proposed rule. 

None of the States for which we have 

an inventory have an applicable 

emission limit specifically for POM or 

CO. However, one State (New Jersey) 

does have standards for CO, but for 

boilers the size of coal-fired area source 

boilers, it is actually a work practice 

standard for CO (i.e., tune-up). For small 

(less than 50 MMBtu/h) boilers, New 

Jersey’s requirement is to maintain and 

operate the source in accordance with 

manufacturers’ specifications. 

Considering available State permit 

data and emission test data for coal-fired 

area source boilers the best controlled 

similar source is a coal-fired area source 

boiler having an average three run CO 

test emission level of 216 ppm at 3 

percent oxygen. The calculated 99 

percent UPL, to account for variability, 

is 640 ppm at 3 percent oxygen. Since 

this 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 (310 ppm at 7 percent 

oxygen). 

2. New area source boilers designed 

for biomass firing: 

POM—None of the States for which 

we have an inventory have an 

applicable emission limit specifically 

for POM or CO. Actual CO emission 

data were available from the Fuels for 

Schools program for 14 biomass-fired 

boilers and from 29 biomass-fired area 

source boilers as part of the major 

source ICR survey. Also, State permits 

limiting CO emissions from biomass 

boilers were obtained on another 27 

biomass-fired area source boilers. 

Therefore, the MACT floor for POM 

achieved by the best controlled similar 

source is based on actual CO emission 

data. 

The average 3-run test CO level of the 

best controlled similar source is 38.6 

ppm at 3 percent oxygen. The SD for the 

test runs is 14 ppm. Therefore, the 99 

percent UPL is 120 ppm at 3 percent 

oxygen, rounded up to the nearest 10 

ppm. Thus, the proposed MACT floor 

level is 100 ppm CO at 7 percent 

oxygen. 

3. New area source boilers designed 

for oil firing: 

POM—None of the States for which 

we have an inventory have an 

applicable emission limit specifically 

for POM or CO. Actual CO emission 

data were available on 66 oil-fired area 

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 CO emission level of the best 

performing similar source is 0.6 ppm at 

3 percent oxygen. The SD of the test 

runs is 0.04 ppm. Therefore, the 99 

percent UPL and the proposed MACT 

floor level is 1 ppm CO at 3 percent 

oxygen, rounded up to the nearest 

whole ppm. 

A detailed description of the MACT 

floor determination is in the 

memorandum, ‘‘MACT Floor Analysis 

for Industrial, Commercial, and 

Institutional Area Source Boilers’’ in the 

docket. 

4. Appropriateness of Work Practice 

Standards for New Area Source Boilers: 

As previously discussed, CAA section 

112(h) states that the Administrator may 

prescribe a work practice standard or 

other requirements, consistent with the 

provisions of CAA sections 112(d) or (f), 

in those cases where, in the judgment of 

the Administrator, it is not feasible to 

enforce an emission standard due to 

technical and economic limitations. 

As was the case for existing small area 

source boilers, total compliance costs 

would likely exceed 3 percent of the 

average firm revenues for some new 

facilities. This indicates that the annual 

costs for testing and monitoring alone 

may have a significant adverse 

economic impact on some new 

facilities. 

As discussed previously, the standard 

reference methods for measuring 

emissions of mercury, CO (as a surrogate 

for POM), and PM (as a surrogate for 

urban non-mercury metals) are EPA 

Methods 29, 10, and 5 and are not 

applicable for sampling small diameter 

stacks. We solicit comment on whether 

it would be technically infeasible to 

design sampling ports adequate for the 

test methods in boilers that are below a 

certain size. 

Based on this analysis and the reason 

discussed below, we are not proposing 

a work practice under CAA section 

112(h) for new area source boilers. New 

facilities, as opposed to existing 

facilities, have the added flexibility of 

including compliance costs into their 

design and planning. This would 

include the design and cost to provide 

a performance testing facility that has 

sampling ports adequate for the test 

methods and constructing the exhaust 

stack such that HAP emission rates can 

be accurately determined. In addition, a 

new facility has the option of fuel 

selection in minimizing their 

compliance costs. 

A detailed discussion of the MACT 

floor methodology is presented in the 

memorandum ‘‘MACT Floor Analysis 

for the Industrial, Commercial, and 

Institutional Area Source Boilers’’ in the 

docket. 

b. Beyond-the-floor Analysis for 

Mercury and POM for New Area Source 

Boilers. The MACT floor level of control 

for new units is based on the emission 

control that is achieved in practice by 

the best controlled similar source within 

each of the subcategories. No 

technologies or other HAP emission 

reduction approaches were identified 

that would achieve mercury or POM 

reduction greater than the new source 

floors for each of the subcategories. 

Therefore, we decided to not go 

beyond the MACT floor level of control 

for mercury and POM emissions for new 

area source boilers in this proposed 

rule. A detailed description of the 

beyond-the-floor consideration is in the 

memorandum ‘‘Methodology for 

Estimating Cost and Emissions Impacts 

for Industrial, Commercial, Institutional 

Area Source Boilers’’ in the docket. 

2. GACT Determination for New Area 

Source Boilers 

The control technologies currently 

used by facilities in the source 

categories that reduce non-mercury 

metallic HAP and PM are fabric filters 

and ESP. We determined that these 

controls are generally available and cost 

effective for new area source boilers. 

New area source boilers with heat input 

capacity of 10 MMBtu/h or greater are 

subject to the NSPS for boilers (either 

subpart Db or Dc of 40 CFR part 60) 

which regulate emissions of PM and 

require performance testing. 

Furthermore, new coal-fired area source 

boilers will likely 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. 


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The proposed GACT PM emission 

level based on NSPS subpart Dc for new 

area source boilers is 0.03 lb/million 

Btu. Of the 82 area source boilers for 

which we have PM emission data, 11 

had reported PM emission levels below 

0.03 lb/million Btu. 

For the organic urban HAP 

(acetaldehyde, acrolein, dioxins, and 

formaldehyde), the most effective 

control technology identified is 

minimizing CO emissions and we 

determined that this control is generally 

available and cost effective for new area 

source boilers. This determination is 

based on the fact there is no additional 

costs associated with proposing a CO 

emission limit (as a surrogate for the 

urban organic HAP) as GACT because it 

is the same as the MACT standard being 

proposed for these subcategories for 

POM. 

F. How did we select the compliance 

requirements? 

We are proposing testing, monitoring, 

notification, and recordkeeping 

requirements that are adequate to assure 

continuous compliance with the 

requirement of the rule. Those 

requirements are described in detail in 

sections IV.F to IV.H. We selected these 

requirements based upon our 

determination of the information 

necessary to ensure that the emission 

standards, work practices, and 

management practices are being 

followed and that emission control 

devices and equipment are maintained 

and operated properly. The proposed 

requirements ensure compliance with 

this proposed rule without proposing a 

significant additional burden for 

facilities that must implement them. 

We are proposing that compliance 

with the PM and mercury emission 

limits be demonstrated by an initial 

performance test. To ensure continuous 

compliance with the proposed PM and 

mercury emission limits, this proposed 

rule would require continuous 

parameter monitoring of control devices 

and recordkeeping. Additionally, this 

proposed rule requires annual 

performance tests to ensure, on an 

ongoing basis, that the air pollution 

control device is operating properly and 

its performance has not deteriorated. If 

initial compliance with the mercury 

emission limit is demonstrated by a fuel 

analysis performance test, this proposed 

rule requires fuel analyses monthly, 

with compliance determined based on 

an annual average. 

We evaluated the cost of applying PM 

CEMS to area source boilers. For PM 

CEM monitoring, capital costs were 

estimated to be $88,000 per unit and 

annualized costs were estimated to be 

$33,000 per unit. The estimated national 

annual cost would be $4.5 billion. We 

determined the costs would make them 

an unreasonable monitoring option. 

We reviewed the cost information for 

CO CEMS provided by commenters on 

the NESHAP for major source boilers to 

make the determination on whether to 

require CO CEMS or conducting annual 

CO testing to demonstrate continuous 

compliance with the CO emission limit. 

In evaluating the available cost 

information, we determined that 

requiring CO CEMS for units with heat 

input capacities greater or equal to 100 

MMBtu/hr is reasonable. This proposed 

rule requires units with heat input 

capacities less than 100 MMBtu/hr to 

conduct initial and annual performance 

(stack) tests. 

G. Alternative MACT Standards for 

Consideration 

Our analysis of the inventory for 

mercury under CAA section 112(c)(6) 

has led us to believe that we do not 

need to regulate biomass-fired and oilfired boilers under MACT in order to 

meet our statutory obligations under 

this provision. We solicit comment on 

whether we should require the MACTbased 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 MACTbased requirements for mercury emitted 

from biomass-fired and oil-fired area 

source boilers in the event comment and 

further analysis of the inventory 

demonstrates such regulation is 

necessary to fulfill the 90 percent 

requirement under CAA section 

112(c)(6) or is otherwise appropriate. 

We present what would be MACT 

below. 

1. Existing area source boilers 

designed for biomass firing: 

Mercury—We obtained mercury 

emission data from two biomass-fired 

area source boilers as part of the 

information collection effort for the 

major source NESHAP. Thus, the top 12 

percent would be comprised of one 

boiler. The average mercury level of the 

top 12 percent is 0.36 lb/TBtu. All 3 test 

runs results were nondetect. The 

standard deviation for the three 

detection limits, when converted to lb/ 

mmBtu using the heat input rates during 

each run, was 1.82E–09. Therefore, the 

resulting MACT floor mercury limit for 

existing biomass-fired area source 

boilers would be 0.37 lb/TBtu (rounded 

to 0.0000004 lb/MMBtu). 

2. Existing area source boilers 

designed for oil firing: 

Mercury—There are no available 

emission data, State regulations, or State 

permits regarding mercury emissions 

from oil-fired area source boilers. 

Available emission factors are generally 

the average of available data and would 

not reasonably represent the average of 

the top 12 percent best performing 

units. However, we have obtained 

mercury emission data on major source 

oil-fired boilers as part of the major 

source rulemaking. Since major source 

oil-fired boilers are similar in design 

and controls as compared to area source 

oil-fired boilers, we are applying the 

major source MACT limit of 4 lb/TBtu 

(0.000004 lb/MMBtu) to existing oilfired area source boilers. 

3. New area source boilers designed 

for biomass firing: 

Mercury—We determined in the 

context of the major source rulemaking 

for boilers that fabric filters are the most 

effective technology employed by 

biomass-fired boilers for controlling 

mercury emissions. However, there is 

no test information on biomass-fired 

boilers equipped with fabric filters in 

which to determine control efficiency. 

The average mercury level of the ‘‘best 

controlled’’ unit for which we have 

emission data is 0.36 lb/TBtu. All 3 test 

runs results were nondetect. The 

standard deviation for the three 

detection limits, when converted to lb/ 

MMBtu using the heat input rates 

during each run, was 1.82E–09. 

Therefore, the resulting MACT floor 

mercury limit for existing biomass-fired 

area source boilers would be 0.36 lb/ 

TBtu (0.0000004 lb/MMBtu). 

4. New area source boilers designed 

for oil firing: 

Mercury—There are no available 

emission data, State regulations, or State 

permits regarding mercury emissions 

from oil-fired area source boilers. 

Available emission factors are generally 

the average of available data and would 

not reasonably represent the best 

performing unit. However, we have 

obtained mercury emission data on 

major source oil-fired boilers as part of 

the major source rulemaking. Since 

major source oil-fired boilers are similar 

in design and controls as compared to 

area source oil-fired boilers, we are 

applying the major source MACT limit 

for new oil-fired boilers of 0.3 lb/TBtu 

(0.0000003 lb/MMBtu) to new oil-fired 

area source boilers. 

H. How did we decide to exempt these 

area source categories from title V 

permitting requirements? 

For the reasons described below, we 

are proposing to exempt from title V 

permitting requirements affected 

sources in the industrial boiler and the 


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institutional/commercial boiler area 

source categories that are not certain 

synthetic area sources. We estimate that 

at least 48 synthetic area sources 

reduced their HAP emissions to below 

the major source thresholds by 

installing air pollution control devices. 

We are not proposing to exempt from 

title V those synthetic area sources that 

have reduced their HAP emissions to 

below the major source thresholds by 

installing air pollution control devices. 

CAA section 502(a) provides that the 

Administrator may exempt an area 

source category (in whole or in part) 

from title V if the Administrator 

determines that compliance with title V 

requirements is ‘‘impracticable, 

infeasible, or unnecessarily 

burdensome’’ on an area source 

category. See CAA section 502(a). In 

December 2005, in a national 

rulemaking, EPA interpreted the term 

‘‘unnecessarily burdensome’’ in CAA 

section 502 and developed a four-factor 

balancing test for determining whether 

title V is unnecessarily burdensome for 

a particular area source category, such 

that an exemption from title V is 

appropriate. See 70 FR 75320, December 

19, 2005 (Exemption Rule). 

The four factors that EPA identified in 

the Exemption Rule for determining 

whether title V is ‘‘unnecessarily 

burdensome’’ on a particular area source 

category include: (1) Whether title V 

would result in significant 

improvements to the compliance 

requirements, including monitoring, 

recordkeeping, and reporting, that are 

proposed for an area source category (70 

FR 75323); (2) whether title V 

permitting would impose significant 

burdens on the area source category and 

whether the burdens would be 

aggravated by any difficulty the sources 

may have in obtaining assistance from 

permitting agencies (70 FR 75324); (3) 

whether the costs of title V permitting 

for the area source category would be 

justified, taking into consideration any 

potential gains in compliance likely to 

occur for such sources (70 FR 75325); 

and (4) whether there are 

implementation and enforcement 

programs in place that are sufficient to 

assure compliance with the NESHAP for 

the area source category, without relying 

on title V permits (70 FR 75326). 

In discussing these factors in the 

Exemption Rule, we further explained 

that we considered on ‘‘a case-by-case 

basis the extent to which one or more 

of the four factors supported title V 

exemptions for a given source category, 

and then we assessed whether 

considered together those factors 

demonstrated that compliance with title 

V requirements would be ‘unnecessarily 

burdensome’ on the category, consistent 

with section 502(a) of the Act.’’ See 70 

FR 75323. Thus, in the Exemption Rule, 

we explained that not all of the four 

factors must weigh in favor of 

exemption for EPA to determine that 

title V is unnecessarily burdensome for 

a particular area source category. 

