6560-50-P

ENVIRONMENTAL PROTECTION AGENCY

40 CFR Part 63

[EPA-HQ-OAR-2002-0058; FRL- ]

RIN 2060-AG69

National Emission Standards for Hazardous Air Pollutants for 

Major Sources: Industrial/, Commercial/, and Institutional

Boilers and Process Heaters

AGENCY: Environmental Protection Agency (EPA).

ACTION: Proposed rule.

SUMMARY: On September 13, 2004, under authority of section 112 

of the Clean Air Act, EPA promulgated national emission 

standards for hazardous air pollutants for new and existing 

industrial/commercial/institutional boilers and process heaters. 

On June 19, 2007, the United States Court of Appeals for the 

District of Columbia Circuit vacated and remanded the national 

emission standards for hazardous air pollutants for 

industrial/commercial/institutional boilers and process heaters.

In response to the court’s vacatur and remand, this action

would require all major sources to meet hazardous air pollutants

emissions standards reflecting the application of the maximum 

achievable control technology. The proposed rule would protect 

air quality and promote public health by reducing emissions of 
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the HAPhazardous air pollutants listed in section 112(b)(1) of 

the Clean Air Act.

We are also proposing that existing major source facilities 

with an affected boiler undergo an energy assessment on the 

boiler system to identify cost-effective energy conservation 

measures.

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

DAYS AFTER PUBLICATION IN THE FEDERAL REGISTER]. Under the 

Paperwork Reduction Act, comments on the information collection 

provisions are best assured of having full effect if the Office 

of Management and Budget (OMB) receives a copy of your comments 

on or before [INSERT DATE 30 DAYS AFTER PUBLICATION IN THE 

FEDERAL REGISTER].

Public Hearing. We will hold a public hearing concerning 

this proposed rule and the interrelated proposed Boiler area 

source, CISWI, and RCRA rules, discussed in this proposal and 

published in the proposed rules section of today’s Federal 

Register, on [INSERT THE DATE 15 DAYS AFTER PUBLICATION IN THE 

FEDERAL REGISTER]. Persons requesting to speak at a public 

hearing must contact EPA by [INSERT THE DATE 10 DAYS AFTER 

PUBLICATION IN THE FEDERAL REGISTER].

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

EPA-HQ-OAR-2002-0058, by one of the following methods:

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Not at 0" + 0.5" + 1" + 1.5" + 2" + 2.5" +

3" + 3.5" + 4" + 4.5" + 5" + 5.5"
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• http://www.regulations.gov. Follow the instructions 

for submitting comments.

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

instructions for submitting comments on the EPA Air 

and Radiation Docket Web Site.

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

No. EPA-HQ-OAR-2002-0058.

• Fax

•

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

No. EPA-HQ-OAR-2002-0058.

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-2002-0058. Please 

include a total of two copies. In addition, please 

mail a copy of your comments on the information 

collection provisions to the Office of Information and 

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

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

Hand Delivery or Courier: Deliver your comments to: 

EPA Docket Center, EPA West, Room 3334, 1301 

Constitution Ave., NW, Washington, DC 20460. Such 

deliveries are only accepted during the Docket’s 
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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 
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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 [INSERT DATE 15 DAYS AFTER PUBLICATION IN THE 

FEDERAL REGISTER]. Persons interested in presenting oral 

testimony at the hearing should contact Ms. Pamela Garrett, 

Energy Strategies Group, at (919) 541-7966 by [INSERT DATE 10 

DAYS AFTER PUBLICATION IN THE FEDERAL REGISTER]. 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 

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

no one requests to speak at the public hearing by [INSERT DATE 

13 DAYS AFTER PUBLICATION IN THE FEDERAL REGISTER] 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, 
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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: Mr. Brian Shrager, 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) 541-7689; Fax number 

(919) 541-5450; E-mail address: shrager.brian@epa.gov. 

SUPPLEMENTARY INFORMATION:

The information presented 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
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A. What is the statutory authority for the proposed rule?

B. Summary of the Natural Resources Defense Council v. EPA

Decision

C. Summary of Other Related Court Decisions

D. EPA’s Response to the Vacatur

E. What is the relationship between the proposed rule and other 

combustion rules?

F. What are the health effects of pollutants emitted from 

industrial/commercial/institutional boilers and process heaters?

III. Summary of the Proposed Rule

A. What source categories are affected by the proposed rule?

B. What is the affected source? 

C. Does the proposed rule apply to me?

D. What emission limitations and work practice standards must I 

meet?

E. What are the startup, shutdown, and malfunction (SSM) 

requirements?

F. What are the testing and initial compliance requirements?

G. What are the continuous compliance requirements?

H. What are the notification, recordkeeping and reporting 

requirements?

I. Submission of Emissions Test Results to EPA

IV. Rationale for the Proposed Rule

A. How did EPA determine which sources would be regulated under 

the proposed rule?

B. How did EPA select the format for the proposed rule?

C. How did EPA determine the proposed emission limitations for 

existing units?

D. How did EPA determine the MACT floor for existing units?

E. How did EPA consider beyond-the-floor for existing units?

F. Should EPA consider different subcategories for solid fuel 

boilers and process heaters?

G. How did EPA determine the proposed emission limitations for 

new units?

H. How did EPA determine the MACT floor for new units?

I. How did EPA consider beyond-the-floor for new units?

J. What other compliance alternatives were considered?

K. How did we select the compliance requirements?

L. What alternative compliance provisions are being proposed?

M. How did EPA determine compliance times for the proposed 

rule?

N. How did EPA determine the required records and reports for 

this proposed rule?

O. How does the proposed rule affect permits?

P. Alternative Standard for Consideration

V. Impacts of the Proposed Rule
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A. What are the air impacts?

B. What are the water and solid waste impacts?

C. What are the energy impacts?

D. What are the control costs?

E. What are the economic impacts?

F. What are the social costs and benefits of the proposed 

rule?

VI. Public Participation and Request for Comment

VII. Relationship of the Proposed Action to Section 112(c)(6) of 

the CAA

VIII. Statutory and Executive Order Reviews

A. Executive Order 12866, Regulatory Planning and Review

B. Executive Order 13132, Federalism

C. Executive Order 13175, Consultation and Coordination with 

Indian Tribal Governments

D. Executive Order 13045, Protection of Children from 

Environmental Health Risks and Safety Risks

E. Unfunded Mandates Reform Act of 1995

F. Regulatory Flexibility Act as Amended by the Small 

Business Regulatory Enforcement Fairness Act (RFA) of 1996 

SBREFA), 5 U.S.C. 601 et Seq.

G. Paperwork Reduction Act

H. National Technology Transfer and Advancement Act

I. Executive Order 13211, Actions Concerning Regulations That 

Significantly Affect Energy Supply, Distribution, or Use

J. Executive Order 12898: Federal Actions to Address 

Environmental Justice in Minority Populations and Low-Income 

Populations

I. General Information

A. Does this action apply to me? 

The regulated categories and entities potentially affected 

by the proposed standards include:

Category

NAICS 

code1

Examples of potentially 

regulated entities
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Any industry 

using a 

boiler or

process heater 

as defined in 

the proposed 

rule

211 Extractors of crude petroleum 

and natural gas

321 Manufacturers of lumber and 

wood products

322 Pulp and paper mills

325 Chemical manufacturers

324 Petroleum refineries, and 

manufacturers of coal 

products

316, 

326,

339 

Manufacturers of rubber and 

miscellaneous plastic 

products

331 Steel works, blast furnaces

332 Electroplating, plating, 

polishing, anodizing, and 

coloring

336 Manufacturers of motor 

vehicle parts and accessories

221 Electric, gas, and sanitary 

services

622 Health services

611 Educational services

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 
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CFR 63.7485 of subpart DDDDD (National Emission Standards for 

Hazardous Air Pollutants (NESHAP) for Industrial, Commercial, 

and Institution Boilers and Process Heaters). If you have any 

questions regarding the applicability of this action to a 

particular entity, consult either the air permitting authority 

for the entity or your EPA regional representative as listed in 

40 CFR 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-2002-0058. 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 
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docket. Information so marked will not be disclosed except in 

accordance with procedures set forth in 40 CFR part 2. 

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

In addition to being available in the docket, an electronic 

copy of this proposed action will also be available on the 

Worldwide Web (WWW) through the Technology Transfer Network 

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

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

proposed or promulgated rules at the following address: 

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

technology exchange in various areas of air pollution control.

D. When would a public hearing occur?

If anyone contacts EPA requesting to speak at a public 

hearing concerning the proposed rule by [INSERT DATE 10 DAYS 

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

public hearing concerning this proposed rule on [INSERT DATE 15 

DAYS AFTER PUBLICATION IN THE FEDERAL REGISTER]. Persons 

interested in presenting oral testimony at the hearing, or 

inquiring as to whether a hearing will be held, should contact

Ms. Pamela Garrett, Energy Strategies Group, at (919) 541-7966 

at least 2 days in advance of the by [INSERT DATE 10 DAYS AFTER 

PUBLICATION IN THE FEDERAL REGISTER]. The public hearing will 

be held in the Washington DC area at a location and time that 

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will be posted at the following web site: 

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

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

no one requests to speak at the public hearing. If a by [INSERT 

DATE 13 DAYS AFTER PUBLICATION IN THE FEDERAL REGISTER] then the

public hearing is held, it will be held at 10 a.m. at the EPA’s 

Campus located at 109 T.W. Alexander Drive in Research Triangle 

Park, NC, or at an alternate site nearby.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 for this proposed rule?

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

set emissions standards for hazardous air pollutants (HAP) 

emitted by major stationary sources based on the performance of 

the maximum achievable control technology (MACT). The MACT

standards for existing sources must be at least as stringent as 

the average emissions limitation achieved by the best performing 

12 percent of existing sources (for which the Administrator has

emissions information) or the best performing 5 sources for 

source categories with less than 30 sources (CAA section

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

called the MACT floor. For new sources, MACT standards must be 

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at least as stringent as the control level achieved in practice 

by the best controlled similar source (CAA section 112(d)(3)). 

EPA also must consider more stringent “beyond-the-floor” control 

options. When considering beyond-the-floor options, EPA must 

consider not only the maximum degree of reduction in emissions 

of HAP, but must take into account costs, energy, and nonair

environmental impacts when doing so.

CAA section 112(c)(6) requires EPA to list categories and 

subcategories of sources assuring that sources accounting for 

not less than 90 percent of the aggregate emissions of each such 

pollutant (alkylated lead compounds; polycyclic organic matter;

hexachlorobenzene; mercury; polychlorinated byphenyls; 2,3,7,8-

tetrachlorodibenzofurans; and 2,3,7,8-

tetrachloroidibenzo-p-dioxin) are subject to standards under

subsection 112(d)(2) or (d)(4). Standards established under CAA 

section 112(d)(2) must reflect the performance of MACT. 

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

“Industrial Wood/Wood Residue Combustion,” “Commercial Coal 

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

Wood/Wood Residue Combustion” are listed as source categories

for regulation pursuant to CAA section 112(c)(6) due to 

emissions of polycyclic organic matter (POM) and mercury (63 FR 

17838, 17848, April 10, 1998). In the documentation for the 
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112(c)(6) listing, the commercial fuel combustion categories 

included institutional fuel combustion (“1990 Emissions 

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

1998).

CAA section 129(a)(1)(A) requires EPA to establish specific

performance standards, including emission limitations, for 

“solid waste incineration units” generally, and, in particular, 

for “solid waste incineration units combusting commercial or

industrial waste” (section 129(a)(1)(D)). Section 129 defines 

“solid waste incineration unit” as “a distinct operating unit of 

any facility which combusts any solid waste material from

commercial or industrial establishments or the general public.”

Section 129(g)(1). Section 129 also provides that “solid waste”

shall have the meaning established by EPA pursuant to its

authority under the Resource Conservation and Recovery Act. 

Section 129(g)(6).

In Natural Resources Defense Council v. EPA, 489 F. 3d 

1250, 1257–61 (D.C. Cir. 2007), the court vacated the

Commercial and Industrial Solid Waste Incineration (CISWI) 

Definitions Rule, 70 FR 55568 (September 22, 2005), which EPA 

issued pursuant to CAA section 129(a)(1)(D). In that rule, EPA

defined the term “commercial or industrial solid waste 

incineration unit” to mean a combustion unit that combusts 
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“commercial or industrial waste.” The rule defined “commercial

or industrial waste” to mean waste combusted at a unit that does 

not recover thermal energy from the combustion for a useful 

purpose. Under these definitions, only those units that

combusted commercial or industrial waste and were not designed 

to, or did not operate to, recover thermal energy from the 

combustion would be subject to section 129 standards. The 

District of Columbia Circuit (DC Circuit) rejected the 

definitions contained in the CISWI Definitions Rule and 

interpreted the term “solid waste incineration unit” in CAA 

section 129(g)(1) “to unambiguously include 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 1250, 1257–58.

CAA section 129 covers any facility that combusts any solid 

waste; CAA section 112(g)(6) directs the Agency to the Resource

Conservation and Recovery Act (RCRA) in terms of the definition 

of solid waste. The Agency is in the process of defining solid 

waste for purposes of Subtitle D of RCRA. EPA initiated a 

rulemaking to define which secondary materials are “solid waste”

for purposes of subtitle D (nonhazardous waste) of RCRA when

burned in a combustion unit. (See Advance Notice of Proposed
16

Rulemaking (74 FR 41, January 2, 2009) soliciting comment on 

whether certain secondary materials used as alternative fuels or

ingredients are solid wastes within the meaning of Subtitle D of 

RCRA.) If a unit combusts solid waste, it is subject to CAA 

section 129 of the Act, unless it falls within one of the four 

specified exceptions in CAA section 129(g).

The solid waste definitional rulemaking under RCRA is being 

proposed in a parallel action and is relevant to this proceeding 

because some industrial, commercial, or institutional boilers 

and process heaters combust secondary materials as alternative 

fuels. If an industrial, commercial, or institutional boilers 

andor process heaters combusts secondary materials that are 

solid waste under the proposed definitional rule, those units 

would be subject to section 129. The units subject to this rule 

include those 

industrial, commercial, or institutional boilers and process 

heaters that do not combust solid waste. EPA recognizes that it 

has imperfect information on the exact nature of the secondary 

materials which boilers and process heaters combust, including, 

for example, how much processing of such materials occurs, if 

any. We nevertheless used the information currently available 

to the Agency to determine which materials are solid waste and,
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therefore, subject to CAA section 129, and which are not solid 

waste and, therefore, subject to CAA section 112.

B. Summary of the Natural Resources Defense Council v. EPA

Decision

On September 13, 2004, EPA issued the NESHAP for 

Industrial, Commercial, and Institutional Boilers and Process 

Heaters (40 CFR 55218) (the Boiler MACT). We identified 18 

subcategories of boilers and process heaters emitting four 

different types of HAPs. See 69 FR 55,223-24. EPA set out to 

establish the MACT floor for each subcategory emitting each HAP 

according to the effectiveness of various add-on technologies. 

(See 68 FR 1660, 1674, Jan. 13, 2003 (proposed rule).) Applying 

this methodology, EPA set 25 numerical emission standards. The 

2004 final rule established emission limitations for particulate 

matter (PM), as a surrogate for non-mercury HAP metals, mercury,

and hydrogen chloride (HCl), as a surrogate for acid gas HAP,

for existing large solid fuel-fired sources only. For the 

remaining 47 boiler subcategory/HAP emissions, EPA determined 

that the appropriate MACT floor was “no emissions reduction” 

because “the best-performing sources were not achieving 

emissions reductions through the use of an emission control 

system and there were no other appropriate methods by which 

boilers and process heaters could reduce HAP emissions.” (69 FR 
18

55,233.) Accordingly, we established no standards. In 

addition, we set risk-based standards, also known as healthbased compliance alternatives, as alternatives to the MACT-based 

standards for hydrogen chloride and manganese.

EPA issued emissions standards for CISWI units on December 

1, 2000, and as part of that rulemaking, defined the term 

“commercial and industrial waste” to mean solid waste combusted 

in an enclosed device using controlled flame combustion without 

energy recovery that is a distinct operating unit of any 

commercial or industrial facility. In response to a petition 

for reconsideration, EPA filed a motion for voluntary remand, 

which the court granted on September 6, 2001. On remand, EPA 

solicited comments on the CISWI Rule’s definitions of “solid 

waste,” “commercial and industrial waste” and “CISWI unit.” On 

September 22, 2005, EPA issued the CISWI Definitions Rule, which 

contained definitions that were substantively the same as those 

issued before reconsideration. In particular, the 2005 CISWI 

Definitions Rule defined “commercial or industrial waste” to 

include only waste that is combusted at a facility that cannot 

or does not use a process that recovers thermal energy from the 

combustion for a useful purpose.

EPA received separate petitions from environmental groups, 

industry, and municipalities seeking judicial review of the 
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NESHAP for Industrial, Commercial, and Institutional Boilers and 

Process Heaters (Boiler MACT) as well as amendments to 

definitional terms in the Standards of Performance for New 

Stationary Sources and Emission Guidelines for Existing Sources: 

Commercial and Industrial Solid Waste Incineration Units (CISWI 

Definitions Rule), promulgated pursuant to CAA section 129. The 

environmental organizations challenged the CISWI Definitions 

Rule on the ground that its definition of “commercial or 

industrial waste” was inconsistent with the plain language of 

CAA section 129 and therefore impermissibly constricted the 

class of “solid waste incineration unit[s]” that were subject to 

the emission standards of the CISWI Rule. The environmental 

groups also challenged specific emission standards that EPA 

promulgated in the Boiler MACT and EPA’s methodology for setting 

them. The municipalities — the American Municipal Power-Ohio, 

Inc. and six of its members, the cities of Dover, Hamilton, 

Orrville, Painesville, Shelby and St. Mary’s, — challenged the 

Boiler MACT on the grounds that EPA failed to comply with the 

requirements of the Regulatory Flexibility Act (RFA) and that 

the standards as applied to small municipal utilities are 

unlawful.

As explained further below, the Court concluded that EPA’s 

definition of “commercial or industrial waste,” as incorporated 
20

in the definition of “commercial and industrial solid waste

incineration unit” (CISWI unit), was inconsistent with the plain 

language of CAA section 129 and that the CISWI Definitions Rule 

must, therefore, be vacated. The Court also vacated and 

remanded the Boiler MACT, finding that the Boiler MACT must be 

substantially revised as a consequence of the vacatur and remand 

of the CISWI Definitions Rule.

In its decision, the Court agreed with the environmental 

petitioners that EPA’s definition of “commercial or industrial 

waste,” as incorporated in the definition of CISWI units, 

conflicted with the plain language of CAA section 129(g)(1). 

That provision defines “solid waste incineration unit” to mean 

“any facility which combusts any solid waste material” from 

certain types of establishments, with four specific exclusions. 

The Court stated that, based on the use of the term “any” and 

the specific exclusions for only certain types of facilities 

from the definition of “solid waste incineration unit,” CAA 

section 129 unambiguously includes among the incineration units 

subject to its standards any facility that combusts any 

commercial or industrial solid waste material at all — subject 

only to the four statutory exclusions. The Court held that the 

definitions EPA promulgated in the CISWI Definitions Rule 

constricted the plain language of CAA section 129(g)(1), because 
21

the CISWI Definitions Rule excluded from its universe operating 

units that combusted solid waste and were designed for or 

operating with energy recovery. 

Having determined that EPA’s definition of “commercial and 

industrial solid waste incineration unit” conflicts with the 

plain meaning of CAA section 129 and must, therefore, be 

vacated, the Court also vacated the Boiler MACT because it 

concluded that the Boiler MACT would need to be revised because 

the universe of boilers subject to its standards will be 

different once EPA revises the CISWI definitions rule consistent 

with the Court’s opinion. The Court did not address 

petitioners’ specific challenges to the Boiler MACT.

C. Summary of Other Related Court Decisions

In March 2007, the D.C. Circuit Court issued an opinion 

(Sierra Club v. EPA, 479 F. 3d 875 (DC Cir. 2007) (Brick

MACT)) vacating and remanding CAA section 112(d) MACT standards 

for the Brick and Structural Clay Ceramics source categories. 

Some key holdings in that case were:

• Floors for existing sources must reflect the average 

emission limitation achieved by the best-performing 12

percent of existing sources, not levels EPA considers to be 

achievable by all sources (479 F. 3d at 880–81);
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• EPA cannot set floors of “no control.” The Court 

reiterated its prior holdings, including National Lime

Association, confirming that EPA must set floor standards 

for all HAP emitted by the major source, including those 

HAP that are not controlled by at-the-stack control devices 

(479 F. 3d at 883);

• EPA cannot ignore non-technology factors that reduce HAP 

emissions. Specifically, the Court held that “EPA’s

decision to base floors exclusively on technology even 

though non-technology factors affect emissions violates the

Act.” (479 F. 3d at 883)

Based on the Brick MACT decision, we believe a source’s 

performance resulting from the presence or absence of HAP in 

fuel materials must be accounted for in establishing floors; 

i.e., a low emitter due to low HAP fuel materials can still be a

best performer. In addition, the fact that a specific level of 

performance is unintended is not a legal basis for excluding the 

source’s performance from consideration. (National Lime Ass’n, 

233 F. 3d at 640.)

The Brick MACT decision also stated that EPA may account 

for variability in setting floors. However, the court found

that EPA erred in assessing variability because it relied on 

data from the worst performers to estimate best performers’
23

variability, and held that “EPA may not use emission levels of 

the worst performers to estimate variability of the best 

performers without a demonstrated relationship between the two.”

(479 F. 3d at 882.)

The majority opinion in the Brick MACT case does not 

address the possibility of subcategorization to address 

differences in the HAP content of raw materials. However, in 

his concurring opinion Judge Williams stated that EPA’s ability 

to create subcategories for sources of different classes, size, 

or type (CAA section 112 (d)(1)) may provide a means out of the

situation where the floor standards are achieved for some 

sources, but the same floors cannot be achieved for other

sources due to differences in local raw materials whose use is 

essential. (Id. At 884–85.9)

A second court opinion is also relevant to this proposal. 

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

court vacated the portion of the regulations contained in the 

General Provisions which exempt major sources from MACT 

standards during periods of startup, shutdown and malfunction

(SSM). The regulations (in 40 CFR 63.6(f)(1) and 63.6(h)(1)) 

provided that sources need not comply with the relevant CAA 

section 112(d) standard during SSM events and instead must

“minimize emissions . . . to the greatest extent which is 
24

consistent with safety and good air pollution control

practices.” The vacated Boiler MACT did not contain specific

provisions covering operation during SSM operating modes; rather 

it referenced the now-vacated exemption in the General 

Provisions. As a result of the court decision, we are 

addressing SSM in this proposed rulemaking. Discussion of this

issue may be found later in this preamble.

D. EPA’s Response to the Vacatur

In response to the NRDC v. EPA mandate, we initiated an 

information collection effort entitled “Information Collection 

Effort for Facilities with Combustion Units.” This information 

collection was conducted by EPA’s Office of Air and Radiation 

pursuant to CAA section 114 to assist the Administrator in 

developing emissions standards for boilers/process heaters and 

CISWI units (collectively, “combustion units”) pursuant to CAA 

sections 112(d) and 129. CAA section 114(a) states, in pertinent 

part:

For the purpose of ...(iii) carrying out any provision of 

this Chapter...(1) the Administrator may require any person 

who owns or operates any emission source...to-. . .(D) sample 

such emissions (in accordance with such procedures or 

methods, at such locations, at such intervals, during such 

periods and in such manner as the Administrator shall 
25

prescribe); (E) keep records on control equipment parameters, 

production variables or other indirect data when direct 

monitoring of emissions is impractical.. .(G) provide such 

other information as the Administrator may reasonably 

require...

There were two components to the information collection. 

To obtain the information necessary to identify and categorize 

all combustion units potentially affected by the revised 

standards for boilers/process heaters and for CISWI units, the 

first component of the information collection effort solicited

information from all potentially affected combustion units in the 

format of an electronic survey. The survey was submitted to the 

following facilities: (1) all facilities that submitted an 

initial notification for the 2004 boiler MACT standard, (2) all 

facilities identified by States as being subject to the 2004 

boiler MACT standard, and (3) facilities that are classified as a 

major source in their Title V permit that have a boiler or 

process heater listed in their permit. The survey was also sent 

to units covered by the 2000 CISWI emissions standards (40 CFR 

part 60 subpart CCCC) and to facilities that have incineration 

units (e.g., energy recovery units) that were listed as exempt 

under the 2000 CISWI standard. Each facility was required to

complete the survey for all combustion units located at the 
26

facility. The information requested for each combustion unit 

included the unit design, operation, air pollution control data, 

the fuels/materials burned, and available emissions test data, 

continuous emission monitoring (CEM) data, fuel/material 

analysis data, and permitted and regulatory emission limits.

The second component of the information collection request 

effort consisted of requiring the owners/operators of 169

boilers/process heaters to conduct emission testing for HAP and 

HAP surrogates. We first analyzed the results of the survey to 

determine if sufficient emissions data existed to develop 

emission standards under CAA sections 112(d) for all types of 

boilers/process heaters, all types of materials combusted, and 

all HAP to be regulated. If data were not sufficient, then we

selected pools of candidates to conduct emission testing. We

submitted a list of candidates to stakeholders, including state, 

industry, and environmental stakeholders, who had an opportunity 

to comment on the technical feasibility, the least-cost impact 

of the testing program, and the appropriateness of the testing 

being requested. We then made a selection of test sites after 

taking into account stakeholder comments. The sites selected 

were required to conduct an outlet stack test, consisting of 

three runs, in accordance with EPA-approved protocols, for all 

of the following pollutants: PM (filterable, condensable, and 
27

PM2.5), dioxins/furans (D/F), hydrogen chloride/hydrogen fluoride, 

mercury, metals (including antimony, arsenic, beryllium, 

cadmium, chromium, cobalt, lead, manganese, nickel, phosphorus, 

and selenium), carbon monoxide (CO), total hydrocarbons (THC), 

formaldehyde, oxides of nitrogen (NOx), and sulfur dioxide 

(SO2). Six facilities (two coal-fired, two biomass-fired, and 

two gas-fired boilers) were required to collect CEM data over 30 

operating days using mobile CEM devices for CO, THC, and NOx. 

The owner/operator of each selected combustion unit was also 

required to collect and analyze, in accordance with acceptable 

procedures, the material(s) fed to the combustion unit during 

each stack test. The results of the stack tests and the 

analyses of materials combusted were required to be submitted to 

the Agency and are available in the docket and can be downloaded 

at http://www.epa.gov/ttn/atw/boiler/boilerpg.html.

When we compared information on boilers and process heaters

from facilities submitting initial notifications to comply with 

the vacated 2004 Boiler MACT to the information gathering effort 

conducted for the 2004 Boiler MACT, a large disparity was 

identified in the number of potentially affected units at major 

sources of HAP. Since the last combustion unit data gathering 

effort in 1996, many sources have shut down, others have selected 

to operate with a permit limit on their HAP emissions in order to 
28

avoid being subject to the Boiler MACT (i.e., synthetic area 

source), and some units have switched out older solid fuel units 

for newer equipment due to increased insurance and maintenance 

costs. 

Based on the definition of solid waste as set forth in a 

parallel proposed action, we revised the population of combustion 

units subject to CAA section 129 (because they combust solid 

waste) and the population of boilers and process heaters subject 

to CAA section 112 (because they do not combust solid waste). We 

then used the new data to develop a revised NESHAP for boilers and 

process heaters under CAA section 112 and revised standards for 

incineration units covered by CAA section 129. Specifically, 

the data provide the Agency with updated information on the number 

of potentially affected units, available emission test data, and 

fuel/material analysis data to address variability. We are using 

all of the information before the Administrator to calculate the 

MACT floors, set emission limits, and evaluate the emission 

impacts of various regulatory options for these revised 

rulemakings. 

E. What is the relationship between this proposed rule and 

other combustion rules?

The proposed rule regulates source categories covering 

industrial boilers, institutional boilers, commercial boilers, 
29

and process heaters. These source categories potentially 

include combustion units that are already regulated by other 

MACT standards. Therefore, we are excluding from this proposed 

rule any boiler or process heater that is subject to regulation 

under other MACT standards.

In 1986, EPA had codified new source performance standards 

(NSPS) for industrial boilers (40 CFR part 60, subparts Db and 

Dc) and revised portions of those standards in 1999 and 2006. 

The NSPS regulates emissions of PM, SO2, and NOx from boilers 

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

will be subject to the final CAA section 112(d) standards for 

boilers and process heaters because it regulates sources of HAP

while the NSPS do not. However, in developing the proposed 

rule, we considered the monitoring requirements, testing 

requirements, and recordkeeping requirements of the NSPS to 

avoid duplicating requirements.

This proposed rule addresses the combustion of non-solid 

waste materials in boilers and process heaters. If an owner or 

operator of an affected source subject to these proposed 

standards were to start combusting a solid waste (as defined by 

the Administrator under RCRA), the affected source would cease 

to be subject to this action and would instead be subject to 

regulation under CAA section 129. A rulemaking under CAA 
30

section 129 is being proposed in a parallel action and is 

relevant to this action because it would apply to boilers and 

process heaters located at a major source that combust any solid 

waste. EPA is taking comment on whether a boiler or process 

heater could then opt back into regulation under this proposed 

rule by taking a federally enforceable restriction precluding

the future combustion of any solid waste material.

F. What are the health effects of pollutants emitted from 

industrial/commercial/institutional boilers and process heaters?

This proposed rule protects air quality and promotes the 

public health by reducing emissions of some of the HAP listed in 

CAA section 112(b)(1). As noted above, emissions data collected 

during development of the proposed rule show that hydrogen 

chloride emissions represent the predominant HAP emitted by 

industrial, commercial, and industrialinstitutional (ICI)

boilers, accounting for 8461 percent of the total HAP 

emissions..1

 

1 See Memorandum “Methodology for Estimating Impacts from Industrial, Commercial, Institutional Boilers and 

Process Heaters at Major Sources of Hazardous Air Pollutant Emissions” located in the docket.

 ICI boilers and process heaters also emit lesser 

amounts of hydrogen fluoride, accounting for about 517 percent 

of total HAP emissions, and metals (arsenic, cadmium, chromium, 

mercury, manganese, nickel, and lead) accounting for about 0.36

percent of total HAP emissions. Organic HAP (formaldehyde, POM, 

acetaldehyde, benzene) account for about 1115 percent of total 
31

HAP emissions. Exposure to these HAP is, depending on exposure 

duration and levels of exposures, can be associated with a 

variety of adverse health effects. These adverse health effects 

may include chronic health disorders (e.g.,, for example,

irritation of the lung, skin, and mucus membranes, effects on 

the central nervous system, and damage to the kidneys),, and 

acute health disorders (e.g., lung irritation and congestion, 

alimentary effects such as nausea and vomiting, and effects on 

the kidney and central nervous system).. We have classified two 

of the HAP as human carcinogens (arsenic and chromium VI) and 

four as probable human carcinogens (cadmium, lead, 

dioxins/furans, and nickel). We do not know the extent to which 

the adverse health effects described above occur in the 

populations surrounding these facilities. However, to the 

extent the adverse effects do occur, this proposed rule would 

reduce emissions and subsequent exposures.

III. Summary of this Proposed Rule

This section summarizes the requirements proposed in 

today’s action. Section IV below provides our rationale for the 

proposed requirements.

A. What source categories are affected by this proposed rule?

This proposed rule affects industrial boilers, 

institutional boilers, commercial boilers, and process heaters. 
32

In this proposed rule, process heaters are defined as units in 

which the combustion gases do not directly come into contact 

with process material or gases in the combustion chamber (e.g., 

indirect fired). Boiler means an enclosed device using 

controlled flame combustion and having the primary purpose of 

recovering thermal energy in the form of steam or hot water. 

B. What is the affected source? 

The affected source is: (1) the collection of all existing 

industrial, commercial, or institutional boilers or process 

heaters within a subcategory located at a major source facility

that do not combust solid waste or (2) each new or reconstructed 

industrial, commercial, or institutional boiler or process 

heater located at a major source facility that do not combust 

solid waste, as that term is defined by the Administrator under 

RCRA.

The affected source does not include boilers and process 

heaters that are subject to another standard under 40 CFR part 

63 or a standard established under CAA section 129.

C. Does this proposed rule apply to me?

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

boiler or process heater at a major source meeting the 

requirements discussed previously in this preamble. A major 

source of HAP emissions is any stationary source or group of 
33

stationary sources located within a contiguous area and under 

common control that emits or has the potential to emit 

considering controls 10 tons per year or more of any HAP or 25 

tons per year or more of any combination of HAP.

D. What emission limitations and work practice standards must I 

meet?

We are proposing the emission limits presented in Table 1 

of this preamble. Emission limits were developed for new and 

existing sources for eleven subcategories, which we developed 

based on unit design. 

We are proposing that if your new or existing boiler or 

process heater burns more thanat least 10 percent coal on aan 

annual average heat input2

 

2 Heat input means heat derived from combustion of fuel in a boiler or process heater and does not include the heat 

derived from preheated combustion air, recirculated flue gases or exhaust gases from other sources (such as 

stationary gas turbines, internal combustion engines, and kilns.

basis on an annual average, the unit 

is in one of the coal subcategories. If your new or existing 

boiler or process heater burns more thanat least 10 percent

biomass, on aan annual average heat input basis on an annual 

average, and less than 10 percent coal, on aan annual average

heat input basis on an annual average, we are proposing that the 

unit is in one of the biomass subcategories. If your new or 

existing boiler or process heater burns aat least 10 percent

liquid fuel (such as distillate oil, residual oil), or a 

liquidand less than 10 percent solid fuel in combination with a 
34

gaseous fuel, on an annual heat input basis, we are proposing 

that the unit is in one of the liquid subcategories.subcategory. 

If your new or existing boiler or process heater burns gaseous 

fuel and less than 10 percent, on aan annual average heat input 

basis on an annual average, of liquid or solid fuel, we are 

proposing that the unit is in one of the gas subcategories. 

Table 1. EMISSION LIMITS FOR BOILERS AND PROCESS HEATERS

(pounds per million British thermal units)

Subcategor

y

Particula

te Matter 

(PM)

Hydrogen 

Chloride 

(HCl)

Mercury

(Hg)

Carbon 

Monoxide(CO)

(ppm

@3%oxygen)

Dioxins/

Furans

(Total 

TEQ)

(ng/dscm)

Existing –

Coal 

Stoker 

0.02 0.00602 0.000003 4050 0.003

Existing -

Coal 

Fluidized 

Bed

0.02 0.00602 0.000003 4030 0.002

Existing –

Pulverized 

Coal

0.02 0.00602 0.000003 7090 0.003004

Existing –

Biomass 

Stoker 

0.0702 0.0006006 0.0000007

0000009

780560 0.003004

Existing -

Biomass 

Fluidized 

Bed

0.0702 0.0006006 0.0000007

0000009

230250 0.02

Existing –

Biomass 

Suspension 

Burner/Dut

ch Oven

0.0702 0.0006006 0.0000007

0000009

4601010 0.03

Existing –

Biomass 

Fuel Cells

0.0702 0.0006006 0.0000007

0000009

270 0.02
35

Existing -

Liquid

0.004 0.0003000

9

0.0000080

00004

1 0.002

Exis

ting – Gas 

(NG/RFG)

-- -- -- -- --

Existing –

Gas (Other 

Process 

Gases)

0.05 0.000003 0.0000002 1 0.008009

Exis

ting –

Metal 

Processing 

Furnaces

-- -- -- -- --

New –Coal 

Stoker 

0.0009001 0.0000500

006

0.0000007

000002

7 0.003

New - Coal 

Fluidized 

Bed

0.0009001 0.0000500

006

0.0000007

000002

4030 0.00003

New –

Pulverized 

Coal

0.0009001 0.0000500

006

0.0000007

000002

190 0.002

New –

Biomass 

Stoker 

0.007008 0.0006004 0.0000000

70000002

780560 0.00005

New -

Biomass 

Fluidized 

Bed

0.007008 0.0006004 0.0000000

70000002

40 0.007

New –

Biomass 

Suspension 

Burner/Dut

ch Oven

0.007008 0.0006004 0.0000000

70000002

4601010 0.000403

New –

Biomass 

Fuel Cells

0.007008 0.0006004 0.0000000

70000002

270 0.030005

New –

Liquid

0.002 0.0001000

4

0.0000003 1 0.00000500

2

New 

– Gas 

(NG/RFG)

0.0

005

0.0

002

0.0

00000002

20 0.01

New – Gas 

(Other 

Process 

0.002003 0.000003 0.0000002 1 0.008009
36

Gases)

New 

– Metal 

Processing 

Furnaces

0.0

3

0.0

002

0.0

000002

2 0.00

4

The proposed emission limits in the above table apply only 

to existing boilers and process heaters that have a designed 

heat input capacity of 10 million British thermal units (Btu) 

per hour or greater. Pursuant to CAA section 112(h), we are 

proposing a work practice standard for twothree particular 

classes of existing boilers and process heaters: existing units 

that have a designed heat input capacity of less than 10 million 

Btu per hour and new and existing units in the Gas 1 (natural 

gas/refinery gas) subcategory and in the metal processingprocess

furnaces subcategory. The work practice standard being proposed 

for these existing boilers and process heaters would require the 

implementation of a tune-up program as described in section 

III.F of this preamble.