Instead, the factors are to be considered 

in combination, and EPA determines 

whether the factors, taken together, 

support an exemption from title V for a 

particular source category. 

In the Exemption Rule, in addition to 

determining whether compliance with 

title V requirements would be 

unnecessarily burdensome on an area 

source category, we considered, 

consistent with the guidance provided 

by the legislative history of CAA section 

502(a), whether exempting the area 

source category would adversely affect 

public health, welfare, or the 

environment. See 70 FR 15254–15255, 

March 25, 2005. As explained below, we 

propose that title V permitting is 

unnecessarily burdensome for a 

majority of the area sources at issue in 

this proposed rule. We have also 

determined that the proposed 

exemptions from title V would not 

adversely affect public health, welfare, 

and the environment. Our rationale for 

this decision follows here. 

In considering the exemption from 

title V requirements for sources in the 

categories affected by this proposed 

rule, we first compared the title V 

monitoring, recordkeeping, and 

reporting requirements (factor one) to 

the requirements in the proposed 

NESHAP for the boiler area source 

categories. This proposed rule requires 

facilities to comply with either emission 

limits using add-on controls or process 

changes or implementation of certain 

work or management practices. This 

proposed rule would require direct 

monitoring of emissions or control 

device parameters, both continuous and 

periodic, recordkeeping that also may 

serve as monitoring, and deviation and 

other semi-annual reporting to assure 

compliance with this NESHAP. 

The monitoring component of the first 

factor favors title V exemption. For the 

work and management practices, this 

proposed standard provides monitoring 

in the form of recordkeeping that would 

assure compliance with the 

requirements of this proposed rule. 

Monitoring by means other than 

recordkeeping for the work and 

management practices is not practical or 

appropriate. Records are required to 

ensure that the work and management 

practices are followed. This proposed 

rule requires continuous parameter 

monitoring, with periodic recording of 

the parameter for the required control 

device, to assure compliance. The 

records are required to be maintained in 

a form suitable and readily available for 

expeditious review, and that they are 

kept for at least five years, the first two 

of which must be onsite. 

As part of the first factor, in addition 

to monitoring, we have considered the 

extent to which title V could potentially 

enhance compliance for area sources 

covered by this proposed rule through 

recordkeeping or reporting 

requirements. We have considered the 

various title V recordkeeping and 

reporting requirements, including 

requirements for a 6-month monitoring 

report, deviation reports, and an annual 

certification in 40 CFR 70.6 and 71.6. 

For any boiler area source, this 

proposed NESHAP requires an Initial 

Notification and a Notification of 

Compliance Status. This proposed rule 

also requires facilities to certify 

compliance with the emission limits, 

work practices, and management 

practices. In addition, facilities must 

maintain records showing compliance 

through the required parameter 

monitoring and deviation requirements. 

The information required in the 

deviation reports is similar to the 

information that must be provided in 

the deviation reports required under 40 

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

We acknowledge that title V might 

require additional compliance 

requirements on these categories, but we 

have determined that the monitoring, 

recordkeeping and reporting 

requirements of the proposed NESHAP 

are sufficient to assure compliance with 

the provisions of the NESHAP. Given 

the nature of the operations at most area 

sources and the types of requirements in 

this rule, title V would not significantly 

improve those compliance 

requirements. 

For the second factor, we determine 

whether title V permitting would 

impose a significant burden on the area 

sources in the categories and whether 

that burden would be aggravated by any 

difficulty the source may have in 

obtaining assistance from the permitting 

agency. Subjecting any source to title V 

permitting imposes certain burdens and 

costs that do not exist outside of the title 

V program. EPA estimated that the 

average cost of obtaining and complying 

with a title V permit was $65,700 per 

source for a 5-year permit period, 

including fees. See Information 

Collection Request for Part 70 Operating 

Permit Regulations, January 2007, EPA 

ICR Number 1587.07. EPA does not 

have specific estimates for the burdens 

and costs of permitting industrial, 

commercial, and institutional boiler 


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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, 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 

estimated 91,300 area source facilities 

(including schools, hospitals, and 

churches) in the categories, it would 

likely be difficult for them to obtain 

sufficient assistance from the permitting 

authority. Thus, we conclude that factor 

two supports title V exemption for the 

sources in these categories that we 

propose to exempt. 

The third factor, which is closely 

related to the second factor, is whether 

the costs of title V permitting for these 

area sources would be justified, taking 

into consideration any potential gains in 

compliance likely to occur for such 

sources. We explained above under the 

second factor that the costs of 

compliance with title V would impose 

a significant burden on many of the 

approximately 137,000 facilities affected 

by this proposed rule. We also 

concluded in considering the first factor 

that, while title V might impose 

additional requirements, the 

monitoring, recordkeeping and 

reporting requirements in this proposed 

NESHAP assure compliance with the 

emission standards, work practices, and 

management practices imposed in the 

NESHAP. In addition, below in our 

consideration of the fourth factor, we 

find that there are adequate 

implementation and enforcement 

programs in place to assure compliance 

with the NESHAP. Because the costs, 

both economic and non-economic, of 

compliance with title V are high, and 

the potential for gains in compliance is 

low, title V permitting is not justified for 

the sources we propose to exempt. 

Accordingly, the third factor supports 

title V exemptions for these area source 

categories, except as discussed below. 

The fourth factor we considered in 

determining if title V is unnecessarily 

burdensome is whether there are 

implementation and enforcement 

programs in place that are sufficient to 

assure compliance with the NESHAP 

without relying on title V permits. EPA 

has implemented regulations that 

provide States the opportunity to take 

delegation of area source NESHAP, and 

we believe that State delegated 

programs are sufficient to assure 

compliance with this NESHAP. See 40 

CFR part 63, subpart E (States must have 

adequate programs to enforce the CAA 

section 112 regulations and provide 

assurances that they will enforce the 

NESHP before EPA will delegate the 

program). 

We also note that EPA retains 

authority to enforce this NESHAP 

anytime under CAA sections 112, 113, 

and 114. Also, States and EPA often 

conduct voluntary compliance 

assistance, outreach, and education 

programs (compliance assistance 

programs), which are not required by 

statute. We determined that these 

additional programs will supplement 

and enhance the success of compliance 

with these proposed standards. We 

believe that the statutory requirements 

for implementation and enforcement of 

this NESHAP by the delegated States 

and EPA and the additional assistance 

programs described above together are 

sufficient to assure compliance with 

these proposed standards without 

relying on title V permitting. 

In light of all the information 

presented here, we believe that there are 

implementation and enforcement 

programs in place that are sufficient to 

assure compliance with the proposed 

standards without relying on title V 

permitting for the sources we are 

proposing to exempt. 

Balancing the four factors for these 

area source categories strongly supports 

the proposed finding that title V is 

unnecessarily burdensome for the 

sources we propose to exempt. While 

title V might add additional compliance 

requirements if imposed, we believe 

that there would not be significant 

improvements to the compliance 

requirements in this proposed rule 

because the proposed rule requirements 

are specifically designed to assure 

compliance with the emission standards 

imposed on the area sources we propose 

to exempt. We further maintain that the 

economic and non-economic costs of 

compliance with title V would impose 

a significant burden on the sources we 

propose to exempt. We determined that 

the high relative costs would not be 

justified given that there is likely to be 

little or no potential gain in compliance 

if title V were required. And, finally, 

there are adequate implementation and 

enforcement programs in place to assure 

compliance with these proposed 

standards. Thus, we propose that title V 

permitting is ‘‘unnecessarily 

burdensome’’ for these area source 

categories, except as discussed below. 

In addition to evaluating whether 

compliance with title V requirements is 

‘‘unnecessarily burdensome’’, EPA also 

considered, consistent with guidance 

provided by the legislative history of 

CAA section 502(a), whether exempting 

these area source categories from title V 

requirements would adversely affect 

public health, welfare, or the 

environment. Exemption of these area 

source categories from title V 

requirements would not adversely affect 

public health, welfare, or the 

environment because the level of 

control would remain the same if a 

permit were required. The title V permit 

program does not impose new 

substantive air quality control 

requirements on sources, but instead 

requires that certain procedural 

measures be followed, particularly with 

respect to determining compliance with 

applicable requirements. As stated in 

our consideration of factor one for this 

category, title V would not lead to 

significant improvements in the 

compliance requirements applicable to 

existing or new area sources that we 

propose to exempt. 


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Furthermore, we explained in the 

Exemption Rule that requiring permits 

for the large number of area sources 

could, at least in the first few years of 

implementation, potentially adversely 

affect public health, welfare, or the 

environment by shifting State agencies 

resources away from assuring 

compliance for major sources with 

existing permits to issuing new permits 

for these area sources, potentially 

reducing overall air program 

effectiveness. Based on the above 

analysis, we conclude that title V 

exemptions for these area sources would 

not adversely affect public health, 

welfare, or the environment for all of the 

reasons explained above. 

For the reasons stated here, we are 

proposing to exempt these area source 

categories, except for certain synthetic 

area sources, as explained below, from 

title V permitting requirements. 

We have determined that it is not 

appropriate to exempt from Title V 

requirements those synthetic area 

sources that installed air pollution 

controls. Unlike many other area source 

categories that we have exempted from 

title V while implementing the 

requirements of CAA sections 112(c)(3) 

and 112(k)(3)(B), the boiler area source 

categories include a number of synthetic 

area sources that installed air pollution 

controls to become area sources. 

Synthetic area sources that installed 

controls represent less than one percent 

of the total number of sources that will 

be subject to the final rule. In fact, these 

sources are much more like the major 

sources of HAP that will be subject to 

the Boiler MACT. In addition, many of 

these sources are located in cities, and 

often in close proximity to residential 

and commercial centers where large 

numbers of people live and work. The 

record also indicates that many of these 

synthetic area sources have significantly 

higher emissions potential when 

uncontrolled than the other sources in 

the boiler area source categories, even 

those that are synthetic minor sources 

that took operational limits to attain 

area source status. 

For these reasons, we believe that the 

additional public participation and 

compliance benefits of additional 

informational, monitoring, reporting, 

certification, and enforcement 

requirements that exist in title V should 

be the same for a major source that 

installed a control device after 1990 to 

become an area source as for a source 

that is major and installed a control 

device to comply with an applicable 

major source NESHAP, and thereby 

reduced emissions below major source 

levels (10 tpy of a single HAP and 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. 

For these reasons above, this 

proposed rule requires title V permits 

for major sources of HAP emissions that 

installed controls after 1990 to become 

area sources of HAP emissions. We 

estimate that approximately 170 sources 

that will be subject to this rule are either 

required to have title V permits because 

of criteria pollutants or the proposed 

rule will require the affected area 

sources to obtain title V permits. 

We are not requiring title V permits 

for sources that reduced their emissions 

to area source levels by taking 

operational restrictions, such as 

restricting hours of operation or 

production, or for natural area sources, 

for the reasons set forth above. 

VI. Summary of the Impacts of This 

Proposed Rule 

A. What are the air impacts? 

Table 2 of this preamble illustrates, 

for each subcategory, the estimated 

emissions reductions achieved by this 

proposed rule (i.e., the difference in 

emissions between an area source boiler 

controlled to the MACT/GACT level of 

control and boilers at the current 

baseline) for new and existing sources. 

Nationwide emissions of total HAP 

(hydrogen chloride, hydrogen fluoride, 

non-mercury metals, mercury, and VOC 

(for organic HAP) will be reduced by 

about 1,200 tpy for existing units and 

340 tpy for new units. Emissions of 

mercury will be reduced by about 0.7 

tpy per year for existing units and by 0.1 

tpy for new units. Emissions of filterable 

PM will be reduced by about 6,300 tpy 

for existing units and 1,300 tpy for new 

units. Emissions of non-mercury metals 

(i.e., antimony, arsenic, beryllium, 

cadmium, chromium, cobalt, lead, 

manganese, nickel, and selenium) will 

be reduced by about 210 tpy for existing 

units and will be reduced by 40 tpy for 

new units. Additionally, EPA has 

estimated that conducting an annual 

tune-up 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. 

TABLE 2—SUMMARY OF HAP EMISSIONS REDUCTIONS FOR EXISTING AND NEW SOURCES (TPY) 

Source Subcategory PM Non mercury 

metals a Mercury POM b

Existing Units .................................. Coal ................................................ 5,350 24 0 .6 0 .2 

Biomass .......................................... 760 10 0 .003 5 

Oil ................................................... 230 175 0 .03 3 

New Units ....................................... Coal ................................................ 510 3 0 .09 0 .02 

Biomass .......................................... 690 8 0 .0003 0 .5 

Oil ................................................... 100 28 0 .005 0 .5 

a Includes antimony, arsenic, beryllium, cadmium, chromium, cobalt, lead, manganese, nickel, and selenium. 

bPOM 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. 


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31914 Federal Register / Vol. 75, No. 107 / Friday, June 4, 2010 / Proposed Rules 

B. What are the cost impacts? 

To estimate the national cost impacts 

of this proposed rule for existing 

sources, EPA developed several model 

boilers and determined the cost of 

control for these model boilers. The EPA 

assigned a model boiler to each existing 

unit based on the fuel, size, and current 

controls. The analysis considered all air 

pollution control equipment currently 

in operation at existing boilers. Model 

costs were then assigned to all existing 

units that could not otherwise meet the 

proposed standards. The resulting total 

national cost impact of this proposed 

rule for existing units is $696 million 

dollars in total annualized costs. The 

total annualized costs (new and 

existing) for installing controls, 

conducting biennial tune-ups and an 

energy assessment, and implementing 

testing and monitoring requirements, is 

$1.0 billion. Table 3 of this preamble 

shows the total annualized cost impacts 

for each subcategory. 

TABLE 3—SUMMARY OF ANNUAL COSTS FOR NEW AND EXISTING SOURCES

Source Subcategory 

Estimated/ 

projected number of affected 

units 

Total 

annualized 

cost 

(106$/yr) a

Existing Units ................................................................ Coal .............................................................................. 3,710 160 

Biomass ........................................................................ 10,958 48 

Oil ................................................................................. 168,003 436 

Facility Energy Assessment ......................................... All .................................................................................. ........................ 52 

New Units b ................................................................... Coal .............................................................................. 155 54 

Biomass ........................................................................ 200 13 

Oil ................................................................................. 6,424 244 

aTAC does not include fuel savings from improving combustion efficiency. 

b Impacts for new units assume the number of units online in the first 3 years of this rule (2010 to 2013). 