We are also proposing a beyond-the-floor standard for all 

existing major source facilities having affected boilers or 

process heaters that would require the performance of ana onetime energy assessment, as described in section III.F of this 

preamble, by qualified personnel, on the affected unitsboilers

and facility and to implementidentify any cost-effective energy 

conservation measures identified.
37

We are also proposing a beyond-the-floor standard that 

would require facilities with boilers or process heaters 

combusting refinery gas to install and maintain a carbon 

adsorber bed system to remove mercury from the refinery gas 

before combustion in a boiler or process heater.

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.

In light of Consistent with Sierra Club v. EPA, the 

proposed emission EPA has established standards summarized in 

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

has attempted to ensure that we have not incorporated into 

proposed regulatory language any provisions that are 

inappropriate, unnecessary, or redundant in the absence of an 

SSM exemption. We are not proposing a separate emission 

standardspecifically 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 source 

categories at issue here that applies during periods of startup 

and shutdown.reasons explained below, has not established 

different standards for those periods. We have evaluated 

whether it is appropriate to have the same standards apply 

during startup and shutdown as applied to normal operations. 

The standards that we are proposing are daily or monthly 

averages based upon. Continuous emission monitoring data 

whichobtained from best performing units, and used in 

establishing the standards, include periods of startup and 
39

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

normally startup and shutdown more thanthe once per day. Thus, 

we are not establishing a separate emission standard for these 

periods because startup and shutdown are part of their 

normalroutine operations and, therefore, are already addressed 

by the standards. Periods of startup, normal operations, and 

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

operation. We have evaluated whether it is appropriate to have 

the same standards apply during startup and shutdown as applied 

to normal operations. 

Periods of startup, normal operations, and shutdown are all 

predictable and routine aspects of a source’s operations. 

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

infrequent, and not reasonably preventable failure of air 

pollution control and monitoring equipment, process equipment or 

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

CFR 63.2). EPA has determined that malfunctions should not be 

viewed as a distinct operating mode and, therefore, any 

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

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

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

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

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in setting emissions standards. For example, we note that 

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

defining MACT, the level of stringency that major source 

standards must meet. It is reasonable to interpret section 

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

setting emissions standards. Applying the concept of “best 

performing” to a source that is malfunctioning presents

significant difficulties. The goal of best performing sources 

is to operate in such a way as to avoid malfunctions of their 

units. 

Moreover, even if malfunctions were considered a distinct

operating mode, we believe it would be impracticable to take 

malfunctions into account in setting CAA section 112(d) 

standards for major source boilers and process heaters. As 

noted above, by definition, malfunctions are sudden and 

unexpected events and it would be difficult to set a standard 

that takes into account the myriad different types of 

malfunctions that can occur across all sources. in the category. 

Moreover, malfunctions can vary in frequency, degree, and 

duration, further complicating standard setting.

For In the event that a source that fails to comply with 

the applicable SectionCAA section 112(d) standards duringas a 

result of a malfunction eventsevent, EPA willwould determine an 

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appropriate response based on, among other things, the good 

faith efforts of the source to minimize emissions during 

malfunction periods, including preventative and corrective 

actions, as well as root cause analyses to ascertain and rectify 

excess emissions. EPA would also consider whether the source's 

failure to comply with the CAA section 112(d) standard was, in 

fact, “sudden, infrequent, not reasonably preventable” and was 

not instead “caused in part by poor maintenance or careless 

operation.” 40 C.F.R. § 63.2 (definition of malfunction).

F. What are the testing and initial compliance requirements?

We are proposing that the owner or operator of a new or 

existing boiler or process heater must conduct performance tests 

to demonstrate compliance with all applicable emission limits. 

Affected units would be required to conduct the following 

compliance tests where applicable: 

(1) Conduct initial and annual stack tests to determine 

compliance with the PM emission limits using EPA Method 5 or 17.

(2) Conduct initial and annual stack tests to determine 

compliance with the mercury emission limits using EPA method 29 

or ASTM-D6784-02 (Ontario Hydro Method).

(3) Conduct initial and annual stack tests to determine 

compliance with the HCl emission limits using EPA Method 26A or 

EPA Method 26 (if no entrained water droplets in the sample).
42

(4) Use EPA Method 19 to convert measured concentration 

values to pound per million Btu values.

(5) Conduct initial and annual test to determine 

compliance with the CO emission limits using either EPA Method 

10 or a CO CEMS.

(6) Conduct initial and annual test to determine 

compliance with the D/F emission limits using EPA Method 23.

As part of the initial compliance demonstration, we are 

proposing that you monitor specified operating parameters during 

the initial performance tests that you would conduct to 

demonstrate compliance with the PM, mercury, D/F, and HCl 

emission limits. You would calculate the average parameter 

values measured during each test run over the three run

performance test. The average of the three average values 

(depending on the parameter measured) for each applicable 

parameter would establish the site-specific operating limit. 

The applicable operating parameters for which operating limits 

would be required to be established are based on the emissions 

limits applicable to your unit as well as the types of add-on 

controls on the unit. The following is a summary of the 

operating limits that would be requiredwe are proposing to be

established for the various types of the following units:
43

(1) For boilers and process heaters without wet or dry 

scrubbers that must comply with an HCl emission limit, you must 

measure the average chlorine content level in the input fuel(s) 

during the HCl performance test. This is your maximum chlorine 

input operating limit. 

(2) For boilers and process heaters with wet scrubbers, 

you must measure pressure drop and liquid flow rate of the 

scrubber during the performance test, and calculate the average 

value for each test run. The average of the three test run 

averages establishes your minimum site-specific pressure drop 

and liquid flow rate operating levels. If different average 

parameter levels are measured during the mercury, PM and HCl 

tests, the highest of the average values becomes your sitespecific operating limit. If you are complying with an HCl 

emission limit, you must measure pH of the scrubber effluent 

during the performance test for HCl and determine the average 

for each test run and the average value for the performance 

test. This establishes your minimum pH operating limit.

(3) For boilers and process heaters with sorbent 

injection, you would be required to measure the sorbent 

injection rate for each sorbent used during the performance 

tests for HCl, mercury, and D/F and calculate the average for 

each sorbent for each test run. The average of the three test 
44

run averages established during the performance tests would be 

your site-specific minimum sorbent injection rate operating 

limit. If different sorbents and/or injection rates are 

measuredused during the mercury, HCl, and D/F tests, the highest 

of the average valuesvalue for each sorbent becomes your sitespecific operating limit. 

(4) For boilers and process heaters with fabric filters in 

combination with wet scrubbers, you must measure the pH, 

pressure drop, and liquid flowrate of the wet scrubber during 

the performance test and calculate the average value for each 

test run. The minimum test run average establishes your sitespecific pH, pressure drop, and liquid flowrate operating limits 

for the wet scrubber. Furthermore, the fabric filter must be 

operated such that the bag leak detection system alarm does not 

sound more than 5 percent of the operating time during any 6-

month period unless a CEMS is installed to measure PM. 

(5) For boilers and process heaters with electrostatic 

precipitators (ESP) in combination with wet scrubbers, you must 

measure the pH, pressure drop, and liquid flow rate of the wet 

scrubber during the HCl performance test and you must measure 

the voltage and current of the ESP collection fields during the 

mercury and PM performance test. You would then be required to 

calculate the average value of these parameters for each test 
45

run. The average of the three test run averages would establish 

your site-specific minimum pH, pressure drop, and liquid 

flowrate operating limit for the wet scrubber and the minimum 

voltage and current operating limits for the ESP.

(6) For boilers and process heaters that choose to 

demonstrate compliance with the mercury emission limit on the 

basis of fuel analysis and have no add-on controls or add-on 

controls for which you do not want to take credit for any 

emission reduction of mercury, you would be required to measure 

the mercury content of the inlet fuel that was burned during the 

mercury performance test. This value is your maximum fuel inlet 

mercury operating limit. 

(7) For boilers and process heaters that choose to 

demonstrate compliance with the HCl emission limit on the basis 

of fuel analysis and have no add-on controls or add-on controls 

for which you do not want to take credit for any emission 

reduction of HCl, you would be required to measure the chlorine 

content of the inlet fuel that was burned during the HCl 

performance test. This value is your maximum fuel inlet 

chlorine operating limit. 

These proposed operating limits would not apply to owners 

or operators of boilers or process heaters having a heat input 

capacity of less than 10 million Btu per hour (MMBtu/h) or 
46

boilers or process heaters of any size which combust natural gas 

or refinery gas., as discussed in section IV.D.3 of this 

preamble. Instead, we are proposing that owners or operators of 

such boilers would be required toand process heaters submit to 

the delegated authority or EPA, as appropriate, if requested, 

documentation that a tune-up meeting the requirements of the 

proposed rule was conducted. We are proposing that, to comply 

with the work practice standard, a tune-up procedure include the 

following:

(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 ppmvd, before and after the adjustments are made,

(6) Submit an annual report containing the concentrations 

of CO in the effluent stream in ppmvd, and oxygen in percent dry 
47

basis, measured before and after the adjustments of the boiler,

a description of any corrective actions taken as a part of the 

combustion adjustment, and the type and amount of fuel used over 

the 12 months prior to the annual adjustment. 

Further, all owners or operators of major source facilities 

having boilers and process heaters subject to this rule would be 

required to submit to the delegated authority or EPA, as 

appropriate, documentation that an energy assessment was 

performed, by qualified personnel, and the cost-effective energy 

conservation measures implemented.indentified. The procedures 

for an energy assessment are:

(1) Conduct 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) Review available architectural and engineering plans, 

facility operation and maintenance procedures and logs, and fuel 

usage,

(5) Identify a list of major energy conservation measures,

(6) Determine the energy savings potential of the energy 

conservation measures identified, and
48

(7) Prepare a comprehensive report detailing the ways to 

improve efficiency, the cost of specific improvements, benefits, 

and the time frame for recouping those investments, and.

(8) Implement each cost-effective energy conservation 

measure identified.

G. What are the continuous compliance requirements?

To demonstrate continuous compliance with the emission 

limitations, we are proposing following requirements:

(1) For units combusting coal, biomass, or residual fuel 

oil (i.e., No 4, 5 or 6 fuel oil) with heat input capacities of 

less than 250 million Btu per hour that do not use a wet 

scrubber, we are proposing that opacity levels be maintained to 

less than 10 percent (daily average) for existing and new units 

with applicable emission limits. Or, if the unit is controlled 

with a fabric filter, instead of continuous monitoring of

opacity, the fabric filter must 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

(unless a PM CEMS is used).

(2) For units combusting coal, biomass, or residual oil 

with heat input capacities of 250 million Btu per hour or 

greater, we are proposing that PM CEMS be installed and operated 
49

and that PM levels (monthly average) be maintained below the 

applicable PM limit.

(3) For boilers and process heaters with wet scrubbers, we 

are proposing that you monitor pressure drop and liquid flow 

rate of the scrubber and maintain the 12-hour block averages at 

or above the operating limits established during the performance 

test. You must monitor the pH of the scrubber and maintain the 

12-hour block average at or above the operating limit 

established during the performance test to demonstrate 

continuous compliance with the HCl emission limits.

(4) For boilers and process heaters with dry scrubbers, we 

are proposing that you continuously monitor the sorbent 

injection rate and maintain it at or above the operating limits 

established during the performance tests.

(5) For boilers and process heaters having heat input 

capacities of less than 250 million Btu per hour with an ESP in 

combination with a wet scrubber, we are proposing that you 

monitor the pH, pressure drop, and liquid flow rate of the wet 

scrubber and maintain the 12-hour block averages at or above the 

operating limits established during the HCl performance test and 

that you monitor the voltage and current of the ESP collection 

plates and maintain the 12-hour block averages at or above the 
50

operating limits established during the mercury or PM 

performance test.

(6) For units that choose to comply with either the mercury 

emission limit or the HCl emission limit based on fuel analysis 

rather than on performance stack testing, we are proposing that 

you maintain daily fuel records that demonstrate that you burned 

no new fuels or fuels from a new supplier such that the mercury 

content or the chlorine content of the inlet fuel was maintained 

at or below your maximum fuel mercury content operating limit or 

your chlorine content operating limit set during the performance 

stack tests. If you plan to burn a new fuel, a fuel from a new 

mixture, or a new supplier’s fuel that differs from what was 

burned during the initial performance tests, then you must 

recalculate the maximum mercury input and/or the maximum 

chlorine input anticipated from the new fuels based on supplier 

data or own fuel analysis, using the methodology specified in 

Table 6 of this proposed rule. If the results of recalculating 

the inputs exceed the average content levels established during 

the initial test then, you must conduct a new performance 

test(s) to demonstrate continuous compliance with the applicable

emission limit.

(7) For all boilers and process heaters, we are proposing 

that you maintain daily records of fuel use that demonstrate 
51

that you have burned no materials that are considered solid 

waste. 

(8) For boilers and process heaters in any of the 

subcategories with heat input capacities greater than 100 

MMBtu/h, we are proposing that you continuously monitor CO and 

maintain the average CO emissions at or below the applicable 

limit listed in Tables 1 or 2 of this proposed rule.

If an owner or operator would like to use a control device 

other than the ones specified in this section to comply with 

this proposed rule, the owner/operator should follow the 

requirements in 40 CFR 63.8(f), which presents the procedure for 

submitting a request to the Administrator to use alternative 

monitoring.

H. What are the notification, recordkeeping and reporting 

requirements?

All new and existing sources would be required to comply 

with certain requirements of the General Provisions (40 CFR part 

63, subpart A), which are identified in Table 10 of this 

proposed rule. The General Provisions include specific 

requirements for notifications, recordkeeping, and reporting.

Each owner or operator would be required to submit a 

notification of compliance status report, as required by

§63.9(h) of the General Provisions. This proposed rule would
52

require 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 §63.10(e)(3) 

of subpart A, would be required only for semiannual reporting 

periods when a deviation from any of the requirements in the 

rule occurred, or any process changes occurred and compliance 

certifications were reevaluated.

This proposed rule would require records to demonstrate 

compliance with each emission limit and work practice standard. 

These recordkeeping requirements are specified directly in the 

General Provisions to 40 CFR part 63, and are identified in 

Table 10. Owners or operators of sources with units with heat 

input capacity of less than 10 MMBtu/h or units combusting

natural gas or refinery gas must keep records of the dates and 

the results of each required boiler tune-up.

Records of either continuously monitored parameter data for 

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

CEMS data would be required.

We are proposing that you must keep the following records:

(1) All reports and notifications submitted to comply with 

this proposed rule.
53

(2) Continuous monitoring data as required in this

proposed rule.

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

limit and each operating limit (i.e., deviations from this

proposed rule).

(4) Daily hours of operation by each source.

(5) Total fuel use by each affected source electing to 

comply with an emission limit based on fuel analysis for each 

30-day period along with a description of the fuel, the total 

fuel usage amounts and units of measure, and information on the 

supplier and original source of the fuel.

(6) Calculations and supporting information of chlorine 

fuel input, as required in this proposed rule, for each affected 

source with an applicable HCl emission limit.

(7) Calculations and supporting information of mercury 

fuel input, as required in this proposed rule, for each affected 

source with an applicable mercury emission limit.

(8) A signed statement, as required in this proposed rule, 

indicating that you burned no new fuel type and no new fuel 

mixture or that the recalculation of chlorine input demonstrated

that the new fuel or new mixture still meets chlorine fuel input 

levels, for each affected source with an applicable HCl emission 

limit.
54

(9) A signed statement, as required in this proposed rule, 

indicating that you burned no new fuels and no new fuel mixture 

or that the recalculation of mercury fuel input demonstrated

that the new fuel or new fuel mixture still meets the mercury 

fuel input levels, for each affected source with an applicable 

mercury emission limit.

(10) A copy of the results of all performance tests, fuel 

analysis, opacity observations, performance evaluations, or 

other compliance demonstrations conducted to demonstrate initial 

or continuous compliance with this proposed rule.

(11) A copy of your site-specific monitoring plan 

developed for this proposed rule as specified in 63 CFR 63.8(e), 

if applicable.

We are also proposing to require that you submit the 

following reports and notifications:

(1) Notifications required by the General Provisions.

(2) Initial Notification no later than 120 calendar days 

after you become subject to this subpart.

(3) Notification of Intent to conduct performance tests 

and/or compliance demonstration at least 60 calendar days before 

the performance test and/or compliance demonstration is 

scheduled.
55

(4) Notification of Compliance Status 60 calendar days 

following completion of the performance test and/or compliance 

demonstration.

(5) Compliance reports semi-annually.

I. Submission of Emissions Test Results to EPA

The EPA must have performance test data to conduct 

effective reviews of CAA Section 112 and 129 standards, as well 

as for many other purposes, including compliance determinations, 

emissions factor development, and annual emissions rate 

quantification.determinations. In conducting these required 

reviews, we have found it burdensomeineffective and time 

consuming not only for us but also for regulatory agencies and 

source owners and operators to locate, collect, and submit 

emissions 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 cumbersome 

paper copies. 

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

accessibility. Boiler Owners and operators of boilers and 

process heater facilitiesheaters will be required to submit to 

an EPA electronic database, the Electronic Reporting Tool (ERT),

an electronic copy of reports of certain performance tests 
56

required under this rule. Data entry will be through an 

electronic emissions test report structure called the Electronic 

Reporting Tool (ERT) that will be used by the EPA staff as part 

of the emissions testing project. The ERT was developed with 

input from stack testing companies who generally collect and 

compile performance test data electronically and offices within 

State, and local, and Tribal agencies which perform field test 

assessments. The ERT is currently available, and access to 

direct data submittal to EPA’s electronic emissions database 

(WebFIRE) will become available by December 31, 2011.

Please note that theThe requirement to submit source test 

data electronically to EPA will not require any additional 

performance testing. and will apply to those performance tests 

conducted using test methods that are supported by ERT. The ERT 

contains a specific electronic data entry form for most of the 

commonly used EPA reference methods. However, at this time, the 

ERT does not have a form for every performance test method, so 

the ERT structure also includes a spreadsheet function for those 

methods not currently supported. For more information, see the 

website link below. WeThe website listed at the end of this 

section contains a listing of the pollutants and test methods 

supported by ERT. In addition, when a facility submits 

performance test data to WebFIRE, there will be no additional 
57

requirements for emissions test data compilation. Moreover, we

believe industry will benefit from development of improved 

emissions factors, fewer follow-up information requests, and 

better regulation development, as discussed below as discussed 

below. The information to be reported is already required for 

the existing test methods and is necessary to evaluate the 

conformance to the test method. 

As mentioned above, the information to be reported is 

already required by the existing test methods and is necessary 

to evaluate the conformance to the test method. One major 

advantage of submitting source test data through the ERT is that 

it provides a standardized method to compile and store much of 

the documentation required to be reported by this rule while 

clearly stating what testing information we require. Another 

important benefit of submitting these data to EPA at the time 

the source test is conducted is that it will substantially 

reduce the effort involved in data collection activities in the 

future. Specifically, because EPA would already have adequate 

source category data to conduct residual risk assessments or 

technology reviews, there would be fewer or less substantial 

data collection requests (e.g., CAA Section 114 letters). This 

results in a reduced burden on both affected facilities (in 

terms of reduced manpower to respond to data collection 
58

requests) and EPA (in terms of preparing and distributing data 

collection requests). 

State/local/Tribal agencies may also benefit in that their 

review may be more streamlined and accurate as the States will 

not have to re-enter the data to assess the calculations and 

verify the data entry. Finally, another benefit of submitting 

these data to WebFIRE electronically is that these data will 

improve greatly the overall quality of the existing and new 

emissions factors will benefit by supplementing the pool of 

emissions test data upon which the emissions factor is based and 

by ensuring that data are more representative of current 

industry operational procedures. A common complaint we hear 

from industry and regulators is that emissions factors are 

outdated or not representative of a particular source category. 

Receiving theand incorporating data fromfor most performance 

tests will ensure that emissions factors, when updated with 

these data, represent accurately the most current operational 

practices. In summary, receiving 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 and work to improve the quality 

of emissions inventories and related regulatory decisions.

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As mentioned earlier, the electronic data base that will be 

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

EPA’s Technology Transfer Network (TTN). The WebFIRE Web site 

was constructed to store emissions test data for use in 

developing emissions 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 database.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. 

Finally, a listing of the pollutants and test methods supported 

by ERT are also available on the web page listed above. 

IV. Rationale for this Proposed Rule

A. How did EPA determine which sources would be regulated under 

this proposed rule?

This proposed rule regulates source categories covering 

industrial boilers, institutional and commercial boilers, and 

process heaters. These source categories potentially include 

combustion units that are already regulated by other MACT 
60

standards under CAA sections 112 or 129. Therefore, we are 

excluding from this proposed rule any units that are subject to 

regulation in another MACT standard established under CAA 

section 112 or a standard established under CAA section 129.

The CAA specifically requires that fossil fuel-fired steam 

generating units of more than 25 megawatts that produce 

electricity for sale (i.e., utility boilers) be reviewed 

separately by EPA. Consequently, this proposed rule would not 

regulate fossil fuel-fired utility boilers greater than 25 

megawatts, but would regulate fossil fuel-fired units less than 

25 megawatts and all utility boilers firing a non-fossil fuel 

that is not a solid waste.

The scope of the process heater source category is limited 

to only indirect-fired units3

 

3 Indirect-fired process heaters are combustion devices in which the combustion gases do not directly come into 

contact with process materials.

. Direct-fired units are covered in 

other MACT standards or rulemakings pertaining to industrial 

process operations. For example, lime kilns are covered by the 

Pulp and Paper NESHAP (40 CFR part 63, subpart S). Indirectfired process heaters are similar to boilers in fuel use, 

emissions, and applicable controls, and, therefore, it is 

appropriate for EPA to combine this listed source category of

units with the listed sources categories of industrial boilers 
61

and commercial/institutional boilers for purposes of developing 

emission standards.

The proposed rule would not regulate hot water heaters, as 

defined in this proposed rule, because such units are not part 

of the listed source categories. Many industrial facilities 

have office buildings located onsite which use hot water 

heaters. Such hot water heaters, by their design and operation, 

could be considered boilers since hot water heaters meet the 

definition of a boiler as specified in the proposed rule. 

However, because they are enclosed devices that combust fuel for 

the purpose of recovery energy to heat water. However, hot 

water heaters are more appropriately described as residentialtype boilers, not industrial, commercial, or institutional 

boilers because their output (i.e., hot water) is intended for 

personal use rather than for use in an industrial, commercial, 

or institutional process. Moreover, since hot water heaters 

generally are small and use natural gas as fuel, their emissions 

are negligible compared to the emissions from the industrial 

operations that make such facilities major sources, and compared 

to boilers that are used for industrial, commercial, or 

institutional purposes. Moreover, hot water heaters are more 

appropriately described as residential-type boilers, not 

industrial, commercial or institutional boilers because their 
62

output (i.e., hot water) is intended for personal use rather 

than for use in an industrial, commercial, or institutional 

process. However, the primary reason that we are excluding hot 

water heaters is that hot water heaters are not part of the 

listed source category. Consequently, we are including a 

definition of hot water heaters that includes fuel, size, 

pressure and temperature limitations that we believe are 

appropriate to distinguish between residential-type units and 

industrial, commercial, or institutional units.

The CAA allows EPA to divide source categories into 

subcategories based on differences in class, type, or size. For 

example, differences between given types of units can lead to 

corresponding differences in the nature of emissions and the 

technical feasibility of applying emission control techniques. 

The design, operating, and emissions information that EPA has 

reviewed indicates differences in unit design that distinguish 

different types of boilers. Data indicate that there are

significant design and operational differences between units 

that burn coal, biomass, liquid, and gaseous fuels.

Boiler systems are designed for specific fuel types and 

will encounter problems if a fuel with characteristics other 

than those originally specified is fired. While many boilers in 

the population database are indicated to co-fire liquids or 
63

gases with solid fuels, in actuality most of these commonly use 

fuel oil or natural gas as a startup fuel only, and operate on 

solid fuel during the remainder of their operation. In 

contrast, some co-fired units are specifically designed to fire 

combinations of solids, liquids, and gases. Changes to the fuel 

type would generally require extensive changes to the fuel 

handling and feeding system (e.g., a stoker using wood as fuel 

would need to be redesigned to handle fuel oil or gaseous fuel). 

Additionally, the burners and combustion chamber would need to 

be redesigned and modified to handle different fuel types and 

account for increases or decreases in the fuel volume. In some 

cases, the changes may reduce the capacity and efficiency of the 

boiler or process heater. An additional effect of these changes 

would be extensive retrofitting needed to operate using a 

different fuel.

The design of the boiler or process heater, which is 

dependent in part on the type of fuel being burned, impacts the 

degree of combustion. Boilers and process heaters emit a number 

of different types of HAP emissions. Organic HAP are formed 

from incomplete combustion and are influenced by the design and 

operation of the unit. The degree of combustion may be greatly 

influenced by three general factors: time, turbulence, and 

temperature. On the other hand, the formation of fuel dependent 
64

HAP (metals, mercury, and acid gases) is dependent upon the 

composition of the fuel. 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.

We first examined the HAP emissions results to determine if 

subcategorization by unit design type was warranted. We 

concluded that the data were sufficient for determining that a 

distinguishable difference in performance exists based on unit 

design type. Therefore, because different types of units have 

different emission characteristics which may influence the 

feasibility of effectiveness of emission control, they should be 

regulated separately (i.e., subcategorized). Accordingly, we

decidedpropose to subcategorize boilers and process heaters 

based on unit design in order to account for these differences 

in emissions and applicable controls.

For the fuel-dependent HAP (metals, mercury, acid gases), 

we identified five basic unit types as subcategories. These are 

the following: (1) units designed to burn coal, (2) units 

designed to burn biomass, (3) units designed to burn liquid 

fuel, (4) units designed to burn natural gas/refinery gas, and

(5) units designed to burn other process gases. Within the 

basic unit types there are different designs and combustion 
65

systems that, while having a minor effect on fuel-related HAP 

emissions, that have a much larger effect on organic HAP 

emissions. Therefore, we decided to further subcategorize based 

on these different unit designs but only in proposing standards 

for organic HAP emissions. We have identified the following 

1011 subcategories for organic HAP:

Pulverized coal units,

Stokers designed to burn coal,

Fluidized bed units designed to burn coal,

Stokers designed to burn biomass,

Fluidized bed units designed to burn biomass,

Suspension burners/Dutch Ovens designed to burn biomass,

Fuel Cells designed to burn biomass,

Units designed to burn liquid fuel,

Units designed to burn natural gas/refinery gas, and

Units designed to burn other gases, and

Metal process furnaces.

These subcategories are based on the primary fuel that the 

boiler or process heater is designed to burn. We are aware that 

some boilers burn a combination of fuel types or burn a 

different fuel type as a backup fuel if the primary fuel supply 

is curtailed. However, boilers are designed based on the 

primary fuel type (and perhaps to burn a backup fuel) and can 

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66

encounter operational problems if another fuel type that was not 

considered in its design is fired at more than 10 percent of the 

heat input to the boiler. Also, in some cases, a small amount 

of coal may be added to a biomass designed boiler to stabilize 

the combustion when the biomass has a higher moisture content 

than normal. In this case, it would not be appropriate to 

classify the boiler as being in one of the “coal” subcategories

because the boiler design is such that it is constructed and 

operated to combust biomass, and could not combust primarily 

coal (without significant retrofitting or design changes). 

Therefore, we are proposing to define boilers and process 

heaters that burn more thanat least 10 percent coal (on an 

annual heat input basis) as being in one of the coal 

subcategories. We are also proposing to define boilers and 

process heaters that burn more thanat least 10 percent biomass, 

and less than 10 percent coal, (on an annual heat input basis) 

as being in one of the biomass subcategories. We are proposing 

to define boilers and process heaters that burn more thanat 

least 10 percent liquid fuel, and less than 10 percent solid 

fuel, (on an annual heat input basis) as being in the liquid 

subcategory. We are proposing to define boilers and process 

heaters that burn more thanat least 90 percent natural gas 

and/or refinery gas (on an annual heat input basis) as being in 
67

the Gas 1 subcategory. This would ensure that each boiler and 

process heater is subject to emissions standards calculated on 

the basis of the best performing units with similar design and 

operation. The remaining boilers and process heaters, except 

for those described below would be in the Gas 2 subcategory.

In addition, there is a certain class of natural gas-fired 

process heaters that are designed and operated in such a manner 

that are differentdifferently compared to typical process 

heaters. A review of information gathered on process heaters 

used in the metal processing industries shows that these process 

heaters typically are designed with multiple burners that 

firedfire into individual combustion chambers. These individual 

burners are operated to cycle on and off to maintain the proper 

temperatures throughout the various zones of the process heater. 

Thus, due to their design, these process heaters rarely operate 

in a steady-state condition due to burners constantly starting 

up and shutting down resulting. This results in emissions 

characteristics different from the process heaters used in other

industries. The process heaters used in metal processing are 

natural gas-fired and include annealing furnaces, preheat 

furnaces, reheat furnaces, aging furnaces, and heat treat 

furnaces. Therefore, we have identifiedpropose to identify
68

these metal processing process heaters (furnaces) as a separate 

eleventh subcategory. 

In summary, we have identified 11 subcategories of boilers 

and process heaters located at major sources..4

B. How did EPA select the format for this proposed rule?

This proposed rule includes numerical emission limits for 

PM, mercury, HCl, CO, and D/F. The selection of numerical 

emission limits as the format for this proposed rule provides 

flexibility for the regulated community by allowing a regulated 

source to choose any control technology or technique to meet the 

emission limits, rather than requiring each unit to use a 

prescribed control method that may not be appropriate in each 

case.

We are proposing numerical emission rate limits as a mass 

of pollutant emitted per heat energy input to the boiler or 

process heater for the fuel-related HAP. The most typical units 

for the limits are pounds of pollutant emitted per million Btu 

of heat input. The mass per heat input units are consistent 

with other Federal and many State boiler regulations5

 

4 See Memorandum “Development of Baseline Emission Factors for Boilers and Process Heaters at Commercial, 

Industrial, and Institutional Facilities” located in the docket.

and allows 

easy comparison between such requirements. Additionally, this

proposed rule contains an option to monitor inlet chlorine and

5 For example, the new source performance standards for industrial, commercial, and institutional steam generating 

units (40 CFR subpart Db) have emission limits for sulfur dioxide, nitrogen oxide, and PM in terms of pounds per 

million Btu. 
69

mercury content in the fuel to meet outlet emission rate limits. 

This option can only be done on a mass basis.

We are proposing outlet concentration as the format for the 

organic HAP. An outlet concentration limit for organic HAP 

would also be consistent with the format of other regulations.

Boilers and process heaters can emit a wide variety of 

compounds, depending on the fuel burned. Because of the large 

number of HAP potentially present and the disparity in the 

quantity and quality of the emissions information available, EPA 

grouped the HAP into five categories: mercury, non-mercury 

metallic HAP, inorganic HAP, non-dioxin organic HAP, and D/F. 

The pollutants within each group have similar characteristics 

and can be controlled with the same techniques. For example, 

non-mercury metallic HAP can be controlled with PM controls. We

chose to look at mercury separately from other metallic HAP due 

to its different chemical characteristics and its different 

control technology feasibility.

Next, EPA identified compounds that could be used as 

surrogates for all the compounds in each pollutant category. 

For the non-mercury metallic HAP, we chose to use PM as a 

surrogate. Most, if not all, non-mercury metallic HAP emitted 

from combustion sources will appear on the flue gas fly-ash. 

Therefore, the same control techniques that would be used to 
70

control the fly-ash PM will control non-mercury metallic HAP. 

PM was also chosen instead of specific metallic HAP because all 

fuels do not emit the same type and amount of metallic HAP but 

most generally emit PM that includes some amount and combination 

of metallic HAP. 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. Since 

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

(i.e., fine particle enrichment), we considered using PM2.5 as 

the surrogate, but we determined that PM (filterable) was the 

more appropriate surrogate since, based on the emission data 

obtained during the information collection effort, the majority 

of the PM emitted from well controlled units is fine particulate 

(PM2.5). Howeverfor two reasons. First, the test method (OTM 

27) for measuring PM2.5 is only applicable for use in exhaust 

stacks without entrained water droplets. Therefore, the test 

method (OTM 27) for measuring PM2.5 is not applicable for units 

equipped with wet scrubbers which will likely be 

requirednecessary to achieve the proposed HCl emission limits. 

Second, based on the emission data obtained during EPA’s

information collection effort from units not equipped with wet 

scrubbers, the majority of the filterable PM emitted from units 

that are well controlled for PM is fine particulate (PM2.5). 
71

Thus, we are proposing to use PM, (filterable), instead of PM2.5,

as the surrogate for non-mercury metals. 

For non-metallic inorganic HAP, EPA is proposing using HCl 

as a surrogate. The emissions test information available to EPA 

indicate that the primary non-metallic inorganic HAP emitted 

from boilers and process heaters are acid gases, with HCl 

present in the largest amounts. Other inorganic compounds 

emitted are found in much smaller quantities. Control 

technologies that reduce HCl also control other inorganic 

compounds that aresuch as chlorine and other acid gases. Thus, 

the best controls for HCl would also be the best controls for 

other inorganic HAP that are acid gases. Therefore, HCl is a 

good surrogate for inorganic HAP because controlling HCl will 

result in control of other inorganic HAP emissions.

For organic HAP, we considered both THC and CO as a 

surrogate for non-dioxin organic HAP emitted from boilers and 

process heaters. CO has generally been used as a surrogate for 

organic HAP because CO is a good indicator of incomplete 

combustion and organic HAP are products of incomplete 

combustion. However, based on concerns that CO may not be an 

appropriate surrogate for D/F because, unlike other organic HAP,

D/F can be formed outside the combustion unit, we are proposing 

to use CO as a surrogate for non-dioxin organic HAP. We are 
72

also proposing a separate emission limits for D/F. For nondioxin organic HAP, using CO as a surrogate is a reasonable 

approach because minimizing CO emissions will result in 

minimizing non-dioxin organic HAP. Methods used for the control 

of non-dioxin organic HAP emissions would be the same methods 

used to control CO emissions. These emission control methods 

include achieving good combustion or using an oxidation 

catalyst. Standards limiting emissions of CO will also result 

in decreases in non-dioxin organic HAP emissions (with the

additional benefit of decreasing volatile organic compounds 

(VOC) emissions). Establishing emission limits for specific 

organic HAP (with the exception of D/F) would be impractical and 

costly. CO, which is less expensive to test for and monitor, is 

appropriate for use as a surrogate for non-dioxin organic HAP.

The Agency recognizes that the level and distribution of 

organic HAP associated with CO emissions will vary from unit to 

unit. For example, the principal organic HAP emitted from coalfired units is benzene accounting, which accounts for about 20 

percent of the organic HAP while the principal organic HAP 

emitted from biomass-fired units is formaldehyde accounting, 

which accounts for 34 percent of the organic HAP..6

 

6 Based on emission factors reported on EPA webpage “AP 42, Fifth Edition, Volume 1 – Chapter 1: External 

Combustion Sources” located at http://www.epa.gov/ttn/chief/ap42/ch01/index.html.

 Limiting CO

as a surrogate for only non-dioxin organic HAP will eliminate 
73

costs associated with speciating numerous compounds. The 

proposed standards establish separate emission limits for D/F 

because of the high toxicity associated with even low masses of 

these compounds.