Using DOE projections on fuel 

expenditures, as well as the history of 

installation dates of area source boilers 

in the dataset, the number of additional 

boilers that could be potentially 

constructed was estimated. The 

resulting total national cost impact of 

this proposed rule on new sources by 

the 3rd year, 2013, is $311 million 

dollars in total annualized costs. When 

accounting for a 1 percent fuel savings 

resulting from improvements to 

combustion efficiency, the total national 

cost impact on new sources is $260 

million. 

A discussion of the methodology used 

to estimate cost impacts is presented in 

the memorandum ‘‘Estimation of 

Impacts for Industrial, Commercial, and 

Institutional Boilers Area Source 

NESHAP’’ in the Docket. 

C. What are the economic impacts? 

The economic impact analysis (EIA) 

that is included in the RIA shows that 

the expected prices for industrial sectors 

could be 0.01 percent higher and 

domestic production may fall by less 

than 0.01 percent. Because of higher 

domestic prices imports may rise by less 

than 0.01 percent. Energy prices will not 

be affected. 

Social costs are estimated to also be 

$0.5 billion in 2008 dollars. This is 

estimated to made up of a $0.3 billion 

loss in domestic consumer surplus, a 

$0.3 billion loss in domestic producer 

surplus, a $0.1 billion increase in rest of 

the world surplus, and a $0.1 billion net 

loss associated with new source costs 

and fuel savings not modeled in a way 

that can be used to attribute it to 

consumers and producers. 

EPA performed a screening analysis 

for impacts on small entities by 

comparing compliance costs to sales/ 

revenues (e.g., sales and revenue tests). 

EPA’s analysis found the tests were 

typically higher than 3 percent for small 

entities included in the screening 

analysis. EPA has prepared an Initial 

Regulatory Flexibility Analysis (IRFA) 

that discusses alternative regulatory or 

policy options that minimize the rule’s 

small entity impacts. It includes key 

information about key results from the 

Small Business Advocacy Review 

(SBAR) panel. 

Precise job effect estimates cannot be 

estimated with certainty. Morgenstern et 

al. (2002) identify three economic 

mechanisms by which pollution 

abatement activities can indirectly 

influence jobs: 

• Higher production costs raise 

market prices, higher prices reduce 

consumption, and employment within 

an industry falls (‘‘demand effect’’); 

• Pollution abatement activities 

require additional labor services to 

produce the same level of output (‘‘cost 

effect’’); and 

• Post regulation production 

technologies may be more or less labor 

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

required per dollar of output) (‘‘factorshift effect’’). 

Several empirical studies, including 

Morgenstern et al. (2002), suggest the 

net employment decline is zero or 

economically small (e.g., Cole and 

Elliot, 2007; Berman and Bui, 2001). 

However, others show the question has 

not been resolved in the literature 

(Henderson, 1996; Greenstone, 2002). 

Morgenstern’s paper uses a six-year 

panel (U.S. Census data for plant-level 

prices, inputs (including labor), outputs, 

and environmental expenditures) to 

econometrically estimate the production 

technologies and industry-level demand 

elasticities. Their identification strategy 

leverages repeat plant-level observations 

over time and uses plant-level and year 

fixed effects (e.g., plant and time 

dummy variables). After estimating their 

model, Morgenstern show and compute 

the change in employment associated 

with an additional $1 million ($1987) in 

environmental spending. Their 

estimates covers four manufacturing 

industries (pulp and paper, plastics, 

petroleum, and steel) and Morgenstern, 

et al. present results separately for the 

cost, factor shift, and demand effects, as 

well as the net effect. They also estimate 

and report an industry-wide average 

parameter that combines the four 

industry-wide estimates and weighting 

them by each industry’s share of 

environmental expenditures. 

EPA has most often estimated 

employment changes associated with 

plant closures due to environmental 

regulation or changes in output for the 

regulated industry (EPA, 1999a; EPA, 

2000). This analysis goes beyond what 

EPA has typically done in two 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 


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2Since Morgenstern’s analysis reports 

environmental expenditures in $1987, we make an 

inflation adjustment to the engineering cost analysis 

using GDP implicit price deflator (64.76/108.48) = 

0.60). 3Roman 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. 

estimate all three effects (‘‘demand,’’ 

‘‘cost,’’ and ‘‘factor shift’’). This transfer 

of results from the Morgenstern study is 

uncertain but avoids ignoring the ‘‘cost 

effect’’ and the ‘‘factor-shift effect.’’ 

We calculated ‘‘demand effect’’ 

employment changes by assuming that 

the number of jobs changes 

proportionally with multi-market 

model’s simulated output changes. 

These results were calculated for all 

sectors in the EPA model that show a 

change in output. The total job losses 

are estimated to be approximately 1,000. 

We also calculated a similar ‘‘demand 

effect’’ estimate that used the 

Morgenstern paper. To do this, we 

multiplied the point estimate for the 

total demand effect (¥3.56 jobs per 

million ($1987) of environmental 

compliance expenditure) by the total 

environmental compliance expenditures 

used in the partial equilibrium model. 

For example, the job loss estimate is 

approximately 1,000 jobs (¥3.56 × $0.5 

billion × 0.60).2

We also present the results of using 

the Morgenstern paper to estimate 

employment ‘‘cost’’ and ‘‘factor-shift’’ 

effects (Table 1). Although using the 

Morgenstern parameters to estimate 

these ‘‘cost’’ and ‘‘factor-shift’’ 

employment changes is uncertain, it is 

helpful to compare the potential job 

gains from these effects to the job losses 

associated with the ‘‘demand’’ effect. 

Table 1 shows that using the 

Morgenstern point estimates of 

parameters to estimate the ‘‘cost’’ and 

‘‘factor shift’’ employment gains may be 

greater than the employment losses 

using either of the two ways of 

estimating ‘‘demand’’ employment 

losses. The 95 percent confidence 

intervals are shown for all of the 

estimates based on the Morgenstern 

parameters. As shown, at the 95 percent 

confidence level, we cannot be certain 

if net employment changes are positive 

or negative. 

Although the Morgenstern paper 

provides additional information about 

the potential job effects of 

environmental protection programs, 

there are several qualifications EPA 

considered as part of the analysis. First, 

EPA has used the weighted average 

parameter estimates for a narrow set of 

manufacturing industries (pulp and 

paper, plastics, petroleum, and steel). 

Absent other data and estimates, this 

approach seems reasonable and the 

estimates come from a respected peerreviewed source. However, EPA 

acknowledges the proposed rule covers 

a broader set of industries not 

considered in original empirical study. 

By transferring the estimates to other 

industrial sectors, we make the 

assumption that estimates are similar in 

size. In addition, EPA assumes also that 

Morgenstern et al.’s estimates derived 

from the 1979–1991 still applicable for 

policy taking place in 2013, almost 20 

years later. Second, the multi-market 

model only considers near term 

employment effects in a U.S. economy 

where production technologies are 

fixed. As a result, the modeling system 

places more emphasis on the short term 

‘‘demand effect’’ whereas the 

Morgenstern paper emphasizes other 

important long term responses. For 

example, positive job gains associated 

with ‘‘factor shift effects’’ are more 

plausible when production choices 

become more flexible over time and 

industries can substitute labor for other 

production inputs. Third, the 

Morgenstern paper estimates rely on 

sector demand elasticities that are 

different from the demand elasticity 

parameters used in the multi-market 

model. As a result, the demand effects 

are not directly comparable with the 

demand effects estimated by the multimarket 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. What are the social costs and benefits 

of this proposed rule? 

We estimated the monetized benefits 

of this proposed regulatory action to be 

$1.0 billion to $2.4 billion (2008$, 3 

percent discount rate) in the 

implementation year (2013). The 

monetized benefits of this proposed 

regulatory action at a 7 percent discount 

rate are $910 million to $2.2 billion 

(2008$). Using alternate relationships 

between PM2.5 and premature mortality 

supplied by experts, higher and lower 

benefits estimates are plausible, but 

most of the expert-based estimates fall 

between these two estimates.3 A 

summary of the monetized benefits 

estimates at discount rates of 3 percent 

and 7 percent is in Table 5 of this 

preamble. 


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4Fann, 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. 

5Pope 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. 

6Laden et al., 2006. ‘‘Reduction in Fine 

Particulate Air Pollution and Mortality.’’ American 

Journal of Respiratory and Critical Care Medicine. 

173:667–672. 

7U.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. 

TABLE 5—SUMMARY OF THE MONETIZED BENEFITS ESTIMATES FOR THE PROPOSED BOILER AREA SOURCE RULE IN 2013 

[Billions of 2008$] 1

Estimated 

emission reductions 

(tons per year) 

Total monetized benefits 

(3% discount rate) 

Total monetized benefits 

(7% discount rate) 

PM2.5 ........................................................ 2,682 $0.96 to $2.4 ........................................... $0.88 to $2.1. 

PM2.5 Precursors ..................................... .............................................................

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

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

Total .................................................. ........................ $1.0 to $2.4 ............................................. $0.91 to $2.2. 

1All 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. 

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 human health 

benefits derived from reducing PM2.5

and PM2.5 precursor emissions, we 

utilized the general approach and 

methodology laid out in Fann et al. 

(2009).4

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 benefit-per-ton estimate 

than direct PM2.5 because it does not 

form as much PM2.5, thus the exposure 

would be lower, and the monetized 

health benefits would be lower. 

For context, it is important to note 

that the magnitude of the PM benefits is 

largely driven by the concentration 

response function for premature 

mortality. Experts have advised EPA to 

consider a variety of assumptions, 

including estimates based both on 

empirical (epidemiological) studies and 

judgments elicited from scientific 

experts, to characterize the uncertainty 

in the relationship between PM2.5

concentrations and premature mortality. 

For this proposed rule we cite two key 

empirical studies, one based on the 

American Cancer Society cohort study 5

and the extended Six Cities cohort 

study.6 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. 

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 7

provides an indication of the sensitivity 

of our results to various assumptions. 

It should be emphasized that the 

monetized benefits estimates provided 

above do not include benefits from 

several important benefit categories, 

including reducing other air pollutants, 

ecosystem effects, and visibility 

impairment. The benefits from reducing 

carbon monoxide and hazardous air 

pollutants have not been monetized in 

this analysis, including reducing 39,000 

tons of carbon monoxide, 0.75 ton of 

mercury, and 130 tons of HCl, 5 tons of 

HF, and 460 grams of dioxins/furans 

each year. Although we do not have 

sufficient information or modeling 

available to provide monetized 

estimates for this rulemaking, we 

include a qualitative assessment of the 

health effects of these air pollutants in 

the Regulatory Impact Analysis (RIA) for 

this proposed rule, which is available in 

the docket. 

The social costs of this proposed 

rulemaking are estimated to be $0.5 

billion (2008$) in the implementation 

year, and the monetized benefits are 

$1.0 billion to $2.4 billion (2008$, 3 

percent discount rate) for that same 

year. The benefits at a 7 percent 

discount rate are $910 million to $2.2 

billion (2008$). Thus, net benefits of 

this rulemaking are estimated at $500 

million to $1.9 billion (2008$, 3 percent 

discount rate) and $400 million to $1.7 

billion (2008$, 7 percent discount rate). 

A summary of the monetized benefits, 

social costs, and net benefits at discount 

rates of 3 percent and 7 percent is in 

Table 6 of this preamble. 


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TABLE 6—SUMMARY OF THE MONETIZED BENEFITS, SOCIAL COSTS, AND NET BENEFITS FOR THE BOILER AREA SOURCE

RULE IN 2013 

[Billions of 2008$] 1

3% Discount rate 7% Discount rate 

Proposed Option 

Total Monetized Benefits 2 ...................................................................... $1.0 to $2.4 ................................... $0.91 to $2.2. 

Total Social Costs 3 ................................................................................. $0.50 .............................................. $0.5. 

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

Non-monetized Benefits .......................................................................... 39,000 tons of carbon monoxide.

130 tons of HCl. 

5 tons of HF. 

0.75 tons of mercury. 

250 tons of other metals. 

470 grams of dioxins/furans. 

Health effects from NO2 and SO2 exposure. 

Ecosystem effects. 

Visibility impairment. 

1All estimates are for the implementation year (2015), and are rounded to two significant figures. 

2The total monetized benefits reflect the human health benefits associated with reducing exposure to PM2.5 through reductions of directly emitted PM2.5 and PM2.5 precursors such as NOX and SO2. It is important to note that the monetized benefits include many but not all health effects 

associated with PM2.5 exposure. 3The methodology used to estimate social costs for one year in the multimarket model using surplus changes results in the same social costs 

for both discount rates. 

For more information on the benefits 

analysis, please refer to the RIA for this 

rulemaking, which is available in the 

docket. 

E. What are the water and solid waste 

impacts? 

The EPA estimated that no additional 

water usage would result from the 

MACT floor level of control or GACT 

requirement. The fabric filter, 

multiclone or combustion control 

devices used to meet the standards of 

this proposed rule do not require any 

water to operate, nor do they generate 

any wastewater. 

The EPA estimated the additional 

solid waste that would result from this 

proposed rule to be 14,300 tpy for 

existing sources due to the dust and 

flyash captured by mercury and PM 

control devices. The cost of handling 

the additional solid waste generated 

from existing sources is $602,000 per 

year. For new sources installed by 2013, 

the EPA estimated the additional solid 

waste that would result from this 

proposed rule to be 1,800 tpy for new 

sources due to the dust and flyash 

captured by mercury and PM control 

devices. The cost of handling the 

additional solid waste generated from 

existing sources is $75,900 per year. 

These costs are also accounted for in the 

control costs estimates. 

A discussion of the methodology used 

to estimate impacts is presented in 

‘‘Estimation of Impacts for Industrial, 

Commercial, and Institutional Boilers 

Area Source NESHAP’’ in the Docket. 

F. What are the energy impacts? 

The EPA expects an increase of 

approximately 206 million kilowatt 

hours (kWh) in national annual energy 

usage from existing sources as a result 

of this proposed rule. The increase 

results from the electricity required to 

operate control devices installed to meet 

this proposed rule, such as fabric filters. 

Additionally, for new sources installed 

by 2013, EPA expects an increase of 

approximately 22 million kWh in 

national annual energy usage in order to 

operate the control devices. 

The Department of Energy has 

conducted energy assessments at 

selected manufacturing facilities and 

reports that facilities can reduce fuel/ 

energy use by 10 to 15 percent by using 

best practices to increase their energy 

efficiency. Additionally, the EPA 

expects work practice standards such as 

boilers tune-ups and combustion 

controls such as new replacement 

burners and will improve the efficiency 

of boilers. The EPA estimates existing 

area source facilities can save 20 trillion 

BTU of fuel each year. For new sources 

online by 2013, the EPA estimates 2.3 

trillion BTU per year of fuel can be 

conserved. This fuel savings estimates 

includes only those fuel savings 

resulting from liquid and coal fuels and 

it is based on the assumption that the 

work practice standards will achieve 1 

percent improvement in efficiency. 

VII. Relationship of This Proposed 

Action to CAA Section 112(c)(6) 

CAA section 112(c)(6) requires EPA to 

identify categories of sources of seven 

specified pollutants to assure that 

sources accounting for not less than 90 

percent of the aggregate emissions of 

each such pollutant are subject to 

standards under CAA Section 112(d)(2) 

or 112(d)(4). EPA has identified 

‘‘Industrial Coal Combustion,’’ 

‘‘Industrial Oil Combustion,’’ Industrial 

Wood/Wood Residue Combustion,’’ 

‘‘Commercial Coal 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 


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controlled by the various postcombustion controls. The add-on PM 

control systems (fabric filter) used to 

reduce mercury and/or PM emissions 

further reduce emissions of these 

organic pollutants, as is evidenced by 

performance data. Specifically, the 

emission tests obtained at currently 

operating major source boilers show that 

the proposed MACT regulations for area 

source boilers will reduce Hg emissions 

by about 86 percent. It is, therefore, 

reasonable to conclude that POM 

emissions will be substantially 

controlled. Thus, while this proposed 

rule does not identify specific numerical 

emission limits for POM, emissions of 

POM are, for the reasons noted below, 

nonetheless ‘‘subject to regulation’’ for 

purposes of CAA section 112(c)(6). 

In lieu of establishing numerical 

emissions limits for pollutants such as 

POM, we regulate surrogate substances. 

While we have not identified specific 

numerical limits for POM, we believe 

CO serves as an effective surrogate for 

this HAP, because CO, like POM, is 

formed as a product of incomplete 

combustion. 

Consequently, we have concluded 

that the emissions limits for CO 

function as a surrogate for control of 

POM, such that it is not necessary to 

propose numerical emissions limits for 

POM with respect to boilers to satisfy 

CAA Section 112(c)(6). 

To further address POM and mercury 

emissions, this proposed rule also 

includes an energy assessment 

provision that encourages modifications 

to the facility to reduce energy demand 

that lead to these emissions. 

VIII. Statutory and Executive Order 

Review 

A. Executive Order 12866: Regulatory 

Planning and Review 

Under 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 OMB for review under EO 

12866 and any changes in response to 

OMB recommendations have been 

documented in the docket for this 

action. For more information on the 

costs and benefits for this rule, please 

refer to Table 5 of this preamble. 

B. Paperwork Reduction Act 

The information collection 

requirements in this proposed rule have 

been submitted for approval to OMB 

under the Paperwork Reduction Act, 44 

U.S.C. 3501 et seq. The Information 

Collection Request (ICR) document 

prepared by EPA has been assigned EPA 

ICR number 2253.01. 

The recordkeeping and reporting 

requirements in this proposed rule 

would be based on the information 

collection requirements in EPA’s 

NESHAP General Provisions (40 CFR 

part 63, subpart A). The recordkeeping 

and reporting requirements in the 

General Provisions are mandatory 

pursuant to section 114 of the CAA (42 

U.S.C. 7414). All information other than 

emissions data submitted to EPA 

pursuant to the information collection 

requirements for which a claim of 

confidentiality is made is safeguarded 

according to CAA section 114(c) and 

EPA’s 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 $523 million. This 

includes 3.6 million labor hours per 

year at a cost of $336 million and total 

non-labor capital costs of $186 million 

per year. This estimate includes initial 

and annual performance tests, 

conducting and documenting an energy 

assessment, conducting and 

documenting a tune-up, semiannual 

excess emission reports, maintenance 

inspections, developing a monitoring 

plan, notifications, and recordkeeping. 

Monitoring, testing, tune-up and energy 

assessment costs were also included in 

the cost estimates presented in the 

control costs impacts estimates in 

section VI.B 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 767,403 hours per year 

at a total labor cost of $37.6 million per 

year. 

Burden means the total time, effort, or 

financial resources expended by persons 

to generate, maintain, retain, or disclose 

or provide information to or for a 

Federal agency. This includes the time 

needed to review instructions; develop, 

acquire, install, and utilize technology 

and systems for the purposes of 

collecting, validating, and verifying 

information, processing and 

maintaining information, and disclosing 

and providing information; adjust the 

existing ways to comply with any 

previously applicable instructions and 

requirements; train personnel to be able 

to respond to a collection of 

information; search data sources; 

complete and review the collection of 

information; and transmit or otherwise 

disclose the information. 

An agency may not conduct or 

sponsor, and a person is not required to 

respond to, a collection of information 

unless the collection displays a 

currently valid OMB control number. 

The OMB control numbers for EPA’s 

regulations in 40 CFR part 63 are listed 

in 40 CFR part 9. 

To comment on EPA’s need for this 

information, the accuracy of the 

provided burden estimates, and any 

suggested methods for 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 June 4, 2010, a comment to 

OMB is best assured of having its full 

effect if OMB receives it by July 6, 2010. 

The final rule will respond to any OMB 

or public comments on the information 

collection requirements contained in 

this proposal. 

C. Regulatory Flexibility Act (RFA) 

The RFA generally requires an agency 

to prepare a regulatory flexibility 

analysis of any rule subject to notice 

and comment rulemaking requirements 

under the Administrative Procedure Act 

or any other statute unless the agency 

certifies that the rule will not have a 


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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-forprofit enterprise which is independently 

owned and operated and is not 

dominant in its field. 

Because an initial screening analysis 

for impact on small entities indicated a 

likely significant impact for substantial 

numbers EPA convened a SBAR Panel 

to obtain advice and recommendation of 

representatives of the small entities that 

potentially would be subject to the 

requirements of this rule. 

(1) Panel Process and Panel Outreach 

As required by section 609(b) of the 

RFA, as amended by SBREFA, EPA also 

has conducted outreach to small entities 

and. On January 22, 2009 EPA’s Small 

Business Advocacy Chairperson 

convened a Panel under section 609(b) 

of the RFA. In addition to the Chair, the 

Panel consisted of the Director of the 

Sector Policies and Programs Division 

within EPA’s Office of Air and 

Radiation, the Chief Counsel for 

Advocacy of the Small Business 

Administration, and the Administrator 

of the Office of Information and 

Regulatory Affairs within the Office of 

Management and Budget. 

As part of the SBAR Panel process we 

conducted outreach with 

representatives from 14 various small 

entities that would be affected by this 

rule. The small entity representatives 

(SERs) included associations 

representing schools, churches, hotels/ 

motels, wood product facilities and 

manufacturers of home furnishings. We 

met with these SERs to discuss the 

potential rulemaking approaches and 

potential options to decrease the impact 

of the rulemaking on their industries/ 

sectors. We distributed outreach 

materials to the SERs; these materials 

included background on the 

rulemaking, possible regulatory 

approaches, preliminary cost and 

economic impacts, and possible 

rulemaking alternatives. The Panel met 

with SERs from the industries that will 

be impacted directly by this rule on 

February 10, 2009 to discuss the 

outreach materials and receive feedback 

on the approaches and alternatives 

detailed in the outreach packet. (EPA 

also met with SERs on November 13, 

2008 for an initial outreach meeting.) 

The Panel received written comments 

from the SERs following the meeting in 

response to discussions at the meeting 

and the questions posed to the SERs by 

the Agency. The SERs were specifically 

asked to provide comment on regulatory 

alternatives that could help to minimize 

the rule’s impact on small businesses. 

(2) Panel Recommendations for Small 

Business Flexibilities 

The Panel recommended that EPA 

consider and seek comment on a wide 

range of regulatory alternatives to 

mitigate the impacts of the rulemaking 

on small businesses, including those 

flexibility options described below. The 

following section summarizes the SBAR 

Panel recommendations. EPA has 

proposed provisions consistent with 

each of the Panel’s recommendations 

regarding area source facilities. 

Consistent with the RFA/SBREFA 

requirements, the Panel evaluated the 

assembled materials and small-entity 

comments on issues related to elements 

of the IRFA. A copy of the Final Panel 

Report (including all comments 

received from SERs in response to the 

Panel’s outreach meeting as well as 

summaries of both outreach meetings 

that were held with the SERs is 

included in the docket for this proposed 

rule. A summary of the Panel 

recommendations is detailed below. As 

noted above, this proposal includes 

proposed provisions for each of the 

Panel recommendations regarding area 

source facilities. 

(a) Work Practice Standards 

The panel recommended that EPA 

consider requiring annual tune-ups, 

including standardized criteria 

outlining proper tune-up 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 assessments, especially 

to smaller boiler operators. 

A work practice standard, instead of 

MACT emission limits, may be 

proposed if it can be justified under 

CAA section 112(h), that is, it is 

impracticable to enforce the emission 

standards due to technical and 

economic limitations. Work practice 

standards could reduce fuel use and 

improve combustion efficiency which 

would result in reduced emissions. 

In general, SERs commented that a 

regulatory approach to improve 

combustion efficiency, such as work 

practice standards, would have positive 

impacts with respect to the environment 

and energy use and save on compliance 

costs. The SERs were concerned with 

work practice standards that would 

require energy assessments and 

implementation of assessment findings. 

The basis of these concerns rested upon 

the uncertainty that there is no 

guarantee that there are available funds 

to implement a particular assessment’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 

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 


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analysis, for proposed and final rules 

with ‘‘Federal mandates’’ that may result 

in expenditures to State, local, and 

tribal governments, in the aggregate, or 

to the private sector, of $100 million or 

more in any 1 year. Before promulgating 

a rule for which a written statement is 

needed, section 205 of the UMRA 

generally requires us to identify and 

consider a reasonable number of 

regulatory alternatives and adopt the 

least costly, most cost-effective or least 

burdensome alternative that achieves 

the objectives of the rule. The 

provisions of section 205 do not apply 

when they are inconsistent with 

applicable law. Moreover, section 205 

allows us to adopt an alternative other 

than the least costly, most cost-effective 

or least burdensome alternative if the 

Administrator publishes with the final 

rule an explanation why that alternative 

was not adopted. Before we establish 

any regulatory requirements that may 

significantly or uniquely affect small 

governments, including tribal 

governments, we must develop a small 

government agency plan under section 

203 of the UMRA. The plan must 

provide for notifying potentially 

affected small governments, enabling 

officials of affected small governments 

to have meaningful and timely input in 

the development of regulatory proposals 

with significant Federal 

intergovernmental mandates, and 

informing, educating, and advising 

small governments on compliance with 

the regulatory requirements. 

We have determined that this 

proposed rule contains a Federal 

mandate that may result in expenditures 

of $100 million or more for State, local, 

and Tribal governments, in the 

aggregate, or the private sector in any 1 

year. Accordingly, we have prepared a 

written statement entitled ‘‘Unfunded 

Mandates Reform Act Analysis for the 

Proposed Industrial Boilers and Process 

Heaters NESHAP’’ under section 202 of 

the UMRA which is summarized below. 

1. Statutory Authority 

As discussed in section I of this 

preamble, the statutory authority for this 

proposed rulemaking is section 112 of 

the CAA. Title III of the CAA 

Amendments was enacted to reduce 

nationwide air toxic emissions. Section 

112(b) of the CAA lists the 188 

chemicals, compounds, or groups of 

chemicals deemed by Congress to be 

HAP. These toxic air pollutants are to be 

regulated by NESHAP. 

Section 112(d) of the CAA requires us 

to establish NESHAP for both major and 

area sources of HAP that are listed for 

regulation under CAA section 112(c). 

CAA section 112(k)(3)(B) calls for EPA 

to identify at least 30 HAP which, as the 

result of emissions from area sources, 

pose the greatest threat to public health 

in the largest number of urban areas. 

CAA section 112(c)(3) requires EPA to 

list sufficient categories or subcategories 

of area sources to ensure that area 

sources representing 90 percent of the 

emissions of the 30 urban HAP are 

subject to regulation. 

Under CAA section 112(d)(5), we may 

elect to promulgate standards or 

requirements for area sources based on 

GACT used by those sources to reduce 

emissions of HAP. Determining what 

constitutes GACT involves considering 

the control technologies and 

management practices that are generally 

available to the area sources in the 

source category. We also consider the 

standards applicable to major sources in 

the analogous source category and, as 

appropriate, the control technologies 

and management practices at area and 

major sources in similar categories, to 

determine if the standards, technologies, 

and/or practices are transferable and 

generally available to area sources. In 

determining GACT for a particular area 

source category, we consider the costs 

and economic impacts of available 

control technologies and management 

practices on that category. 

While GACT may be a basis for 

standards for most types of HAP emitted 

from area source, CAA section 112(c)(6) 

requires that source categories 

accounting for emissions of the HAP 

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. 

Consequently, we deem it reasonable to 

propose to regulate the coal-fired boilers 

under MACT, rather than the biomass 

and oil-fired 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 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 GACT-based 

emission limits for PM (as a surrogate 

for urban metals). New biomass and oilfired 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 MMBtu/h 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 MMBtu/h. 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 MMBtu/h or 

greater that requires the performance of 

an energy assessment on the boiler and 

the facility to identify cost-effective 

energy conservation measures. 