THC could also be an appropriate surrogate for non-dioxin 

organic HAP because low THC also ensures good combustion 

efficiency and, thus, low organic HAP. However, we believe CO 

is preferable because many sources currently have CO CEMS. In 

addition, there are more CO emission data available for the 

various subcategories than THC emission data. EPA’s Office of 

Research and Development (ORD) is currently conducting research 

on surrogates for the Utility MACT rulemaking and ORD findings 

will be considered in the final rulemaking.

C. How did EPA determine the proposed emission limitations for 

existing units?

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

must reflect MACT, the maximum degree of reduction in emissions 

of air pollutants that the Administrator, taking into 

consideration the cost of achieving such emissions reductions, 

and any nonair quality health and environmental impacts and 

energy requirements, determined is achievable for each category. 

For existing sources, MACT cannot be less stringent than the 

average emission limitation achieved by the best performing 12 
74

percent of existing sources for categories and subcategories 

with 30 or more sources or the best performing 5 sources for 

subcategories with less than 30 sources. This requirement 

constitutes the MACT floor for existing boilers and process 

heaters. However, EPA may not consider costs or other impacts 

in determining the MACT floor. EPA must consider cost, nonair 

quality health and environmental impacts, and energy 

requirements in connection with any standards that are more 

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

D. How did EPA determine the MACT floorfloors for existing 

units?

EPA must consider available emissions information to 

determine the MACT floor. Wefloors. For each pollutant, we

calculated the MACT floor for a subcategory of sources by 

ranking all the available emissions data from units within the 

subcategory from lowest emissions to highest emissions, and then 

taking the numerical average of the test results from the best 

performing (lowest emitting) 12 percent of sources.

TheWe 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 
75

would achieve lower HAP emissions. A second consideration was 

whether fuel switching could be technically achieved by boilers 

and process heaters in the subcategory considering the existing

design of boilers and process heaters. 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.

Based on the emission factors reported in EPA’s Technology 

Transfer Network, we determined that while fuel switching from 

solid fuels to gaseous or liquid fuels would decrease PM and 

some metals emissions, emissions of some organic HAP (e,g., 

formaldehyde) would increase.7

 

7

See EPA webpage “AP 42, Fifth Edition, Volume 1 – Chapter 1: External Combustion Sources” located at 

http://www.epa.gov/ttn/chief/ap42/ch01/index.html. 

 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” located in the docket.
76

A similar determination was made when considering fuel 

switching to cleaner fuels within a subcategory. For example, 

the term “clean coal” refers to coal that is lower in sulfur 

content and not necessarily lower in HAP content. Data gathered 

by EPA also indicates that within specific coal types HAP 

content can vary significantly. Switching to a low sulfur coal 

may actually increase emissions of some HAP. Therefore, it is

not appropriate for EPA to include fuel switching to a low 

sulfur coal as part of the MACT standards for boilers and

process heaters. Fuel switching from coal to biomass would 

result in similar impacts on HAP emissions. While this would 

reduce metallic HAP emissions, it would likely increase 

emissions of organics based on information in the emissions 

database. 

Another factor considered was the availability of 

alternative fuel types. Natural gas pipelines are not available

in all regions of the U.S., and natural gas is simply not 

available as a fuel for many industrial, commercial, and

institutional boilers and process heaters. Moreover, even where 

pipelines provide access to natural gas, supplies of natural gas 

may not be adequate. For example, it is common practice in 

cities during winter months (or periods of peak demand) to 

prioritize natural gas usage for residential areas before 
77

industrial usage. Requiring boilers and process heaters to 

switch to natural gas would place an even greater strain on 

natural gas resources. Consequently, even where pipelines 

exist, some units would not be able to run at normal or full 

capacity during these times if shortages were to occur. 

Therefore, under any circumstances, there would be some units 

that could not comply with a requirement to switch to natural

gas.

Similar problems for fuel switching to biomass could arise. 

Existing sources burning biomass generally are combusting a 

recovered material from the manufacturing or agriculture

process. Industrial, commercial, and institutional facilities 

that are not associated with the wood products industry or 

agriculture may not have access to a sufficient supply of 

biomass materials to replace their fossil fuel.

As discussed previously in this preamble, there is a 

significant concern that switching fuels would be infeasible for 

sources designed and operated to burn specific fuel types. 

Changes in the type of fuel burned by a boiler or process heater 

(solid, liquid, or gas) may require extensive changes to the 

fuel handling and feeding system (e.g., a stoker using wood as 

fuel would need to be redesigned to handle fuel oil or gaseous 

fuel). Additionally, burners and combustion chamber designs are
78

generally not capable of handling different fuel types, and 

generally cannot accommodate increases or decreases in the fuel 

volume. Design changes to allow different fuel use, in some 

cases, may reduce the capacity and efficiency of the boiler or

process heater. Reduced efficiency may result in less complete 

combustion and, thus, an increase in organic HAP emissions. For 

the reasons discussed above, we decided that fuel switching to

cleaner solid fuels or to liquid or gaseous fuels is not an 

appropriate criteria for identifying the MACT floor emission 

levels for units in the boilers and process heaters category.

Therefore, the MACT floor limits for each of the HAP and 

HAP surrogates (PM, mercury, CO, HCl, and D/F) 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 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 
79

conditions. The DC Circuit Court of Appeals has recognized that 

EPA may consider variability in estimating the degree of 

emission reduction achieved by best-performing sources and in 

setting MACT floors. See Mossville Envt’l Action Now v. EPA, 

370 F.3d 1232, 1241–42 (D.C. Cir 2004) (holding EPA may consider 

emission variability in estimating performance achieved by bestperforming sources and may set the floor at level that bestperforming source can expect to meet “every day and under all 

operating conditions”). 

In determining the MACT floor limits, we first determine 

the floor, which is the level achieved in practice by the 

average of the top 12 percent. We then assess variability of 

the best performers by using a statistical formula designed to 

estimate a MACT floor level that is achievable by the average of 

the best performing sources if the best performing sources were 

able to replicate the compliance tests in our data base. 

Specifically, the MACT floor limit is an upper prediction limit 

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

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

used in other EPA rulemakings (e.g., NSPS for

Hospital/Medical/Infectious Waste Incinerators) in accounting 

for variability. A prediction interval for a future observation 

is an interval that will, with a specified degree of confidence, 
80

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 a independent sample from the same 

population. In other words, if we were to randomly select a 

future test condition from any of these sources (i.e., average 

of 3 runs), we can be 99% 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, 

which are two statistical measures calculated from the sample 

data. The average is the central value of a data set, and the 

standard deviation is the common measure of the dispersion of 

the data set around the average.

We first determined the distribution of the emissions data 

for the best-performing 12 percent of units within each 

subcategory prior to calculating UPL values. To evaluate the 

distribution of the best performing dataset, we first computed 

the skewness and kurtosis statistics and then conducted the 

appropriate small-sample hypothesis tests.
81

The skewness statistic (S) characterizes the degree of 

asymmetry of a given data distribution. Normally distributed 

data have a skewness of 0. A skewness statistic that is greater 

(less) than 0 indicates that the data are asymmetrically 

distributed with a right (left) tail extending towards positive 

(negative) values. Further, the standard error of the skewness 

statistic (SES) is given by SES = SQRT(6/N) where N is the 

sample size. According to the small sample skewness hypothesis 

test, if the skewness statistic (S) is greater than two times 

the SES, the data distribution can be considered non-normal. 

The kurtosis statistic (K) characterizes the degree of 

peakedness or flatness of a given data distribution in 

comparison to a normal distribution. Normally distributed data 

have a kurtosis of 0. A kurtosis statistic that is greater 

(less) than 0 indicates a relatively peaked (flat) distribution. 

Further, the standard error of the kurtosis statistic (SEK) is 

given by SEK = SQRT(24/N) where N is the sample size. According 

to the small sample kurtosis hypothesis test, if the kurtosis 

statistic (K) is greater than two times the SEK, the data 

distribution is typically considered to be non-normal.

We applied the skewness and kurtosis hypothesis tests to 

both the reported test values and the lognormal values of the 

reported test values. If the skewness (S) and kurtosis (K) 
82

statistics of the reported data set were both less than twice 

the SES and SEK, respectively, the dataset was classified as 

normally distributed. If neither of the skewness (S) and 

kurtosis (K) statistics, or only one of these statistics were 

less than twice the SES or SEK, respectively, then the skewness 

and kurtosis hypothesis tests were conducted for the natural 

log-transformed data. Then the distribution most similar to a 

normal distribution was selected as the basis for calculating 

the UPL. If both the reported values and the natural-log 

transformed reported values had skewness (S) and kurtosis (K) 

statistics that were greater than twice the SES or SEK, 

respectively, the normally distributed dataset was selected as 

the basis of the floor to be conservative. If the results of 

the skewness and kurtosis hypothesis tests were mixed for the 

reported values and the natural log-transformed reported values, 

we also chose the normal distribution to be conservative. We 

believe this approach is more accurate and obtained more 

representative results than a more simplistic normal 

distribution assumption.

We calculated the 99 percent UPL values (which was 

determined to be the appropriate percentile to use in setting 

MACT limits in the Hospital/Medical/Infectious Waste 

Incinerators NSPS) using the following Microsoft Excel 
83

equations, based on the test run data for those units in the 

best-performing 12 percent:

Since the compliance with the MACT floor emission limit is 

based on the average of a three run test, the UPL is calculated 

by:

Where:

n = the number of test runs

m = the number of test runs in the compliance average

This calculation was performed using the following two Excel 

functions:

Normal distribution: 99% UPL = AVERAGE(Test Runs in Top 12%) + 

[STDEV(Test Runs in Top 12%) x TINV(2 x probability, n-1 degrees 

of freedom)],)*SQRT((1/n)+(1/3))], for a one-tailed t-value 

(with 2 x probability), probability of 0.01, and sample size of 

n

Lognormal distribution: 99% UPL = EXP{AVERAGE(Natural Log 

Values of Test Runs in Top 12%) + [STDEV(Natural Log Values of 

Test Runs in Top 12%) x TINV(2 x probability, n-1 degrees of 

freedom)]},)* SQRT((1/n)+(1/3))]}, for a one-tailed t-value 

(with 2 x probability), probability of 0.01, and sample size of 

n

Test method measurement imprecision can also be a component 

of data variability. At very low emissions levels as 

encountered in the data used to support this rule, the inherent 

imprecision in the pollutant measurement method has a large 

influence on the reliability of the data underlying the 

Formatted: Line spacing: single
84

regulatory floor or beyond-the-floor emissions limit. Of 

particular concern are those data that are reported near or 

below a test method’s pollutant detection capability. In our 

guidance for reporting pollutant emissions used to support this 

rule, we specified the criteria for determining test-specific 

method detection levels. Those criteria insure that there is 

about a 1 percent probability of an error in deciding that the 

pollutant measured at the method detection level is present when 

in fact it was absent. Such a probability is also called a 

false positive or the alpha, Type I, error. Another view of 

this probability is that one is 99 percent certain of the 

presence of the pollutant measured at the method detection 

level. Because of matrix effects, laboratory techniques, sample 

size, and other factors, method detection levels normally vary 

from test to test. We requested sources to identify (i.e., 

flag) data which were measured below the method detection level 

and to report those values as equal to the test-specific method 

detection level.

Variability of data due to measurement imprecision is 

inherently and reasonably addressed in calculating the floor 

emissions limit when the data base represents multiple tests for 

which all of the data are measured significantly above the 

method detection level. That is less true when the database 
85

includes emissions occurring below method detection capabilities 

and are reported as the method detection level values. The data 

base is then truncated at the lower end of the measurement range 

(i.e., no values reported below the method detection level) and 

we believe that a floor emissions limit based on a truncated 

data base or otherwise including values at or near the method 

detection level may not adequately account for data measurement 

variability. We did not adjust the calculated floor for the 

data used for this proposal; although, we believe that 

accounting for measurement imprecision should be an important 

consideration in calculating the floor emissions limit. We

request comment on approaches suitable to account for 

measurement variability in establishing the floor emissions 

limit when based on measurements at or near the method detection 

level.

As noted above, the confidence level that a value measured 

at the detection level is greater than zero is about 99 percent. 

The expected measurement imprecision for an emissions value 

occurring at or near the method detection level is about 40 to 

50 percent. Pollutant measurement imprecision decreases to a 

consistent relative 10 to 15 percent for values measured at a 

level about three times the method detection level8

 

8

American Society of Mechanical Engineers, Reference Method Accuracy and Precision 

. One 
86

approach that we believe could be applied to account for 

measurement variability would require defining a method 

detection level that is representative of the data used in 

establishing the floor emissions limits and also minimizes the 

influence of an outlier test-specific method detection level 

value. The first step in this approach would be to identify the 

highest test-specific method detection level reported in a data 

set that is also equal to or less than the floor emissions limit 

calculated for the data set. This approach has the advantage of 

relying on the data collected to develop the floor emissions 

limit while to some degree minimizing the effect of a test(s) 

with an inordinately high method detection level (e.g., the 

sample volume was too small, the laboratory technique was 

insufficiently sensitive, or the procedure for determining the 

detection level was other than that specified).

The second step would be to determine the value equal to 

three times the representative method detection level and 

compare it to the calculated floor emissions limit. If three 

times the representative method detection level were less than 

the calculated floor emissions limit, we would conclude that 

measurement variability is adequately addressed and we would not 

 

(ReMAP): Phase 1, Precision of Manual Stack Emission Measurements, CRTD Vol. 60, 

February 2001.
87

adjust the calculated floor emissions limit. If, on the other 

hand, the value equal to three times the representative method 

detection level were greater than the calculated floor emissions 

limit, we would conclude that the calculated floor emissions 

limit does not account entirely for measurement variability. We 

then would use the value equal to three times the method 

detection level in place of the calculated floor emissions limit 

to ensure that the floor emissions limit accounts for 

measurement variability. We request comment on this approach.

We are requesting comment on whether there is a more 

appropriate statistical approach to account for variability in 

the MACT floor analyses when there are emission data from a 

limited number of units in the subcategory.

However, after review of the available HAP data, 

including both emission test data and fuel analyses, we 

determined that it was inappropriate to use only this MACT floor 

approach to determine variability and to establish emission 

limits for boilers and process heaters, because this approach 

considers only the emissions test data. The main problem with 

using only the HAP emissions test data is that the data, which 

may reflect the variability of fuel-related HAP of the best 

performing units, may not reflect the variability of fuelrelated HAP from the best performing units over the long term. 

Formatted
88

Based on our current informationfuel-related HAP concentrations 

(nine individual samples collected over a 30-day period) 

obtained, pursuant to letters mandating data gathering issued 

under the authority of CAA section 114, fuel-related HAP levels 

in the various fuels can vary significantly over time. 

The first step in establishing a MACT standard is to 

determine the MACT floor. A necessary step in doing so is

determining the amount of HAP emitted. In the case of fuelrelated HAP emitted, this is not necessarily a straightforward 

undertaking. Single stack measurements represent a snapshot in 

time of a source’s emissions, always raising questions of how 

representative such emissions are of the source’s emissions over 

time. The variations in fuel-related HAP inputs directly

translate to a variability of fuel-related HAP stack emissions.

We believe that single short term stack test data 

(typically a few hours) are probably not indicative of long term 

emissions performance, and so are not the best indicators of

performance over time. With these facts in mind, we carefully 

considered alternatives other than use of only single short-term 

stack test results to quantify performance for fuel-related HAP. 

We decided that the most accurate method available to us to 

determine long term fuel-related HAP emissions performance was 

to obtainuse data on the fuel-related HAP inputs in the fuels
89

used by the best performing units. Pursuant to letters 

mandating data gathering, issued, obtained as part of our 

information collection effort under the authority of CAA section 

114, we obtainedon long-term fuel-related HAP concentrations 

(nine individual samples collected over a 30-day period) in each 

fuel, along with the fuel-related HAP concentrations during the 

stack tests.

As previously discussed above, we account for variability 

in setting floors, not only because variability is an element of 

performance, but because it is reasonable to assess best 

performance over time. Here, for example, we know that the HAP 

emission data from the best performing units are short-term 

averages, and that the actual HAP emissions from those sources 

will vary over time. If we do not account for this variability, 

we would expect that even the units that perform better than the

floor on average would potentially exceed the floor emission 

levels a significant part of the time which would mean that 

variability was not properly taken into account. This 

variability includes the day-to-day variability in the total

fuel-related HAP input to each unit and variability of the 

sampling and analysis methods, and it includes the variability 

resulting from site-to-site differences for the best performing 

units. We calculated the MACT floor based on the UPL (upper 
90

99th percentile) as described earlier from the average 

performance of the best performing units, Students t-factor, and 

the total variability of the best performing units.

This approach reasonably ensures that the emission limit 

selected as the MACT floor adequately represents the average 

level of controlemissions actually achieved by the average of 

the units in the top 12 percent, considering ordinary 

operational variability of those units. Both the analysis of 

the measured emissions from units representative of the top 12 

percent, and the variability analysis, are reasonably designed 

to provide a meaningful estimate of the average performance, or 

central tendency, of the best controlled 12 percent of units in 

a given subcategory. 

A detailed discussion of the MACT floor methodology is 

presented in the memorandum “MACT Floor Analysis (2010) for the 

Industrial, Commercial, and Institutional Boilers and Process 

Heaters National Emission Standards for Hazardous Air Pollutants

– Major Source” in the docket.

1. Determination of MACT for the Fuel-related HAP

In developing the proposed MACT floor for the fuel-related 

HAP (PM, HClnon-mercury metals, acid gases, and mercury), as 

described earlier, we are using PM as a surrogate for nonmercury metallic HAP and HCl as a surrogate for the acid gases. 
91

Table 2 of this preamble presents the number of units in each of 

the five subcategories, along with the number of units from 

which we have collected emission data. Table 2 also presents

for each subcategory and fuel-related HAP the number of units 

comprising the best performing units (top 12 percent), the 

average emission level of the top 12 percent, and the MACT floor 

(99 percent UPL of top 12 percent) which includes the 

variability across the best performing units and the long term 

variability across those units.

Table 2. Summary of MACT Floor Results for the Fuel-Related HAP 

for Existing Subcategories. 

Subcategory Parameter PM

Lb/MMBtu

Mercury

Lb/MMBtu

HCl

LB/MMBtu

Units 

designed 

for Coal 

firing

No. of 

sources in 

subcategory 

=

577578 577578 577578

No. of 

sources with 

data =

350366 269285 302318

No. in MACT 

floor =

4244 3335 3739

Avg of top 

12%%, 

lb/MMBtu

0.00757.

24E-03

0.0000005

25.95E-07

0.00424.

23E-03

99% UPL of 

top 12% 

(test runs)

=, lb/MMBtu

0.020179 0.0000016

1.64E-06

0.0067.3

8E-03

99% UPL with 

fuel 

variability 

of top% 12%, 

lb/MMBtu

0.0000032

.88E-06

1.11E-02

Units No. of 420 420 420

Formatted Table
92

designed 

for Biomass

firing 

sources in 

subcategory 

=

No. of 

sources with 

data =

197192 9391 9492

No. in MACT 

floor =

24 1211 12

Avg of top 

12%%, 

lb/MMBtu

0.01336.

06E-03

0.0000002

93.46E-07

0.00024.

34E-03

99% UPL of 

top 12% 

(test runs)

=, lb/MMBtu

0.070162 0.0000006

7.52E-07

0.00066.

00E-03

99% UPL with 

fuel 

variability 

of top% 12%, 

lb/MMBtu

0.0000007

8.88E-07

Units 

designed 

for Liquid 

Fuel firing

No. of 

sources in 

subcategory 

=

831826 831826 831826

No. of 

sources with 

data =

8691 150177 160190

No. in MACT 

floor =

11 1822 2023

Avg of top 

12%%, 

lb/MMBtu

0.00151.

40E-03

0.0000038

1.91E-06

0.000262

.59E-04

99% UPL of 

top 12% 

(test runs)

=, lb/MMBtu

0.003500

323

0.0000072

.78E-06

0.00033.

26E-04

99% UPL with 

fuel 

variability 

of top% 12%, 

lb/MMBtu

0.0000083

.97E-06

8.04E-04

Units 

designed 

for 

NG/RGother 

gas firing

No. of 

sources in 

subcategory 

=

10,66119

9

10,661199 10,66119

9
93

No. of 

sources with 

data =

13313 168 118

No. in MACT 

floor =

162 21 21

Avg of top 

12%%, 

lb/MMBtu

0.004201

1

0.0000000

0068.25E08

0.000131

.70E-06

99% UPL of 

top 12% 

(test runs)

=, lb/MMBtu

0.03045 0.0000000

021.86E07

0.00022.

50E-06

Units 

designed 

for other 

gas firing

No. of 

sources in 

subcategory 

=

196 196 19

6

No. of 

sources with 

data =

14 8 8

No. in 

MACT floor =

2 1 1

Avg of 

top 12%

0.0

11

0.000

000083

0.

0000017

99% UPL 

of top% 

(test runs) 

=

0.0

5

0.000

0002

0.

000003

Metal 

Processing 

Furnaces

No. of 

sources in 

subcategory 

=

749 749 74

9

No. of 

sources with 

data =

9 6 8

No. in 

MACT floor =

2 1 1

Avg of 

top 12%

0.0

047

0.000

000033

0.

000086

99% UPL 

of top% 

(test runs) 

=

0.0

2

0.000

0002

0.

0002
94

 For eightthree cases, the proposed new and existing source 

MACT floors are almost identical because the best performing 12 

percent of existing units (for which we have emissions 

information) is only one, or two or three sources. The reason 

we look to the best performing 12 percent of sources, even 

though we have data on fewer than 5 sources, is that these 

subcategories consist of 30 or more units. CAA section 

112(d)(3)(A) provides that standards for existing sources shall

not be less stringent than “the average emission limitation 

achieved by the best performing 12 percent of the existing 

sources (for which the Administrator has emissions information), 

* * * in the category or subcategory for categories and 

subcategories with 30 or more sources.” A plain reading of the 

above statutory provisions is to apply the 12 percent rule in 

deriving the MACT floor for those categories or subcategories 

with 30 or more sources. The parenthetical “(for which the 

Administrator has emissions information)” in CAA section 

112(d)(3)(A) modifies the best performing 12 percent of existing 

sources, which is the clause it immediately follows.

 However, in cases where there are 30 or more sources but 

little emission data, this results in only a few units setting 

the existing source floor with the result that the new and 

existing source MACT floors are almost identical. In contrast, 
95

if these subcategories had less than 30 sources, we would be 

required to use the top five best performing sources, rather 

than the one, two, or threetwo that comprise the top 12 percent. 

Section 112 (d)(3)(B).

 We are seeking comment on whether, with the facts of this 

rulemaking, we should consider reading the intent of Congress to 

allow us to consider five sources rather than just one, two, or

three.two. First, it seems evident that Congress was concerned 

that floor determinations should reflect a minimum quantum of 

data: At least data from 5 sources for source categories of 

less than 30 sources (assuming that data from 5 sources exist). 

Second, it does not appear that this concern would be any less 

for subcategories with 30 or more sources. We are specifically 

requesting comment on interpretivethis interpretation relating 

to the proposed MACT floors..9

2. Determination of MACT for Organic HAP

In developing the MACT floor for organic HAP, as described 

earlier, we are using CO as a surrogate for non-dioxin organic 

HAP. Table 3 of this preamble presents the number of units in 

each of the 11 subcategories, along with the number of units 

from which we have collected emission data. Table 3 also 

 

9 The impact of using a minimum of five sources in the MACT floor analyses for these subcategories and HAP are 

presented in the Memorandum “MACT Floor Analysis (2010) for the Industrial, Commercial, and Institutional 

Boilers and Process Heaters National Emission Standards for Hazardous Air Pollutants – Major Sources” located in 

the Docket.
96

presentedpresents for each subcategory and(for CO and D/F) the 

number of units comprising the best performing units (top 12 

percent), the average emission level of the top 12 percent, and 

the MACT floor (99 percent UPL of top 12 percent) which includes 

the variability across the best performing units and the long 

term variability.

We calculated the MACT floors based on the upper 99th

percentile UPL from the average performance of the best 

performing units and their variances as described earlier for 

the fuel-related HAP. 

Table 3. Summary of MACT Floor Results for the Organic HAP 

Subcategories. 

Subcategory Parameter CO

(ppm @ 3 

percent 

oxygen)

Dioxin/Furan

(Total TEQ)

(ng/dscm @ 7 

percent 

oxygen)

Stoker –

Coal

No. of sources in 

subcategory =

360361 360361

No. of sources with 

data =

5561 1514

No. in MACT floor = 78 2

Avg of top 12% 1921.4 ppm 

@ 3% O2

0.00180.0018

2 ng/dscm @ 

7% O2

99% UPL of top% 

(test runs) =

4048.8 ppm 

@ 3% O2

0.0030.00274 

ng/dscm @ 7% 

O2

Fluidized 

Bed -– Coal

No. of sources in 

subcategory =

31 31

No. of sources with 

data =

1417 1112

No. in MACT floor = 23 2

Avg of top 12% 1712.5 ppm 0.000470.000
97

@ 3% O2 471 ng/dscm 

@ 7% O2

99% UPL of top% 

(test runs) =

4021.4 ppm 

@ 3% O2

0.0020.00168 

ng/dscm @ 7% 

O2

PC – Coal No. of sources in 

subcategory =

186 186

No. of sources with 

data =

4041 10

No. in MACT floor = 5 2

Avg of top 12% 1419.2 ppm

@ 3% O2

0.00160.0015

8 ng/dscm @ 

7% O2

99% UPL of top% 

(test runs) =

7082.8 ppm 

@ 3% O2

0.0030.00307 

ng/dscm @ 7% 

O2

Stoker –

Biomass

No. of sources in 

subcategory =

334320 334320

No. of sources with 

data =

124119 16

No. in MACT floor = 15 2

Avg of top 12% 260203 ppm 

@ 3% O2

0.000820.000

819 ng/dscm 

@ 7% O2

99% UPL of top% 

(test runs) =

780551 ppm 

@ 3% O2

0.0030.00339 

ng/dscm @ 7% 

O2

Fluidized 

Bed –

Biomass

No. of sources in 

subcategory =

2612 2612

No. of sources with 

data =

187 76

No. in MACT floor = 5 5

Avg of top 12% 9297.1 ppm 

@ 3% O2

0.0060.00507 

ng/dscm @ 7% 

O2

99% UPL of top 12% 

(test runs) =

230245 ppm 

@ 3% O2

0.020.0127 

ng/dscm @ 7% 

O2

Suspension 

Burner/

Dutch Oven

No. of sources in 

subcategory =

4862 4862

No. of sources with 

data =

717 3

No. in MACT floor = 13 1
98

Avg of top 12% 69362 ppm 

@ 3% O2

0.00950.0095

2 ng/dscm @ 

7% O2

99% UPL of top 12% 

(test runs) =

2201010 

ppm @ 3% O2

0.030.0279 

ng/dscm @ 7% 

O2

99% UPL of top

12% with load 

variability

460

Fuel Cell –

Biomass

No. of sources in 

subcategory =

26 26

No. of sources with 

data =

1816 7

No. in MACT floor = 5 5

Avg of top 12% 130 ppm @ 

3% O2

0.00550.0055

2 ng/dscm @ 

7% O2

99% UPL of top 12% 

(test runs) =

270262 ppm 

@ 3% O2

0.020.0148 

ng/dscm @ 7% 

O2

Units 

designed 

for Liquid 

fuel firing

No. of sources in 

subcategory =

831826 831826

No. of sources with 

data =

115116 1517

No. in MACT floor = 14 23

Avg of top 12% 0.44443 

ppm @ 3% O2

0.000550.000

733 ng/dscm 

@ 7% O2

99% UPL of top 12% 

(test runs) =

10.911 ppm 

@ 3% O2

0.0020.00182 

ng/dscm @ 7% 

O2

Units 

designed 

for 

NG/RGother 

gases

firing

No. of sources in 

subcategory =

10,661199 10,661199

No. of sources with 

data =

72375 85

No. in MACT floor = 879 1

Avg of top 12% 1.70.0737 

ppm @ 3% O2

0.00260.0026

7 ng/dscm @ 

7% O2
99

99% UPL of top 12% 

(test runs) =

200.134 

ppm @ 3% O2

0.010.00828 

ng/dscm @ 7% 

O2

Units 

designed 

for other 

gases 

firing

No. of sources 

in subcategory =

196 196

No. of sources 

with data =

70 5

No. in MACT 

floor =

9 1

Avg of top 12% 0.08 0.0027

99% UPL of top

12% (test runs) =

1 0.008

Metal 

Processing 

Furnaces

No. of sources 

in subcategory =

749 749

No. of sources 

with data =

14 7

No. in MACT 

floor =

2 1

Avg of top 12% 0.38 0.0026

99% UPL of top

12% (test runs) =

2 0.004

For organic HAP, as previously discussed above for the 

fuel-related HAP, we account for variability in setting floors,

not only because variability is an element of performance, but 

because it is reasonable to assess best performance over time. 

Here, however, we know that the organic HAP emissions will also 

vary over the operating range of the unit, unlike fuel-related 

HAP emissions. Organic HAP are combustion-related pollutants. 

That is, their levels of emissions are a function of the 

combustion process. Combustion units operate most efficiently 
100

when operated at or near their design capacity. The combustion 

efficiency tends to decrease as the unit’s load (steam 

production) decreases. Most industrial or 

commercial/institutional units do not continuously operate at or 

near their design capacity but operate according to the 

facility’s demand for steam. Thus, operation at lower capacity 

rates must be accounted for in determining operational 

variability. 

As part of EPA’s information collection effort, we obtained 

data on organic HAP (THC and CO) from six units (two coal-fired, 

two biomass-fired, and two gas-fired) that were collected by 

using CEM over a 30-day period. All of these units were 

selected to test using CEM to provide variability information

because their stack test results indicated that they were among 

the best performing units.

 The CEMS data shows that CO (as a surrogate for non-dioxin 

organic HAP) from best performing units did not vary much, 

except for one biomass design type, when such unit is operated

at below design capacity. Therefore, even though ICI units, due 

to steam demand, may operate at these low load conditions for 

long continuous periods, no additional variability due to 

operating load needs to be accounted for, except for boilers in

since the biomass suspension burner/Dutch oven 
101

subcategory.average CO emission levels that include these low 

load conditions are within the variability range determined by 

the statistical analyses of CO emissions from the best 

performing units. Thus, to the MACT floor values determined 

from the stack test data for organic HAP, we have added anare 

proposing to add no additional variability factor to account for 

load variability only for boilers in the biomass suspension 

burner/Dutch oven subcategory.to the MACT floor 99 percent UPL 

values determined from the stack test data for CO emissions.

This approach reasonably ensures that the emission limit 

selected as the MACT floor adequately represents the average 

level of control actually achieved by units in the top 12 

percent in each subcategory, considering ordinary operational 

variability of those units. Both the analysis of the measured 

emissions from units representative of the top 12 percent, and 

the variability analysis of those units, are reasonably designed 

to provide a meaningful estimate of the average performance, or 

central tendency, of the best controlled 12 percent of units in 

a given subcategory. 

As was the case for the eightthree fuel-dependent MACT 

floors, the proposed new and existing source MACT floors for 

twelveeight combustion-dependent subcategories are almost 

identical because the best performing 12 percent of units (for
102

which we have emissions information) is only one or two sources. 

Again, the reason we look to the best performing 12 percent of 

sources is that these subcategories consist of 30 or more units. 

In contrast, if these subcategories had less than 30 sources, we 

would be required to use the top five best performing sources, 

rather than the one or two that comprise the top 12 percent. As 

stated previously, we are seeking comment on whether, with the 

facts of this rulemaking, we should consider reading the intent 

of Congress to allow us to consider five sources rather than 

just one, two, or three. We are specifically requesting comment 

on this interpretation relating to the proposed MACT floors.

3. Determination of the Work Practice Standard

CAA section 112(h)(1) states that the Administrator may 

prescribe a work practice standard or other requirements, 

consistent with the provisions of CAA sections 112(d) or (f), in 

those cases where, in the judgment of the Administrator, it is 

not feasible to enforce an emission standard. CAA section 

112(h)(2)(B) further defines the term “not feasible” in this 

context to apply when “the application of measurement technology 

to a particular class of sources is not practicable due to 

technological and economic limitations.” 

The standard reference methods for measuring emissions of 

mercury, CO (as a surrogate for organic HAP), D/F, HCl (as a 
103

surrogate for acid gases) and PM (as a surrogate for non-mercury 

metals) are EPA Methods 29, 10, 23, 26A and 5. These methods 

are reliable but relatively expensive as a group. However, the 

methods are generally not able to accurately sample small 

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

small diameter stacks, the conventional EPA Method 5 stack 

assembly blocks a significant portion of the cross-section of 

the duct and, if unaccounted for, could cause inaccurate 

measurements. Many existing small boilers and process heaters 

have stacks with diameters less than 12 inches. The stack 

diameter is generally related to the size of the unit. Units 

that have capacity below 10 million Btu per hour generally have 

stacks with diameters less than 12 inches. Also, many existing 

small units 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 analysis10

 

10Memorandum: Methodology for Estimating Impacts from Industrial, Commercial, 

and Institutional Boilers and Process Heaters at Major Sources of Hazardous 

Air Pollutant Emissions, March 23, 2010. 

to evaluate the economic 

impact of the testing and monitoring costs that facilities with 

small units would incur to demonstrate compliance with the 

proposed emission limits. The annual compliance costs imposed 

on each facility is for the costs of the stack tests. The 
104

compliance costs imposed on each facility would not only include

the costs of the stack tests and monitoring equipment but would 

also include the capital costs of any installed control 

equipment. We estimate that the total capital costs of 

installing control equipment on the over 7,400 small boilers and 

process heaters to achieve the proposed emission limits would be 

$6.3 billion. In addition to these costs, additional costs 

would be incurred because many of these small units do not have 

test ports or testing platforms installed in order to conduct 

performance testing. Prior to conducting a stack test each unit 

would need to construct or rent scaffolding and install test 

ports. EPA estimates that these small sources would incur an 

additional $185 million to install test ports and rent temporary 

scaffolding. Many establishments in each industry, commercial, 

or institutional sector are associated with multiple (as many as 

a 100700) small units.

The results of the analysis indicate that the annual costs 

for testing and monitoring costs alone would have a significant 

adverse economic impact on these facilities. The severity of 

the economic impact would depend on the size of the facility. 

Based on this analysis, the Administrator has determined, 

as allowed under CAA section 112(h),) that it is not feasible to 

enforce emission standards for a particular class of existing 
105

boilers and process heaters because of the technological and 

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

discussed below, is being proposed to limit the emission of HAP

for existing boilers and process heaters having a heat input 

capacity of less than 10 million Btu per hour. We are 

specifically requesting comment on whether a threshold higher 

than 10 million Btu per hour meets the technical and economic 

limitations as specified in CAA section 112(h). 

For existing units, the only work practice being used that 

potentially controls HAP emissions is a tune-up. Fuel dependent 

HAP are typically controlled by removing them from the flue gas 

after combustion. The only work practices expected to minimize 

fuel dependent HAP emissions are reducing the fuel usage or fuel 

switching to a fuel type with a lower HAP content or reducing 

the fuel usage. As discussed later, we determined that fuel 

switching is not an appropriate emission reduction approach. 

However, fuel. Fuel usage can be reduced by improving the 

combustion efficiency of the unit, such as, by a tune-up. As 

combustion efficiency decreases, fuel usage increasesmust 

increase to maintain constant energy output resulting. This 

increased fuel use results in increased emissions. 

On the other hand, organic HAP are formed from incomplete 

combustion of the fuel. The objective of good combustion is to 
106

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 oxygen-fuel contact), and sufficient time (to complete 

the process), sometimes referred to the three Ts of combustion. 

Good combustion practice (GCP), in terms of combustion units, 

could be defined as the system design and work practices 

expected to minimize organic HAP emissions.