2. Social Costs and Benefits 

The regulatory impact analysis 

prepared for the proposed rule 

including the Agency’s assessment of 

costs and benefits, is detailed in the 

‘‘Regulatory Impact Analysis for the 

Proposed Industrial Boilers and Process 

Heaters MACT’’ in the docket. Based on 

estimated compliance costs associated 

with the proposed rule and the 

predicted change in prices and 

production in the affected industries, 

the estimated social costs of the 

proposed rule are $0.5 billion (2008 

dollars). 

It is estimated that 3 years after 

implementation of the proposed rule, 

HAP would be reduced by hundreds of 


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tons, including reductions in metallic 

HAP including mercury, hydrochloric 

acid, hydrogen fluoride, and several 

other organic HAP from area source 

boilers. Studies have determined a 

relationship between exposure to these 

HAP and the onset of cancer, however, 

the Agency is unable to provide a 

monetized estimate of the HAP benefits 

at this time. In addition, there are 

reductions in PM2.5 and in SO2 that 

would occur, including 2,700 tons of 

PM2.5 and 1,500 tons of SO2. These 

reductions occur within 3 years after the 

implementation of the proposed 

regulation and are expected to continue 

throughout the life of the affected 

sources. The major health effect 

associated with reducing PM2.5 and 

PM2.5 precursors (such as SO2) is a 

reduction in premature mortality. Other 

health effects associated with PM2.5

emission reductions include avoiding 

cases of chronic bronchitis, heart 

attacks, asthma attacks, and work-lost 

days (i.e., days when employees are 

unable to work). While we are unable to 

monetize the benefits associated with 

the HAP emissions reductions, we are 

able to monetize the benefits associated 

with the PM2.5 and SO2 emissions 

reductions. For SO2 and PM2.5, we 

estimated the benefits associated with 

health effects of PM but were unable to 

quantify all categories of benefits 

(particularly those associated with 

ecosystem and visibility effects). Our 

estimates of the monetized benefits in 

2013 associated with the 

implementation of the proposed 

alternative range from $1.0 billion (2008 

dollars) to $2.4 billion (2008 dollars) 

when using a 3 percent discount rate (or 

from $0.9 billion (2008 dollars) to $2.2 

billion (2008 dollars) when using a 7 

percent discount rate. The general 

approach used to value benefits is 

discussed in more detail earlier in this 

preamble. For more detailed 

information on the benefits estimated 

for the proposed rulemaking, refer to the 

RIA in the docket. 

3. Future and Disproportionate Costs 

The Unfunded Mandates Reform Act 

requires that we estimate, where 

accurate estimation is reasonably 

feasible, future compliance costs 

imposed by the proposed rule and any 

disproportionate budgetary effects. Our 

estimates of the future compliance costs 

of the proposed rule are discussed 

previously in this preamble. 

We do not believe that there will be 

any disproportionate budgetary effects 

of the proposed rule on any particular 

areas of the country, State or local 

governments, types of communities 

(e.g., urban, rural), or particular industry 

segments. See the results of the 

‘‘Economic Impact Analysis of the 

Proposed Industrial Boilers and Process 

Heaters NESHAP,’’ the results of which 

are discussed previously in this 

preamble. 

4. Effects on the National Economy 

The Unfunded Mandates Reform Act 

requires that we estimate the effect of 

the proposed rule on the national 

economy. To the extent feasible, we 

must estimate the effect on productivity, 

economic growth, full employment, 

creation of productive jobs, and 

international competitiveness of the 

U.S. goods and services, if we determine 

that accurate estimates are reasonably 

feasible and that such effect is relevant 

and material. 

The nationwide economic impact of 

the proposed rule is presented in the 

‘‘Economic Impact Analysis for the 

Industrial Boilers and Process Heaters 

MACT’’ in the docket. This analysis 

provides estimates of the effect of the 

proposed rule on some of the categories 

mentioned above. The results of the 

economic impact analysis are 

summarized previously in this 

preamble. The results show that there 

will be a small impact on prices and 

output (less than 0.01 percent). In 

addition, there should be little impact 

on energy markets (in this case, coal, 

natural gas, petroleum products, and 

electricity). Hence, the potential impacts 

on the categories mentioned above 

should be small. 

5. Consultation With Government 

Officials 

The Unfunded Mandates Reform Act 

requires that we describe the extent of 

the Agency’s prior consultation with 

affected State, local, and tribal officials, 

summarize the officials’ comments or 

concerns, and summarize our response 

to those comments or concerns. In 

addition, section 203 of the UMRA 

requires that we develop a plan for 

informing and advising small 

governments that may be significantly 

or uniquely impacted by a proposal. 

Consistent with the intergovernmental 

consultation provisions of section 204 of 

the UMRA, EPA has initiated 

consultations with governmental 

entities affected by this proposed rule. 

EPA invited the following 10 national 

organizations representing State and 

local elected officials to a meeting held 

on March 24, 2010 in Washington DC: 

(1) National Governors Association; (2) 

National Conference of State 

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, and (3) information on 

potential size of boilers used for various 

facility types and sizes. EPA has not 

received additional questions or 

requests from State or local officials. 

Consistent with section 205, EPA has 

identified and considered a reasonable 

number of regulatory alternatives. 

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 

assessment. 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. 


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The regulatory alternative upon 

which the proposed standards are based 

represents the MACT floor for mercury 

for coal-fired boilers, the MACT floor for 

POM (CO is used as a 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 and CO is used as a 

surrogate for urban organic pollutants) 

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 MMBtu/h or 

greater. A work practice standard (for 

mercury from coal-fired boilers and for 

POM from all boilers) or management 

practice (for all other HAP, including 

mercury from biomass-fired and oilfired 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 MMBtu/h. 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 

MMBtu/h or greater that requires the 

performance of an energy assessment on 

the boiler and the facility to identify 

cost-effective energy conservation 

measures. 

The proposed use of surrogate 

pollutants would result in reduced 

compliance costs because testing would 

only be required for the surrogate 

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

the HAP (i.e., POM and metals). The 

proposed work practice standard/ 

management practice also would result 

in reduced compliance costs with 

respect to monitoring/testing for the 

smaller existing area source boilers. 

EPA’s proposed exemption of most area 

source facilities from title V permit 

requirements also would reduce burden 

on area source boiler facilities. 

This proposed rule is not subject to 

the requirements of section 203 of 

UMRA because it contains no regulatory 

requirements that might significantly or 

uniquely affect small governments. 

While some small governments may 

have boilers that would be affected by 

the proposed rule, EPA’s analysis shows 

that other public facilities that are 

located at area source facilities owned 

by small entities would have cost-torevenue ratios exceeding 10 percent. 

Hospitals’ and schools’ revenue tests fall 

below 1 percent. Because the proposed 

rule’s requirements apply equally to 

boilers owned and/or operated by 

governments and to boilers owned and/ 

or operated by private entities, there 

would be no requirements that uniquely 

apply to such governments or impose 

any disproportionate impacts on them. 

E. Executive Order 13132: Federalism 

Under Executive Order 13132, EPA 

may not issue an action that has 

federalism implications, that imposes 

substantial direct compliance costs, and 

that is not required by statute, unless 

the Federal government provides the 

funds necessary to pay the direct 

compliance costs incurred by State and 

local governments, or EPA consults with 

State and local officials early in the 

process of developing the proposed 

action. 

EPA has concluded that this action 

may have federalism implications, 

because it may impose substantial direct 

compliance costs on State or local 

governments, and the Federal 

government will not provide the funds 

necessary to pay those costs. 

Accordingly, EPA provides the 

following federalism summary impact 

statement as required by section 6(b) of 

Executive Order 13132. 

Based on the estimates in EPA’s RIA 

for today’s action, the proposed 

regulatory option, if promulgated, may 

have federalism implications because 

the option may impose approximately 

$416 million in annual direct 

compliance costs on an estimated 

57,000 State or local governments. 

Boiler inventories for the health 

services, educational services, and 

government-owned buildings sectors 

from 13 States were used to estimate the 

nationwide number of potentially 

impacted State or local governments. 

Because the inventories for these sectors 

include privately owned and Federal 

government owned facilities, the 

estimate may include many facilities 

that are not State or local government 

owned. Table 7 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 MMBtu/h) would be subject to 

a work practice standard that requires a 

boiler tune-up every 2 years. Large coalfired boilers (boilers with heat input 

capacity of 10 MMBtu/h or greater) 

would be subject to emission limits for 

mercury and CO, while large biomass 

and oil-fired boilers would be subject to 

emission limits for CO. All facilities 

with large boilers would be required to 

conduct a one-time energy assessment. 

TABLE 7—STATE AND LOCAL GOVERNMENTS POTENTIALLY IMPACTED BY THE PROPOSED STANDARDS FOR BOILERS AT

AREA SOURCE FACILITIES

Sector 

Number of potentially impacted facilities 

Annual compliance costs to meet standards 

Total Small Large 

Health Services ..................................................... 17,206 15,293 1,913 $143 million. 

Educational Services ............................................ 34,052 33,303 749 $200 million. 

Government-Owned 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 solicits comment on this 

proposed action from State and local 

officials. 

F. Executive Order 13175: Consultation 

and Coordination with Indian Tribal 

Governments 

Executive Order 13175 (65 FR 67249, 

November 9, 2000), requires EPA to 

develop an accountable process to 


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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. 

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 peer-reviewed 

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), provides that agencies 

shall prepare and submit to the 

Administrator of the Office of 

Information and Regulatory Affairs, 

OMB, a Statement of Energy Effects for 

certain actions identified as significant 

energy actions. Section 4(b) of 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. 

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 (Pub. L. 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 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 

section 3.7(f) and section 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 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 


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make EJ part of their mission by 

identifying and addressing, as 

appropriate, disproportionately high 

and adverse human health or 

environmental effects of their programs, 

policies, and activities on minority 

populations, low-income, 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, theaters, 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 91,000 

facilities affected by the proposed rule, 

most of which are small entities. By the 

defined nature of the category, many of 

these sources are located in close 

proximity to residential areas, 

commercial centers, and other locations 

where large numbers of people live and 

work. 

Due to the large number of these 

sources, their nation-wide dispersal, 

and the absence of site specific 

coordinates, EPA is unable to examine 

the distributions of exposures and 

health risks attributable to these sources 

among different socio-demographic 

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 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 an 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?opendocument). 

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 

communities the opportunity to provide 

their comments on the permit 

conditions associated with permitting 

these sources. 

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: April 29, 2010. 

Lisa P. Jackson, 

Administrator. 

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 

Analyzers,1 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. 

* * * * * 

(39) ASTM Method D388–99 ε1, 

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 Waste,1 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 Activities,1 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 Calorimeter,1 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 Fuels,1

IBR approved for Table 6 to subpart 

DDDDD and Table 5 to subpart JJJJJJ of 

this part. 

* * * * * 

(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 ε1, 

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 


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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 part. 

* * * * * 

3. Add subpart JJJJJJ to read as 

follows: 

Subpart JJJJJJ—National Emission 

Standards for Hazardous Air Pollutants 

for Industrial, Commercial, and 

Institutional Boilers Area Sources 

Sec. 

What This Subpart Covers 

63.11193 Am I subject to this subpart? 

63.11194 What is the affected source of this 

subpart? 

63.11195 Are any boilers not subject to this 

subpart? 

63.11196 When do I have to comply with 

this subpart? 

Emission Limits, Work Practice Standards, 

Emission Reduction Measures, and 

Management Practices 

63.11200 What are the subcategories of 

boilers? 

63.11201 What standards must I meet? 

Initial Compliance Requirements 

63.11205 What are my general requirements 

for complying with this subpart? 

63.11210 What are my initial compliance 

requirements and by what date must I 

conduct them? 

63.11211 How do I demonstrate initial 

compliance with the emission limits? 

63.11212 What stack tests and procedures 

must I use for the performance tests? 

63.11213 What fuel analyses and 

procedures must I use for the 

performance tests? 

63.11214 When must I conduct subsequent 

performance tests? 

63.11215 How do I demonstrate initial 

compliance with the work practice 

standard, emission reduction measures, 

and management practice? 

Continuous Compliance Requirements 

63.11220 How do I monitor and collect data 

to demonstrate continuous compliance? 

63.11221 How do I demonstrate continuous 

compliance with the emission limits? 

63.11222 How do I demonstrate continuous 

compliance with the work practice 

standards? 

63.11223 What are my monitoring, 

installation, operation, and maintenance 

requirements? 

63.11225 What are my notification, 

reporting, and recordkeeping 

requirements? 

Other Requirements and Information 

63.11235 What parts of the General 

Provisions apply to me? 

63.11236 Who implements and enforces 

this subpart? 

63.11237 What definitions apply to this 

subpart? 

Table 1 to Subpart JJJJJJ of Part 63. Emission 

Limits 

Table 2 to Subpart JJJJJJ of Part 63. Work 

Practice Standards 

Table 3 to Subpart JJJJJJ of Part 63. Operating 

Limits for Boilers With Emission Limits 

Table 4 to Subpart JJJJJJ of Part 63. 

Performance (Stack) Testing 

Requirements 

Table 5 to Subpart JJJJJJ of Part 63. Fuel 

Analysis Requirements 

Table 6 to Subpart JJJJJJ of Part 63. 

Applicability of General Provisions to 

Subpart JJJJJJ 

Subpart JJJJJJ—National Emission 

Standards for Hazardous Air Pollutants 

for Industrial, Commercial, and 

Institutional Boilers Area Sources 

What This Subpart Covers 

§ 63.11193 Am I subject to this subpart? 

You are subject to this subpart if you 

own or operate an industrial, 

commercial, or institutional boiler as 

defined in § 63.11237 that is located at, 

or is part of, an area source of hazardous 

air pollutants (HAP), as defined in 

§ 63.2. 

§ 63.11194 What is the affected source of 

this subpart? 

(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 June 4, 2010. 

(c) An affected source is a new source 

if you commenced construction or 

reconstruction of the affected source 

after June 4, 2010. 

(d) A boiler is a new affected source 

if you commenced fuel switching from 

natural gas to coal, biomass, or oil after 

June 4, 2010. 

(e) Any source that was a major 

source and installed a control device on 

a boiler after November 15, 1990, and, 

as a result, became an area source under 

40 CFR part 63 is required to obtain a 

permit under 40 CFR part 70 or 40 CFR 

part 71. Otherwise, you are exempt from 

the obligation to obtain a permit under 

40 CFR part 70 or 40 CFR part 71, 

provided you are not otherwise required 

by law to obtain a permit under 40 CFR 

70.3(a) or 40 CFR 71.3(a). 

Notwithstanding the previous sentence, 

you must continue to comply with the 

provisions of this subpart. 

§ 63.11195 Are any boilers not subject to 

this subpart? 

The types of boilers listed in 

paragraphs (a) through (e) of this section 

are not subject to this subpart. 

(a) Any boiler specifically listed as an 

affected source in another standard(s) 

under this part. 

(b) Any boiler specifically listed as an 

affected source in another standard(s) 

established under section 129 of the 

Clean Air Act (CAA). 

(c) A boiler required to have a permit 

under section 3005 of the Solid Waste 

Disposal Act or covered by subpart EEE 

of this part (e.g., hazardous waste 

boilers). 

(d) A boiler that is used specifically 

for research and development. This does 

not include boilers that only provide 

steam to a process or for heating at a 

research and development facility. 

(e) A gas-fired boiler as defined in this 

subpart. 

§ 63.11196 What are my compliance 

dates? 

(a) If you own or operate an existing 

affected source, you must achieve 

compliance with the applicable 

provisions in this subpart no later than 

[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 [DATE OF 

PUBLICATION OF THE FINAL RULE 

IN THE FEDERAL REGISTER], you must 

achieve compliance with the provisions 

of this subpart no later than [DATE OF 

PUBLICATION OF THE FINAL RULE 

IN THE FEDERAL REGISTER]. 

(c) If you start up a new affected 

source after [DATE OF PUBLICATION 

OF THE FINAL RULE IN THE FEDERAL 

REGISTER], you must achieve 

compliance with the provisions of this 


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subpart upon startup of your affected 

source. 

Emission Limits, Work Practice 

Standards, Emission Reduction 

Measures, and Management Practices 

§ 63.11200 What are the subcategories of 

boilers? 

The subcategories of boilers are coal, 

biomass, and oil. Each subcategory is 

defined in § 63.11237. 

§ 63.11201 What standards must I meet? 

(a) You must comply with each 

emission limit specified in Table 1 of 

this subpart that applies to your boiler. 

(b) You must comply with each work 

practice standard, emission reduction 

measure, and management practice 

specified in Table 2 of this subpart that 

applies to your boiler. 

(c) These standards apply at all times. 

Initial Compliance Requirements 

§ 63.11205 What are my general 

requirements for complying with this 

subpart? 

(a) At all times you must operate and 

maintain any affected source, including 

associated air pollution control 

equipment and monitoring equipment, 

in a manner consistent with safety and 

good air pollution control practices for 

minimizing emissions. The general duty 

to minimize emissions does not require 

you to make any further efforts to 

reduce emissions if levels required by 

this standard have been achieved. 

Determination of whether such 

operation and maintenance procedures 

are being used will be based on 

information available to the 

Administrator which may include, but 

is not limited to, monitoring results, 

review of operation and maintenance 

procedures, review of operation and 

maintenance records, and inspection of 

the source. 

(b) You can demonstrate compliance 

with any applicable mercury emission 

limit using fuel analysis if the emission 

rate calculated according to 

§ 63.11211(b) is less than the applicable 

emission limit. Otherwise, you must 

demonstrate compliance using stack 

testing. 

§ 63.11210 What are my initial compliance 

requirements and by what date must I 

conduct them? 

(a) You must demonstrate initial 

compliance with each emission limit 

specified in Table 1 of this subpart that 

applies to you by either conducting 

performance (stack) tests, as applicable, 

according to § 63.11212 and Table 4 of 

this subpart or conducting fuel analyses, 

as applicable, according to § 63.11213 

and Table 5 to this subpart. 

(b) For affected sources that have an 

applicable carbon monoxide (CO) 

emission limit, your initial compliance 

requirements depend on the rated 

capacity of your boiler. If your boiler 

has a heat input capacity between 10 

and 100 million British thermal units 

(MMBtu) per hour, your initial 

compliance demonstration is 

conducting a performance test for CO 

according to Table 4 to this subpart. If 

your boiler has a heat input capacity of 

100 MMBtu per hour or greater, your 

initial compliance demonstration is 

conducting a performance evaluation of 

your continuous emission monitoring 

system (CEMS) for CO according to 

§ 63.11223. 

(c) For existing affected sources that 

have applicable emission limits, you 

must demonstrate initial compliance no 

later than 180 days after the compliance 

date that is specified in § 63.11196 and 

according to the applicable provisions 

in § 63.7(a)(2). 

(d) For existing affected sources that 

have applicable work practice standards 

or emission reduction measures, you 

must demonstrate initial compliance no 

later than the compliance date that is 

specified in § 63.11196 and according to 

the applicable provisions in § 63.7(a)(2). 

(e) For new affected sources, you must 

demonstrate initial compliance no later 

than 180 calendar days after [INSERT 

THE DATE OF PUBLICATION OF THE 

FINAL RULE IN THE FEDERAL 

REGISTER] or within 180 calendar days 

after startup of the source, whichever is 

later, according to § 63.7(a)(2)(ix). 

§ 63.11211 How do I demonstrate initial 

compliance with the emission limits? 

(a) For affected sources that elect to 

demonstrate compliance with any of the 

emission limits of this subpart through 

performance (stack) testing, your initial 

compliance requirements include 

conducting performance tests according 

to § 63.11212 and Table 4 to this subpart 

and conducting CMS performance 

evaluations according to § 63.11223. 

(b) If you elect to demonstrate 

compliance with an applicable mercury 

emission limit through fuel analysis, 

you must conduct fuel analyses 

according to § 63.11213 and follow the 

procedures in paragraphs (b)(1) through 

(3) of this section. 

(1) If you burn more than one fuel 

type, you must determine the fuel 

mixture you could burn in your boiler 

that would result in the maximum 

emission rates of mercury that you elect 

to demonstrate compliance through fuel 

analysis. 

(2) You must determine the 90th 

percentile confidence level fuel mercury 

concentration of the composite samples 

analyzed for each fuel type using 

Equation 1 of this section. 

P mean SD t) (Eq. 1) 90 = +∗ (

Where: 

P90 = 90th percentile confidence level 

mercury concentration, in pounds per 

million Btu; 

mean = Arithmetic average of the fuel 

mercury concentration in the fuel 

samples analyzed according to 

§ 63.11213, in units of pounds per 

million Btu; 

SD = Standard deviation of the mercury 

concentration in the fuel samples 

analyzed according to § 63.11213, in 

units of pounds per million Btu; 

t = t distribution critical value for 90th 

percentile (0.1) probability for the 

appropriate degrees of freedom (number 

of samples minus one) as obtained from 

a Distribution Critical Value Table. 

(3) To demonstrate compliance with 

the applicable mercury emission limit, 

the emission rate that you calculate for 

your boiler using Equation 1 of this 

section must be less than the applicable 

mercury emission limit. 

§ 63.11212 What stack tests and 

procedures must I use for the performance 

tests? 

(a) You must conduct all performance 

tests according to the requirements in 

§ 63.7. 

(b) You must conduct each stack test 

according to the requirements in Table 

4 to this subpart. 

(c) You must conduct stack tests at the 

maximum normal operating load while 

burning the type of fuel or mixture of 

fuels that have the highest content of 

mercury, and you must demonstrate 

initial compliance based on these tests. 

(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 


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paragraphs (b) and (c) of this section 

and Table 5 to this subpart, as 

applicable. 

(b) At a minimum, you must obtain 

three composite fuel samples for each 

fuel type according to the procedures in 

Table 5 of this subpart. Each composite 

sample will consist of a minimum of 

three samples collected at 

approximately equal intervals during a 

test run period. 

(c) Determine the concentration of 

mercury in the fuel in units of pounds 

per million Btu of each composite 

sample for each fuel type according to 

the procedures in Table 5 to this 

subpart. 

§ 63.11214 When must I conduct 

subsequent performance tests? 

(a) You must conduct all applicable 

performance (stack) tests according to 

§ 63.11212 on an annual basis, unless 

you follow the requirements listed in 

paragraphs (b) through (d) of this 

section. Annual performance tests must 

be completed between 10 and 12 

months after the previous performance 

test, unless you follow the requirements 

listed in paragraphs (b) through (d) of 

this section. 

(b) You can conduct performance 

stack tests less often for particulate 

matter or mercury if your performance 

stack tests for the pollutant for at least 

3 consecutive years show that your 

emissions are at or below 75 percent of 

the emission limit, and if there are no 

changes in the operation of the affected 

source or air pollution control 

equipment that could increase 

emissions. In this case, you do not have 

to conduct a performance test for that 

pollutant for the next 2 years. You must 

conduct a performance test during the 

third year and no more than 36 months 

after the previous performance test. 

(c) If your boiler continues to meet the 

emission limit for particulate matter or 

mercury, you may choose to conduct 

performance stack tests for the pollutant 

every third year if your emissions are at 

or below 75 percent of the emission 

limit, and if there are no changes in the 

operation of the affected source or air 

pollution control equipment that could 

increase emissions, but each such 

performance test must be conducted no 

more than 36 months after the previous 

performance test. 

(d) If a performance test shows 

emissions exceeded 75 percent of the 

emission limit, you must conduct 

annual performance tests for that 

pollutant until all performance tests 

over consecutive 3-year period show 

compliance. 

(e) If you have an applicable CO 

emission limit and your boiler has a 

heat input capacity between 10 and 100 

MMBtu per hour, you must conduct 

annual performance tests for CO 

according to § 63.11211. Each annual 

performance test must be conducted 

between 10 and 12 months after the 

previous performance test. 

(f) If you demonstrate compliance 

with the mercury based on fuel analysis, 

you must conduct a fuel analysis 

according to § 63.11213 for each type of 

fuel burned monthly. If you plan to burn 

a new type of fuel or fuel mixture, you 

must conduct a fuel analysis before 

burning the new type of fuel or mixture 

in your boiler. You must recalculate the 

mercury emission rate using Equation 1 

of § 63.11211. The recalculated mercury 

emission rate must be less than the 

applicable emission limit. 

§ 63.11215 How do I demonstrate initial 

compliance with the work practice 

standard, emission reduction measures, 

and management practice? 

(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 sitespecific monitoring plan required by 

§ 63.11223. 

(b) Except for monitor malfunctions, 

associated repairs, and required quality 

assurance or control activities 

(including, as applicable, calibration 

checks and required zero and span 

adjustments), you must monitor 

continuously (or collect data at all 

required intervals) at all times that the 

affected source is operating. 

(c) You may not use data recorded 

during monitoring malfunctions, 

associated repairs, or required quality 

assurance or control activities in data 

averages and calculations used to report 

emission or operating levels. You must 

use all the data collected during all 

other periods in assessing the operation 

of the control device and associated 

control system. 

§ 63.11221 How do I demonstrate 

continuous compliance with the emission 

limits? 

(a) You must demonstrate continuous 

compliance with each emission limit 

and operating limit in Tables 1 and 3 to 

this subpart that applies to you 

according to paragraphs (a)(1) through 

(5) of this section. 

(1) Following the date on which the 

initial performance test is completed or 

is required to be completed under 

§§ 63.7 and 63.11196, whichever date 

comes first, you must not operate above 

any of the applicable maximum 

operating limits or below any of the 

applicable minimum operating limits 

listed in Table 3 to this subpart at all 

times. Operation above the established 

maximum or below the established 

minimum operating limits shall 

constitute a deviation of established 

operating limits. Operating limits are 

confirmed or reestablished during 

performance tests. 

(2) If you have 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 you have you have an applicable 

mercury emission limit and you plan to 

burn a new type of fuel, you must 

determine the mercury concentration for 

any new fuel type in units of pounds 

per million Btu, based on supplier data 

or your own fuel analysis and meet the 

requirements in paragraphs (a)(3)(i) or 

(ii) of this section. 

(i) The recalculated mercury emission 

rate must be less than the applicable 

emission limit. 

(ii) If the results are higher than 

mercury fuel input during the previous 

performance test, then you must 

conduct a new performance test within 

60 days of burning the new fuel type or 

fuel mixture according to the 

procedures in § 63.11212 to demonstrate 

that the mercury emissions do not 

exceed the emission limit. 

(4) If your unit is controlled with a 

fabric filter, and you demonstrate 

continuous compliance using a bag leak 

detection system, you must initiate 

corrective action within 1 hour of a bag 

leak detection system alarm and operate 

and maintain the fabric filter system 

such that the alarm does not sound 

more than 5 percent of the operating 

time during a 6-month period. You must 

also keep records of the date, time, and 

duration of each alarm, the time 

corrective action was initiated and 

completed, and a brief description of the 


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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 CO 

according to §§ 63.11223(a) and 

63.11220 and maintain a CO emission 

level below your applicable CO 

emission limit in Table 1 to this subpart 

at all times. 

(b) You must report each instance in 

which you did not meet each emission 

limit and operating limit in Tables 1 and 

3 to this subpart that apply to you. 

These instances are deviations from the 

emission limits in this subpart. These 

deviations must be reported according 

to the requirements in § 63.11224. 

§ 63.11222 How do I demonstrate 

continuous compliance with the work 

practice and management practice 

standards? 

(a) For affected sources subject to the 

work practice standard or the 

management practices, you must keep 

records as required in § 63.11224(c) to 

demonstrate continuous compliance. 

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

boiler biennially to demonstrate 

continuous compliance as specified in 

paragraphs (b)(1) through (6) of this 

section. 

(1) Inspect the burner, and clean or 

replace any components of the burner as 

necessary; 

(2) Inspect the flame pattern and make 

any adjustments to the burner necessary 

to optimize the flame pattern consistent 

with the manufacturer’s specifications; 

(3) Inspect the system controlling the 

air-to-fuel ratio, and ensure that it is 

correctly calibrated and functioning 

properly; 

(4) Minimize total emissions of CO 

consistent with the manufacturer’s 

specifications; 

(5) Measure the concentration in the 

effluent stream of CO in parts per 

million, by volume, dry basis (ppmvd), 

before and after the adjustments are 

made; and 

(6) Maintain on-site and submit, if 

requested by the Administrator, an 

annual report containing the 

information in paragraphs (b)(6)(i) 

through (iii) of this section, 

(i) The concentrations of CO in the 

effluent stream in ppmvd, and oxygen 

in percent dry basis, measured before 

and after the adjustments of the boiler; 

(ii) A description of any corrective 

actions taken as a part of the 

combustion adjustment; and 

(iii) The type and amount of fuel used 

over the 12 months prior to the annual 

adjustment. 