We have obtained information on units that reported using 

GCP, as part of the information collection effort for the

NESHAP. The data that we have suggests that units typically 

conduct tune-ups. We also reviewed stateState regulations and 

permits. The work practices listed in stateState regulations 

includes tune-ups (10 statesStates), operator training (1 

stateState), periodic inspections (2 States), and operation in 

accordance with manufacturer specifications (1 State). Of the 

units with a capacity of less than 10 MMBtu/h that responded to 

EPA’s information collection effort for the NESHAP, 80 percent 

reported conducting a tune-up program. Ultimately, we determine 

that at least 6 percent of the units in each of the 

subcategorysubcategories are subject to an annuala tune-up 

requirement under other applicable requirements.. Therefore, 
107

the proposed work practice of an annuala tune-up11

We are also proposing a work practice standard under 

section 112(h) that would require an annual tune-up for existing 

boilers and process heaters combusting natural gas or refinery 

gas. These boilers and process heaters are units included in 

the Gas 1 and metal processing furnace subcategories. We are 

specifically seeking comment on whether the application of 

measurement methodology to sources in this subcategory is 

impracticable due to technological or economic limitations, as 

specified in section 112(h)(2)(B).

program does 

establish the MACT floor for HAP emissions from existing units 

with a heat input capacity of less than 10 MMBtu/h.

This proposalwork practice standard is based onbeing 

proposed for several reasons. First, the capital costs 

estimated for installing controls on these boilers and process 

heaters to comply with MACT limits for the five HAP groups is 

over $14 billion to install. This cost includes installation of

a combination system of a fabric filter (for PM, mercury, and 

D/F control) and a wet scrubber (for HCl control). This capital 

cost is higher than the estimated combined capital cost for 

boilers and process heaters in all of the other subcategories to 

comply with the proposed emission limits.. The projected

 

11 Tune-up procedure is specified in section 63.7540 of this proposed rule and includes making adjustments to the 

burner to optimize the flame to minimize CO emissions consistent with the manufacturer’s specifications. 
108

control system needed for boilers and process heaters in the 

other subcategories is also a combined fabric filter/wet 

scrubber system.

Second, we believe that proposing emission standards for 

gas-fired boilers and process heaters that result in the need to 

employ the same emission control system as needed for the other 

fuel types would have the negative benefit of providing a 

disincentive for switching to gas as a control technique (and a 

pollution prevention technique) for boilers and process heaters 

in the other fuel subcategories. In addition, emission limits 

on gas-fired boilers and process heaters may have the negative 

benefit of providing an incentive for a facility to switch from 

gas (considered a “clean” fuel) to a “dirtier” but cheaper fuel 

(i.e., coal). It would be inconsistent with the emissions 

reductions goals of the CAA, and of section 112 in particular, 

to adopt requirements that would result in an overall increase 

in HAP emissions. We are soliciting comment on the extent to 

which natural gas facilities would be expected to switch to a 

“dirtier” fuel if emissions limits for such facilities are 

adopted.

Thus, a work practice, as discussed above for small boilers 

and process heaters, is being proposed to limit the emission of 
109

HAP for existing natural gas-fired and refinery gas-fired 

boilers and process heaters.

We request comments on whether the emission limits listed 

in Tables 2 and 3Table 4 of this preamble for the Gas 1 and 

Metal processing furnaceProcess Furnace subcategories should be 

promulgated. Comments should include detailed information 

regarding why emission limits for these gas-fired boilers and 

process heaters are appropriate.

Table 4. Summary of MACT Floor Results for the Gas 1 and Metal 

Process Furnace Subcategories.

Subcate

gory

Parame

ter

PM Mercury HCl CO Dioxin/Furan

(Total TEQ)

Units 

designe

d for 

NG/RG 

firing

No. of 

source

s in 

subcat

egory 

10,783 10,783 10,783 10,783 10,783

No. of 

source

s with 

data 

144 14 11 754 8

No. in 

MACT 

floor 

18 2 2 91 1

Avg of 

top 

12%

0.0038

8

lb/MMB

tu

1.1E-07 

lb/MMBt

u

1.01E04 

lb/MMB

tu

1.45

ppm @ 

3%

oxygen

0.0026

ng/dscm @ 

7% oxygen

99% 

UPL of 

top

12% 

(test 

0.03 

lb/MMB

tu

2.0E-07 

lb/MMBt

u

0.0002 

lb/MMB

tu

20 ppm 

@ 3%

oxygen

0.01

ng/dscm @ 

7% oxygen
110

E. How did EPA consider beyond-the-floor options for existing 

units?

Once the MACT floor determinations were done for each 

subcategory, we considered various regulatory options more 

stringent than the MACT floor level of control (i.e., 

technologies or other work practices that could result in lower 

emissions) for the different subcategories. A detailed 

description of the beyond-the-floor consideration is in the 

memorandum “Methodology for Estimating Cost and Emissions 

Impacts for Industrial, Commercial, Institutional Boilers and 

runs) 

Metal 

Process

Furnace

s

No. of 

source

s in 

subcat

egory 

749 749 749 749 749

No. of 

source

s with 

data

9 7 9 15 7

No. in 

MACT 

floor 

2 1 2 2 1

Avg of 

top 

12%

0.0047 

lb/MMB

tu

3.3E-08 

lb/MMBt

u

1.92E04 

lb/MMB

tu

0.38

ppm @ 

3%

oxygen

0.0026

ng/dscm @ 

7% oxygen

99% 

UPL of 

top

12% 

(test 

runs) 

0.02 

lb/MMB

tu

2.0E-07 

lb/MMBt

u

0.0004 

lb/MMB

tu

2 ppm 

@ 3%

oxygen

0.004

ng/dscm @ 

7% oxygen
111

Process Heaters National Emission Standards for Hazardous Air 

Pollutants” in the docket.

We could not identify better control technologiesHAP 

emissions reduction approaches that could achieve greater 

emissions reductions of HAP than the control technology 

combination (fabric filter, carbon injection, scrubber, and GCP) 

that we expect will be used to meet the MACT floor level of 

control. 

For each subcategory, fuel switching to natural gas is a 

regulatoryan option more stringent than the MACT floor that 

would reduce HAP emissions. We determined that fuel switching 

was not an appropriate beyond-the-floor option. First, natural 

gas supplies are not available in some areas, and supplies to 

industrial customers can be limited during periods when natural 

gas demand exceeds supply. Additionally, the estimated 

emissions reductions that would be achieved if solid and liquid 

fuel units switched to natural gas were compared with the 

estimated cost of converting existing solid fuel and liquid fuel 

units to fire natural gas. The annualized cost of fuel 

switching was estimated to be $13.5 billion compared with $3.5.1

billion under the floor approach. The emission reduction 

associated with fuel switching was estimated to be 5,1144,296

tons per year for metallic HAP, 198 tons per year for mercury, 
112

and 40,08950,332 tons per year for inorganic HAP (HCl and HF). 

The cost for fuel switching is over double the cost of the floor 

approach while the emission reductions associated with fuel 

switching are approximately the same. Additional detail on the 

calculation procedures is provided in the memorandum 

“Development (2010) of Fuel Switching Costs and Emissions 

Reductions for Industrial, Commercial, and Institutional Boilers 

and Process Heaters National Emission Standards for Hazardous 

Air Pollutants” in the docket.

We also considered the pollution prevention and energy 

conservation measure of an energy assessment/audit as a beyondthe-floor option for HAP emissions. An energy assessment

provides valuable information on improving energy efficiency. 

An energy assessment, or audit, is an in-depth 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 and results in reduced emissions and 
113

improved public health. Improvement in energy efficiency 

results in decreased fuel use which results in a corresponding 

decrease in emissions (both HAP and non-HAP) from the combustion 

unit, but not necessarily all those present.a decrease in 

emissions of all HAP emitted. 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. 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. The total 

annualized cost if each major source facility conducted an 

energy assessment is estimated at $26 million. If a facility 

elected to implementimplemented the cost-effective energy 

conservation measures identified in the energy auditassessment, 

it would potentially result in greater HAP reduction than 

achieved by a boiler tune-up alone. and potentially reducing HAP 

emissions (HCl, mercury, non-mercury metals, and VOC) by an 
114

additional 820 to 1,640 tons per year. In addition, 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 

units. These proposed standards for existing units include the 

requirement of a performance of an energy assessment to identify 

cost-effective energy conservation measures. Since there was 

insufficient information to determine if requiring 

implementation of cost-effective 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 32 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 
115

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 one-time energy assessment to identify 

cost-effective energy conservation measures. 

In addition to the energy assessment requirement, we are 

proposing an 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 
116

systems. We are proposing that a qualified specialized 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.

As part of the energy assessment, we are proposing that the 

facility assess its energy management program and practices 

using EPA’s ENERGY STAR Facility Energy Management Assessment 

Matrix. ENERGY STAR has a simple facility energy management 

assessment tool that can be used as part of the assessment 

process. This tool identifies gaps in current practices. 

Facilities, as part of the requirement, would identify steps to 

close the management gaps. We are also proposing that the 

facility develop an energy management program according to the 

ENERGY STAR Guidelines for Energy Management (see 

www.energystar.gov/guidelines).12

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 to inform the facility’s decision to make 

efficiency upgrades; (5) is the definition of “cost-effective” 

 

12 The location of the guidance is: http://www.energystar.gov/index.cfm?c=guidelines.assess_facility_energy.
117

appropriate in this context since it refers to payback of energy 

saving investments without regard to the impact on HAP 

reduction; (6) what rate of return should be used; and (7) are 

there other guidelines for energy management beside ENERGY 

STAR’s that would be appropriate.

We considered proposing a beyond-the-floor requirement for 

certain sources in the natural gas and refinery gas subcategory 

(i.e., the Gas 1 subcategory). Specifically, we areconsidered

proposing that facilities with boilers or process heaters 

combusting refinery gas install and maintain a carbon adsorber 

bed system13

 

13 Carbon adsorption of mercury can be accomplished by (a) injecting dry carbon with or without 

other dry sorbents into the offgas upstream of a PM control device (typically a baghouse), or (b) using 

a fixed or moving bed of granular carbon through which the offgas flows. In a typical fixed bed carbon 

adsorption system, the flue gas flows through a vessel packed with a specified depth of the carbon 

granules. The bed and packing are designed to limit the linear velocity of the offgas in the bed to 

increase the contact time with the carbon. Due to the increased contact times and typically lower 

operating temperatures, better removal efficiencies can be achieved than for carbon injection. At a

to remove mercury from the refinery gas before 

combustion in a boiler or process heater. Based on data from 

the information collection effort, refinery gas contains high 

levels of mercury compared to natural gas, and significant and 

additional mercury reductions can be achieved from units

combusting refinery gas. In addition, the cost of 

Consequently, we analyzed the mercury controls for such units is 

reasonable, because theemissions reductions and additional cost 

residence time of 10 seconds in the carbon bed, virtually all of the mercury can be removed. (Ref. 

NUCON INTERNATIONAL, Inc., “ Design & Performance Characteristics of MERSORBB Mercury

Adsorbents in Liquids and Gases,” NUCON 11B28, August 1995.)
118

of adopting this work practice. The annualized cost of the 

carbon adsorber bed system to treat the refinery gas prior to 

combustion is less expensive than installingestimated to be 

about 1.6 billion dollars with a fabric filter/carbon injection 

system on each individual unit to treat its exhaust gas,

compared to the significant mercury emissions reductions 

emission reduction of 0.8 tons. The results indicated that 

would be achieved. EPA iswhile additional mercury emissions 

reductions would be realized, the costs would be too high to 

consider it a feasible beyond-the-floor option. Nonair quality 

health, environmental impacts, and energy effects were not 

significant factors, because there would be little difference in 

the nonair quality health and environmental impacts of requiring 

the installation of carbon bed adsorbers. Therefore, we are not 

proposing installation of a carbon adsorber bed system as a 

beyond-the-floor requirement for natural gas boilers and process 

heaters because such a requirement would achieve minimal 

emissions reductions from such units, and therefore the cost of 

installing and maintaining the system is not warranted. 

F. Should EPA consider different subcategories for solid fuel 

boilers and process heaters?

The boilers and process heaters source category is 

tremendously heterogeneous. EPA has attempted to identify 
119

subcategories that provide the most reasonable basis for 

grouping and estimating the performance of generally similar 

units using the available data. We believe that the 

subcategories we selected are appropriate.

EPA requests comments on whether additional or different 

subcategories should be considered. Comments should include 

detailed information regarding why a new or different 

subcategory is appropriate (based on the available data or 

adequate data submitted with the comment), how EPA should define 

any additional/different subcategories, how EPA should account 

for varied or changing fuel mixtures, and how EPA should use the 

available data to determine the MACT floor for any new or 

different categories.

G. How did EPA determine the proposed emission limitations for 

new units?

All standards established pursuant to section 112 of the 

CAA must reflect MACT, the maximum degree of reduction in 

emissions of air pollutants that the Administrator, taking into 

consideration the cost of achieving such emissions reductions, 

and any nonair quality health and environmental impacts and 

energy requirements, determines is achievable for each category. 

The CAA specifies that MACT for new boilers and process heaters 

shall not be less stringent than the emission control that is 
120

achieved in practice by the best-controlled similar source. 

This minimum level of stringency is the MACT floor for new 

units. However, EPA may not consider costs or other impacts in 

determining the MACT floor. EPA must consider cost, nonair 

quality health and environmental impacts, and energy 

requirements in connection with any standards that are more 

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

H. How did EPA determine the MACT floor for new units?

Similar to the MACT floor process used for existing units, 

the approach for determining the MACT floor must be based on 

available emissions test data. Using such an approach, we 

calculated the MACT floor for a subcategory of sources by 

ranking the emission test results from units within the 

subcategory from lowest to highest to identify the best 

controlled similar source. The MACT floor limits for each of 

the HAP and HAP surrogates (PM, mercury, CO, HCl, and D/F) are 

calculated based on the performance (numerical average) of the 

lowest emitting (best controlled) source for each pollutant in 

each of the subcategories.

The MACT floor limits for new sources were calculated using 

the same formula as was used for existing sources. However, as 

was the case for the existing MACT floor analysis, we determined 

that it was inappropriate to use only this MACT floor approach 
121

to determine variability and to establish emission limits for 

new boilers and process heaters. The main problem with using 

only the HAP emissions test data is that the data may not 

reflect the variability of fuel-related HAP from the best 

controlled similar source over the long term. Based on our 

current information, fuel-related HAP levels in the various 

fuels can vary significantly over time. The variations in fuelrelated HAP inputs directly translate to a variability of fuelrelated HAP stack emissions.

As previously discussed above, we account for variability

of the best-controlled source in setting floors, not only 

because variability is an element of performance, but because it

is reasonable to assess best performance over time. If we do 

not account for this variability, we would expect that even the 

best controlled similar source would potentially exceed the 

floor emission levels a significant part of the time which would 

mean that their variability was not properly accounted for when 

setting the floor. We calculated the MACT floor based on the 

UPL (upper 99th percentile) as described earlier from the 

average performance of the best controlled similar source, 

Students t-factor, and the total variability of the bestcontrolled source.
122

This approach reasonably ensures that the emission limit 

selected as the MACT floor adequately represents the average 

level of control actually achieved by the best controlled 

similar source, considering ordinary operational variability.

A detailed discussion of the MACT floor methodology is 

presented in the memorandum “MACT Floor Analysis for the 

Industrial, Commercial, and Institutional Boilers and Process 

Heaters National Emission Standards for Hazardous Air 

Pollutants” in the docket.

The approach that we use to calculate the MACT floors for 

new sources is somewhat different from the approach that we use 

to calculate the MACT floors for existing sources. While the 

MACT floors for existing units are intended to reflect the 

average performance achieved by the average of the best 

performing twelve12 percent of sources, the MACT floors for new 

units are meant to reflect the emission control that is achieved 

in practice by the best controlled source. Thus, for existing 

units, we are concerned about estimating the central tendency of 

a set of multiple units, while for new units, we are concerned 

about estimating the level of control that is representative of 

that achieved by a single best controlled source. As with the 

analysis for existing sources, the new unit analysis must 

account for variability. To accomplish this for new sources, 
123

for the fuel dependent HAP emissions, we determined what the 

best controlled source can achievehas achieved in light of the 

inherent and unavoidable variations in the HAP content of the 

fuel that such unit might potentially use. For non-fuel 

dependent HAP emissions, on the other hand, we look at the 

inherent variability of the control technology used by the bestcontrolled source in the subcategory. These approaches, 

respectively, represent the most reasonable way to estimate 

performance for purposes of establishing MACT floors for new 

units, given the data available. 

For fuel dependent HAP emissions (mercury and HCl), we 

calculated the variability factor by looking at data on HAP 

variability in fuel obtained through our information collection 

request. We derived the fuel dependent variability factor by 

dividing the highest observed HAP concentration by the lowest 

observed HAP concentration from the fuel analyses from the bestcontrolled source. Once we calculated the fuel dependent 

variability factors, we applied these factors to the average 

measured emissions performance of the unit with the best 

datacontrolled similar source to derive the MACT floor level of 

control. This approach reasonably estimates the best source’s 

level of controlemissions, adjusted for unavoidable variation in 

fuel characteristics which have a direct impact on emissions. 
124

1. Determination of MACT for the Fuel-related HAP

In developing the MACT floor for the fuel-related HAP (PM, 

HCl, and mercury), as described earlier, we are using PM as a 

surrogate for non-mercury metallic HAP and HCl as a surrogate 

for the acid gases. Table 45 presents for each subcategory and 

fuel-related HAP the average emission level of the best 

controlled similar source and the MACT floor (99 percent UPL) 

which includes the variability across the best controlled 

similar source and the long term variability of that source.

Table 4.5. Summary of MACT Floor Results for the Fuel-Related 

HAP for New Sources. 

Subcategory Parameter PM

Lb/MMBtu

Mercury

Lb/MMBtu

HCl

LBLb/MMB

tu

Units 

designed 

for Coal 

firing

Avg of top

performer

0.000400

0396

0.0000001

1.18E-07

0.000015

3.85E-05

99% UPL of 

top

performer 

(test runs) 

=

0.000900

0928

0.0000004

3.89E-07

0.000045

.21E-05

Units 

designed 

for Biomass 

firing 

Avg of top 

performer

0.002200

216

0.0000001

9.73E-08

0.000797

.85E-04

99% UPL of 

top 

performer(te

st runs) =

0.007007

11

0.0000004

1.86E-07

0.0033.0

7E-03

Units 

designed 

for Liquid 

Fuel firing

Avg of top 

performer 

0.000600

0511

0.0000000

075.87E08

0.00013.

99E-04
125

99% UPL of 

top 

performer(te

st runs) =

0.002001

54

0.0000000

32.47E-07

0.00029.

80E-04

Units 

designed 

for 

NG/RGother 

gas firing

Avg of top 

performer 

0.006500

042

0.0000000

0038.25E08

0.000037

1.70E-06

99% UPL of 

top 

performer(te

st runs) =

0.024002

4

0.0000000

021.86E07

0.000062

.50E-06

Units 

designed 

for other 

gas firing

Avg of 

top 

performer 

0.0

002

0.00

000005

0.0

000017

99% UPL 

of top (test 

runs) =

0.0

01

0.00

000006

0.0

000025

Metal 

Processing 

Furnaces

Avg of 

top 

performer 

0.0

065

0.00

0000033

0.0

00037

99% UPL 

of top (test 

runs) =

0.0

2

0.00

00002

0.0

0006

2. Determination of MACT for Organic HAP

In developing the MACT floor for organic HAP, as described 

earlier, we are using CO as a surrogate for non-dioxin organic 

HAP. Table 56 presents for each subcategory and CO and D/F the 

average emission level of the best controlled similar source and 

the MACT floor (99 percent UPL) which includes the variability 

across the best controlled similar source and the long term 

variability of that source.
126

Table 5.6. Summary of MACT Floor Results for the Organic HAP

for New Sources. 

Subcategory Parameter CO

(ppm @ 3 

percent 

oxygen)

Dioxin/Furan

(TEQ)

(ng/dscm @ 7 

percent 

oxygen)

Stoker –

Coal

Avg of top 

performer

0.2624.29 0.002531.52E

-03

99% UPL of top%

performer (test 

runs) =

16.53 0.0062.82E03

Fluidized 

Bed - Coal

Avg of top 

performer

0.2318.26 0.001919.05E

-06

99% UPL of top%

performer (test 

runs) =

039.9* 0.0032.54E05

PC – Coal Avg of top 

performer

25.0.279 0.01821.04E03

99% UPL of top%

performer (test 

runs) =

097.5* 0.051.47E-03

Stoker –

Biomass

Avg of top 

performer

3.74920 0.01921.52E05

99% UPL of top%

performer (test 

runs) =

123730* 0.024.86E-05

Fluidized 

Bed –

Biomass

Avg of top 

performer

0.046725.8 0.1832.27E03

99% UPL of top%

performer (test 

runs) =

0.934.2 1.6.48E-03

Suspension 

Burner/

Dutch Oven

Avg of top 

performer

1.22352 2.499.52E-03

99% UPL of top%

performer (test 

runs) =

431050* 2.579E-02

Fuel Cell –

Biomass

Avg of top 

performer

2.37110 0.01792.42E04

99% UPL of top%

performer (test 

runs) =

4264* 0.14.17E-04
127

Units 

designed 

for Liquid 

fuel firing

Avg of top 

performer

0.129125 0.001771.09E

-03

99% UPL of top%

performer (test 

runs) =

0.13125 0.0041.52E03

Units 

designed 

for 

NG/RGother 

gases

firing

Avg of top 

performer

0.0129 0.01272.67E03

99% UPL of top%

performer (test 

runs) =

0.0130129 0.018.28E-03

Units 

designed 

for other 

gases 

firing

Avg of top 

performer

0.168 0.045

99% UPL of 

top% (test runs) =

6 0.2

Metal 

Processing 

Furnaces

Avg of top 

performer

1.1 0.0425

99% UPL of 

top% (test runs) =

35 0.2

*Value is higher than existing floor limit in the same 

subcategory. Therefore defaulted to existing floor limit for 

the same subcategory.

For organic HAP, as previously discussed above for the 

fuel-related, we account for variability in setting floors, not 

only because variability is an element of performance, but 

because it is reasonable to assess best performance over time. 

Here, we know that CO (as a surrogate for non-dioxin organic 

HAP) emissions does not vary significantly over the operating 

range of the unit. Thus, we have not added any additional 

Formatted: Font: Not Bold

Formatted
128

operational variability to account for operation at lower 

capacity rates. 

We are proposing a work practice standard under section 

112(h) that would require an annual tune-up for new boilers and 

process heaters combusting natural gas or refinery gas. These 

boilers and process heaters are units included in the Gas 1 and 

metal processing furnace subcategories. We are specifically 

seeking comment on whether the application of measurement 

methodology to sources in this subcategory is impracticable due 

to technological or economic limitations, as specified in 

section 112(h)(2)(B).

This proposal for new boilers and process heaters 

combusting natural gas or refinery gas is based on the same 

reasons discussed previously for existing boilers and process 

heaters combusting natural gas or refinery gas. That is, we 

believe that proposing emission standards for new gas-fired 

boilers and process heaters that result in the need to employ 

the same emission control system as needed for the other fuel 

types would have the negative benefit of providing a 

disincentive for switching to gas as a control technique (and a 

pollution prevention technique) for boilers and process heaters 

in the other fuel subcategories. In addition, emission limits 

on gas-fired boilers and process heaters may have the negative 
129

benefit of providing an incentive for a facility to switch from 

gas (considered a “clean” fuel) to a “dirtier” but cheaper fuel 

(i.e., coal). It would be inconsistent with the emissions 

reductions goals of the CAA, and of section 112 in particular, 

to adopt requirements that would result in an overall increase 

in HAP emissions. We are soliciting comment on the extent to 

which new facilities would be expected to switch away from 

natural gas to a “dirtier” fuel if emissions limits for new such 

facilities are adopted.

Thus, a work practice, as discussed above for existing 

boilers and process heaters combusting natural gas or refinery 

gas, is being proposed to limit the emission of HAP for new 

natural gas-fired and refinery gas-fired boilers and process 

heaters.

We request comments on whether the emission limits listed 

in Table 7 of this preamble for new units in the Gas 1 and Metal 

Process Furnace subcategories should be promulgated. Comments 

should include detailed information regarding why emission 

limits for these gas-fired boilers and process heaters are 

appropriate.

Table 7. Summary of MACT Floor Results for New Units in the Gas 

1 and Metal Process Furnace Subcategories.
130

I. How did EPA consider beyond-the-floor for new units?

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 were identified that would achieve HAP reduction 

greater than the new source floors for the subcategories. 

Fuel switching to natural gas is a potential regulatory 

option beyond the new source floor level of control that would 

Subcate

gory

Parame

ter

PM

Lb/MMB

tu

Mercury

Lb/MMBt

u

HCl

LB/MMB

tu

CO

(ppm @ 

3 

percent 

oxygen)

Dioxin/Furan

(Total TEQ)

(ng/dscm @ 

7 percent 

oxygen)

Units 

designe

d for 

NG/RG 

firing

Avg of 

top 

perfor

mer 

0.0001

3

9.4E-08 7.3E055 0.0026

99% 

UPL of 

top 

(test 

runs) 

=

0.0005 2.0E-07 0.0002 20 0.01

Metal 

Process

Furnace

s

Avg of 

top 

perfor

mer 

0.0065 3.3E-08 8.6E050.5 0.0026

99% 

UPL of 

top 

(test 

runs) 

=

0.02 2.0E-07 0.0002 2 0.004
131

reduce HAP emissions from non-gas-fired units. However, based 

on current trends within the industry, EPA projects that the 

majority of new boilers and process heaters will be built to 

fire natural gas as opposed to solid and liquid fuels such that 

the overall emissions reductions associated with this option 

would be minimal. In addition, natural gas supplies are not 

available in some areas, and supplies to industrial customers 

can be limited during periods when natural gas demand exceeds 

supply. Thus, this potential control option may be unavailable 

to many sources in practice. Limited emissions reductions in 

combination with the high cost of fuel switching and 

considerations about the availability and technical feasibility 

of fuel switching makes this an unreasonable regulatory option 

that was not considered further..14

An energy assessment is a beyond-the-floor standard being 

proposed for existing facilities. However, we are not proposing 

it as a beyond-the-floor option for new major source facilities 

since we believe it would not be cost effective because most 

projected new boilers or process heaters will be installed at 

 Nonair quality health, 

environmental impacts, and energy effects were not significant 

factors. No beyond-the-floor options for gas-fired boilers were 

identified. 

 

14 Memorandum “Development (2010) of Fuel Switching Costs and Emission Reductions for Industrial, 

Commercial, and Institutional Boilers and Process Heaters National Emission Standards for Hazardous Air 

Pollutants,” April 2010.
132

existing major source facility which would have already 

conducted aan energy assessment as required by this proposed 

rule. We also believe that any new greenfield major source 

facility having boilers or process heaters will be designed to 

operate with energy efficiency. 

Based on the analysis discussed above, EPA decided to not 

go beyond the MACT floor level of control for new sources for 

MACT 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 Boilers and Process Heaters National 

Emission Standards for Hazardous Air Pollutants” in the docket.

J. What other compliance alternatives were 

considered?Consideration of whether to set standards for HCl and 

other acid gases under section 112(d)(4)

CAA section 112(d)(4) allows the Administrator to set a 

health-based standard for a limited set of HAP: “pollutants for 

which a health threshold has been established.” EPA may

consider that threshold, with an ample margin of safety, in 

establishing standards under CAA section 112(d). In the 2007

rule, EPA took the position that HCl and manganese were both 

“health threshold pollutants” and relied on section 112(d)(4) in 

deciding to establish alternative standards for HCl and 
133

manganese. 69 FR at 55239–44. In today’s proposed action, we 

considered whether to propose the health-based compliance 

alternatives that were part of the vacated Boiler MACT standard. 

As noted in the proposal of the MACT II chemical recovery 

combustion sources (63 FR 18755; April 15, 1998), “use of

section 112(d)(4) authority is wholly discretionary . . .[C]ases 

may arise in which . . . considerations dictate that the Agency 

should not invoke this authority to establish less stringent 

standards, despite the existence of a health effects threshold 

that is not jeopardized.” We further stated in that rule that 

“in considering appropriate uses of its discretionary authority 

under section 112(d)(4), EPA intends to consider other factors 

in addition to health thresholds, including uncertainty and 

potential’ adverse environmental effects,’ as that phrase is 

defined in section 1 12(a)(7).”

Thus while we have discretion to set a health-based 

standard under section 112(d)(4) where we believe a pollutant 

has an established health threshold, that discretion must be

exercised reasonably. As explained further below, we do not 

believe that establishing a threshold level would provide an 

“ample margin of safety,” as required by section 112(d)(4), and 

therefore are not proposing to relax the stringency of the 
134

emission standard for HCl using the section 112(d)(4) in this 

case. 

We are not proposing health-based compliance alternatives 

here for three primary reasons. First, while the CAA allows the 

Administrator to consider a health-based standard, such a 

standard must be robust enough to allow her to ensure that an 

ample margin of safety has been provided. Second, since HCl is 

used as a surrogate for other HAP acid gases hydrogen fluoride 

and hydrogen cyanide, she must consider whether such a strategy 

would necessitate setting additional MACT standards for these 

gases for which HCl was being used as a surrogate. And third, 

since the decision to propose health-based standards is 

discretionary, consideration can and should be given to all the 

direct effects that result from controlling HCl emissions.

First, the classification of HCl as a threshold pollutant 

is based on only one animal study, and no human data are

available for review (63 FR 18755) – clearly not sufficient to 

ensure protection with adequate margin of safety. Second, it is 

clear that hydrogen chloride (HCl) is a respiratory toxic

pollutant; that is, it can cause irritation in the nose, throat, 

and upper respiratory tract which could ultimately lead to 

chronic damage. This is also true of the HAPs hydrogen fluoride 

(HF) and hydrogen cyanide (HCN), the other acid gas HAPs that 
135

may be emitted by coal-fired boilers which can be controlled via 

the same technologies, and for which EPA must issue standards in

this rulemaking. The respiratory toxicity of HCl is generally 

considered not to occur at chronic exposure concentrations below 

the reference concentration, or RfC, which is 20 ug/m3. 

However, the determination of this reference concentration does 

not consider the potential for simultaneous exposures to other 

respiratory toxicants. In addition, HCl is corrosive to the 

eyes, skin, and mucous membranes. Acute inhalation exposure may 

cause eye, nose, and respiratory tract irritation and 

inflammation and pulmonary edema in humans. Chronic 

occupational exposure to hydrochloric acid has been reported to 

cause gastritis, bronchitis, and dermatitis in workers. 

Prolonged exposure to low concentrations may also cause dental 

discoloration and erosion. No information is available on the 

reproductive or developmental effects of hydrochloric acid in 

humans. In rats exposed to hydrochloric acid by inhalation, 

altered estrus cycles have been reported in females and 

increased fetal mortality and decreased fetal weight have been 

reported in offspring. EPA has not classified hydrochloric acid 

for carcinogenicity. The inhalation of HCl has also been known 

to lead to chemical-induced asthma in some cases. As such, its 

effects can be manifested when it is inhaled in combination with 
136

other asthma-inducing pollutants (e.g., ozone, formaldehyde, or 

acrolein), triggering asthma attacks, even at concentration 

levels well below its RfC. Since boilers are often located at 

industrial sites where other pollutants are emitted, it would be 

reasonable to consider the boiler emissions in conjunction with 

other emissions at the same site, particularly since such sites 

are often found in polluted urban areas as well as in polluted 

urban areas. At a minimum, it would be reasonable to consider 

the combination of all respiratory toxicants and asthmaexacerbating pollutants in the ambient air near boilers when 

estimating their potential impacts to the human respiratory 

system, and when considering the adoption of HCl emission 

standards less stringent than the MACT approach would dictate, 

in light of the fact that there can be significant pollutant 

emissions from other emissions points at industrial sites where 

boilers are located. Since EPA cannot quantify with sufficient 

certainty the potential health effects of this complex mixture 

of pollutants at every industrial site in the country at which 

a boiler is located, we are choosing to err on the side of 

protecting public health by not proposing to use the discretion 

offered by section 112(d)(4). 

We further note that there are other adverse environmental 

effects of HCl emissions from boilers. When HCl gas encounters 
137

water in the atmosphere, it forms hydrochloric acid, which can 

contribute to further aquatic and terrestrial acidification, 

ecological impacts that are already causing environmental 

degradation in many areas of the country. Similarly, when HF 

gas encounters water in the atmosphere, it forms hydrofluoric 

acid. We believe that it is reasonable for EPA to decide not to 

use its discretion under section 112(d)(4) to weaken the 

emission standard for HCl (and in turn for HF) from boilers, 

adding to this environmental burden, when it is simultaneously 

investigating ways to reduce environmental degradation from 

acidification (i.e., EPA is currently considering the adoption 

of tighter ambient standards for oxides of sulfur (SOx) and 

oxides of nitrogen (NOx) to reduce environmental acidification).

Lastly, setting MACT standards for HCl (as a surrogate 

for the other HAP acid gases hydrogen fluoride and hydrogen 

cyanide) and PM (as a surrogate for metals including manganese) 

is anticipated to result in significant control for other 

pollutants emitted, most notably SO2 and other non-HAP acid gases 

(e.g., hydrogen bromide), along with condensable PM and will 

likely provide additional control forWe are proposing to set a 

conventional MACT standard for HCl and, for the reasons 

explained elsewhere in today’s notice, are proposing that the 

HCl limit also serve as a surrogate for other acid gas HAP. We 
138

also considered whether it was appropriate to exercise our 

discretionary authority to establish health-based emission 

standards under section 112(d)(4) for HCl and each of the other 

relevant HAP acid gases: chlorine (Cl2), hydrogen fluoride (HF), 

and hydrogen cyanide (HCN)15 (since if it were regulated under 

section 112(d)(4), HCl may no longer be the appropriate 

surrogate for these other HAPs).16

As a general matter, section 112(d) requires MACT standards 

at least as stringent as the MACT floor to be set for all HAP 

emitted from major sources. However, section 112(d)(4) provides 

that for HAP with established health thresholds, the 

Administrator has the discretionary authority to consider such 

health thresholds when establishing emission standards under 

section 112(d). This provision is intended to allow EPA to 

This section sets forth the 

requirements of section 112(d)(4), our analysis of the 

information available to us that informed the decision on 

whether to exercise discretion, questions regarding the 

application of 112(d)(4) and solicitation of comments, and 

explains how this case relates to prior decisions EPA has made 

under section 112(d)(4) with respect to HCl.

 

15 Before considering whether to exercise her discretion under section 112(d)(4) for a particular pollutant, the 

Administrator must first conclude that a health threshold has been established for the pollutant. 16 HCl can serve as a surrogate for the other acid gases in a technology-based MACT standard, because the control 

technology that would be used to control HCl would also reduce the other acid gases. By contrast, HCl would not 

be an appropriate surrogate for a health-based emission standard that is protective against the potential adverse 

health effects from the other acid gases, because these gases (e.g., HCN) can act on biological organisms in a 

different manner than HCl, and each of the acid gases affects human health with a different dose-response 

relationship.
139

establish emission standards other than conventional MACT 

standards, in cases where a less stringent emission standard 

will still ensure that the health threshold will not be 

exceeded, with an ample margin of safety. In order to exercise 

this discretion, EPA must first conclude that the HAP at issue 

has an established health threshold and must then provide for an 

ample margin of safety when considering the health threshold to 

set an emission standard. 

The legislative history of section 112(d)(4) indicates that 

Congress did not intend for this provision to provide a 

mechanism for EPA to delay issuance of emission standards for 

sources of HAPs. Finally, the legislative history also 

indicates that a health-based emission limit under section 

112(d)(4) should be set at the level at which no observable 

effects occur, with an ample margin of safety. S. Rep. 101-228 

at 171-72. 

It is clear the Administrator may exercise her 

discretionary authority under 112(d)(4) only with respect to 

pollutants with an health threshold. Where there is an 

established threshold, the Administrator interprets section 

112(d)(4) to allow her to weigh additional factors, beyond any 

established health threshold, in making a judgment whether to 

set a standard for a specific pollutant based on the threshold, 
140

or instead follow the traditional path of developing a MACT 

standard after determining a MACT floor. In deciding whether to 

exercise her discretion for a threshold pollutant for a given 

source category, the Administrator interprets section 112(d)(4) 

to allow her to take into account factors such as the following: 

the potential for cumulative adverse health effects due to 

concurrent exposure to other HAPs with similar biological 

endpoints, from either the same or other source categories, 

where the concentration of the threshold pollutant emitted from 

the given source category is below the threshold; the potential 

impacts on ecosystems of releases of the pollutant; and 

reductions in criteria pollutant emissions and other co-benefits 

that would be achieved via the MACT standard. Each of these 

factors is directly relevant to the health and environmental 

outcomes at which section 112 of the Clean Air Act is 

fundamentally aimed. If the Administrator does determine that 

it is appropriate to set a standard based on a health threshold, 

she must develop emission standards that will ensure the public 

will not be exposed to levels of the pertinent HAP in excess of 

the health threshold, with an ample margin of safety. 

EPA has exercised its discretionary authority under section 

112(d)(4) in a handful of prior actions setting emissions 

standards for other major source categories, including the 
141

emissions standards issued in 2004 for commercial and industrial 

boilers and process heaters, which were vacated on other grounds 

by the U.S. Court of Appeals for the D.C. Circuit. In both the 

Pulp and Paper MACT, 63 Fed. Reg. at 18765 (April 15, 1998), and 

Lime Manufacturing MACT, 67 Fed. Reg. at 78054 (December 20, 

2002), EPA invoked 112(d)(4) for HCl emissions for discrete 

units within the facility. In those actions, EPA concluded that 

HCl had an established health threshold (in those cases it was 

interpreted as the reference concentration for chronic effects, 

or RfC) and was not classified as a human carcinogen. In light 

of the absence of evidence of carcinogenic risk, the 

availability of information on non-carcinogenic effects, and the 

limited potential health risk associated with the discrete units 

being regulated, EPA concluded that it was appropriate to 

exercise its discretion under § 112(d)(4) for HCl under the 

circumstances of those actions. EPA did not set an emission 

standard based on the health threshold; rather, the exercise of 

EPA’s discretion in those cases in effect exempted HCl from the 

MACT requirement. In a more recent action, EPA decided not to 

propose a health-based emission standard for HCl emissions under 

section 112(d)(4) for Portland Cement facilities, 74 Fed. Reg. 
142

at 21154 (May 6, 2009). EPA has never implemented a NESHAP that 

used section 112(d)(4) with respect to HF, Cl2 or HCN.17

Since any emission standard under section 112(d)(4) must 

consider the established health threshold level, with an ample 

margin of safety, in this rulemaking EPA has considered the 

adverse health effects of the HAP acid gases, beginning with 

HCl. Research indicates that HCl is associated with chronic 

respiratory toxicity. In the case of HCl, this means that 

chronic inhalation of HCl can cause tissue damage in humans. 

Among other things, it is corrosive to mucous membranes and can 

cause damage to eyes, nose, throat, and the upper respiratory 

tract as well as pulmonary edema, bronchitis, gastritis, and 

dermatitis. Considering this respiratory toxicity, EPA has 

established a chronic reference concentration (RfC) for the 

inhalation of HCl of 20 μg/m3. An RfC is defined as an estimate 

(with uncertainty spanning perhaps an order of magnitude) of a 

continuous inhalation exposure to the human population 

(including sensitive subgroups

 

18

 

17 EPA has not classified HF, chlorine gas, or HCN with respect to carcinogenicity. However, at this time the 

Agency is not aware of any data that would suggest any of these HAPs are carcinogens.

) that is likely to be without an 

appreciable risk of deleterious effects during a lifetime. The 

development of the RfC for HCl reflected data only on its 

chronic respiratory toxicity. It did not take into account 

18 “Sensitive subgroups” may refer to particular life stages, such as children or the elderly, or to those with particular 

medical conditions, such as asthmatics.
143

effects associated with acute exposure,19

With respect to the potential health effects of HCl, we 

know the following:

and, in this situation, 

the IRIS health assessment did not evaluate the potential 

carcinogenicity of HCl (on which there are very limited 

studies). As a reference value for a single pollutant, the RfC 

also did not reflect any potential cumulative or synergistic 

effects of an individual’s exposure to multiple HAPs or to a 

combination of HAPs and criteria pollutants. As the RfC 

calculation focused on health effects, it did not take into 

account the potential environmental impacts of HCl. 

1. Chronic exposure to concentrations at or below the RfC 

is not expected to cause chronic respiratory effects; 

2. Little research has been conducted on its 

carcinogenicity. The one occupational study of which 

we are aware found no evidence of carcinogenicity;

3. There is a significant body of scientific literature 

addressing the health effects of acute exposure to HCl 

(California Office of Health Hazard Assessment, 2008. 

Acute Toxicity Summary for Hydrogen Chloride, 

http://www.oehha.ca.gov/air/hot_spots/2008/AppendixD2_

 

19 California EPA considered acute toxicity and established a 1-hour reference exposure level (REL) of 2.1 mg/m3

. 

An REL is the concentration level at or below which no adverse health effects are anticipated for a specified 

exposure duration. RELs are designed to protect the most sensitive individuals in the population by the inclusion of 

margins of safety. 
144

final.pdf#page=112 EPA, 2001). However, we currently 

lack information on the peak short-term emissions of 

HCl from boilers, which might allow us to determine 

whether a chronic health-based emission standard for 

HCl would ensure that acute exposures will not pose 

any health concerns;

4. We are aware of no studies explicitly addressing the 

toxicity of mixtures of HCl with other respiratory 

irritants. However, many of the other HAPs (and 

criteria pollutants) emitted by boilers also are 

respiratory irritants, and in the absence of 

information on interactions, EPA assumes an additive 

cumulative effect (Supplementary Guidance for 

Conducting Health Risk Assessment of Chemical 

Mixtures. 

http://cfpub.epa.gov/ncea/cfm/recordisplay.cfm?deid=20

533). The fact that boilers can be located among a 

wide variety of industrial facilities makes predicting 

and assessing all possible mixtures of HCl and other 

emitted air pollutants difficult, if not impossible.

In addition to potential health impacts, the Administrator 

also has evaluated the potential for environmental impacts when 

considering whether to exercise her discretion under section 
145

112(d)(4). The legislative history states that employing a 

section 112(d)(4) standard rather than a conventional MACT 

standard “shall not result in adverse environmental effects 

which would otherwise be reduced or eliminated.” S. Rep. 101-

228 at 171. When HCl gas encounters water in the atmosphere, it 

forms an acidic solution of hydrochloric acid. In areas where 

the deposition of acids derived from emissions of sulfur and 

nitrogen oxides are causing aquatic and/or terrestrial 

acidification, with accompanying ecological impacts, the 

deposition of hydrochloric acid could exacerbate these impacts. 

Being mindful of the legislative history, it is appropriate to 

consider potential adverse environmental effects in addition to 

adverse health effects when setting an emission standard for HCl 

under section 112(d)(4). 

Because the statute requires an ample margin of safety, it 

would be reasonable to set any section 112(d)(4) emission 

standard for a pollutant with a health threshold at a level that 

at least assures that, for the sources in the controlled 

category or subcategory, persons exposed to emissions of the 

pollutant would not experience the adverse health effects on 

which the threshold is based. In the case of this proposed 

rulemaking, we have concluded that we do not have sufficient 

information at this time to establish what the health-based 
146

emission standards would be for HCl or the other acid gases. 

Public comments are invited on our information and conclusion.

When Congress established the technology-based MACT program 

in the 1990 Clean Air Act Amendments, it recognized the 

challenges involved in evaluating health risk. Determining an 

emission standard that will protect the public health with an 

ample margin of safety is complex, in part because of the 

limited data available on cumulative impacts. In order to 

assess the feasibility of health-based standards in this rule, 

the agency believes it would need additional facility-specific 

emissions information. Such information would enable us to

develop model plants for the eleven subcategories considered in 

the proposed rule and allow us to conduct the dispersion 

modeling necessary to establish health-based emission limits. 

These limits would need to be established to ensure that 

exposure is below the health threshold for sources in the 

subcategory, and account for the possibility of multiple 

exposures from co-located sources as well as potential shortterm increases in emissions for these sources and their shortterm impacts. Currently, the Agency has very limited 

information on facility-specific emissions, plant 

configurations, and overall fence-line characteristics for this 

large and diverse source category. This information is a 
147

precondition to establishing health-based emission standards 

that provide an ample margin of safety. To this end, the Agency 

is requesting information on these factors from the regulated 

community and others to allow us to evaluate the appropriateness 

and viability of health-based emission limits. 

EPA specifically requests comment on the following issues. 

Additional information on these issues is important to implement 

section 112(d)(4) in a reasonable and appropriate manner, if we 

were to establish emissions standards under that provision. 

First, EPA requests comment on whether it would be appropriate 

to establish section 112(d)(4) standards for each acid gas 

described above, or whether EPA could set a single 112(d)(4) 

standard for one of the acid gases as a surrogate for the other 

acid gases. Commenters who believe a surrogate would be 

appropriate should also address the mechanism that should be 

used to determine the appropriate surrogate. In order to set 

individual standards under section 112(d)(4) for each acid gas, 

we would need to be able to conclude that each has an 

appropriate health threshold, that there is no scientific 

evidence that they are carcinogenic, and that the emission 

standard for each uses the best available science to consider 

the possibility of toxicologic interactions with the other 

emitted gases. Alternatively, if we were to establish a health-
148

based emission standard for one of the acid gases as a surrogate 

for the others, in addition to the above considerations, we 

would need to demonstrate, based on a knowledge of the 

effectiveness of scrubbers for controlling each of the acid 

gases, that the surrogate emission standard effectively ensures 

that ambient levels of each of the other acid gases do not 

exceed their respective chronic health thresholds.

EPA also solicits comments on whether there would be an 

additive effect if individual section 112(d)(4) standards are 

established for each acid gas, and if so, how we would simulate 

that effect. Individual acid gas standards under section 

112(d)(4) would likely be established using the hazard quotient 

(HQ) approach, under which we would develop the ratio of the 

maximum ambient level to the chronic threshold. However, this 

approach would not by itself account for potential toxicologic 

interactions. Since all of the acid gases are respiratory 

irritants, one way to account for potential toxicologic 

interactions of these pollutants would be the use of the hazard 

index (HI) approach, as described in EPA’s “Guideline for the 

Health Risk Assessment of Chemical Mixtures.” EPA requests 

comment on that approach, and on whether there are any other 

approaches to address such additive effects. 
149

Additionally, EPA requests comment on whether we should 

consider the affected sources (boilers) by themselves, or 

whether we should consider all HAP emissions at the facility 

when developing a 112(d)(4) standard. Given that section 

112(d)(4) requires an “ample margin of safety,” EPA believes it 

should consider all reasonable circumstances in order to ensure 

such a margin. Since boilers are, in many cases, located at

industrial sites with significant additional sources of HAP 

(e.g., petroleum refineries, furniture manufacturers, etc.), EPA 

requests comment on how we should consider the potential 

interactions of acid gases with other emitted respiratory 

irritants at these locations if we were to develop emission 

limits under section 112(d)(4). Commenters are requested to 

provide any actual data that is available to make this type of 

demonstration. If no data are available, we request comment on 

whether such a demonstration could be made using a bounding 

calculation.

EPA also requests comment on whether we should consider HAP 

emissions from neighboring facilities, and, if so, what the 

geographic scope of such consideration should be (e.g., 1 km, 3 

km, etc.). We note that consideration of emissions from nearby 

facilities is a more difficult task than consideration of 

facility-wide emissions, since it requires information on all 
150

potential HAP emissions near all of the locations with boilers. 

Therefore, we request comment on whether such emissions should 

be considered in setting section 112(d)(4) emissions standards, 

and if so, how they should be considered. For example, the 

consideration could be limited in geographic scope (e.g., a 

radius of 3 km), or could be based on “average” or “high-end” 

ambient levels of respiratory irritants seen in recent 

monitoring data or modeled estimates, since site-specific data 

might not be available on all respiratory irritants.

Further, EPA requests comment on how to appropriately 

simulate all reasonable facility/exposure situations (e.g., 

using worst-case facility emissions coupled with worst-case 

population proximity, average emissions and population, or 90th 

percentile emissions and population). Such a simulation could 

be based on a sequential examination of the facilities with the 

highest-emitting boilers on-site using site-specific data, or it 

could use screening or bounding methodologies with high-end or 

worst-case exposure assumptions to remove facilities from a more 

site-specific examination. We request comment on these and 

other approaches.

Finally, we considered the fact that setting conventional 

MACT standards for HCl as well as PM (as a surrogate for metals 

including manganese) would result in significant reductions in 

Formatted: Indent: First line: 0.5"
151

emissions of other pollutants, most notably SO2, non-condensable 

PM, and other non-HAP acid gases (e.g., hydrogen bromide) and 

would likely also result in additional reductions in emissions 

of mercury and other HAP metals (e.g., selenium). The 

additional reductions of SO2 alone attributable to the proposed 

MACT standard for HCl are estimated to be 400340,000 tons per 

year in the third year following promulgation of the proposed 

HCl standard. These are substantial reductions with substantial 

public health benefits. Although MACT standards may only 

directly address HAPonly HAPs, not criteria pollutants, Congress 

fully expected did recognize, in the legislative history to 

section 112(d)(4), that MACT standards towould have the 

collateral benefit of controlling criteria pollutants as well,

and viewed this as an important benefit of the air toxics 

program.20

Although we are not proposing this approach for the 

reasons discussed above, we request comment on a health-based 

compliance alternative for HCl and/or manganese and other 

 It, therefore, is appropriate that EPA Therefore, 

even where EPA concludes a HAP has a health threshold, the 

Agency may consider such benefits as a factor in determining 

whether to exercise its discretionary CAAdiscretion under

section 112 (d)(4) authority.).

 

20 See S. Rep. No. 101-228, 101st Cong. 1st sess. At 172
152

information on HCl and manganese health and environmental 

effects we should consider. Commenters should also address the 

issue of other environmental benefits which might result from 

control of HCl and manganese at MACT levels, including control 

of other acid gases and metals and control of secondary PM 

(i.e., PM condensing from acid gases). We will consider these 

comments in making an ultimate determination as to whether to 

adopt a health-based compliance alternatives for HCl or

manganese.

Given the limitations of the currently available 

information (i.e., the HAP mix where boilers are located, and 

the cumulative health impacts from co-located sources), the 

environmental effects of HCl, and the significant co-benefits of 

setting a conventional MACT standard for HCl, the Administrator 

is proposing not to exercise her discretion to use section 

112(d)(4). 

This conclusion is not contrary to EPA’s prior decisions 

where we found it appropriate to exercise the discretion to 

invoke the authority in section 112(d)(4) for HCl, since the 

circumstances in this case differ from previous considerations. 

Boilers and process heaters differ from the other source 

categories for which EPA has exercised its authority under 

section 112(d)(4) in ways that affect consideration of any 
153

health threshold for HCl. Commercial and industrial boilers and 

process heaters are much more likely to be co-located with 

multiple other sources of HAPs than are pulp and paper mills and 

lime manufacturing facilities. In addition, boilers and process 

heaters are often located at facilities in heavily populated 

urban areas where many other sources of HAPs exist. These 

factors make an analysis of the health impact of emissions from 

these sources on the exposed population significantly more 

complex than for many other source categories, and therefore 

make it more difficult to establish an ample margin of safety. 

Given the particular complexities of this source category 

(the location of boilers and process heaters near other 

significant sources of HAP emissions and the use of HCl as a 

surrogate for other HAPs), we solicit comment on all of the 

conclusions in this section, including the way the agency has 

used 112(d)(4) previously, and in particular whether it would be 

feasible and appropriate to establish such a standard and, if 

so, the methodology by which it could be established.

K. How did we select the compliance requirements?

We are proposing testing, monitoring, notification, and 

recordkeeping requirements that are adequate to assure 

continuous compliance with the requirement of this proposed

rule. These requirements are described in detail in sections 
154

IV.K to IV.N. We selected these requirements based upon our 

determination of the information necessary to ensure that the 

emission standards and work practices are being followed and 

that emission control devices and equipment are maintained and 

operated properly. These proposed requirements ensure 

compliance with this proposed rule without imposing a 

significant additional burden for facilities that must implement 

them.

We are proposing that compliance with the emission limits 

for PM, HCl, mercury, CO, and D/F be demonstrated by an initial 

performance test. To ensure continuous compliance with the 

proposed PM, HCl, and mercury emission limits, this proposed 

rule would require continuous parameter monitoring of control 

devices and recordkeeping. Additionally, this proposed rule 

would require 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 and/or HCl emission limits are

demonstrated by a fuel analysis performance test, this proposed 

rule would require fuel analyses monthly, with compliance 

determined based on an annual average.

We evaluated the feasibility and cost of applying PM CEMS 

to boilers and process heaters. CEMS have been used in Europe 
155

to monitor PM emissions from a variety of industrial sources. 

Several electric utility companies in the United States have now 

installed or are planning to install PM CEMS. In recognition of 

the fact that PM CEMS are commercially available, EPA developed 

and promulgated Performance Specifications (PS) for PM CEMS (69 

FR 1786, January 12, 2004). PS for PM CEMS are established 

under PS-11 in appendix B to 40 CFR part 60 for evaluating the 

acceptability of a PM CEM used for determining compliance with 

the emission standards on a continuous basis. 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. We 

determined that requiring PM CEMS for units with heat input 

capacity greater or equal to 250 MMBtu/hr and combusting either 

coal, biomass, or oil is a reasonable monitoring option. We are 

requesting comment on the application of PM CEMS to boilers and 

process heaters, and the use of data from such systems for 

compliance determinations under this proposed rule.

We reviewed cost information for CO CEMS to make the 

determination on whether to require CO CEMS or conducting annual 

THCCO testing to demonstrate continuous compliance with the 

THCCO 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 
156

reasonable. This proposed rule would require units with heat 

input capacities less than 100 MMBtu/hr to conduct initial and 

annual performance (stack) tests. 

The majority of test methods that this proposed rule would 

require for the performance stack tests have been required under 

many other EPA standards. The only applicable voluntary 

consensus standard identified is ASTM Method D6784-02 (Ontario 

Hydro). The majority of emissions tests upon which the proposed 

emission limits are based were conducted using these test 

methods.

When a performance test is conducted, we are proposing that 

parameter operating limits be determined during the tests. 

Performance tests to demonstrate compliance with any applicable 

emission limits are either stack tests or fuel analysis or a 

combination of both.

To ensure continuous compliance with the proposed emission 

limits and/or operating limits, this proposed rule would require 

continuous parameter monitoring of control devices and 

recordkeeping. We selected the following requirements based on 

reasonable cost, ease of execution, and usefulness of the 

resulting data to both the owners or operators and EPA for 

ensuring continuous compliance with the emission limits and/or

operating limits.
157

We are proposing that certain parameters be continuously 

monitored for the types of control devices commonly used in the 

industry. These parameters include opacity monitoring except 

for wet scrubbers; pH, pressure drop and liquid flowrate for wet 

scrubbers; and sorbent injection rate for dry scrubbers. You 

must also install a bag leak detection system for fabric 

filters. If you cannot monitor opacity for control systems with 

an ESP then you must monitor the secondary current and voltage 

or total power input for the ESP. These monitoring parameters 

have been used in other standards for similar industries. The 

values of these parameters are established during the initial or 

most recent performance test that demonstrates compliance. 

These values are your operating limits for the control device.

You would be required to set parameters based on 4-hour 

block averages during the compliance test, and demonstrate 

continuous compliance by monitoring 12-hour block average values 

for most parameters. We selected this averaging period to 

reflect operating conditions during the performance test to 

ensure the control system is continuously operating at the same 

or better level as during a performance test demonstrating 

compliance with the emission limits.

To demonstrate continuous compliance with the emission and 

operating limits, you would also need daily records of the 
158

quantity, type, and origin of each fuel burned and hours of 

operation of the affected source. If you are complying with the 

chlorine fuel input option, you must keep records of the 

calculations supporting your determination of the chlorine 

content in the fuel.

If a source elected to demonstrate compliance with the HCl

or mercury limit by using fuel which has a statistically lower

pollutant content than the emission limit, we are proposing that 

the source’s operating limit is the emission limit of the 

applicable pollutant. Under this option, a source is not 

required to conduct performance stack tests. If a source

demonstrates compliance with the HCl or mercury limit by using 

fuel with a statistically higher pollutant content than the 

applicable emission limit, but performance tests demonstrate 

that the source can meet the emission limits, then the source’s 

operating limits are the operating limits of the control device 

(if used) and the fuel pollutant content of the fuel 

type/mixture burned.

This proposed rule would specify the testing methodology 

and procedures and the initial and continuous compliance

requirements to be used when complying with the fuel analysis

options. Fuel analysis tests for total chloride, gross 
159

calorific value, mercury, sample collection, and sample 

preparation are included in this proposed rule.

If you elect to comply based on fuel analysis, you will be

required to statistically analyze, using the z-test, the data to

determine the 90th percentile confidence level. It is the 90th

percentile confidence level that is required to be used to 

determine compliance with the applicable emission limit. The 

statistical approach is required to assist in ensuring

continuous compliance by statistically accounting for the 

inherent variability in the fuel type.

We are proposing that a source be required to recalculate 

the fuel pollutant content only if it burns a new fuel type or 

fuel mixture and conduct another performance test if the results 

of recalculating the fuel pollutant content are higher than the 

level established during the initial performance test.

For boilers and process heaters with heat input capacities 

greater or equal to 100 MMBtu/hr, we are proposing that CO be 

continuously monitored to demonstrate that average CO emissions, 

on a 30-day rolling average, are at or below the proposed CO

limit.

For boilers and process heaters with heat input capacities 

between 10 and 100 MMBtu/hr, we are proposing that a performance 
160

stack test of CO emissions be conducted to demonstrate 

compliance with the CO emission limit.

L. What alternative compliance provisions are being proposed?

We are proposing that owners and operators of existing 

affected sources may demonstrate compliance by emissions 

averaging for units at the affected source that are within the 

samea single subcategory.

As part of the EPA’s general policy of encouraging the use 

of flexible compliance approaches where they can be properly 

monitored and enforced, we are including emissions averaging in 

this proposed rule. Emissions averaging can provide sources the 

flexibility to comply in the least costly manner while still

maintaining regulation that is workable and enforceable. 

Emissions averaging would not be applicable to new sources and 

could only be used between boilers and process heaters in the 

same subcategory. at a particular affected source. Also, owners 

or operators of existing sources subject to the Industrial 

Boiler NSPS (40 CFR part 60, subparts Db and Dc) would be

required to continue to meet the PM emission standard of that 

NSPS regardless of whether or not they are using emissions 

averaging.

Emissions averaging would allow owners and operators of an 

affected source to demonstrate that the source complies with the 
161

proposed emission limits by averaging the emissions from an 

individual affected unit that is emitting above the proposed

emission limits to comply with the emission limits by averaging 

its emissions with other affected units at the same facility 

that are emitting below the proposed emission limits.

This proposed rule would includeincludes an emissions 

averaging compliance alternative because emissions averaging

represents an equivalent, more flexible, and less costly 

alternative to controlling certain emission points to MACT 

levels. We have concluded that a limited form of averaging 

could be implemented andthat would not lessen the stringency of 

the standardMACT floor limits and would provide flexibility in

compliance, cost and energy savings to owners and operators. We 

also recognize that we must ensure that any emissions averaging 

option can be implemented and enforced, will be clear to 

sources, and most importantly, will achievebe no less emissions 

reductionsstringent than unit by unit implementation of the MACT 

requirementsfloor limits.

This proposed rule would not be the first NESHAP to include 

provisions permitting emission averaging. In general, EPA 

has concluded that it is permissible to establish within a 

NESHAP a unified compliance regimen that permits averaging 

within an affected source across individual affected units 
162

subject to the standard under certain conditions. Averaging 

across affected units is permitted only if it can be 

demonstrated that the total quantity of any particular HAP that 

may be emitted by that portion of a contiguous major source that 

is subject to the NESHAP will not be greater under the averaging 

mechanism than it could be if each individual affected unit 

complied separately with the applicable standard. Under this

test, the practical outcome of averaging is equivalent to 

compliance with the MACT floor limits by theeach discrete 

unitsunit, and the statutory policy embodied in the MACT floor 

provisionsrequirement that the MACT standard reflect the maximum 

achievable emissions reductions is, therefore, fully 

effectuated.

In past rulemakings, EPA has generally imposed certain 

limits on the scope and nature of emissions averaging programs. 

These limits include: (1) No averaging between different types 

of pollutants, (2) no averaging between sources that are not

part of the same majoraffected source, (3) no averaging between 

individual sources within the samea single major source thatif 

the individual sources are not subject to the same NESHAP, and 

(4) no averaging between existing sources and new sources.

This proposed rule would fully satisfy each of these 

criteria. First, emissions averaging would only be permitted 
163

between individual sources at a single existing affected source, 

and would only be permitted between individual sources subject 

to the boiler and process heater NESHAP. Further, emissions 

averaging would not be permitted between two or more different 

affected sources. Finally, new sources could not use emissions 

averaging. Accordingly, we have concluded that the averaging of

emissions across affected units is consistent with the CAA. In 

addition, the provision in this proposed rule would require each 

facility that intends to utilize emission averaging to submit an

emission averaging plan, which provides additional assurance 

that the necessary criteria will be followed. In this emission 

averaging plan, the facility must include the identification of 

(1) all units in the averaging group, (2) the control technology 

installed, (3) the process parameter that will be

monitored, (4) the specific control technology or pollution 

prevention measure to be used, (5) the test plan for the 

measurement of the HAP being averaged, and (6) the operating

parameters to be monitored for each control device. Upon

receipt, the regulatory authority willwould not be able to

approve an emission averaging plan containing averaging between 

emissions of different types of pollutants or between sources in 

different subcategories.
164

This proposed rule would also exclude new affected sources 

from the emissions averaging provision. New sources have

historically been held to a stricter standard than existing EPA 

believes emissions averaging is not appropriate for new sources 

because it is most cost effective to integrate state-of-the-art 

controls into equipment design and to install the technology

during construction of new sources. One reason we allow 

emissions averaging is to give existing sources flexibility to

achieve compliance at diverse points with varying degrees of 

add-on control already in place in the most cost-effective and 

technically reasonable fashion. This concern doesflexibility is

not apply toneeded for new sources whichbecause they can be 

designed and constructed with compliance in mind.

With concern about the equivalency of emissions reductions 

from averaging and non-averaging in mind, we are also proposing

under the emission averaging provision caps on the current 

emissions from each of the sources in the averaging group. The

emissions for each unit in the averaging group would be capped 

at the emission level being achieved on the effective date of 

the final rule. These caps would ensure that emissions do not 

increase above the emission levels that sources currently are 

designed, operated, and maintained to achieve. In the absence 

of performance tests, in documenting these caps, these sources 
165

will document the type, design, and operating specification of 

control devices installed on the effective date of the final 

rule to ensure that existing controls are not removed or

lessen.operated less efficiently. By including this provision 

in this proposed rule, we have taken yet another step to assist 

in ensuringwould further ensure that emission averaging results

in environmental benefits equivalent to or better over what 

would have happenedthan without emission averaging.

In addition, we are proposing that a discount factor of ten 

percent would be applied when emissions averaging is used. This 

discount factor will further ensure that averaging will be at 

least as stringent as the MACT floor limits in the absence of 

averaging. The EPA is soliciting comment on use of a discount 

factor and whether ten percent is the appropriate discount 

factor. The emissions averaging provision would not apply to 

individual units if the unit shares a common stack with units in 

other subcategories, because in that circumstance it is not 

possible to distinguish the emissions from each individual unit.

The emissions averaging provisions in this proposed rule 

are based in part on the emissions averaging provisions in the 

Hazardous Organic NESHAP (HON). The legal basis and rational 

for the HON emissions averaging provisions were provided in the 

preamble to the final HON (59 FR 19425, April 22, 1994).
166

M. How did EPA determine compliance times for the proposed 

rule?

Section 112 of the CAA specifies the dates by which 

affected sources must comply with the emission standards. New 

or reconstructed units must be in compliance with this proposed 

rule immediately upon startup or [DATE THE FINAL RULE IS 

PUBLISHED IN THE FEDERAL REGISTER], whichever is later. 

Existing sources are allowed 3 years to comply with the final 

rule. This is the maximum period allowed by the CAA. We 

believe that 3 years for compliance is necessary to allow 

adequate time to design, install and test control systems that 

will be retrofitted onto existing boilers, as well as obtain 

permits for the use of add-on controls.

N. How did EPA determine the required records and reports for 

this proposed rule?

You would be required to comply with the applicable 

requirements in the NESHAP General Provisions, subpart A of 40 

CFR part 63, as described in Table 10 of the proposed subpart 

DDDDD. We evaluated the General Provisions requirements and 

included those we determined to be the minimum notification, 

recordkeeping, and reporting necessary to ensure compliance 

with, and effective enforcement of, this proposed rule. 
167

We are also requiring that you keep daily records of the 

total fuel use by each affected source, subject to an emission 

limit or work practice standard, along with a description of the 

fuel, the total fuel usage amounts and units of measure, and 

information on the supplier and original source of the fuel. 

This information is necessary to ensure that the affected source 

is complying with the emission limits from the correct 

subcategory.

We would require additional recordkeeping if you chose to 

comply with the chlorine or mercury fuel input option. You 

would need to keep records of the calculations and supporting 

information used to develop the chlorine or mercury fuel input 

operating limit.

O. How does this proposed rule affect permits?

The CAA requires that sources subject to this proposed rule 

be operated pursuant to a permit issued under EPA-approved State 

operating permit program. The operating permit programs are 

developed under title V of the CAA and the implementing 

regulations under 40 CFR parts 70 and 71. If you are operating 

in the first 3 years of your operating permit, you will need to 

obtain a revised permit to incorporate this proposed rule. If 

you are in the last 2 years of your operating permit, you will 
168

need to incorporate this proposed rule into the next renewal of 

your permit.

P. Alternate Standard for Consideration

The As discussed above, EPA is proposing a definition of 

“non-hazardous secondary materials” is being proposed solid 

waste under RCRA in a concurrent notice under RCRA; this RCRA 

proposal also identifies an “alternative approach”. The 

proposed CAA section 112(d) standards for consideration and 

comment. The concurrently boilers and process heaters were 

developed considering that proposed RCRA non-hazardous secondary 

materials definition is integral in defining of solid waste. 

Therefore, the ICI boiler and process heater source categories. 

The emission limits presented in Tables 1 through 5 above are 

based on subcategories established considering sources that are 

ICI boilers and process heaters under the “proposed approach” 

definition being proposed concurrentlyof solid waste under RCRA. 

The “However, the RCRA proposal also identifies and solicits 

comment on an alternative approach for defining solid waste, 

under which more units would be considered solid waste 

incineration units than under the proposed definition. As such, 

the alternative approach” identified for consideration and 

comment in the concurrently proposed RCRA notice for defining 

solid waste under RCRA would result in a different, smaller
169

population of units being covered by Boiler MACT. We 

Consistent with EPA’s solicitation of comment on an alternative 

proposed definition of solid waste under RCRA, we calculated 

MACT floors using emission rates for units that would be ICI 

boilers and process heaters under the “that alternative 

approach” anddefinition, using the same statistical procedures 

previously described.that were used to calculate the standards 

that are being proposed. Table 6 reflects the potentialthat 

calculation of MACT floor limits for the existing source 

subcategories that would be affected consideringchanged by the 

“alternative approach” definition of solid waste identified in 

the concurrent RCRA proposal, compared to the proposed 

definition of solid waste in that proposal. The MACT floor 

limits for the remaining existing source subcategories (Gas 1, 

Gas 2, and Liquid) would not change under the “alternative 

approach” identified for consideration anddefinition of solid 

waste on which EPA is soliciting comment in athe concurrent RCRA 

proposal under RCRA , and are reflectedtherefore not included in 

Table 1 of today’s notice8 because the MACT floor limits for 

those subcategories would be the same under the alternative 

definition of solid waste as under the proposed definition.

TABLE 6.8. EXISTING MACT FLOOR LIMITS USING THE “ALTERNATIVE 

APPROACH” UNDER CONSIDERATION AND COMMENT IN THE CONCURRENTLY 

PROPOSED RCRA RULE

(pounds per million British thermal units)

Formatted: Font: Not Bold

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170

Subcategory Particulate 

Matter (PM)

Hydrogen 

Chloride 

(HCl)

Mercury

(Hg)

Carbon 

Monoxide(CO)

(ppm

@3%oxygen)

Dioxins/

Furans

(Total TEQ)

(ng/dscm) @ 7%O2

Existing –

Coal Stoker 

0.0203 0.00802 0.000003

4.0E-06

3040 0.0029003

Existing -

Coal 

Fluidized 

Bed

0.0203 0.00802 0.000003

4.0E-06

4050 0.0073008

Existing –

Pulverized 

Coal

0.0203 0.00802 0.000003

4.0E-06

7090 0.0038004

Existing –

Biomass 

Stoker 

0.02 0.03 0.000000

45.0E-07

540180 0.00004900005

Existing -

Biomass 

Fluidized 

Bed

0.02 0.03 0.000000

45.0E-07

10,650 0.0931

Existing –

Biomass 

Suspension 

Burner/Dutc

h Oven

0.02 0.03 0.000000

45.0E-07

1,430060 0.613

Existing –

Biomass 

Fuel Cells

0.02 0.03 0.000000

45.0E-07

460 0.06202

Exist

ing – Metal 

Industry 

Process 

Heaters

-- -- -- -- --

Comparing the emissions limits in Table 1 (based on the 

proposed definition of solid waste) with those in Table 6 (8

(based on the alternative approachdefinition of solid waste), 

the MACT emission limits for PM and mercury for the biomass 

subcategories would be less stringent if they are higher 
171

underbased on the “alternative approach”definition of solid 

waste while the HCl emission limits for the coal and biomass 

subcategories are would be more stringent underif they are based 

on the “alternative approach.”definition.

The potential emissions reductions if the MACT floor limits 

are calculated based on this “the alternative approach” are 

definition of solid waste would be generally lower due to 

281than the potential emissions reductions for MACT floors based 

on the proposed definition of solid waste, because 280 fewer 

boilers and process heaters that would be considered CISWI 

unitssubject to the boiler and process heater MACT standards

under the “alternative approach.”definition. These units would 

instead be considered CISWI units under the alternative 

definition of solid waste. For example, mercury emissions 

reduction would be 177 tons per year instead of 19based on the 

alternative definition of solid waste (compared to 8 tons per 

year based on the proposed definition) and HCl emissions 

reduction would be 445,100 tons per year based on the 

alternative definition (compared to 37,000 tons per year instead 

of 47,000 tons per year.based on the proposed definition). Most 

(181) of the 281 units280 units that would be considered CISWI 

units under the alternative definition of solid waste proposed 

under RCRA are biomass-fired boilers or process heaters, with 
172

the others being in the coal and liquid fuel subcategories. 

The resulting total national cost impact for existing 

boilers and process heaters of the proposed emission limits 

based on the “alternative approach” is 11.3definition of solid 

waste would be 8.0 billion dollars in capital expenditures and 

4.3 billion2.4billion dollars per year in total annual costs. 

This compares to $139.5 billion in capital costs and $5.42.9

billion in annual costs under the “proposed approach”definition 

of solid waste in the RCRA proposed rule. Table 6a9 of this 

preamble shows the capital and annual cost impacts for each 

subcategory under the alternative definition of solid waste. 

Costs include testing and monitoring costs, but not 

recordkeeping and reporting costs.

TABLE 6a.9. SUMMARY OF CAPITAL AND ANNUAL COSTS FOR 

EXISTING SOURCES UNDER THE ALTERNATIVE SOLID WASTE DEFINITION

Source Subcategory Estimated/

Projected 

No. of 

Affected 

Units

Capital 

Costs 

(106$)

Annualized 

Cost 

(106$/yr)

Existing 

Units

Coal units 524525 3,850861 1,484508

Biomass 

units

239 1,324250 359317

Liquid 

units

796791 2,1531,35

2

658417

Gas (NG/RG) 

units

11,402524 2,67475 1,399259

Gas (other) 193196 1,298476 387434

Formatted: Font: 10 pt
173

units

Energy 

AuditAsse

ssment

ALL 1,550551

facilities

24.9

A discussion of the methodology used to estimate cost 

impacts is presented in “Methodology and Results of Estimating 

the Cost of Complying with the Industrial, Commercial, and 

Institutional Boiler and Process Heater NESHAP (2010)” in the 

Docket.

We are also proposingsoliciting public comments on the 

emission limits listed in Table 6 of this preamble as an 

alternate in case public, consistent with EPA’s solicitation of

comments on the alternative definition of solid waste 

concurrently proposed under RCRA rule warrant promulgation of . 