§ 63.11223 What are my monitoring, 

installation, operation, and maintenance 

requirements? 

(a) If you are using a control device 

to comply with the emission limits 

specified in Table 1 of this subpart, you 

must maintain each operating limit in 

Table 3 of this subpart that applies to 

your boiler. If you use a control device 

not covered in Table 3, or you wish to 

establish and monitor an alternative 

operating limit and alternative 

monitoring parameters, you must apply 

to the United States Environmental 

Protection Agency (EPA) Administrator 

for approval of alternative monitoring 

under § 63.8(f). 

(b) If you demonstrate compliance 

with any applicable emission limit 

through stack testing, you must develop 

a site-specific 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 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 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 


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continuous opacity monitoring system 

(COMS) according to the procedures in 

paragraphs (d)(1) through (7) of this 

section by the compliance date specified 

in § 63.11196. 

(1) Each COMS must be installed, 

operated, and maintained according to 

PS 1 of 40 CFR part 60, appendix B. 

(2) You must conduct a performance 

evaluation of each COMS according to 

the requirements in § 63.8 and 

according to PS 1 of 40 CFR part 60, 

appendix B. 

(3) As specified in § 63.8(c)(4)(i), each 

COMS must complete a minimum of 

one cycle of sampling and analyzing for 

each successive 10-second period and 

one cycle of data recording for each 

successive 6-minute period. 

(4) The COMS data must be reduced 

as specified in § 63.8(g)(2). 

(5) You must include in your sitespecific monitoring plan procedures and 

acceptance criteria for operating and 

maintaining each COMS according to 

the requirements in § 63.8(d). At a 

minimum, the monitoring plan must 

include a daily calibration drift 

assessment, a quarterly performance 

audit, and an annual zero alignment 

audit of each COMS. 

(6) You must operate and maintain 

each COMS according to the 

requirements in the monitoring plan 

and the requirements of § 63.8(e). 

Identify periods the COMS is out of 

control including any periods that the 

COMS fails to pass a daily calibration 

drift assessment, a quarterly 

performance audit, or an annual zero 

alignment audit. 

(7) You must determine and record all 

the 1-hour block averages collected for 

periods during which the COMS is not 

out of control. 

(e) If you have an applicable CO 

emission limit and your boiler has a 

heat input capacity of 100 MMBtu per 

hour or greater, you must install, 

operate, and maintain a CEMS for CO 

and oxygen according to the procedures 

in paragraphs (e)(1) through (6) of this 

section by the compliance date specified 

in § 63.11196. The CO and oxygen shall 

be monitored at the same location at the 

outlet of the boiler. 

(1) Each CEMS must be installed, 

operated, and maintained according to 

Performance Specification (PS) 4A of 40 

CFR part 60, appendix B, and according 

to the site-specific monitoring plan 

developed according to § 63.11223. 

(2) You must conduct a performance 

evaluation of each CEMS according to 

the requirements in § 63.8 and 

according to PS 4A of 40 CFR part 60, 

appendix B. 

(3) Each CEMS must complete a 

minimum of one cycle of operation 

(sampling, analyzing, and data 

recording) for each successive 15- 

minute period. 

(4) The CEMS data must be reduced 

as specified in § 63.8(g)(2). 

(5) You must calculate and record all 

daily averages. A new daily average 

emission rate is calculated as the 

average of all of the hourly CO emission 

data for the calendar day. 

(6) For purposes of calculating data 

averages, you must not use data 

recorded during periods of monitoring 

malfunctions, associated repairs, out-ofcontrol 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 sitespecific monitoring plan procedures and 

acceptance criteria for operating and 

maintaining each CEMS according to 

the requirements in § 63.8(d). 

§ 63.11224 What are my notification, 

reporting, and recordkeeping, 

requirements? 

(a) You must submit the notifications 

specified in paragraphs (a)(1) through 

(a)(4) of this section. 

(1) You must submit all of the 

notifications in §§ 63.5(b), 63.7(b): 

63.8(e) and (f); 63.9(b) through (e); and 

63.9(g) and (h) that apply to you by the 

dates specified in those sections. 

(2) As specified in § 63.9(b)(2), you 

must submit the Initial Notification no 

later than 120 calendar days after 

[INSERT THE DATE OF PUBLICATION 

OF THE FINAL RULE IN THE FEDERAL 

REGISTER] or within 120 days after the 

source becomes subject to the standard. 

(3) You must submit the Notification 

of Compliance Status in accordance 

with § 63.9(h) no later than 120 days 

after the applicable compliance date 

specified in § 63.11196 unless you must 

conduct a performance test. If you must 

conduct a performance test, you must 

submit the Notification of Compliance 

Status within 60 days of completing the 

performance test. In addition to the 

information required in § 63.9(h)(2), 

your notification must include the 

following certification(s) of compliance, 

as applicable, and signed by a 

responsible official: 

(i) ‘‘This facility complies with the 

requirements in § 63.11222(b) to 

conduct a biennial tune-up of the 

boiler’’. 

(ii) ‘‘This facility has had an energy 

assessment performed according to 

§ 63.11215.’’ 

(iii) This certification of compliance 

by the owner or operator that installs 

bag leak detection systems: ‘‘This facility 

has prepared a bag leak detection 

system monitoring plan in accordance 

with § 63.11221 and will operate each 

bag leak detection system according to 

the plan.’’ 

(4) If you are using data from a 

previously conducted emission test to 

serve as documentation of conformance 

with the emission standards and 

operating limits of this subpart 

consistent with § 63.7(e)(2)(iv), you 

must submit the test data in lieu of the 

initial performance test results with the 

Notification of Compliance Status 

required under paragraph (a)(3) of this 

section. 

(b) You must prepare, by March 1 of 

each year, an annual compliance 

certification report for the previous 

calendar year containing the 

information specified in paragraphs 

(b)(1) through (b)(3) of this section. You 

must submit the report by March 15 if 

you had any instance described by 

paragraph (b)(3) of this section. 

(1) Company name and address. 

(2) Statement by a responsible official, 

with the official’s name, title, phone 

number, e-mail address, and signature, 

certifying the truth, accuracy and 

completeness of the notification and a 

statement of whether the source has 

complied with all the relevant standards 

and other requirements of this subpart. 

(3) If the source is not in compliance, 

include a description of deviations from 

the applicable requirements, the time 

periods during which the deviations 

occurred, and the corrective actions 

taken. 

(4) The total fuel use by each affected 

source subject to an emission limit, for 

each calendar month within the 

reporting period, including, but not 

limited to, a description of the fuel, 

including whether the fuel has received 

a non-waste determination by you or 

EPA, and the total fuel usage amount 

with units of measure. 

(c) You must maintain the records 

specified in paragraphs (c)(1) through 

(5) of this section. 

(1) As required in § 63.10(b)(2)(xiv), 

you must keep a copy of each 

notification and report that you 

submitted to comply with this subpart 

and all documentation supporting any 

Initial Notification or Notification of 

Compliance Status that you submitted. 

(2) You must keep records to 

document conformance with the work 

practices, emission reduction measures, 

and management practices required by 


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§ 63.11215 as specified in paragraphs 

(c)(2)(i) through (iv) of this section. 

(i) Records must identify each boiler, 

the date of tune-up, the procedures 

followed for tune-up, and the 

manufacturer’s specifications to which 

the boiler was tuned. 

(ii) Records documenting monthly 

fuel use by each boiler, including the 

type(s) of fuel, including, but not 

limited to, a description of the fuel, 

including whether the fuel has received 

a non-waste determination by you or 

EPA, and the total fuel usage amount 

with units of measure. 

(3) For sources that demonstrate 

compliance through fuel analysis, a 

copy of all calculations and supporting 

documentation that were done to 

demonstrate compliance with the 

mercury emission limits. Supporting 

documentation should include results of 

any fuel analyses. You can use the 

results from one fuel analysis for 

multiple boilers provided they are all 

burning the same fuel type. 

(4) You must keep the records of all 

inspection and monitoring data required 

by §§ 63.11221 and 63.11222, and the 

information identified in paragraphs 

(c)(4)(i) through (vi) of this section for 

each required inspection or monitoring. 

(i) The date, place, and time of the 

monitoring event; 

(ii) Person conducting the monitoring; 

(iii) Technique or method used; 

(iv) Operating conditions during the 

activity; 

(v) Results, including the date, time, 

and duration of the period from the time 

the monitoring indicated a problem to 

the time that monitoring indicated 

proper operation; and 

(vi) Maintenance or corrective action 

taken (if applicable). 

(5) If you use a bag leak detection 

system, you must keep the records 

specified in paragraphs (c)(5)(i) through 

(iii) of this section. 

(i) Records of the bag leak detection 

system output. 

(ii) Records of bag leak detection 

system adjustments, including the date 

and time of the adjustment, the initial 

bag leak detection system settings, and 

the final bag leak detection system 

settings. 

(iii) The date and time of all bag leak 

detection system alarms, and for each 

valid alarm, the time you initiated 

corrective action, the corrective action 

taken, and the date on which corrective 

action was completed. 

(d) Your records must be in a form 

suitable and readily available for 

expeditious review, according to 

§ 63.10(b)(1). As specified in 

§ 63.10(b)(1), you must keep each record 

for 5 years following the date of each 

recorded action. You must keep each 

record onsite for at least 2 years after the 

date of each recorded action according 

to § 63.10(b)(1). You may keep the 

records offsite for the remaining 3 years. 

(e) For affected facilities having 

applicable emission limits, you must 

submit an electronic copy of stack test 

reports to EPA’s WebFIRE data base, the 

owner or operator of an affected facility 

shall enter the test data into EPA’s data 

base using the Electronic Reporting Tool 

located at http://www.epa.gov/ttn/chief/ 

ert/ert_tool.html. 

Other Requirements and Information 

§ 63.11235 What parts of the General 

Provisions apply to me? 

Table 6 to this subpart shows which 

parts of the General Provisions in 

§§ 63.1 through 63.15 apply to you. 

§ 63.11236 Who implements and enforces 

this subpart? 

(a) This subpart can be implemented 

and enforced by EPA or a delegated 

authority such as your State, local, or 

tribal agency. If the EPA Administrator 

has delegated authority to your State, 

local, or tribal agency, then that agency 

has the authority to implement and 

enforce this subpart. You should contact 

your EPA Regional Office to find out if 

implementation and enforcement of this 

subpart is delegated to your State, local, 

or tribal agency. 

(b) In delegating implementation and 

enforcement authority of this subpart to 

a State, local, or tribal agency under 40 

CFR part 63, subpart E, the authorities 

contained in paragraphs (c) 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 nonopacity emission standard and work 

practice standards in § 63.11223(a). 

(2) Approval of alternative opacity 

emission standard under § 63.6(h)(9). 

(3) Approval of major change to test 

methods under § 63.7(e)(2)(ii) and (f). A 

‘‘major change to test method’’ is defined 

in § 63.90. 

(4) Approval of a major change to 

monitoring under § 63.8(f). A ‘‘major 

change to monitoring’’ is defined in 

§ 63.90. 

(5) Approval of major change to 

recordkeeping and reporting under 

§ 63.10(f). A ‘‘major change to 

recordkeeping/reporting’’ is defined in 

§ 63.90. 

§ 63.11237 What definitions apply to this 

subpart? 

Terms used in this subpart are 

defined in the CAA, in § 63.2 (the 

General Provisions), and in this section 

as follows: 

Bag leak detection system means an 

instrument that is capable of monitoring 

particulate matter loadings in the 

exhaust of a fabric filter (i.e., baghouse) 

in order to detect bag failures. A bag 

leak detection system includes, but is 

not limited to, an instrument that 

operates on electrodynamic, 

triboelectric, light scattering, light 

transmittance, or other principle to 

monitor relative particulate matter 

loadings. 

Biomass means but is not limited to, 

wood residue, and wood products (e.g., 

trees, tree stumps, tree limbs, bark, 

lumber, sawdust, sanderdust, chips, 

scraps, slabs, millings, and shavings); 

animal manure, including litter and 

other bedding materials; vegetative 

agricultural and silvicultural materials, 

such as logging residues (slash), nut and 

grain hulls and chaff (e.g., almond, 

walnut, peanut, rice, and wheat), 

bagasse, orchard prunings, corn stalks, 

coffee bean hulls and grounds. This 

definition of biomass fuel is not 

intended to suggest that these materials 

are or not solid waste. 

Biomass subcategory includes any 

boiler that burns any amount of 

biomass, but no coal, either alone or in 

combination with liquid fuels or 

gaseous fuels. 

Boiler means an enclosed combustion 

device in which water is heated to 

recover thermal energy in the form of 

steam or hot water. A device 

combusting solid waste, as defined in 40 

CFR 241.3, is not a boiler. Waste heat 

boilers are excluded from this 

definition. 

Boiler system means the boiler and 

associated components, such as, the 

feedwater system, the combustion air 

system, the fuel system (including 

burners), blowdown system, combustion 

control system, and the energy 

consuming systems. 

Coal means all solid fuels classifiable 

as anthracite, bituminous, subbituminous, 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, coal-oil 

mixtures, and coal-water mixtures. Coal 

derived gases are excluded from this 

definition. 

Coal subcategory includes any boiler 

that burns any coal alone or at least 10 


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percent coal on an annual heat input 

basis in combination with biomass, 

liquid fuels, or gaseous fuels. 

Commercial boiler means a boiler 

used in commercial establishments such 

as hotels, restaurants, and laundries to 

provide electricity, steam, and/or hot 

water that does not combust solid waste, 

as that term is defined by the 

Administrator under RCRA. 