As explained above, the emissionsMACT floor limits proposed 

today are based on the “alternative approach.” Therefore, we 

proposed definition of solid waste under RCRA. However, because 

EPA is seeking comment on an alternative definition of solid 

waste under RCRA, the Agency believes it is necessary to also 

solicit comment on what the emissionsMACT floor limits listed in 

Table 6 of this preamblewould be based on the universe of 

sources that would be subject to the boiler and process heater 

MACT under that alternative definition. 

V. Impacts of the Proposed Rule
174

A. What are the air impacts?

Table 710 of this preamble illustrates, for each basic fuel 

subcategory, the emissions reductions achieved by the proposed 

rule (i.e., the difference in emissions between a boiler or 

process heater controlled to the floor level of control and 

boilers or process heaters at the current baseline) for new and 

existing sources. Nationwide emissions of selected HAP (i.e., 

HCl, HF, mercury, metals, and VOC) will be reduced by 

53,56043,000 tons per year for existing units and 6715 tons per 

year for new units. Emissions of HCl will be reduced by 

4737,000 tons per year for existing units and 529 tons per year 

for new units. Emissions of mercury will be reduced by 198 tons 

per year for existing units and 122.6 pounds per year for new 

units. Emissions of filterable PM will be reduced by 4250,100 

tons per year for existing units and 140130 tons per year 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 3,900200 tons per year 

for existing units and will be reduced by 1,380 pounds0.6 ton

per year for new units. In addition, emissions of SO2 are 

establishedestimated to be reduced by 383,340,000 tons per year 

for existing sources and 500 tons per year for existing sources 

and 550 tons per year for new sources. Emissions of 
175

dioxin/furans, on a total mass basis, will be reduced by 844722

grams per year for existing units and 2 grams1 gram per year for 

new units. A discussion of the methodology used to estimate 

emissions and emissions reductions is presented in “Estimation 

of Baseline Emissions and Emissions Reductions for Industrial, 

Commercial, and Institutional Boilers and Process Heaters 

(2010)” in the docket.

TABLE 7.10. SUMMARY OF EMISSIONS REDUCTIONS FOR EXISTING AND NEW 

SOURCES (TONS/YR)b

Source Subcategory HCl PM Non 

Mercury 

Metalsa

Mercuryb

VOC

Existing 

Units

Coal units 40,6003

5,450

17,000 879770 15,3007

.1

510490

Biomass 

units

1,60052

0

13,7002

2,500

133230 4300.2 334760

Liquid units 4,50084

0

11,3001

0,400

2,90020

0

2040.00

005

325290

Gas 1 

(NG/RG) 

units

479 130 1.2 21,6700

.01

5372

Gas 2 

(other)units

234220 0 0 3370.2 210170

New 

Units

Coal units 0 0 0 0 0

Biomass 

units

0 0 0 0 0

Liquid units 439 130 0.6 100.000

7

3

Gas 1 units 90.01 50.1 0.04001 20.0000

08

10.01

Gas 2 units 1 54 0.0201 10.0006 1
176

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

cobalt, lead, manganese, nickel, and selenium.

b Emission reductions for mercury are presented in units of 

pounds per year.

B. What are the water and solid waste impacts?

The EPA estimated the additional water usage that would 

result from installing wet scrubbers to meet the emission limits 

for HCl would be 3,2002,400 million gallons per year for 

existing sources and 1.2 million200,000 gallons per year for new 

sources. In addition to the increased water usage, an 

additional 944730 million gallons per year of wastewater would 

be produced for existing sources and 790140,000 gallons per year 

for new sources. The annual costs of treating the additional 

wastewater are $5.14.0 million for existing sources and 

$4,300774 for new sources. These costs are accounted for in the 

control costs estimates.

The EPA estimated the additional solid waste that would 

result from the MACT floor level of control to be 25081,000 tons 

per year for existing sources and 3,100149,800 tons per year for 

new sources. Solid waste is generated from flyash and dust 

captured in PM and mercury controls as well as from spent carbon 

that is injected into exhaust streams or used to filter gas 

streams. The costs of handling the additional solid waste 

generated are $10.53.4 million for existing sources and 
177

$130,6006.3 million for new sources. 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 and Process Heaters NESHAP (2010)” in 

the Docket.

C. What are the energy impacts?

The EPA expects an increase of approximately 3,9012.995

million kilowatt hours (kWh) in national annual energy usage as 

a result of the proposed rule. Of this amount, 3,8892,944

million kWh would be from existing sources and 1211 million kWh 

are estimated from new sources. The increase results from the 

electricity required to operate control devices, such as wet 

scrubbers, electrostatic precipitators, and fabric filters which 

are expected to be installed to meet the proposed rule. 

Additionally, the EPA expects work practice standards such as 

boilers tune-ups and combustion controls will improve the 

efficiency of boilers, resulting in an estimated fuel savings of 

4142 trillion BTU each year from existing sources and an 

additional 168100,000 million BTU each year. This fuel savings 

estimatesestimate includes only those fuel savings resulting 

from gas, liquid, and coal fuels and it is based on the 
178

assumption that the work practice standards will achieve 1%

percent improvement in efficiency.

D. What are the control costs?

To estimate the national cost impacts of the proposed rule 

for existing sources, we developed average baseline emission 

factors for each fuel type/control device combination based on 

the emission data obtained and contained in the Boiler MACT 

emission database. If a unit reported emission data, we 

assigned its unit-specific emission data as its baseline 

emissions. For units that did not report emission data, we 

assigned the appropriate emission factors to each existing unit 

in the inventory database, based on the average emission factors 

for boilers with similar fuel, design, and control devices. We 

then compared each unit’s baseline emission factors to the 

proposed MACT floor emission limit to determine if control 

devices were needed to meet the emission limits. The control 

analysis considered fabric filters, carbon bed adsorbers, and 

activated carbon injection to be the primary control devices for 

mercury control, electrostatic precipitators for units meeting 

mercury limits but requiring additional control to meet the PM 

limits, wet scrubbers to meet the HCl limits, tune-ups, 

replacement burners, and combustion controls for CO and organic 

HAP control, and carbon injection for dioxin/furan control. We 
179

identified where one control device could achieve reductions in 

multiple pollutants, for example a fabric filter was expected to 

achieve both PM and mercury control in order to avoid 

overestimating the costs. We also included costs for testing 

and monitoring requirements contained in the proposed rule. The 

resulting total national cost impact of the proposed rule is 

139.5 billion dollars in capital expenditures and 5.43.2 billion

dollars per year in total annual costs. Considering estimated 

fuel savings resulting from work practice standards and 

combustion controls, the total annualized costs are reduced to 

5.12.9 billion. dollars. The total capital and annual costs 

include costs for control devices, work practices, testing and 

monitoring. Table 811 of this preamble shows the capital and 

annual cost impacts for each subcategory. Costs include testing 

and monitoring costs, but not recordkeeping and reporting costs.

TABLE 8.11. SUMMARY OF CAPITAL AND ANNUAL COSTS FOR NEW AND 

EXISTING SOURCES

Source Subcategory Estimated/

Projected 

No. of 

Affected 

Units

Capital 

Costs 

(106$)

Testing 

and 

Monitoring 

Annualized 

Costs

(106$/yr)

Annualized 

Cost 

(106

$/yr))(con

sidering 

fuel 

savings)

Existing 

Units

Coal units 577578 4,542468 62.4 1,665619

Biomass 

units

420 2,646003 35.5 880609

Formatted Table
180

Liquid 

units

831826 2,2451,38

9

27.4 694419

Gas (NG/RG) 

units

11,411532 2,67475 0 1,396(260)

Gas (other) 

units

196199 1,367554 10.4 407459

Energy 

AuditAsse

ssment

ALL 26

New Units Coal units 0 0 0 0

Biomass 

units

0 0 0 0

Liquid 

units

11 12 0.5 5.86.1

Gas (NG/RG) 

units

3233 43.60.2 0 18.90.01

Gas (other) 

units

2 6.35.5 0.14 1.7

Using Department of Energy projections on fuel 

expenditures, the number of additional boilers that could be 

potentially constructed was estimated. The resulting total 

national cost impact of the proposed rule in the 3rd year is 

6217 million dollars in capital expenditures and 26.46.2 million 

dollars per year in total annual costs, when considering a 1 

percent fuel savings. 

Potential control device cost savings and increased 

recordkeeping and reporting costs associated with the emissions 

averaging provisions in the proposed rule are not accounted for

in either the capital or annualized cost estimates.
181

A discussion of the methodology used to estimate cost 

impacts is presented in “Methodology and Results of Estimating 

the Cost of Complying with the Industrial, Commercial, and 

Institutional Boiler and Process Heater NESHAP (2010)” in the 

Docket.

E. 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 about 

0.01 percent. Because of higher domestic prices imports may 

rise by 0.01 percent. In addition, impacts to affected energy 

markets show that prices may rise by 0.204 percent. 

 Social costs are estimated to also be $5.12.9 billion in 

2008 dollars. This is estimated to be made up of a $10.8 

billion loss in domestic consumer surplus, a $3.82.5 billion 

loss in domestic producer surplus, a $0.21 billion increase in 

rest of the world surplus, and a $0.434 billion in net 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 
182

the screening analysis. EPA has prepared an Initial Regulatory 

Flexibility Analysis (IRFA) that discusses alternative 

regulatory or policy options that minimize the rule’s small 

entity impacts. It includes key information about key results 

from the Small Business Advocacy Review (SBAR) panel.

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

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

point estimate of 8,000 less jobs; data is not available to estimate uncertainty ranges. This 

does not include job increases associated with pollutanteffect estimates cannot be 

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

three economic mechanisms by which pollution abatement 

activities that can indirectly influence jobs:

 higher production costs raise market prices, higher 

prices reduce consumption, and employment within an 

industry falls (“demand effect”); 

 pollution abatement activities require additional labor 

services to produce the same level of output or changes related 

to (“cost effect”); and 

 post regulation production technologies. The second approach is 

more comprehensive and looks may be more or less labor intensive 

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

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

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183

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

effect”).

Several empirical studies, including Morgenstern et al. 

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

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

Berman and Bui, 2001). However, statistical others show the question 

has not been resolved in the literature (Henderson, 1996; 

Greenstone, 2002). Morgenstern’s paper uses a six-year panel 

(U.S. Census data for plant-level prices, inputs (including 

labor), outputs, and environmental expenditures) to 

econometrically estimate the production technologies and 

industry-level demand elasticities. Their identification 

strategy leverages repeat plant-level observations over time and 

uses plant-level and year fixed effects (e.g., plant and time 

dummy variables). After estimating their model, Morgenstern 

show and compute the change in employment associated with an 

additional $1 million ($1987) in environmental spending. Their 

estimates covers four manufacturing industries (pulp and paper, 

plastics, petroleum, and steel) and Morgenstern, et al. present 

results separately for the cost, factor shift, and demand 

effects, as well as the net effect. They also estimate and 

report an industry-wide average parameter that combines the four 

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184

industry-wide estimates and weighting them by each industry’s 

share of environmental expenditures. 

EPA has most often estimated employment changes associated 

with plant closures due to environmental regulation or changes 

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

This analysis of the data indicates goes beyond what EPA has typically 

done in two ways. First, because the multimarket model provides 

estimates for changes in output for sectors not directly 

regulated, we were able to estimate a more comprehensive “demand 

effect.” Secondly, parameters estimated in the Morgenstern paper 

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

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

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

“factor-shift effect.” 

We calculated “demand effect” employment changes by 

assuming that we can not state whether the net change will be an increase or a decrease 

the number of jobs changes proportionally with multi-market 

model’s simulated output changes. These results were calculated 

for all sectors in the EPA model that show a change in output. 

The total job losses are estimated to be approximately 6,000.

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 

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185

($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 7,000 jobs (−3.56× $3.5 billion × 0.60)21

We also present the results of using the second 

method.Morgenstern paper to estimate employment “cost” and 

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

Morgenstern parameters to estimate these “cost” and “factorshift” employment changes is uncertain, it is helpful to compare 

the potential job gains from these effects to the job losses 

associated with the “demand” effect. Table 1 shows that using 

the Morgenstern point estimates of parameters to estimate the 

“cost” and “factor shift” employment gains may be greater than 

the employment losses using either of the two ways of estimating 

“demand” employment losses. The 95 percent confidence intervals 

are shown for all of the estimates based on the Morgenstern 

parameters. As shown, at the 95% confidence level, we cannot be 

certain if net employment changes are positive or negative. 

. 

Although the Morgenstern paper provides additional 

information about the potential job effects of environmental 

protection programs, there are several qualifications EPA 

considered as part of the analysis. First, EPA has used the 

 

21 Since Morgenstern’s analysis reports environmental expenditures in $1987, 

we make an inflation adjustment the engineering cost analysis using GDP 

implicit price deflator (64.76/108.48) = 0.60) 

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186

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 
187

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

Morgenstern identifies the industry average as economically and 

statistically insignificant effect (i.e., the point estimates 

are small, measured imprecisely, and not distinguishable from 

zero.) EPA acknowledges this fact and has reported the 95 

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

methodology assumes large plants bear most of the regulatory 

costs. By transferring the estimates, EPA assumes a similar 

distribution of regulatory costs by plant size and that the 

regulatory burden does not disproportionately fall on smaller 

plants.

TABLE 12. Employment Changes: 2013

Estimation Method 1,000 Jobs

Partial equilibrium model (multiple markets) 

(demand effect only)

−5

Literature-based estimate (net effect [A + B 

+C below])

+3

(−6 to +12)

A. Literature-based estimate: Demand 

effect

−7

(−15 to +1)

B. Literature-based estimate: Cost effect +5

(+2 to +8)

C. Literature-based estimate: Factor 

shift effect

+5

(0 to +10)

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

percent confidence intervals for literature-based estimates are 

shown in parenthesis.

F. 

We estimate the monetized benefits of this proposed 

regulatory action to be $1617 billion to $4041 billion (2008$, 3 

Formatted

What are the social costs and benefits of this proposed rule?
188

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

monetized benefits of the proposed regulatory action at a 7 

percent discount rate are $15 billion to $3637 billion (2008$). 

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.22

TABLE 9.13. Summary of the Monetized Benefits Estimates for the 

Proposed Boiler MACT for Major Sources in 2013 (billions of 

2008$)1

 A summary of the monetized 

benefits estimates at discount rates of 3 percent and 7 percent 

is in Table 913 of this preamble. 

Estimated 

Emission 

reductions

(tons per year)

Total 

monetized 

benefits

(3% Discount 

Rate)

Total 

monetized 

benefits

(7% Discount 

Rate)

PM2.5

22,662 tons PM2.5

384,024 tons SO2

1,436 tons 

VOC29,020

$166.6 to 

$4016

$156.0 to 

$3615

PM2.5 Precursors

SO2 339,996 $10 to $25 $9.1 to $22

VOC 1,786 $0.002 to 

$0.005

$0.002 to 

$0.005

Total $17 to $41 $15 to $37 1

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

rounded to two significant figures so numbers may not sum across 

rows. All fine particles are assumed to have equivalent health 

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

precursors because each ton of precursor reduced has a different 

 

22 Roman et al, 2008. Expert Judgment Assessment of the Mortality Impact of 

Changes in Ambient Fine Particulate Matter in the U.S. Environ. Sci. 

Technol., 42, 7, 2268 – 2274.

Formatted Table

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189

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

pollutants (HAPs) 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 of human health benefits 

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

utilized the general approach and methodology on the laid out in 

Fann et al. (2009)23

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 

. 

 

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

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

reducing a ton of air pollution..” Air Qual Atmos Health (2009) 2:169–176.
190

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

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

health benefits would be lower. 

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 study24 and the extended Six Cities cohort study25

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 

. 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.

 

24 Pope et al, 2002. “Lung Cancer, Cardiopulmonary Mortality, and Long-term 

Exposure to Fine Particulate Air Pollution.” Journal of the American Medical 

Association 287:1132-1141 25 Laden et al, 2006. “Reduction in Fine Particulate Air Pollution and 

Mortality.” American Journal of Respiratory and Critical Care Medicine. 

173: 667-672

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191

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

analysis26

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 360330,000 tons of carbon monoxide, 19 tons of mercury, 

4737,000 tons of HCl, and 1,000 tons of HF each year, 7.5 tons 

of mercury, 3,200 tons of HFother metals, and 720 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.

provides an indication of the sensitivity of our 

results to various assumptions. 

The social costs of this proposed rulemaking are estimated 

to be $5.12.9 billion (2008$) in the implementation year, and 

the monetized benefits are $1617 billion to $4041 billion 

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

 

26 U.S. Environmental Protection Agency, 2006. Final Regulatory Impact 

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

Available on the Internet at http://www.epa.gov/ttn/ecas/ria.html
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benefits at a 7 percent discount rate are $15 billion to $3637

billion (2008$). Thus, net benefits of this rulemaking are 

estimated at $1114 billion to $3538 billion (2008$, 3 percent 

discount rate) and $9.812 billion to $3134 billion (2008$, 7 

percent discount rate). EPA believes that the benefits of the 

proposed rule are likely to exceed the costs even when taking 

into account the uncertainties in the cost and benefit 

estimates. A summary of the monetized benefits, social costs, 

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

in Table 14 of this preamble. 

TABLE 14. Summary of the Monetized Benefits, Social Costs, and 

Net Benefits for the Boiler MACT (Major Sources) in 2013 

(millions of 2008$)1

3% Discount Rate 7% Discount Rate

Proposed Option

Total Monetized 

Benefits2 $17 to $41 $15 to $37

Total Social Costs3 $2.9 $2.9

Net Benefits $14 to $38 $12 to $34

Non-monetized Benefits

340,000 tons of carbon monoxide

37,000 tons of HCl

1,000 tons of HF

7.5 tons of mercury

3,200 tons of other metals

720 grams of dioxins/furans 

Health effects from NO2 and SO2

exposure

Ecosystem effects 

Visibility impairment 

Proposed Option with Alternate Solid Waste Definition

Total Monetized 

Benefits2 $3.1 to $7.7 $2.8 to $6.9

Total Social Costs3 $2.2 $2.2
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Net Benefits $0.93 to $5.5 $0.64 to $4.7

Non-monetized Benefits

280,000 tons of carbon monoxide

5,100 tons of HCl

1,100 tons of HF

7.1 tons of mercury 

1,600 tons of other metals

290 grams of dioxins/furans

Health effects from NO2 and SO2

exposure

Ecosystem effects 

Visibility impairment 1

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

rounded to two significant figures. 

2 The total monetized benefits reflect the human health benefits 

associated with reducing exposure to PM2.5 through reductions of 

directly emitted PM2.5 and PM2.5 precursors such as NOx and SO2. It 

is important to note that the monetized benefits include many 

but not all health effects associated with PM2.5 exposure. 3 The methodology used to estimate social costs for one year in 

the multimarket model using surplus changes results in the same 

social costs for both discount rates.

For more information on the benefits analysis, please refer 

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

docket.

VI. Public Participation and Requests for Comment

We request comment on all aspects of this proposed rule. 

In 2004 we published a final rule for boilers and process 

heaters located at major source facilities (69 FR 55218, 

September 13, 2004). The final rule was vacated and remanded by 

the Court on June 19, 2007. We are reissuing our proposal, in 

response to the Court’s decisions, in this notice. We received 

many comments on that vacated rule during its rulemaking and
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have attempted to take all those comments into account in this 

action. This proposal includes a variety of changes from the 

vacated rule, mostly centered on emission limits for the various 

HAP and subcategories.

During this rulemaking, we conducted outreach to small 

entities and convened a Small Business Advocacy Review (SBAR)

Panel to obtain advice and recommendation of representatives of 

the small entities that potentially would be subject to the

requirements of this proposed rule. As part of the SBAR Panel 

process we conducted outreach with representatives from various 

small entities that would be affected by this proposed rule. We 

met with these small entity representatives (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. We met with SERs 

from the industries that will be impacted directly by this 

proposed rule to discuss the outreach materials and receive 

feedback on the approaches and alternatives detailed in the 

outreach packet. The Panel received written comments from the

SERs following the meeting in response to discussions at the 
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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.

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

of the CAA

Section 112(c)(6) of the CAA 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 and extractable

organic matter.) 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 

Formatted: Indent: First line: 0.5"
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Residue Combustion,” “Commercial Coal Combustion,” “Commercial 

Oil Combustion,” and “Commercial Wood/Wood Residue Combustion” 

as source category “subject to regulation” for purposes of CAA 

Section 112(c)(6) with respect to the CAA Section 112(c)(6) 

pollutants that these units emit.

Specifically, as byproducts of combustion, the formation of 

POM is effectively reduced by the combustion and post-combustion

practices required to comply with the CAA Section 112 standards. 

Any POM that do form during combustion are further controlled by 

the various post-combustion controls. The add-on PM control

systems (either fabric filter or wet scrubber) and activated 

carbon injection in the fabric filter-based systems further

reduce emissions of these organic pollutants, and also reduce 

mercury emissions, as is evidenced by performance data. 

Specifically, the emission tests obtained at currently

operating units show that the proposed MACT regulations

will reduce mercury 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 Section 112(c)(6) of the 

CAA.

Formatted: Indent: First line: 0.5"
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In lieu of establishing numerical emissions limits for 

pollutants such as POM, CAA Section 129(a)(4) allows EPA towe

regulate surrogate substances. While we have not identified 

specific numerical limits for POM, we believe CO serves as an 

effective surrogate for this HAP, because CO, like POM, is 

formed as a byproduct of combustion. 

Consequently, we have concluded that the emissions limits 

for CO function as a surrogate for control of POM, such that it 

is not necessary to propose numerical emissions limits for POM 

with respect to boilers and process heaters to satisfy CAA 

Section 112(c)(6).

To further address POM and mercury emissions, this proposed

rule also includes an energy assessment provision that encourage 

modifications to the facility to reduce energy demand that lead 

to these emissions.

VIII. Statutory and Executive Order Reviews

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

or tribal governments or communities.

Accordingly, EPA submitted this action to the Office of 

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

changes in response to OMB recommendations have been documented 

in the docket for this action. For more information on the 

costs and benefits for this rule, please refer to Table 14 of 

this preamble.

B. Executive Order 13132, Federalism

Executive Order 13132 (64 FR 43255, August 10, 1999), 

requires EPA to develop an accountable process to ensure 

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

development of regulatory policies that have federalism 

implications.” “Policies that have federalism implications” is 

defined in the Executive Order to include regulations that have 

“substantial direct effects on the States, on the relationship 

between the national government and the States, or on the 

distribution of power and responsibilities among the various 

levels of government.

This proposed rule does not have federalism implications. 

It will not have substantial direct effects on the States, on 

the relationship between the national government and the States, 

or on the distribution of power and responsibilities among the 
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various levels of government, as specified in Executive Order 

13132. Thus, Executive Order 13132 does not apply to this

proposed rule. In the spirit of Executive Order 13132, and 

consistent with EPA policy to promote communications between EPA 

and State and local governments, EPA specifically solicited 

comment on this proposed rule from State and local officials.

C. Executive Order 13175, Consultation and Coordination with 

Indian Tribal Governments

Executive Order 13175 (65 FR 67249, November 9, 2000), 

requires EPA to develop an accountable process to ensure 

“meaningful and timely input by tribal officials in the 

development of regulatory policies that have tribal 

implications.” This 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. This

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 
200

there are any, the effect of this 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 this proposed rule. EPA specifically solicits 

additional comment on this proposed rule from tribal officials.

D. 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 this planned rule on children, and explain why this planned 

regulation is preferable to other potentially effective and 

reasonably feasible alternatives considered by the Agency.

This proposed rule is 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 this proposed rule is based solely on 

technology performance.
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The public is invited to submit comments or identify peerreviewed studies and data that assess effects of early life 

exposure to this proposed rule. 

E. Unfunded Mandates Reform Act of 1995

Title II of the Unfunded Mandates Reform Act of 1995 

(UMRA), Public Law 104-4, establishes requirements for Federal 

agencies to assess the effects of their regulatory actions on 

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

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

written statement, including a cost-benefit analysis, for 

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

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

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

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

statement is needed, section 205 of the UMRA generally requires 

us to identify and consider a reasonable number of regulatory 

alternatives and adopt the least costly, most cost-effective or 

least burdensome alternative that achieves the objectives of the 

rule. The provisions of section 205 do not apply when they are 

inconsistent with applicable law. Moreover, section 205 allows 

us to adopt an alternative other than the least costly, most 

cost-effective or least burdensome alternative if the 

Administrator publishes with the final rule an explanation why 
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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 
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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 directs us to develop NESHAP 

which require existing and new major sources to control 

emissions of HAP using MACT based standards. This NESHAP 

applies to all industrial, commercial, and institutional boilers 

and process heaters located at major sources of HAP emissions.

In compliance with section 205(a) of the UMRA, we 

identified and considered a reasonable number of regulatory 

alternatives. Additional information on the costs and 

environmental impacts of these regulatory alternatives is 

presented in the docket.

The regulatory alternative upon which the proposed rule is 

based represents the MACT floor for industrial boilers and 

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

least burdensome alternative.

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. 

Formatted: Line spacing: Double
204

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 $5.12.9 billion (2008 dollars).

 It is estimated that 3 years after implementation of the 

proposed rule, HAPs would be reduced by thousands of tons, 

including reductions in hydrochloric acid, hydrogen fluoride, 

metallic HAP including mercury, and several other organic HAP 

from boilers and process heaters. Studies have determined a 

relationship between exposure to these HAP and the onset of 

cancer, however, the Agency is unable to provide a monetized 

estimate of the HAP benefits at this time. In addition, there 

are significant reductions in PM2.5 and in SO2 that would occur, 

including 2329 thousand tons of PM2.5 and 384340 thousand 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 
205

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 is range from $1617 billion (2008 

dollars) to $4041 billion (2008 dollars) when using a 3 percent 

discount rate (or from $15 billion (2008 dollars)to $3637

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

This estimate, at a 3 percent discount rate, is about $1114

billion (2008 dollars) to $3538 billion (2008 dollars) higher 

than the estimated social costs shown earlier in this section. 

The general approach used to value benefits is discussed in more 

detail earlier in this preamble. For more detailed information 

on the benefits estimated for the proposed rulemaking, refer to 

the RIA in the docket.

3. Future and Disproportionate Costs

The Unfunded Mandates Act requires that we estimate, where 

accurate estimation is reasonably feasible, future compliance 

costs imposed by the proposed rule and any disproportionate 
206

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 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 
207

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

output, and little impact on communities that may be affected by 

the proposed rule. 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 Act requires that we describe the 

extent of the Agency’s prior consultation with affected State, 

local, and tribal officials, summarize the officials’ comments 

or concerns, and summarize our response to those comments or 

concerns. In addition, section 203 of the UMRA requires that we 

develop a plan for informing and advising small governments that 

may be significantly or uniquely impacted by a proposal. 

Although the proposed rule does not affect any State, local, or 

Tribal governments, we have consulted with State and local air 

pollution control officials. We also have held meetings on the 

proposed rule with many of the stakeholders from numerous 

individual companies, environmental groups, consultants and 

vendors, labor unions, and other interested parties. We have 

added materials to the Air Docket to document these meetings.

In addition, we have determined that the proposed rule 

contains no regulatory requirements that might significantly or 
208

uniquely affect small governments. While some small governments 

may have some sources affected by the proposed rule, the impacts 

are not expected to be significant. Therefore, today's proposed 

rule is not subject to the requirements of section 203 of the 

UMRA.

F. Regulatory Flexibility Act (RFA), as Amended by the Small 

Business Regulatory Enforcement Fairness Act of 1996 (SBREFA), 5 

U.S.C. 601 et seq.

The RFA generally requires an agency to prepare a 

regulatory flexibility analysis of any rule subject to notice 

and comment rulemaking requirements under the Administrative 

Procedure Act or any other statute unless the agency certifies 

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

substantial number of small entities. Small entities include 

small businesses, small organizations, and small governmental 

jurisdictions.

For purposes of assessing the impacts of today’s proposed 

rule on small entities, small entity is defined as: (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 
209

utilities. In these latter two industries, the size standard is 

1,500 employees and a mass throughput of 75,000 barrels/day or 

less, and 4 million kilowatt-hours of production or less, 

respectively; (2) a small governmental jurisdiction that is a 

government of a city, county, town, school district or special 

district with a population of less than 50,000; and (3) a small 

organization that is any not-for-profit enterprise which is 

independently owned and operated and is not dominant in its 

field. 

Because an initial screening analysis for impact on small 

entities indicated a likely significant impact for substantial 

numbers EPA convened a SBAR Panel to obtain advice and 

recommendation of representatives of the small entities that

potentially would be subject to the requirements of this rule.

(a) 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
210

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 
211

comment on regulatory alternatives that could help to minimize

the rule’s impact on small businesses.

(1) 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 four of the Panel’s recommendations.

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 all but one of the 

Panel recommendations.

(a) Work Practice Standards

The panel recommended that EPA consider requiring annual 

tune-ups, including standardized criteria outlining proper tuneup methods targeted at smaller boiler operators. The panel 
212

further recommended that EPA take comment on the efficacy of 

energy assessments/audits at improving combustion efficiency and 

the cost of performing the auditsassessments, especially to 

smaller boiler operators.

A work practice standard, instead of MACT emission limits, 

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

the CAA, that is, it is impracticable to enforce the emission 

standards due to technical or 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 

auditsassessments and implementation of auditassessment

findings. The basis of these concerns rested upon the 

uncertainty that there is no guarantee that there are available 

funds to implement a particular audit’sassessment’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. 
213

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) Health Based Compliance Alternatives (HBCA)

The Panel recommended that EPA adopt the HBCA as a 

regulatory flexibility option for the Boiler MACT rulemaking. 

The panel recognized, however, that EPA has concerns about its 

legal authority to provide an HBCA under the Clean Air Act, and 

EPA may ultimately determine that this flexibility is 

inconsistent with the Clean Air Act.

SERs commented that adopting an HBCA would perhaps be the 

most important step EPA could take to mitigate the serious 

financial harm the Boiler MACT would otherwise inflict on small 

entities using solid fuels nationwide and, therefore, HBCA 

should be a critical component of any future rule to lessen 

impact on small entities.

(d) Emissions Averaging
214

The Panel recommended that EPA consider a provision for 

emission averaging and long averaging times for the proposed 

emission limits.

SERs commented that a measure EPA should consider to lessen 

the regulatory burden of complying with Boiler MACT is to allow 

emissions averaging at sources with multiple regulated units. 

SERs commented that another approach that can aide small entity 

compliance is to set longer averaging times (i.e., 30-days or 

more) rather than looking at a mere 3-run (hour) average for 

performance. Given the inherent variability in boiler 

performance, an annual or quarterly averaging period for all HAP 

would prevent a single spike in emissions from throwing a unit 

into non-compliance.

(e) 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. 
215

G. Paperwork Reduction Act

The information collection requirements in the proposed 

rule will be submitted for approval to the Office of Management 

and Budget under the Paperwork Reduction Act, 44 U.S.C. 3501 et

seq. An Information Collection Request (ICR) document has been 

prepared by EPA (ICR No. 2028.01).

 The information requirements are based on notification, 

recordkeeping, and reporting requirements in the NESHAP General 

Provisions (40 CFR part 63, subpart A), which are mandatory for 

all operators subject to national emission standards. These 

recordkeeping and reporting requirements are specifically 

authorized by section 114 of the CAA (42 U.S.C. 7414). All 

information submitted to EPA pursuant to the recordkeeping and 

reporting requirements for which a claim of confidentiality is 

made is safeguarded according to Agency policies set forth in 40 

CFR part 2, subpart B.

The proposed rule would require maintenance inspections of 

the control devices but would not require any notifications or 

reports beyond those required by the General Provisions. The 

recordkeeping requirements require only the specific information 

needed to determine compliance.

 The annual monitoring, reporting, and recordkeeping burden 

for this collection (averaged over the first 3 years after the 
216

effective date of the standards) is estimated to be $10987.6

million. This includes 364,942208,832 labor hours per year at a 

total labor cost of $34.519.8 million per year, and total nonlabor capital costs of $74.567.8 million per year. This 

estimate includes initial and annual performance test, 

conducting an documenting an energy auditassessment, 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 auditassessment costs and cost were also included in 

the cost estimates presented in the control costs impacts 

estimates in section IV.D of this preamble. The total burden 

for the Federal government (averaged over the first 3 years 

after the effective date of the standard) is estimated to be 

121,50693,648 hours per year at a total labor cost of $6.4.9

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 
217

providing information; adjust the existing ways to comply with 

any previously applicable instructions and requirements; train 

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

search data sources; complete and review the collection of 

information; and transmit or otherwise disclose the information.

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

required to respond to, a collection of information unless it 

displays a currently valid OMB control number. The OMB control 

numbers for our regulations are listed in 40 CFR part 9 and 48 

CFR chapter 15.

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

of the provided burden estimates, and any suggested methods for 

minimizing respondent burden, including the use of automated 

collection techniques, EPA has established a public docket for 

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

EPA-HQ-OAR-2002-0058. Submit any comments related to the ICR to 

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

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

OMB at the Office of Information and Regulatory Affairs, Office 

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

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

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

after [INSERT DATE OF PUBLICATION IN THE FEDERAL REGISTER], a 
218

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

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

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

or public comments on the information collection requirements 

contained in this proposal.

H. National Technology Transfer and Advancement Act

Section 12(d) of the National Technology Transfer and 

Advancement Act (NTTAA) of 1995 (Public Law No. 104-113; 

15 U.S.C. 272 note) directs the EPA to use voluntary consensus 

standards in their regulatory and procurement activities unless 

to do so would be inconsistent with applicable law or otherwise 

impractical. Voluntary consensus standards are technical 

standards (e.g., materials specifications, test methods, 

sampling procedures, business practices) developed or adopted by 

one or more voluntary consensus bodies. The NTTAA directs EPA 

to provide Congress, through annual reports to the Office of 

Management and Budget, with explanations when an agency does not 

use available and applicable voluntary consensus standards. 

This rulemaking involves technical standards. The EPA 

cites the following standards in the proposed rule: EPA Methods 

1, 2, 2F, 2G, 3A, 3B, 4, 5, 5D, 17, 19, 26, 26A, 29 of 40 CFR 

part 60. Consistent with the NTTAA, EPA conducted searches to 

identify voluntary consensus standards in addition to these EPA 
219

methods. No applicable voluntary consensus standards were 

identified for EPA Methods 2F, 2G, 5D, and 19. The search and 

review results have been documented and are placed in the docket 

for the proposed rule. 

The three voluntary consensus standards described below 

were identified as acceptable alternatives to EPA test methods 

for the purposes of the proposed rule. 

The voluntary consensus standard ASME PTC 19-10-1981-Part 

10, “Flue and Exhaust Gas Analyses,” is cited in the proposed 

rule for its manual method for measuring the oxygen, carbon 

dioxide, and carbon monoxide content of exhaust gas. This part 

of ASME PTC 19-10-1981-Part 10 is an acceptable alternative to 

Method 3B.

The voluntary consensus standard ASTM D6522-00, “Standard 

Test Method for the 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” is an acceptable 

alternative to EPA Method 3A for identifying carbon monoxide and 

oxygen concentrations for the proposed rule when the fuel is 

natural gas. 

The voluntary consensus standard ASTM Z65907, “Standard 

Method for Both Speciated and Elemental Mercury Determination,” 
220

is an acceptable alternative to EPA Method 29 (portion for 

mercury only) for the purpose of the proposed rule. This 

standard can be used in the proposed rule to determine the 

mercury concentration in stack gases for boilers with rated heat 

input capacities of greater than 250 MMBtu per hour.

In addition to the voluntary consensus standards EPA uses 

in the proposed rule, the search for emissions measurement 

procedures identified 15 other voluntary consensus standards. 

The EPA determined that 13 of these 15 standards identified for 

measuring emissions of the HAP or surrogates subject to emission 

standards in the proposed rule were impractical alternatives to 

EPA test methods for the purposes of the rule. Therefore, EPA 

does not intend to adopt these standards for this purpose. The 

reasons for this determination for the 13 methods are discussed 

below.

The voluntary consensus standard ASTM D3154-00, “Standard 

Method for Average Velocity in a Duct (Pitot Tube Method),” is 

impractical as an alternative to EPA Methods 1, 2, 3B, and 4 for 

the purposes of the proposed rulemaking since the standard 

appears to lack in quality control and quality assurance 

requirements. Specifically, ASTM D3154-00 does not include the 

following: (1) proof that openings of standard pitot tube have 

not plugged during the test; (2) if differential pressure gauges 
221

other than inclined manometers (e.g., magnehelic gauges) are 

used, their calibration must be checked after each test series; 

and (3) the frequency and validity range for calibration of the 

temperature sensors.

The voluntary consensus standard ASTM D3464-96 (2001), 

“Standard Test Method Average Velocity in a Duct Using a Thermal 

Anemometer,” is impractical as an alternative to EPA Method 2 

for the purposes of the proposed rule primarily because 

applicability specifications are not clearly defined, e.g., 

range of gas composition, temperature limits. Also, the lack of 

supporting quality assurance data for the calibration procedures 

and specifications, and certain variability issues that are not 

adequately addressed by the standard limit EPA’s ability to make 

a definitive comparison of the method in these areas.

The voluntary consensus standard ISO 10780:1994, 

“Stationary Source Emissions–Measurement of Velocity and Volume 

Flowrate of Gas Streams in Ducts,” is impractical as an 

alternative to EPA Method 2 in the proposed rule. The standard 

recommends the use of an L-shaped pitot, which historically has 

not been recommended by EPA. The EPA specifies the S-type 

design which has large openings that are less likely to plug up 

with dust.
222

The voluntary consensus standard, CAN/CSA Z223.2-M86(1999), 

“Method for the Continuous Measurement of Oxygen, Carbon 

Dioxide, Carbon Monoxide, Sulphur Dioxide, and Oxides of 

Nitrogen in Enclosed Combustion Flue Gas Streams,” is 

unacceptable as a substitute for EPA Method 3A since it does not 

include quantitative specifications for measurement system 

performance, most notably the calibration procedures and 

instrument performance characteristics. The instrument 

performance characteristics that are provided are nonmandatory 

and also do not provide the same level of quality assurance as 

the EPA methods. For example, the zero and span/calibration 

drift is only checked weekly, whereas the EPA methods requires 

drift checks after each run.

Two very similar voluntary consensus standards, ASTM D5835-

95 (2001), “Standard Practice for Sampling Stationary Source 

Emissions for Automated Determination of Gas Concentration,” and 

ISO 10396:1993, “Stationary Source Emissions: Sampling for the 

Automated Determination of Gas Concentrations,” are impractical 

alternatives to EPA Method 3A for the purposes of the proposed 

rule because they lack in detail and quality assurance/quality 

control requirements. Specifically, these two standards do not 

include the following: (1) sensitivity of the method; 

(2) acceptable levels of analyzer calibration error; (3) 
223

acceptable levels of sampling system bias; (4) zero drift and 

calibration drift limits, time span, and required testing 

frequency; (5) a method to test the interference response of the 

analyzer; (6) procedures to determine the minimum sampling time 

per run and minimum measurement time; and (7) specifications for 

data recorders, in terms of resolution (all types) and recording 

intervals (digital and analog recorders, only).

The voluntary consensus standard ISO 12039:2001, 

“Stationary Source Emissions--Determination of Carbon Monoxide, 

Carbon Dioxide, and Oxygen--Automated Methods,” is not 

acceptable as an alternative to EPA Method 3A. This ISO 

standard is similar to EPA Method 3A, but is missing some key 

features. In terms of sampling, the hardware required by 

ISO 12039:2001 does not include a 3-way calibration valve 

assembly or equivalent to block the sample gas flow while 

calibration gases are introduced. In its calibration 

procedures, ISO 12039:2001 only specifies a two-point 

calibration while EPA Method 3A specifies a three-point 

calibration. Also, ISO 12039:2001 does not specify performance 

criteria for calibration error, calibration drift, or sampling 

system bias tests as in the EPA method, although checks of these 

quality control features are required by the ISO standard. 
224

The voluntary consensus standard ASME PTC-38-80 R85 (1985), 

“Determination of the Concentration of Particulate Matter in Gas 

Streams,” is not acceptable as an alternative for EPA Method 5 

because ASTM PTC-38-80 is not specific about equipment 

requirements, and instead presents the options available and the 

pro’s and con’s of each option. The key specific differences 

between ASME PTC-38-80 and the EPA methods are that the ASME 

standard: (1) allows in-stack filter placement as compared to 

the out-of-stack filter placement in EPA Methods 5 and 17; 

(2) allows many different types of nozzles, pitots, and 

filtering equipment; (3) does not specify a filter weighing 

protocol or a minimum allowable filter weight fluctuation as in 

the EPA methods; and (4) allows filter paper to be only 

99 percent efficient, as compared to the 99.95 percent 

efficiency required by the EPA methods. 

The voluntary consensus standard ASTM D3685/D3685M-98, 

“Test Methods for Sampling and Determination of Particulate 

Matter in Stack Gases,” is similar to EPA Methods 5 and 17, but 

is lacking in the following areas that are needed to produce 

quality, representative particulate data: (1) requirement that 

the filter holder temperature should be between 120o

C and 134oC, 

and not just “above the acid dew-point;” (2) detailed 

specifications for measuring and monitoring the filter holder 
225

temperature during sampling; (3) procedures similar to EPA 

Methods 1, 2, 3, and 4, that are required by EPA Method 5; (4) 

technical guidance for performing the Method 5 sampling 

procedures, e.g., maintaining and monitoring sampling train 

operating temperatures, specific leak check guidelines and 

procedures, and use of reagent blanks for determining and 

subtracting background contamination; and (5) detailed equipment 

and/or operational requirements, e.g., component exchange leak 

checks, use of glass cyclones for heavy particulate loading 

and/or water droplets, operating under a negative stack 

pressure, exchanging particulate loaded filters, sampling 

preparation and implementation guidance, sample recovery 

guidance, data reduction guidance, and particulate sample 

calculations input.

The voluntary consensus standard ISO 9096:1992, 

“Determination of Concentration and Mass Flow Rate of 

Particulate Matter in Gas Carrying Ducts - Manual Gravimetric 

Method,” is not acceptable as an alternative for EPA Method 5. 

Although sections of ISO 9096 incorporate EPA Methods 1, 2, and 

5 to some degree, this ISO standard is not equivalent to EPA 

Method 5 for collection of particulate matter. The standard ISO 

9096 does not provide applicable technical guidance for 

performing many of the integral procedures specified in Methods 
226

1, 2, and 5. Major performance and operational details are 

lacking or nonexistent, and detailed quality assurance/quality 

control guidance for the sampling operations required to produce 

quality, representative particulate data (e.g., guidance for 

maintaining and monitoring train operating temperatures, 

specific leak check guidelines and procedures, and sample 

preparation and recovery procedures) are not provided by the 

standard, as in EPA Method 5. Also, details of equipment and/or 

operational requirements, such as those specified in EPA 

Method 5, are not included in the ISO standard, e.g., stack gas 

moisture measurements, data reduction guidance, and particulate 

sample calculations. 

The voluntary consensus standard CAN/CSA Z223.1-M1977, 

“Method for the Determination of Particulate Mass Flows in 

Enclosed Gas Streams,” is not acceptable as an alternative for 

EPA Method 5. Detailed technical procedures and quality control 

measures that are required in EPA Methods 1, 2, 3, and 4 are not 

included in CAN/CSA Z223.1. Second, CAN/CSA Z223.1 does not 

include the EPA Method 5 filter weighing requirement to repeat 

weighing every 6 hours until a constant weight is achieved. 

Third, EPA Method 5 requires the filter weight to be reported to 

the nearest 0.1 mg, while CAN/CSA Z223.1 requires only to the 

nearest 0.5 mg. Also, CAN/CSA Z223.1 allows the use of a 
227

standard pitot for velocity measurement when plugging of the 

tube opening is not expected to be a problem. Whereas, EPA 

Method 5 requires an S-shaped pitot. 

The voluntary consensus standard EN 1911-1,2,3 (1998), 

“Stationary Source Emissions-Manual Method of Determination of 

HCl-Part 1: Sampling of Gases Ratified European Text-Part 2: 

Gaseous Compounds Absorption Ratified European Text-Part 3: 

Adsorption Solutions Analysis and Calculation Ratified European 

Text,” is impractical as an alternative to EPA Methods 26 and 

26A. Part 3 of this standard cannot be considered equivalent to 

EPA Method 26 or 26A because the sample absorbing solution 

(water) would be expected to capture both HCl and chlorine gas, 

if present, without the ability to distinguish between the two. 

The EPA Methods 26 and 26A use an acidified absorbing solution 

to first separate HCl and chlorine gas so that they can be 

selectively absorbed, analyzed, and reported separately. In 

addition, in EN 1911 the absorption efficiency for chlorine gas 

would be expected to vary as the pH of the water changed during 

sampling.

The voluntary consensus standard EN 13211 (1998), is not 

acceptable as an alternative to the mercury portion of EPA 

Method 29 primarily because it is not validated for use with 

impingers, as in the EPA method, although the method describes 
228

procedures for the use of impingers. This European standard is 

validated for the use of fritted bubblers only and requires the 

use of a side (split) stream arrangement for isokinetic sampling 

because of the low sampling rate of the bubblers (up to 3 liters 

per minute, maximum). Also, only two bubblers (or impingers) 

are required by EN 13211, whereas EPA Method 29 require the use 

of six impingers. In addition, EN 13211 does not include many 

of the quality control procedures of EPA Method 29, especially 

for the use and calibration of temperature sensors and 

controllers, sampling train assembly and disassembly, and filter 

weighing.

Two of the 15 voluntary consensus standards identified in 

this search were not available at the time the review was 

conducted for the purposes of the proposed rule because they are 

under development by a voluntary consensus body: ASME/BSR MFC 

13M, “Flow Measurement by Velocity Traverse,” for EPA Method 2 

(and possibly 1); and ASME/BSR MFC 12M, “Flow in Closed Conduits 

Using Multiport Averaging Pitot Primary Flowmeters,” for EPA 

Method 2. 

Section 63.7520 and Tables 4A through 4D to subpart DDDDD, 

40 CFR part 63, list the EPA testing methods included in the 

proposed rule. Under §63.7(f) and §63.8(f) of subpart A of the 

General Provisions, a source may apply to EPA for permission to 
229

use alternative test methods or alternative monitoring 

requirements in place of any of the EPA testing methods, 

performance specifications, or procedures.

I. Executive Order 13211, Actions Concerning Regulations That 

Significantly Affect Energy Supply, Distribution, or Use

Executive Order 13211, (66 FR 28355, May 22, 2001), 

provides that agencies shall prepare and submit to the 

Administrator of the Office of Information and Regulatory 

Affairs, Office of Management and Budget, a Statement of Energy 

Effects for certain actions identified as significant energy 

actions. Section 4(b) of Executive Order 13211 defines 

“significant energy actions” as “any action by an agency 

(normally published in the Federal Register) that promulgates or 

is expected to lead to the promulgation of a final rule or 

regulation, including notices of inquiry, advance notices of 

proposed rulemaking, and notices of proposed rulemaking: (1)(i) 

that is a significant regulatory action under Executive Order 

12866 or any successor order, and (ii) is likely to have a 

significant adverse effect on the supply, distribution, or use 

of energy; or (2) that is designated by the Administrator of the 

Office of Information and Regulatory Affairs as a significant 

energy action.” The proposed rule is not a “significant 

regulatory action” because it is not likely to have a 
230

significant adverse effect on the supply, distribution, or use 

of energy. The basis for the determination is as follows.

We estimate a 0.14% price increase for the energy sector 

and a 0.07% percentage change in production. We estimate a 

0.18% increase in energy 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. 

J. Executive Order 12898: Federal Actions to Address 

Environmental Justice in Minority Populations and Low-Income 

Populations

Executive Order 12898 (59 FR 7629, February 16, 1994) 

establishes Federal executive policy on environmental justice 

(EJ). Its main provision directs Federal agencies, to the 

greatest extent practicable and permitted by law, to make 

environmental justice part of their mission by identifying and 

addressing, as appropriate, disproportionately high and adverse 

human health or environmental effects of their programs, 

policies, and activities on minority populations, low-income, 

and Tribal populations in the United States.
231

This proposed action establishes national emission 

standards for new and existing industrial, commercial, 

institutional boilers and process heaters that combust non-waste 

materials (i.e. natural gas, process gas, fuel oil, biomass, and 

coal) and that are located at a major source. The EPA estimates 

that there are approximately 38,00013,555 units located at 1,608 

facilities covered by this rule.

The proposed rule will reduce emissions of all the listed 

HAP that come from boilers and process heaters. This includes 

metals (mercury, arsenic, beryllium, cadmium, chromium, lead, 

manganese, nickel, and selenium), organics (POM, acetaldehyde, 

acrolein, benzene, dioxins, ethylene dichloride, formaldehyde, 

and PCB), hydrochloric acid, and hydrofluoric acid (See Table 6 

of this preamble).. Adverse health effects from these 

pollutants include cancer and chronic health disorders (e.g.,,

irritation of the lunglungs, skin, and mucus membranes,; effects 

on the central nervous system, and damage to the kidneys),, and 

other acute health disorders (e.g., lung irritation and 

congestion, alimentary effects such as nausea and vomiting, and 

effects on the kidney and central nervous system).. The rule 

will also result in substantial reductions of criteria 

pollutants (i.e. such as carbon monoxide (CO, ), nitrogen oxides 

(NOx), particulate matter (PM, ), and sulfur dioxide (SO2)). 

Sulfur dioxide and ozoneNO2 are precursors. for the formation of 
232

PM2.5 and ozone. Reducing these emissions will reduce ozone and 

PM2.5 formation and associated health effects, such as adult 

premature mortality, chronic and acute bronchitis, asthma, and 

other respiratory and cardiovascular diseases. (Please refer to 

the RIA contained in the docket for this rulemaking.)

Pursuant to E.O. 12898 EPA has undertaken to determine the 

aggregate demographic makeup of the communities near affected 

sources. This analysis used “proximity-to-a-source” to identify 

the populations considered to be living near affected sources, 

such that they have notable exposures to current emissions from 

these sources. In this approach EPA reviewed the distributions 

of baseline exposures to and risks from all HAP from all sources 

among different socio-demographic groups for this rule, and 

relatedin the locations of the expected emission reductions from 

this rule to the locations of higher than average cancer risks 

due to HAP, as estimated via EPA’s 2002 National Air Toxics 

Assessment (NATA).. The review identified those census blocks 

within a circular distance of 3 miles of affected sources and 

determined the demographic and socio-economic composition (e.g. 

race, income, education, etc) of these census blocks. The 

radius of 3 miles (or approximately 5 kilometers) has been used 

in other demographic analyses focused on areas around potential 
233

sources.27,28,29,30

EPA’s demographic analysis showed that major source 

boilers are located in areas where minorities’ share of the 

population living within a three-mile buffer is higher than the 

national average. For these same areas, the percent of the 

population below the poverty line is also higher than the 

national average.

 In addition, air modeling experience has shown 

that beyond 3 miles the influence of an individual source of 

emissions can generally be considered to be small, both in 

absolute terms and relative to the influence of other sources 

(assuming there are other sources in the area, as is typical in 

urban areas). 

31

 

27 U.S. GAO (Government Accountability Office). Demographics of People Living Near Waste Facilities.

Washington DC: Government Printing Office; 1995.

 Based on the fact that the rule does not 

allow emission increases, the EPA has determined that the 

proposed rule will not have disproportionately high and adverse 

human health or environmental effects on minority, low-income, 

or Tribal populations. Also, based on the review of NATA 

results, estimated emission reductions associated with this 

rule, and the demographics within 3 miles of each boiler, EPA 

has determined that the greatest emission reductions tend to 

28 Mohai P, Saha R. “Reassessing Racial and Socio-economic Disparities in Environmental Justice Research”. 

Demography. 2006;43(2): 383–399. 29 Mennis J. “Using Geographic Information Systems to Create and Analyze Statistical Surfaces of Populations and 

Risk for Environmental Justice Analysis”. Social Science Quarterly, 2002;83(1):281-297. 30 Bullard RD, Mohai P, Wright B, Saha R, et al. Toxic Waste and Race at Twenty 1987-2007. United Church of 

Christ. March, 2007. 

31 The results of the demographic analysis are presented in “Review of Environmental Justice Impacts”, April 2010, 

a copy of which is available in the docket and from the EPA website _________. 
234

occur in the areas of higher total cancer risks from HAPs. 

These areas tend to have lower proportions of Whites and 

American Indians, higher proportions of African-Americans, 

Hispanics, and “Other and Multi-racial” populations, and higher 

proportions of families with incomes below the poverty level. 

However, to the extent that any minority, low income, or Tribal 

subpopulation is disproportionately impacted by the current 

emissions as a result of the proximity of their homes to these 

sources, that subpopulation also stands to see increased 

environmental and health benefit from the emissions reductions 

called for by this rule.

EPA defines “Environmental Justice” to include meaningful 

involvement of all people regardless of race, color, national 

origin, or income with respect to the development, 

implementation, and enforcement of environmental laws, 

regulations, and polices. To promote meaningful involvement, 

EPA has developed a communication and outreach strategy to 

ensure that interested communities have access to this proposed 

rule, are aware of its content, and have an opportunity to 

comment during the comment period. During the comment period, 

EPA will publicize the rulemaking via EJ newsletters, Tribal 

newsletters, EJ listserveslistservs, and the internet, including 

the Office of Policy, Economics, and Innovation’s (OPEI) 

Rulemaking Gateway web site 
235

(http://yosemite.epa.gov/opei/rulegate.nsf/content/index.html?op

endocument). (http://yosemite.epa.gov/opei/RuleGate.nsf/). EPA 

will also provide general rulemaking fact sheets (e.g., why is 

this important for my community) for EJ community groups and 

conduct conference calls and Webinars with interested 

communities. In addition, state and federal permitting 

requirements will provide state, and local governments, and 

members of affected communities anthe opportunity to provide

their comments on the permit conditions associated with 

permitting the sources affected by this rulemaking.

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:

_______________________
236

Lisa P. Jackson,

Administrator. 
237

For the reasons stated in the preamble, title 40, chapter I, 

part 63 of the Code of the 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.

2. Part 63 is amended by addingrevising subpart DDDDD to read 

as follows:

Subpart DDDDD--National Emission Standards for Hazardous Air 

Pollutants for Major Sources: Industrial, Commercial, and 

Institutional Boilers and Process Heaters

Sec.

What this Subpart Covers

63.7480 What is the purpose of this subpart?

63.7485 Am I subject to this subpart?

63.7490 What partsis the affected source of my facility does 

this subpart cover??

63.7491 Are any boilers or process heaters not subject to this 

subpart?

63.7495 When do I have to comply with this subpart?

Emission Limitations and Work Practice Standards

63.7499 What are the subcategories of boilers and process 

heaters?

63.7500 What emission limitations and , work practice

standards, and operating limits must I meet?

General Compliance Requirements

Formatted: Left: 1", Top: 1"

Formatted: Indent: Left: 0", Hanging: 1",

Tab stops: Not at 0"
238

63.7505 What are my general requirements for complying with 

this subpart?

Testing, Fuel Analyses, and Initial Compliance Requirements

63.7510 ByWhat are my initial compliance requirements and by

what date must I conduct performance tests or other 

initial compliance demonstrationsthem?

63.7515 When must I conduct subsequent performance tests or 

fuel analyses?

63.7520 What performancestack tests, design evaluations, and

other procedures must I use for the performance tests?

63.7521 What fuel analyses and procedures must I use for the 

performance tests?

63.7522 Can I use emission averaging to comply with this 

subpart?

63.7525 What are my monitoring, installation, operation, and 

maintenance requirements?

63.7530 How do I demonstrate initial compliance with the 

emission limitations and work practice standards?

Continuous Compliance Requirements

63.7535 How do I monitor and collect data to demonstrate 

continuous compliance?

63.7540 How do I demonstrate continuous compliance with the 

emission limitations and work practice standards?

63.7541 How do I demonstrate continuous compliance under the 

emission averaging provision?

Notifications, Reports, and Records

63.7545 What notifications must I submit and when?

63.7550 What reports must I submit and when?

63.7555 What records must I keep?

63.7560 In what form and how long must I keep my records?

Other Requirements and Information

63.7565 What parts of the General Provisions apply to me?

63.7570 Who implements and enforces this subpart?

63.7575 What definitions apply to this subpart?

Tables to Subpart DDDDD of Part 63

Table 1 to Subpart DDDDD of Part 63-- - Emission Limits for New 

or Reconstructed Boilers and Process Heaters

Formatted: Indent: Left: 0", Hanging: 0.5",

Tab stops: Not at 0"
239

Table 2.A to Subpart DDDDD of Part 63--Operating – Emission 

Limits for Existing Boilers and Process Heaters in the 

Large, Limited Use, or Small Solid Fuel Subcategories(Units 

with heat input capacity of 10 million Btu per hour or 

greater)

Table 2.B to Subpart DDDDD of Part 63--Operating Limits for Boilers an 

Table 3 to Subpart DDDDD of Part 63-- - Work Practice Standards

Table 4.A to Subpart DDDDD of Part 63--Requirements – Operating 

Limits for Performance Tests for Particulate Matter 

Emissions or Total Selected Metals Emissions from Boilers 

orand Process Heaters in Large, Limited Use, or Small Solid 

Fuel Subcategories

Table 4.B5 to Subpart DDDDD of Part 63-- - Performance Testing 

Requirements for Performance Tests for Particulate Matter 

Emissions from Boilers or Process Heaters in Large, Limited 

Use, or Small Liquid Fuel Subcategories 

Table 4.C to Subpart DDDDD of Part 63--Requirements for 

Performance Tests for Hydrogen Chloride Emissions from 

Boilers or Process Heaters in Large, Limited Use, or Small 

Solid Fuel Subcategories

Table 4.D to Subpart DDDDD of Part 63--Requirements for 

Performance Tests for Hydrogen Chloride Emissions from 

Boilers or Process Heaters in Large, Limited Use, or Small 

Liquid Fuel Subcategories

Table 4.E to Subpart DDDDD of Part 63--Requirements for 

Performance Tests for Mercury Emissions from Boilers or 

Process Heaters in Large, Limited Use, or Small Solid Fuel 

Subcategories

Table 5.A to Subpart DDDDD of Part 63--Initial Compliance With 

Emission Limitations for Particulate Matter or Total 

Selected Metals for Boilers or Process Heaters in Large, 

Limited Use, or Small Solid Fuel Subcategories

Table 5.B to Subpart DDDDD of Part 63--Initial Compliance With 

Emission Limitations for Particulate Matter for Boilers or 

Process Heaters in Large, Limited Use, or Small Liquid Fuel 

Subcategories

Table 5.C to Subpart DDDDD of Part 63--Initial Compliance With 

Emission Limitations for Hydrogen Chloride for Boilers or 

Process Heaters in Large, Limited Use, or Small Solid Fuel 

Subcategories

Table 5.D to Subpart DDDDD of Part 63--Initial Compliance With 

Emission Limitations for Hydrogen Chloride for Boilers or 

Process Heaters in Large, Limited Use, or Small Liquid Fuel 

Subcategories

Table 5.E to Subpart DDDDD of Part 63--Initial Compliance With 

Emission Limitations for Mercury for Boilers or Process 

Formatted: Indent: Left: 0", Hanging: 0.5",

Tab stops: Not at 0"
240

Heaters in Large, Limited Use, or Small Solid Fuel, 

Subcategories

Table 6 to Subpart DDDDD of Part 63--Initial Compliance with 

Work Practice Standards – Fuel Analysis Requirements

Table 7.A to Subpart DDDDD of Part 63--Continuous Compliance 

with Emission Limitations for Boilers or Process Heaters in 

Large, Limited Use, or Small Solid Fuel Subcategories –

Establishing Operating Limits

Table 7.B to Subpart DDDDD of Part 63--Continuous Compliance 

with Emission Limitations for Boilers or Process Heaters in 

Large, Limited Use, or Small Liquid Fuel Subcategories

Table 8 to Subpart DDDDD of Part 63-- – Demonstrating Continuous 

Compliance with Work Practice Standards

Table 9 to Subpart DDDDD of Part 63-- – Reporting Requirements

for Reports

Table 10 to Subpart DDDDD of Part 63-- - Applicability of 

General Provisions to Subpart DDDDD

WHAT THIS SUBPART COVERS

What this Subpart Covers

§63.7480 What is the purpose of this subpart? 

This subpart establishes national emission limitations and 

work practice standards for hazardous air pollutants (HAP)

emitted from industrial, commercial, and institutional boilers 

and process heaters. located at major sources of HAP. This 

subpart also establishes requirements to demonstrate initial and 

continuous compliance with the emission limitations and work 

practice standards.

§63.7485 Am I subject to this subpart? 

You are subject to this subpart if you own or operate an 

industrial, commercial, or institutional boiler or process 

heater as defined in §63.7575 that is located at, or is part of, 

a major source of HAP as defined in §63.2 or §63.761 (40 CFR 
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part 63, subpart HH, National Emission Standards for Hazardous 

Air Pollutants from Oil and Natural Gas Production Facilities), 

except as specified in §63.7491. 

§ 63.7490 What is the affected source of this subpart?

(a) This subpart applies to new, reconstructed, orand existing 

affected sources as described in paragraphs (a)(1) and (2) of 

this section.

(1) The affected source of this subpart is the collection of all 

existing industrial, commercial, and institutional boilers and 

process heaters within a subcategory located at a major source 

as defined in §63.7575.

(2) The affected source of this subpart is each new or 

reconstructed industrial, commercial, or institutional boiler or 

process heater located at a major source as defined in §63.7575.

(b) A boiler or process heater is new if you commence 

construction of the boiler or process heater after [INSERT DATE 

OF PUBLICATION OF THIS PROPOSED RULE IN THE FEDERAL REGISTER],

and you meet the applicability criteria at the time you commence 

construction.

(c) A boiler or process heater is reconstructed if you meet the 

reconstruction criteria as defined in §63.2, you commence 

reconstruction after [INSERT DATE OF PUBLICATION OF THIS 

PROPOSED RULE IN THE FEDERAL REGISTER], and you meet the 

applicability criteria at the time you commence reconstruction.
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(d) A boiler or process heater is existing if it is not new or 

reconstructed.

§ 63.7491 Are any boilers or process heaters not subject to 

this subpart?

The types of boilers and process heaters listed in paragraphs 

(a) through (o) of this section are not subject to this subpart.

(a) A municipal waste combustor covered by 40 CFR part 60, 

subpart AAAA, subpart BBBB, subpart Cb or subpart Eb.

(b) A hospital/medical/infectious waste incinerator covered by 

40 CFR part 60, subpart Ce or subpart Ec.

(c(a) An electric utility steam generating unit.

(d) A boiler or process heater required to have a permit under 

section 3005 of the Solid Waste Disposal Act or covered by 40 

CFR part 63, subpart EEE (e.g., hazardous waste boilers).

(e) A commercial and industrial solid waste incineration unit 

covered by 40 CFR part 60, subpart CCCC or subpart DDDD.

(f(b) A recovery boiler or furnace covered by 40 CFR part 63, 

subpart MM.

(gc) A boiler or process heater that is used specifically for 

research and development. This does not include units that 

provide heat or steam to a process at a research and development 

facility.

(hd) A hot water heater as defined in this subpart.

(ie) A refining kettle covered by 40 CFR part 63, subpart X.
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(jf) An ethylene cracking furnace covered by 40 CFR part 63, 

subpart YY.

(kg) Blast furnace stoves as described in the EPA document, 

entitled “National Emission Standards for Hazardous Air 

Pollutants (NESHAP) for Integrated Iron and Steel Plants—

Background Information for Proposed Standards,” (EPA–453/R–01–

005).

(li) Any boiler or process heater specifically listed as an 

affected source in another standard(s) under 40 CFR part 63.

(m) Any boiler or process heater specifically listed as an 

affected source in another standard(s) established under section 

129 of the Clean Air Act (CAA).

(nj) Temporary boilers as defined in this subpart.

(ok) Blast furnace gas fuel-fired boilers and process heaters as 

defined in this subpart.

§63.7495 When do I have to comply with this subpart? 

(a) If you have a new or reconstructed boiler or process heater, 

you must comply with this subpart by [DATE THE FINAL RULE IS 

PUBLISHED IN THE FEDERAL REGISTER] or upon startup of your 

boiler or process heater, whichever is later.

(b) If you have an existing boiler or process heater, you must 

comply with this subpart no later than [3 YEARS AFTER DATE THE 

FINAL RULE IS PUBLISHED IN THE FEDERAL REGISTER].
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(c) If you have an area source that increases its emissions or 

its potential to emit such that it becomes a major source of 

HAP, paragraphs (c)(1) and (2) of this section apply to you.

(1) Any new or reconstructed boiler or process heater at the 

existing source must be in compliance with this subpart upon 

startup.

(2) Any existing boiler or process heater at the existing source

must be in compliance with this subpart within 3 years after the 

source becomes a major source.

(d) You must meet the notification requirements in §63.7545 

according to the schedule in §63.7545 and in subpart A of this 

part. Some of the notifications must be submitted before you are 

required to comply with the emission limits and work practice 

standards in this subpart.

EMISSION LIMITATIONS AND WORK PRACTICE STANDARDS

Emission Limitations and Work Practice Standards

§ 63.7499 What are the subcategories of boilers and process 

heaters?

The subcategories of boilers and process heaters are:

(1) Pulverized coal units,

(2) Stokers designed to burn coal,

(3) Fluidized bed units designed to burn coal,

(4) Stokers designed to burn biomass,

(5) Fluidized bed units designed to burn biomass,
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(6) Suspension burners/Dutch Ovens designed to burn biomass,

(7) Fuel Cells designed to burn biomass,

(8) Units designed to burn liquid fuel,

(9) Units designed to burn natural gas/refinery gas, and

(10) Units designed to burn other gases, and

(10)(11) Metal process furnaces.

Each subcategory is defined in §63.7575.

§ 63.7500 What emission limits, work practice standards, and 

operating limits must I meet?

(a) You must meet the requirements in paragraphs (a)(1) and 

(2) of this section. You must meet these requirements at all 

times.

(1) You must meet each emission limit and work practice 

standard in Table 1 through 3 to this subpart that applies to 

your boiler or process heater, for each boiler or process heater 

at your source, except as provided under §63.7522.

(2) You must meet each operating limit in Table 4 to this 

subpart that applies to your boiler or process heater. If you 

use a control device or combination of control devices not 

covered in Table 4 to this subpart, or you wish to establish and 

monitor an alternative operating limit and alternative 

monitoring parameters, you must apply to the United States

Environmental Protection Agency (EPA) Administrator for approval 

of alternative monitoring under §63.8(f).
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(b) As provided in §63.6(g), EPA may approve use of an 

alternative to the work practice standards in this section.

GENERAL COMPLIANCE REQUIREMENTS

General Compliance Requirements

§63.7505 What are my general requirements for complying with 

this subpart?

(a) You must be in compliance with the emission limits and 

operating limits in this subpart that. These limits apply to 

you at all times.

(b) At all times you must operate and maintain any 

affected source, including associated air pollution control 

equipment and monitoring equipment, in a manner consistent with 

safety and good air pollution control practices for minimizing 

emissions. 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.

(c) You can demonstrate compliance with the applicable 

emission limit for HCl or mercury using fuel analysis if the 
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emission rate calculated according to §63.7530(d) is less than 

the applicable emission limit. Otherwise, you must demonstrate 

compliance for HCl or mercury using performance stack testing. 

You must demonstrate compliance with all other applicable limits 

using performance stack testing, or the continuous monitoring 

system (CMS) where applicable.

(d) If you demonstrate compliance with any applicable 

emission limit through performance stack testing, you must 

develop a site-specific monitoring plan according to the 

requirements in paragraphs (d)(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 permitting 

authority for approval upon request, a site-specific monitoring 

plan that addresses paragraphs (d)(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 

process unit such that the measurement is representative of 
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control of the exhaust emissions (e.g., on or downstream of the 

last control device);

(ii) Performance and equipment specifications for the 

sample interface, the pollutant concentration or parametric 

signal analyzer, and the data collection and reduction systems; 

and

(iii) Performance evaluation procedures and acceptance 

criteria (e.g., calibrations).

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

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

(i) Ongoing operation and maintenance procedures in 

accordance with the general requirements of §63.8(c)(1)(i) and 

(ii), (c)(3), and (c)(4)(ii);

(ii) Ongoing data quality assurance procedures in 

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

(iii) Ongoing recordkeeping and reporting procedures in 

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

TESTING, FUEL ANALYSES, AND INITIAL COMPLIANCE REQUIREMENTS

Testing, Fuel Analyses, and Initial Compliance Requirements
249

§ 63.7510 What are my initial compliance requirements and by 

what date must I conduct them?

(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 stack tests 

according to §63.7520 and Table 5 to this subpart, conducting a 

fuel analysis for each type of fuel burned in your boiler or 

process heater according to §63.7521 and Table 6 to this 

subpart, establishing operating limits according to §63.7530 and 

Table 7 to this subpart, and conducting CMS performance 

evaluations according to §63.7525. For affected sources that 

burn a single type of fuel, you are exempted from the initial 

compliance requirements of conducting a fuel analysis for each 

type of fuel burned in your boiler or process heater according 

to §63.7521 and Table 6 to this subpart.

(b) For affected sources that elect to demonstrate 

compliance with the emission limits for HCl or mercury through 

fuel analysis, your initial compliance requirement is to conduct 

a fuel analysis for each type of fuel burned in your boiler or 

process heater according to §63.7521 and Table 6 to this subpart 

and establish operating limits according to §63.7530 and Table 8 

to this subpart.
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(c) If your boiler or process heater has a heat input 

capacity less than 100 MMBtu per hour, your initial compliance 

demonstration for CO is conducting a performance stack test for 

CO according to Table 5 to this subpart. If your boiler or 

process heater has a heat input capacity of 100 MMBtu per hour 

or greater, your initial compliance demonstration for CO is 

conducting a performance evaluation of your continuous emission 

monitoring system for CO according to §63.7525(a).

(d (d) If your boiler or process heater has a heat input 

capacity of 250 MMBtu per hour or greater and combusts coal, 

biomass, or residual oil, your initial compliance demonstration 

for PM is conducting a performance evaluation of your continuous 

emission monitoring system for PM according to §63.7525(b).

(e) For existing affected sources, you must demonstrate 

initial compliance no later than 180 days after the compliance 

date that is specified for your source in §63.7495 and according 

to the applicable provisions in §63.7(a)(2) as cited in Table 10 

to this subpart.

(ef) If your new or reconstructed affected source commenced 

construction or reconstruction between [INSERT DATE OF 

PUBLICATION OF THIS PROPOSED RULE IN THE FEDERAL REGISTER] and

[INSERT DATE 60 DAYS AFTER PUBLICATION OF THE FINAL RULE IN THE 

FEDERAL REGISTER], you must demonstrate initial compliance with 

either the proposed emission limits or the promulgated emission 
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limits no later than 180 days after [INSERT DATE 60 DAYS AFTER 

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

180 days after startup of the source, whichever is later, 

according to §63.7(a)(2)(ix).

(fg) If your new or reconstructed affected source commenced 

construction or reconstruction between [INSERT DATE OF 

PUBLICATION OF THIS PROPOSED RULE IN THE FEDERAL REGISTER], and 

[INSERT DATE 60 DAYS AFTER PUBLICATION OF THE FINAL RULE IN THE 

FEDERAL REGISTER], and you chose to comply with the proposed 

emission limits when demonstrating initial compliance, you must 

conduct a second compliance demonstration for the promulgated 

emission limits within 3 years after [INSERT DATE 60 DAYS AFTER 

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

3 years after startup of the affected source, whichever is 

later.

(gh) If your new or reconstructed affected source commences 

construction or reconstruction after [INSERT DATE 60 DAYS AFTER 

PUBLICATION OF THE FINAL RULE IN THE FEDERAL REGISTER], you must 

demonstrate initial compliance with the promulgated emission 

limits no later than 180 days after startup of the source.

§ 63.7515 When must I conduct subsequent performance tests or 

fuel analyses?

(a) You must conduct all applicable performance tests 

according to §63.7520 on an annual basis, unless you follow the 
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requirements listed in paragraphs (b) through (e) 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 (e) of 

this section.