Deviation means any instance in 

which an affected source subject to this 

subpart, or an owner or operator of such 

a source: 

(1) Fails to meet any requirement or 

obligation established by this subpart 

including, but not limited to, any 

emission limit, operating limit, or work 

practice standard; 

(2) Fails to meet any term or condition 

that is adopted to implement an 

applicable requirement in this subpart 

and that is included in the operating 

permit for any affected source required 

to obtain such a permit; or 

(3) A deviation is not always a 

violation. The determination of whether 

a deviation constitutes a violation of the 

standard is up to the discretion of the 

entity responsible for enforcement of the 

standards. 

Dry scrubber means an add-on air 

pollution control system that injects dry 

alkaline sorbent (dry injection) or sprays 

an alkaline sorbent (spray dryer) to react 

with and neutralize acid gas in the 

exhaust stream forming a dry powder 

material. Sorbent injection systems in 

fluidized bed boilers are included in 

this definition. 

Electrostatic precipitator means an 

add-on air pollution control device used 

to capture particulate matter by charging 

the particles using an electrostatic field, 

collecting the particles using a grounded 

collecting surface, and transporting the 

particles into a hopper. 

Energy assessment means an in-depth 

assessment of a facility to identify 

immediate and long-term opportunities 

to save energy, focusing on the steam 

and process heating systems which 

involves a thorough examination of 

potential savings from energy efficiency 

improvements, waste minimization and 

pollution prevention, and productivity 

improvement. 

Equivalent means the following only 

as this term is used in Table 5 to this 

subpart: 

(1) An equivalent sample collection 

procedure means a published voluntary 

consensus standard or practice (VCS) or 

EPA method that includes collection of 

a minimum of three composite fuel 

samples, with each composite 

consisting of a minimum of three 

increments collected at approximately 

equal intervals over the test period. 

(2) An equivalent sample compositing 

procedure means a published VCS or 

EPA method to systematically mix and 

obtain a representative subsample (part) 

of the composite sample. 

(3) An equivalent sample preparation 

procedure means a published VCS or 

EPA method that: Clearly states that the 

standard, practice or method is 

appropriate for the pollutant and the 

fuel matrix; or is cited as an appropriate 

sample preparation standard, practice or 

method for the pollutant in the chosen 

VCS or EPA determinative or analytical 

method. 

(4) An equivalent procedure for 

determining heat content means a 

published VCS or EPA method to obtain 

gross calorific (or higher heating) value. 

(5) An equivalent procedure for 

determining fuel moisture content 

means a published VCS or EPA method 

to obtain moisture content. If the sample 

analysis plan calls for determining 

mercury using an aliquot of the dried 

sample, then the drying temperature 

must be modified to prevent vaporizing 

this metal. On the other hand, if metals 

analysis is done on an ‘‘as received’’ 

basis, a separate aliquot can be dried to 

determine moisture content and the 

mercury concentration mathematically 

adjusted to a dry basis. 

(6) An equivalent mercury 

determinative or analytical procedure 

means a published VCS or EPA method 

that clearly states that the standard, 

practice, or method is appropriate for 

mercury and the fuel matrix and has a 

published detection limit equal or lower 

than the methods listed in Table 5 to 

this subpart for the same purpose. 

Fabric filter means an add-on air 

pollution control device used to capture 

particulate matter by filtering gas 

streams through filter media, also 

known as a baghouse. 

Federally enforceable means all 

limitations and conditions that are 

enforceable by the EPA Administrator, 

including the requirements of 40 CFR 

part 60 and 40 CFR part 61, 

requirements within any applicable 

State implementation plan, and any 

permit requirements established under 

40 CFR 52.21 or under 40 CFR 51.18 

and 40 CFR 51.24. 

Fuel type means each category of fuels 

that share a common name or 

classification. Examples include, but are 

not limited to, bituminous coal, 

subbituminous coal, lignite, anthracite, 

biomass, distillate oil, residual oil. 

Gaseous fuels includes, but is not 

limited to, natural gas, process gas, 

landfill gas, coal derived gas, refinery 

gas, and biogas. 

Gas-fired boiler includes any boiler 

that burns gaseous fuels not combined 

with any solid fuels, burns liquid fuel 

only during periods of gas curtailment, 

gas supply emergencies, or periodic 

testing on liquid fuel. Periodic testing of 

liquid fuel shall not exceed a combined 

total of 48 hours during any calendar 

year. 

Heat input means heat derived from 

combustion of fuel in a boiler and does 

not include the heat input from 

preheated combustion air, recirculated 

flue gases, or exhaust gases from other 

sources such as gas turbines, internal 

combustion engines, kilns, etc. 

Industrial boiler means a boiler used 

in manufacturing, processing, mining, 

and refining or any other industry to 

provide steam, hot water, and/or 

electricity that does not combust solid 

waste, as that term is defined by the 

Administrator under RCRA. 

Institutional boiler means a boiler 

used in institutional establishments 

such as medical centers, research 

centers, and institutions of higher 

education to provide electricity, steam, 

and/or hot water that does not combust 

solid waste, as that term is defined by 

the Administrator under RCRA. 

Liquid fuel means petroleum, 

distillate oil, residual oil, any form of 

liquid fuel derived from petroleum, onspec 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 

(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)). 


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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 gas does not constitute 

a period of natural gas curtailment or 

supply interruption. 

Qualified personnel mean specialists 

in evaluating energy systems, such as, 

those who have successfully completed 

the DOE Qualified Specialist program 

for all systems, Certified Energy 

Managers certified by the Association of 

Energy Engineers, or the equivalent. 

Responsible official means 

responsible official as defined in 40 CFR 

70.2. 

Tune-up means adjustments made to 

a boiler in accordance with procedures 

supplied by the manufacturer (or an 

approved specialist) to optimize the 

combustion efficiency. 

Waste heat boiler means a device that 

recovers normally unused energy and 

converts it to usable heat. Waste heat 

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. 

As stated in § 63.11201, you must 

comply with the following applicable 

emission limits: 

TABLE 1 TO SUBPART JJJJJJ OF PART 63—EMISSION LIMITS

If your boiler is in this 

subcategory . . . 

For the following 

pollutants . . . 

You must meet the following emission 

limits . . . 

1. New coal ..................................... a. Particulate Matter ...................... 0.03 lb per MMBtu of heat input. 

b. Mercury ...................................... 0.000003 lb per MMBtu of heat input. 

c. Carbon Monoxide ...................... 310 ppm by volume on a dry basis corrected to 7 percent oxygen 

(daily average). 

2. New biomass .............................. a. Particulate Matter ...................... 0.03 lb per MMBtu of heat input. 

b. Carbon Monoxide ...................... 100 ppm by volume on a dry basis corrected to 7 percent oxygen 

(daily average). 

3. New oil ........................................ a. Particulate Matter ...................... 0.03 lb per MMBtu of heat input. 

b. Carbon Monoxide ...................... 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. Mercury ......................................

b. Carbon Monoxide ......................

0.000003 lb per MMBtu of heat input. 

310 ppm by volume on a dry basis corrected to 7 percent oxygen 

(daily average). 

5. Existing biomass (units with heat 

input capacity of 10 million Btu 

per hour or greater).

Carbon Monoxide .......................... 160 ppm by volume on a dry basis corrected to 7 percent oxygen 

(daily average). 

6. Existing oil (units with heat input 

capacity of 10 million Btu per 

hour or greater).

Carbon Monoxide .......................... 2 ppm by volume on a dry basis corrected to 3 percent oxygen (daily 

average). 

As stated in §§ 63.11202 and 

63.11203, you must comply with the 

following applicable work practice 

standards: 

TABLE 2 TO SUBPART JJJJJJ OF PART 63—WORK PRACTICE STANDARDS, EMISSION REDUCTION MEASURES, AND

MANAGEMENT PRACTICES

If your boiler is in this 

subcategory . . . You must meet the following . . . 

1. Existing coal, biomass, or oil (units with heat input capacity of less than 10 million Btu per hour).a. Conduct a tune-up of the boiler biennially as specified in § 63.11222. 

2. Existing coal, biomass, or oil (units with heat input capacity of 10 million Btu per hour and greater).Must have an energy assessment performed by qualified personnel which includes: 

(1) a visual inspection of the boiler system. 

(2) establish operating characteristics of the facility, energy system specifications, operating and maintenance procedures, and unusual operating constraints, 

(3) identify major energy consuming systems, 

(4) a review of available architectural and engineering plans, facility operation 

and maintenance procedures and logs, and fuel usage, 

(5) a list of major energy conservation measures, 

(6) the energy savings potential of the energy conservation measures identified, 


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TABLE 2 TO SUBPART JJJJJJ OF PART 63—WORK PRACTICE STANDARDS, EMISSION REDUCTION MEASURES, AND

MANAGEMENT PRACTICES—Continued 

If your boiler is in this 

subcategory . . . You must meet the following . . . 

(7) a comprehensive report detailing the ways to improve efficiency, the cost of 

specific improvements, benefits, and the time frame for recouping those investments. 

As stated in § 63.11201, you must 

comply with the applicable operating 

limits: 

TABLE 3 TO SUBPART JJJJJJ OF PART 63—OPERATING LIMITS FOR BOILERS WITH MERCURY EMISSION 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 precipitator control ..................................... Maintain opacity to less than or equal to 10 percent opacity (daily block average). 

3. Dry scrubber or carbon injection control ....................... Maintain the minimum sorbent or carbon injection rate at or above the operating levels established during the performance test that demonstrated compliance with the 

applicable emission limit for mercury. 

4. Fuel analysis .................................................................. Maintain the fuel type or fuel mixture (annual average) such that the mercury emission rates calculated according to § 63.11211(c) is less than the applicable emission limits for mercury. 

As stated in § 63.11212, you must 

comply with the following requirements 

for performance (stack) test for new 

affected sources: 

TABLE 4 TO SUBPART JJJJJJ OF PART 63—PERFORMANCE (STACK) TESTING REQUIREMENTS

To conduct a performance 

test for the following 

pollutant . . . 

You must . . . Using . . . 

1. Particulate Matter ............. a. Select sampling ports location and the number of traverse points.Method 1 in appendix A to part 60 of this chapter. 

b. Determine velocity and volumetric flow-rate of the 

stack gas.

Method 2, 2F, or 2G in appendix A to part 60 of this 

chapter. 

c. Determine oxygen and carbon dioxide concentrations 

of the stack gas.

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)). 

d. Measure the moisture content of the stack gas ......... Method 4 in appendix A to part 60 of this chapter. 

e. Measure the particulate matter emission concentration.Method 5 or 17 (positive pressure fabric filters must 

use Method 5D) in appendix A to part 60 of this 

chapter. 

f. Convert emissions concentration to lb/MMBtu emission rates.Method 19 F-factor methodology in appendix A to part 

60 of this chapter. 

2. Mercury ............................ a. Select sampling ports location and the number of traverse points.Method 1 in appendix A to part 60 of this chapter. 

b. Determine velocity and volumetric flow-rate of the 

stack gas.

Method 2, 2F, or 2G in appendix A to part 60 of this 

chapter. 

c. Determine oxygen and carbon dioxide concentrations 

of the stack gas.

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)). 

d. Measure the moisture content of the stack gas ......... Method 4 in appendix A to part 60 of this chapter. 

e. Measure the mercury emission concentration ............ 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)). 

f. Convert emissions concentration to lb/MMBtu emission rates.Method 19 F-factor methodology in appendix A to part 

60 of this chapter. 

3. Carbon Monoxide ............ a. Select the sampling ports location and the number of 

traverse points.

Method 1 in appendix A to part 60 of this chapter. 

b. Determine velocity and volumetric flow-rate of the 

stack gas.

Method 2, 2F, or 2G in appendix A to part 60 of this 

chapter. 


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TABLE 4 TO SUBPART JJJJJJ OF PART 63—PERFORMANCE (STACK) TESTING REQUIREMENTS—Continued 

To conduct a performance 

test for the following 

pollutant . . . 

You must . . . Using . . . 

c. Determine oxygen and carbon dioxide concentrations 

of the stack gas.

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)). 

d. Measure the moisture content of the stack gas ......... Method 4 in appendix A to part 60 of this chapter. 

e. Measure the carbon monoxide emission concentration.Method 10, 10A, or 10 B in appendix A to part 60 of 

this chapter or ASTM D6522–00 (IBR, see 

§ 63.14(b). 

f. Convert emissions concentration to lb/MMBtu emission rates.Method 19 F-factor methodology in appendix A to part 

60 of this chapter. 

As stated in § 63.11213, you must 

comply with the following requirements 

for fuel analysis testing for new affected 

sources: 

TABLE 5 TO SUBPART JJJJJJ OF PART 63—FUEL ANALYSIS REQUIREMENTS

To conduct a fuel 

analysis for the 

following pollutant . . . 

You must . . . Using . . . 

1. Mercury ............................ a. Collect fuel samples .................................................... Procedure in § 63.11213(c) or ASTM D2234–D2234M– 

03ε1 (for coal) (IBR, see § 63.14(b)) or ASTM D6323– 

98 (2003) (for biomass) (IBR, see § 63.14(b)) or 

equivalent. 

b. Compose fuel samples ............................................... Procedure in § 63.11213(c) or equivalent. 

c. Prepare composited fuel samples .............................. 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. 

d. Determine heat content of the fuel type ..................... ASTM D5865–04 (for coal) (IBR, see § 63.14(b)) or 

ASTM E711–87 (1996) (for biomass) (IBR, see 

§ 63.14(b)) or equivalent. 

e. Determine moisture content of the fuel type .............. ASTM D3173–03 (IBR, see § 63.14(b)) or ASTM E871– 

82 (1998) (IBR, see § 63.14(b)) or equivalent. 

f. Measure mercury concentration in fuel sample .......... 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. 

g. Convert concentrations into units of lb/MMBtu of heat 

content.

As stated in § 63.11235, you must 

comply with the applicable General 

Provisions according to the following: 

TABLE 6 TO SUBPART JJJJJJ OF PART 63—APPLICABILITY OF GENERAL PROVISIONS TO SUBPART JJJJJJ 

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. 

§ 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. 


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TABLE 6 TO SUBPART JJJJJJ OF PART 63—APPLICABILITY OF GENERAL PROVISIONS TO SUBPART JJJJJJ—Continued 

Citation Subject Applies to subpart JJJJJJ 

§ 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.

§ 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. 

[FR Doc. 2010–10832 Filed 6–3–10; 8:45 am] 

BILLING CODE 6560–50–P 


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