(b) You can conduct performance stack tests less often for 

a given pollutant if your performance stack tests for the 

pollutant for at least 3 consecutive years show that your 

emissions are withinat 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. This 

reduced testing option does not apply to performance stack tests 

for dioxin/furan. If you elect to demonstrate compliance using 

emission averaging under §63.7522, you must continue to conduct 

performance stack tests annually. 

(c) If your boiler or process heater continues to meet the 

emission limit for the pollutant, you may choose to conduct 

performance stack tests for the pollutant every third year if 

your emissions are withinat or below 75 percent of the emission 

limit, and if there are no changes in the operation of the 
253

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. This reduced testing option does not apply to performance 

stack tests for dioxin/furan. If you elect to demonstrate 

compliance using emission averaging under §63.7522, you must 

continue to conduct performance stack tests annually.

(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 a consecutive 3-year period show compliance.

(e) For affected units in the natural gas/refinery gas 

subcategory, you are only required to conduct an initial 

performance test for PM, mercury, HCl, and dioxin/furan unless 

you change the source or supplier of the gaseous fuel. 

(f (e) If you are required to meet an applicable work practice 

standard, you must conduct annual performance tune-ups according 

to §63.7520. Each annual tune-up must be conducted between 10 

and 12 months after the previous tune-up.

(gf) If you demonstrate compliance with the mercury or HCl 

based on fuel analysis, you must conduct a monthly fuel analysis 

according to §63.7521 for each type of fuel burned monthly. If 

you burn a new type of fuel, you must conduct a fuel analysis 

before burning the new type of fuel in your boiler or process 

Formatted: Indent: First line: 0"
254

heater. You must still meet all applicable continuous 

compliance requirements in §63.7540.

(hg) You must report the results of performance tests

(stack test and fuel analyses) within 60 days after the 

completion of the performance tests. This report shouldmust

also verify that the operating limits for your affected source 

have not changed or provide documentation of revised operating 

parameters established according to §63.7530 and Table 7 to this 

subpart, as applicable. The reports for all subsequent 

performance tests shouldmust include all applicable information 

required in §63.7550.

§ 63.7520 What stack tests and procedures must I use for the 

performance tests?

(a) You must conduct all performance tests according to 

§63.7(c), (d), (f), and (h). You must also develop a sitespecific test plan according to the requirements in §63.7(c).

(b) You must conduct each performance test according to the 

requirements in Table 5 to this subpart.

(c) You must conduct each performance stack test under the 

specific conditions listed in Tables 5 and 7 to this subpart. 

You must conduct performance stack tests at the maximum normal 

operating load while burning the type of fuel or mixture of 

fuels that havehas the highest content of chlorine, and

mercury, and total selected metals, and you must demonstrate 
255

initial compliance and establish your operating limits based on 

these tests. These requirements could result in the need to 

conduct more than one performance test.

(d) You must conduct three separate test runs for each 

performance test required in this section, as specified in 

§63.7(e)(3). Each test run must last at least 4 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, the measured HCl concentrations, and the 

measured mercury concentrations that result from the initial 

performance test to pounds per million Btu heat input emission 

rates using F-factors.

§ 63.7521 What fuel analyses and procedures must I use for the 

performance tests?

(a) You must conduct performance fuel analysis tests 

according to the procedures in paragraphs (b) through (e) of 

this section and Table 6 to this subpart, as applicable.

(b) You must develop and submit a site-specific fuel 

analysis plan to the EPA Administrator for review and approval 

according to the following procedures and requirements in 

paragraphs (b)(1) and (2) of this section.
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(1) You must submit the fuel analysis plan no later than 60 

days before the date that you intend to demonstrate compliance.

(2) You must include the information contained in 

paragraphs (b)(2)(i) through (vi) of this section in your fuel 

analysis plan.

(i) The identification of all fuel types anticipated to be 

burned in each boiler or process heater.

(ii) For each fuel type, the notification of whether you or 

a fuel supplier will be conducting the fuel analysis.

(iii) For each fuel type, a detailed description of the 

sample location and specific procedures to be used for 

collecting and preparing the composite samples if your 

procedures are different from paragraph (c) or (d) of this 

section. Samples should be collected at a location that most 

accurately represents the fuel type, where possible, at a point 

prior to mixing with other dissimilar fuel types.

(iv) For each fuel type, the analytical methods from Table 

6, with the expected minimum detection levels, to be used for

the measurement of chlorine or mercury.

(v) If you request to use an alternative analytical method 

other than those required by Table 6 to this subpart, you must 

also include a detailed description of the methods and 

procedures that you are proposing to use. Methods in Table 6 

shall be used until the requested alternative is approved.
257

(vi) If you will be using fuel analysis from a fuel 

supplier in lieu of site-specific sampling and analysis, the 

fuel supplier must use the analytical methods required by Table 

6 to this subpart.

(c) At a minimum, you must obtain three composite fuel 

samples for each fuel type according to the procedures in 

paragraph (c)(1) or (2) of this section.

(1) If sampling from a belt (or screw) feeder, collect fuel 

samples according to paragraphs (c)(1)(i) and (ii) of this 

section.

(i) Stop the belt and withdraw a 6-inch wide sample from 

the full cross-section of the stopped belt to obtain a minimum 

two pounds of sample. CollectYou must collect all the material 

(fines and coarse) in the full cross-section. TransferYou must 

transfer the sample to a clean plastic bag.

(ii) Each composite sample will consist of a minimum of 

three samples collected at approximately equal 1-hour intervals 

during the testing period.

(2) If sampling from a fuel pile or truck, you must collect 

fuel samples according to paragraphs (c)(2)(i) through (iii) of 

this section.

(i) For each composite sample, you must select a minimum of 

five sampling locations uniformly spaced over the surface of the 

pile.

Formatted: Indent: First line: 0.5"
258

(ii) At each sampling site, you must dig into the pile to a 

depth of 18 inches. InsertYou must insert a clean flat square 

shovel into the hole and withdraw a sample, making sure that 

large pieces do not fall off during sampling.

(iii) TransferYou must transfer all samples to a clean 

plastic bag for further processing.

(d) PrepareYou must prepare each composite sample according 

to the procedures in paragraphs (d)(1) through (7) of this 

section.

(1) ThoroughlyYou must thoroughly mix and pour the entire 

composite sample over a clean plastic sheet.

(2) BreakYou must break sample pieces larger than 3 inches 

into smaller sizes.

(3) MakeYou must make a pie shape with the entire composite 

sample and subdivide it into four equal parts.

(4) SeparateYou must separate one of the quarter samples as 

the first subset.

(5) If this subset is too large for grinding, you must 

repeat the procedure in paragraph (d)(3) of this section with 

the quarter sample and obtain a one-quarter subset from this 

sample.

(6) GrindYou must grind the sample in a mill.

(7) UseYou must use the procedure in paragraph (d)(3) of 

this section to obtain a one-quarter subsample for analysis. If 
259

the quarter sample is too large, subdivide it further using the 

same procedure.

(e) DetermineYou must determine the concentration of 

pollutants in the fuel (mercury and/or chlorine) in units of 

pounds per million Btu of each composite sample for each fuel 

type according to the procedures in Table 6 to this subpart.

§ 63.7522 Can I use emission averaging to comply with this 

subpart?

(a) As an alternative to meeting the requirements of 

§63.7500 for particulate matter, HCl, or mercury on a boiler or 

process heater-specific basis, if you have more than one 

existing boiler or process heater in any subcategory located at 

your facility, you may demonstrate compliance by emission 

averaging, if your averaged emissions are within 90 percent of 

the applicable emission limit, according to the procedures in 

this section.

(b) Separate stack requirements. For a group of two or 

more existing boilers or process heaters in the same subcategory

that each vent to a separate stack, you may average particulate 

matter, HCl, and mercury emissions to demonstrate compliance 

with the limits in Table 2 to this subpart if you satisfy the 

requirements in paragraphs (c), (d), (e), (f), and (g) of this 

section.
260

(c) For each existing boiler or process heater in the 

averaging group, the emission rate achieved during the initial 

compliance test for the HAP being averaged must not exceed the 

emission level that was being achieved on [INSERT THE DATE 30 

DAYS AFTER PUBLICATION OF THE FINAL RULE IN THE FEDERAL 

REGISTER] or the control technology employed during the initial 

compliance test must not be less effective for the HAP being 

averaged than the control technology employed on [INSERT THE 

DATE 30 DAYS AFTER PUBLICATION OF THE FINAL RULE IN THE FEDERAL 

REGISTER] .

(d) The averaged emissions rate from the existing boilers 

and process heaters participating in the emissions averaging 

option must be in compliance with the limits in Table 2 to this 

subpart at all times following the compliance date specified in 

§63.7495.

(e) You must demonstrate initial compliance according to 

paragraph (e)(1) or (2) of this section.

(1) You must use Equation 1 of this section to demonstrate 

that the particulate matter, HCl, and mercury emissions from all 

existing units participating in the emissions averaging option 

do not exceed the emission limits in Table 2 to this subpart.
261

Where:

Ave Weighted Emissions = Average weighted emissions for 

particulate matter, HCl, or mercury, in units of pounds per 

million Btu of heat input.

Er = Emission rate (as calculated according to Table 5 to 

this subpart for particulate matter, HCl, or mercury or by fuel 

analysis for HCl or mercury as calculated by the applicable 

equation in §63.7530(c)) for unit, i, for particulate matter, 

HCl, or mercury, in units of pounds per million Btu of heat 

input.

Hm = Maximum rated heat input capacity of unit, i, in units 

of million Btu per hour.

n = Number of units participating in the emissions 

averaging option.

0.90 = Required discount factor.

(2) If you are not capable of monitoring heat input, and 

the boiler generates steam, you may use Equation 2 of this 

section as an alternative to using Equation 1 of this section to 

demonstrate that the particulate matter, HCl, and mercury 

emissions from all existing units participating in the emissions 

averaging option do not exceed the emission limits in Table 2 to 

this subpart.

Where:

Ave Weighted Emissions = Average weighted emission level 

for PM, HCl, or mercury, in units of pounds per million Btu of 

heat input.

Formatted: Left
262

Er = Emission rate (as calculated according to Table 5 to 

this subpart for particulate matter, HCl, or mercury or by fuel 

analysis for HCl or mercury as calculated by the applicable 

equation in §63.7530(c)) for unit, i, for particulate matter, 

HCl, or mercury, in units of pounds per million Btu of heat 

input.

Sm = Maximum steam generation by unit, i, in units of 

pounds.

Cf = Conversion factor, calculated from the most recent 

compliance test, in units of million Btu of heat input per 

pounds of steam generated for unit, i.

0.90 = Required discount factor.

(f) You must demonstrate compliance on a monthly basis 

determined at the end of every month (12 times per year) 

according to paragraphs (f)(1) through (3) of this section. The 

first monthly period begins on the compliance date specified in 

§63.7495.

(1) For each calendar month, you must use Equation 3 of 

this section to calculate the monthly average weighted emission 

rate using the actual heat capacity for each existing unit

participating in the emissions averaging option.

Where:

Ave Weighted Emissions = monthly average weighted emission 

level for particulate matter, HCl, or mercury, in units of 

pounds per million Btu of heat input.

Er = Emission rate, (as calculated during the most recent 

compliance test, (as calculated according to Table 5 to this 

subpart for particulate matter, HCl, or mercury or by fuel 

analysis for HCl or mercury as calculated by the applicable 

Formatted: Left
263

equation in §63.7530(c)) for unit, i, for particulate matter, 

HCl, or mercury, in units of pounds per million Btu of heat 

input.

Hb = The average heat input for each calendar month of 

boiler, i, in units of million Btu.

n = Number of units participating in the emissions 

averaging option.

0.90 = Required discount factor.

(2) If you are not capable of monitoring heat input, you 

may use Equation 4 of this section as an alternative to using 

Equation 3 of this section to calculate the monthly weighted 

emission rate using the actual steam generation from the units 

participating in the emissions averaging option.

Where:

Ave Weighted Emissions = monthly average weighted emission 

level for PM, HCl, or mercury, in units of pounds per million 

Btu of heat input.

Er = Emission rate, (as calculated during the most recent 

compliance test (as calculated according to Table 5 to this 

subpart for particulate matter, HCl, or mercury or by fuel 

analysis for HCl or mercury as calculated by the applicable 

equation in §63.7530(c)) for unit, i, for particulate matter, 

HCl, or mercury, in units of pounds per million Btu of heat 

input.

Sa = Actual steam generation for each calendar month by 

boiler, i, in units of pounds.

Cf = Conversion factor, as calculated during the most 

recent compliance test, in units of million Btu of heat input 

per pounds of steam generated for unit, i.

0.90 = Required discount factor.

(3) Until 12 monthly weighted average emission rates have 

been accumulated, calculate and report only the monthly average 
264

weighted emission rate determined under paragraph (f)(1) or (2) 

of this section. After 12 monthly weighted average emission 

rates have been accumulated, for each subsequent calendar month, 

use Equation 5 of this section to calculate the 12-month rolling 

average of the monthly weighted average emission rates for the 

current month and the previous 11 months.

Where:

Eavg = 12-month rolling average emission rate, (pounds per 

million Btu heat input)

ERi = Monthly weighted average, for month “i”, (pounds per 

million Btu heat input)(as calculated by (f)(1) or (2))

(g) You must develop, and submit to the applicable 

regulatory authority for review and approval upon request, an 

implementation plan for emission averaging according to the 

following procedures and requirements in paragraphs (g)(1) 

through (4).

(1) You must submit the implementation plan no later than 

180 days before the date that the facility intends to 

demonstrate compliance using the emission averaging option.

(2) You must include the information contained in 

paragraphs (g)(2)(i) through (vii) of this section in your 

implementation plan for all emission sources included in an 

emissions average:
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(i) The identification of all existing boilers and process 

heaters in the averaging group, including for each either the 

applicable HAP emission level or the control technology 

installed as of [INSERT DATE 60 DAYS AFTER PUBLICATION OF THE 

FINAL RULE IN THE FEDERAL REGISTER] and the date on which you 

are requesting emission averaging to commence;

(ii) The process parameter (heat input or steam generated) 

that will be monitored for each averaging group;

(iii) The specific control technology or pollution 

prevention measure to be used for each emission boiler or 

process heater in the averaging group and the date of its 

installation or application. If the pollution prevention 

measure reduces or eliminates emissions from multiple boilers or 

process heaters, the owner or operator must identify each boiler 

or process heater;

(iv) The test plan for the measurement of particulate 

matter, HCl, or mercury emissions in accordance with the 

requirements in §63.7520;

(v) The operating parameters to be monitored for each 

control system or device consistent with 63.7500 and Table 4, 

and a description of how the operating limits will be 

determined;

(vi) If you request to monitor an alternative operating 

parameter pursuant to §63.7525, you must also include:
266

(A) A description of the parameter(s) to be monitored and 

an explanation of the criteria used to select the parameter(s); 

and

(B) A description of the methods and procedures that will 

be used to demonstrate that the parameter indicates proper 

operation of the control device; the frequency and content of 

monitoring, reporting, and recordkeeping requirements; and a 

demonstration, to the satisfaction of the applicable regulatory 

authority, that the proposed monitoring frequency is sufficient 

to represent control device operating conditions; and

(vii) A demonstration that compliance with each of the 

applicable emission limit(s) will be achieved under 

representative operating conditions.

(3) The regulatory authority shall review and approve or 

disapprove the plan according to the following criteria:

(i) Whether the content of the plan includes all of the 

information specified in paragraph (g)(2) of this section; and

(ii) Whether the plan presents sufficient information to 

determine that compliance will be achieved and maintained.

(4) The applicable regulatory authority shall not approve 

an emission averaging implementation plan containing any of the 

following provisions:

(i) Any averaging between emissions of differing pollutants 

or between differing sources; or
267

(ii) The inclusion of any emission source other than an 

existing unit in the same subcategory.

(h) Common stack requirements. For a group of two or more 

existing affected units, each of which vents through a single 

common stack, you may average particulate matter, HCl and 

mercury emissions to demonstrate compliance with the limits in 

Table 2 to this subpart if you satisfy the requirements in 

paragraph (i) or (j) of this section.

(i) For a group of two or more existing units in the same 

subcategory, each of which vents through a common emissions 

control system to a common stack, that does not receive 

emissions from units in other subcategories or categories, you 

may treat such averaging group as a single existing unit for 

purposes of this subpart and comply with the requirements of 

this subpart as if the group were a single unit.

(j) For all other groups of units subject to paragraph (h) 

of this section, the owner or operator may elect to:

(1) Conduct performance tests according to procedures 

specified in §63.7520 in the common stack if affected units from 

other subcategories vent to the common stack. The emission 

limits that the group must comply with are determined by the use 

of equation 6.
268

Where:

En= HAP emission limit, lb/MMBtu, ppm, or ng/dscm;

ELi= Appropriate emission limit from Table 2 to this subpart for 

unit i, in units of lb/MMBtu, ppm or ng/dscm;

Hi= Heat input from unit i, MMBtu;

(2) Conduct performance tests according to procedures 

specified in §63.7520 in the common stack. If affected units 

from nonaffected units vent to the common stack, the units from 

nonaffected units must be shut down or vented to a different 

stack during the performance test); and

(3) Meet the applicable operating limit specified in 

§63.7540 and Table 8 to this subpart for each emissions control 

system (except that, if each unit venting to the common stack 

has an applicable opacity operating limit, then a single 

continuous opacity monitoring system may be located in the 

common stack instead of in each duct to the common stack).

(k) Combination requirements. The common stack of a group 

of two or more existing boilers or process heaters in the same 

subcategory subject to paragraph (h) of this section may be 

treated as a separate stack for purposes of paragraph (b) of 
269

this section and included in an emissions averaging group 

subject to paragraph (b) of this section.

§ 63.7525 What are my monitoring, installation, operation, and 

maintenance requirements?

(a) If your boiler or process heater has a heat input 

capacity of 100 MMBtu per hour or greater, you must install, 

operate, and maintain a continuous emission monitoring system 

(CEMS) for CO and oxygen according to the procedures in 

paragraphs (a)(1) through (6) of this section by the compliance 

date specified in §63.7495. The CO and oxygen shall be monitored 

at the same location at the outlet of the boiler or process 

heater.

(1) Each CEMS must be installed, operated, and maintained 

according to the applicable procedures under Performance 

Specification (PS) 3 or 4A of 40 CFR part 60, appendix B, and 

according to the site-specific monitoring plan developed 

according to §63.7505(d).

(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.

Formatted: No underline

Formatted: No underline
270

(4) The CEMS data must be reduced as specified in 

§63.8(g)(2).

(5) You must calculate and record a 30-day rolling average 

emission rate on a daily basis. A new 30-day rolling average 

emission rate is calculated as the average of all of the hourly 

CO emission data for the preceding 30 operating days.

(6) For purposes of calculating data averages, you must use 

all the data collected during all periods in assessing 

compliance. 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.

(b) If your boiler or process heater has a heat input 

capacity of 250 MMBtu per hour or greater and combustcombusts

coal, biomass, or residual oil, you must install, certify,

maintain, and operate a CEMS measuring PM emissions discharged

to the atmosphere and record the output of the system as 

specified in paragraphs (b)(1) through (b)(6) of this section.

(1) Each CEMS shall be installed, certified, operated, and 

maintained according to the requirements in §63.7540(a)(8).

(2) The initial performance evaluation shall be completed 

no later than 180 days after the date of initial startup of a 

new unit or within 180 days of the compliance date for an 

existing unit, as specified under §63.7495 of this subpart.
271

(3) Compliance with the applicable emissions limit shall be 

determined based on the 24-hour daily (block) average of the 

hourly arithmetic average emissions concentrations using the

continuous monitoring system outlet data. The 24-hour block 

arithmetic average emission concentration shall be calculated 

using EPA Reference Method 19 of appendix A of 40 CFR part 60.

(4) Obtain valid CEMS hourly averages for all operating 

hours on a 30-day rolling average basis. At least two data 

points per hour shall be used to calculate each 1-hour

arithmetic average.

(5) The 1-hour arithmetic averages required shall be 

expressed in lb/MMBtu and shall be used to calculate the boiler 

operating day daily arithmetic average emissions.

(6) When PM emissions data are not obtained because of CEMS 

breakdowns, repairs, calibration checks, and zero and span 

adjustments, emissions data shall be obtained by using other 

monitoring systems as approved by the Administrator or EPA 

Reference Method 19 of appendix A of 40 CFR part 60 to provide,

as necessary, valid emissions data for all operating hours per 

30-day rolling average.

(c) If you have an applicable opacity operating limit, you 

must install, operate, certify and maintain each continuous 

opacity monitoring system (COMS) according to the procedures in 
272

paragraphs (c)(1) through (7) of this section by the compliance 

date specified in §63.7495.

(1) Each COMS must be installed, operated, and maintained 

according to PS 1 of 40 CFR part 60, appendix B.

(2) You must conduct a performance evaluation of each COMS 

according to the requirements in §63.8 and according to PS 1 of 

40 CFR part 60, appendix B.

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

a minimum of one cycle of sampling and analyzing for each 

successive 10-second period and one cycle of data recording for 

each successive 6-minute period.

(4) The COMS data must be reduced as specified in 

§63.8(g)(2).

(5) You must include in your site-specific monitoring plan 

procedures and acceptance criteria for operating and maintaining 

each COMS according to the requirements in §63.8(d). At a 

minimum, the monitoring plan must include a daily calibration 

drift assessment, a quarterly performance audit, and an annual 

zero alignment audit of each COMS.

(6) You must operate and maintain each COMS according to 

the requirements in the monitoring plan and the requirements of 

§63.8(e). You must 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 
273

an annual zero alignment audit. Any 6-minute 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.

(7) You must determine and record all the 6-minute averages 

(and 1-hour block averages as applicable) collected for periods 

during which the COMS is not out of control.

(d) 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 (d)(1) through (5) of this section by the 

compliance date specified in §63.7495.

(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. 
274

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 15-minute 

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) DetermineYou must determine the 3-hour block average of 

all recorded readings, except as provided in paragraph (c)(3) of 

this section.

(5) RecordYou must record the results of each inspection, 

calibration, and validation check.

(e) If you have an operating limit that requires the use of 

a flow measurement device, you must meet the requirements in 

paragraphs (d) and (e)(1) through (4) of this section.

(1) LocateYou must locate the flow sensor and other 

necessary equipment in a position that provides a representative 

flow.

(2) UseYou must use a flow sensor with a measurement 

sensitivity of 2 percent of the flow rate.
275

(3) ReduceYou must reduce swirling flow or abnormal 

velocity distributions due to upstream and downstream 

disturbances.

(4) ConductYou must conduct a flow sensor calibration check 

at least semiannually.

(f) If you have an operating limit that requires the use of 

a pressure measurement device, you must meet the requirements in 

paragraphs (d) and (f)(1) through (6) of this section.

(1) Locate the pressure sensor(s) in a position that 

provides a representative measurement of the pressure.

(2) Minimize or eliminate pulsating pressure, vibration, 

and internal and external corrosion.

(3) Use a gauge with a minimum tolerance of 1.27 

centimeters of water or a transducer with a minimum tolerance of 

1 percent of the pressure range.

(4) Check pressure tap pluggage daily.

(5) Using a manometer, you must check gauge calibration 

quarterly and transducer calibration monthly.

(6) Conduct calibration checks any time the sensor exceeds 

the manufacturer's specified maximum operating pressure range or 

install a new pressure sensor.

(g) If you have an operating limit that requires the use of 

a pH measurement device, you must meet the requirements in 

paragraphs (d) and (g)(1) through (3) of this section.
276

(1) Locate the pH sensor in a position that provides a 

representative measurement of scrubber effluent pH.

(2) Ensure the sample is properly mixed and representative 

of the fluid to be measured.

(3) Check the pH meter's calibration on at least two points 

every 8 hours of process operation.

(h) If you have an operating limit that requires the use of 

equipment to monitor voltage and secondary amperage (or total 

power input) of an electrostatic precipitator (ESP), you must 

use voltage and secondary current monitoring equipment to 

measure voltage and secondary current to the ESP.

(i) If you have an operating limit that requires the use of 

equipment to monitor sorbent injection rate ( e.g. , weigh belt, 

weigh hopper, or hopper flow measurement device), you must meet 

the requirements in paragraphs (c) and (i)(1) through (3) of 

this section.

(1) Locate the device in a position(s) that provides a 

representative measurement of the total sorbent injection rate.

(2) Install and calibrate the device in accordance with 

manufacturer's procedures and specifications.

(3) At least annually, calibrate the device in accordance 

with the manufacturer's procedures and specifications.

(j) If you elect to use a fabric filter bag leak detection 

system to comply with the requirements of this subpart, you must 
277

install, calibrate, maintain, and continuously operate a bag 

leak detection system as specified in paragraphs (j)(1) through 

(8) of this section.

(1) You must install and operate a bag leak detection 

system for each exhaust stack of the fabric filter.

(2) Each bag leak detection system must be installed, 

operated, calibrated, and maintained in a manner consistent with 

the manufacturer's written specifications and recommendations 

and in accordance with the guidance provided in EPA–454/R–98–

015, September 1997.

(3) The bag leak detection system must be certified by the 

manufacturer to be capable of detecting particulate matter 

emissions at concentrations of 10 milligrams per actual cubic 

meter or less.

(4) The bag leak detection system sensor must provide 

output of relative or absolute particulate matter loadings.

(5) The bag leak detection system must be equipped with a 

device to continuously record the output signal from the sensor.

(6) The bag leak detection system must be equipped with an 

alarm system that will sound automatically when an increase in 

relative particulate matter emissions over a preset level is 

detected. The alarm must be located where it is easily heard by 

plant operating personnel.
278

(7) For positive pressure fabric filter systems that do not 

duct all compartments of cells to a common stack, a bag leak 

detection system must be installed in each baghouse compartment 

or cell.

(8) Where multiple bag leak detectors are required, the 

system's instrumentation and alarm may be shared among 

detectors.

§ 63.7530 How do I demonstrate initial compliance with the 

emission limits and work practice standards?

(a) You must demonstrate initial compliance with each 

emission limit that applies to you by conducting initial 

performance tests (performance stack tests and fuel analyses) 

and establishing operating limits, as applicable, according to 

§63.7520, paragraph (c) of this section, and Tables 5 and 7 to 

this subpart.

(b) If you demonstrate compliance through performance stack

testing, you must establish each site-specific operating limit 

in Table 2 to this subpart that applies to you according to the 

requirements in §63.7520, Table 7 to this subpart, and paragraph 

(c)(4) of this section, as applicable. You must also conduct 

fuel analyses according to §63.7521 and establish maximum fuel 

pollutant input levels according to paragraphs (c)(1) through 

(3) of this section, as applicable.
279

(1) You must establish the maximum chlorine fuel input 

(Cinput) during the initial performance testing according to the 

procedures in paragraphs (c)(1)(i) through (iii) of this 

section.

(i) You must determine the fuel type or fuel mixture that 

you could burn in your boiler or process heater that has the 

highest content of chlorine.

(ii) During the performance testing for HCl, you must 

determine the fraction of the total heat input for each fuel 

type burned (Qi) based on the fuel mixture that has the highest 

content of chlorine, and the average chlorine concentration of 

each fuel type burned (Ci).

(iii) You must establish a maximum chlorine input level 

using Equation 7 of this section.

Where:

Clinput = Maximum amount of chlorine entering the boiler or 

process heater through fuels burned in units of pounds per 

million Btu.

Ci = Arithmetic average concentration of chlorine in fuel 

type, i, analyzed according to §63.7521, in units of pounds per 

million Btu.

Qi = Fraction of total heat input from fuel type, i, based 

on the fuel mixture that has the highest content of chlorine. If 

you do not burn multiple fuel types during the performance 
280

testing, it is not necessary to determine the value of this 

term. Insert a value of “1” for Qi.

n = Number of different fuel types burned in your boiler 

or process heater for the mixture that has the highest content 

of chlorine.

(2) You must establish the maximum mercury fuel input level 

(Mercuryinput) during the initial performance testing using the 

procedures in paragraphs (c)(3)(i) through (iii) of this 

section.

(i) You must determine the fuel type or fuel mixture that 

you could burn in your boiler or process heater that has the 

highest content of mercury.

(ii) During the compliance demonstration for mercury, you 

must determine the fraction of total heat input for each fuel 

burned (Qi) based on the fuel mixture that has the highest 

content of mercury, and the average mercury concentration of 

each fuel type burned (HGi).

(iii) You must establish a maximum mercury input level 

using Equation 8 of this section.

Where:

Mercuryinput= Maximum amount of mercury entering the boiler 

or process heater through fuels burned in units of pounds per 

million Btu.
281

HGi= Arithmetic average concentration of mercury in fuel 

type, i, analyzed according to §63.7521, in units of pounds per 

million Btu.

Qi= Fraction of total heat input from fuel type, i, based on 

the fuel mixture that has the highest mercury content. If you do 

not burn multiple fuel types during the performance test, it is 

not necessary to determine the value of this term. Insert a 

value of “1” for Qi.

n = Number of different fuel types burned in your boiler or 

process heater for the mixture that has the highest content of 

mercury.

(3) You must establish parameter operating limits according 

to paragraphs (c)(4)(i) through (iv) of this section.

(i) For a wet scrubber, you must establish the minimum 

scrubber effluent pH, liquid flowrate, and pressure drop as 

defined in §63.7575, as your operating limits during the threerun performance test. If you use a wet scrubber and you conduct 

separate performance tests for particulate matter, HCl, and 

mercury emissions, you must establish one set of minimum 

scrubber effluent pH, liquid flowrate, and pressure drop 

operating limits. The minimum scrubber effluent pH operating 

limit must be established during the HCl performance test. If 

you conduct multiple performance tests, you must set the minimum 

liquid flowrate and pressure drop operating limits at the 

highest minimum values established during the performance tests.

(ii) For an electrostatic precipitator, you must establish 

the minimum voltage and secondary current (or total power 
282

input), as defined in §63.7575, as your operating limits during 

the three-run performance test.

(iii) For a dry scrubber, you must establish the minimum 

sorbent injection rate for each sorbent, as defined in §63.7575, 

as your operating limit during the three-run performance test.

(iv) The operating limit for boilers or process heaters 

with fabric filters that choose to demonstrate continuous 

compliance through bag leak detection systems is that a bag leak 

detection system be installed according to the requirements in 

§63.7525, and that each fabric filter must be operated such that 

the bag leak detection system alarm does not sound more than 5 

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

(c) If you elect to demonstrate compliance with an 

applicable emission limit through fuel analysis, you must 

conduct fuel analyses according to §63.7521 and follow the 

procedures in paragraphs (c)(1) through (5) of this section.

(1) If you burn more than one fuel type, you must determine 

the fuel mixture you could burn in your boiler or process heater 

that would result in the maximum emission rates of the 

pollutants that you elect to demonstrate compliance through fuel 

analysis.

(2) You must determine the 90th percentile confidence level 

fuel pollutant concentration of the composite samples analyzed 
283

for each fuel type using the one-sided z-statistic test 

described in Equation 9 of this section.

Where:

P90= 90th percentile confidence level pollutant 

concentration, in pounds per million Btu.

mean = Arithmetic average of the fuel pollutant 

concentration in the fuel samples analyzed according to 

§63.7521, in units of pounds per million Btu.

SD = Standard deviation of the pollutant concentration in 

the fuel samples analyzed according to §63.7521, 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 emission 

limit for HCl, the HCl emission rate that you calculate for your 

boiler or process heater using Equation 10 of this section must 

not exceed the applicable emission limit for HCl.

Where:

HCl = HCl emission rate from the boiler or process heater 

in units of pounds per million Btu.

Ci90= 90th percentile confidence level concentration of 

chlorine in fuel type, i, in units of pounds per million Btu as 

calculated according to Equation 8 of this section.

Qi= Fraction of total heat input from fuel type, i, based on 

the fuel mixture that has the highest content of chlorine. If 
284

you do not burn multiple fuel types, it is not necessary to 

determine the value of this term. Insert a value of “1” for Qi.

n = Number of different fuel types burned in your boiler or 

process heater for the mixture that has the highest content of 

chlorine.

1.028 = Molecular weight ratio of HCl to chlorine.

(4) To demonstrate compliance with the applicable emission 

limit for mercury, the mercury emission rate that you calculate 

for your boiler or process heater using Equation 11 of this 

section must not exceed the applicable emission limit for 

mercury.

Where:

Mercury = Mercury emission rate from the boiler or process 

heater in units of pounds per million Btu.

HGi90= 90th percentile confidence level concentration of 

mercury in fuel, i, in units of pounds per million Btu as 

calculated according to Equation 8 of this section.

Qi= Fraction of total heat input from fuel type, i, based on 

the fuel mixture that has the highest mercury content. If you do 

not burn multiple fuel types, it is not necessary to determine 

the value of this term. Insert a value of “1” for Qi.

n = Number of different fuel types burned in your boiler or 

process heater for the mixture that has the highest mercury 

content.

(d) If you own or operate an existing unit with a heat 

input capacity of 10 million Btu per hour or less, you must 

submit a signed statement in the Notification of Compliance 
285

Status report that indicates that you conducted a tune-up of the 

unit.

(e) You must submit the energy assessment report, along 

with a signed certification that the assessment is an accurate 

depiction of your facility.

(f) You must submit the Notification of Compliance Status 

containing the results of the initial compliance demonstration 

according to the requirements in §63.7545(e).

CONTINUOUS COMPLIANCE REQUIREMENTSContinuous Compliance

Requirements

§ 63.7535 How do I monitor and collect data to demonstrate 

continuous compliance?

(a) You must monitor and collect data according to this 

section and the site-specific monitoring plan required by 

§63.7505(d).

(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 
286

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. 

§ 63.7540 How do I demonstrate continuous compliance with the 

emission limits and work practice standards?

(a) You must demonstrate continuous compliance with each 

emission limit, operating limit, and work practice standard in 

Tables 1 through 3 to this subpart that applies to you according 

to the methods specified in Table 8 to this subpart and 

paragraphs (a)(1) through (10) 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 63.7510, whichever date comes first, you must not operate 

above any of the applicable maximum operating limits or below 

any of the applicable minimum operating limits listed in Table 4 

to this subpart at any times. Operation above the established 

maximum or below the established minimum operating limits shall 

constitute a deviation of established operating limits. 

Operating limits aremust be confirmed or reestablished during 

performance tests.

(2) As specified in §63.7550(c), you must keep records of 

the type and amount of all fuels burned in each boiler or 

process heater during the reporting period to demonstrate that 

all fuel types and mixtures of fuels burned would either result 
287

in lower emissions of HCl and mercury, than the applicable 

emission limit for each pollutant (if you demonstrate compliance 

through fuel analysis), or result in lower fuel input of 

chlorine and mercury than the maximum values calculated during 

the last performance tests (if you demonstrate compliance 

through performance stack testing).

(3) If you demonstrate compliance with an applicable HCl 

emission limit through fuel analysis and you plan to burn a new 

type of fuel, you must recalculate the HCl emission rate using 

Equation 9 of §63.7530 according to paragraphs (a)(3)(i) through 

(iii) of this section.

(i) You must determine the chlorine concentration for any 

new fuel type in units of pounds per million Btu, based on 

supplier data or your own fuel analysis, according to the 

provisions in your site-specific fuel analysis plan developed 

according to §63.7521(b).

(ii) You must determine the new mixture of fuels that will 

have the highest content of chlorine.

(iii) Recalculate the HCl emission rate from your boiler or 

process heater under these new conditions using Equation 9 of 

§63.7530. The recalculated HCl emission rate must be less than 

the applicable emission limit.

(4) If you demonstrate compliance with an applicable HCl 

emission limit through performance testing and you plan to burn 
288

a new type of fuel or a new mixture of fuels, you must 

recalculate the maximum chlorine input using Equation 5 of 

§63.7530. If the results of recalculating the maximum chlorine 

input using Equation 5 of §63.7530 are higher than the maximum 

chlorine input level established during the previous performance 

test, then you must conduct a new performance test within 60 

days of burning the new fuel type or fuel mixture according to 

the procedures in §63.7520 to demonstrate that the HCl emissions 

do not exceed the emission limit. You must also establish new 

operating limits based on this performance test according to the 

procedures in §63.7530(c).

(5) If you demonstrate compliance with an applicable 

mercury emission limit through fuel analysis, and you plan to 

burn a new type of fuel, you must recalculate the mercury 

emission rate using Equation 11 of §63.7530 according to the 

procedures specified in paragraphs (a)(7)(i) through (iii) of 

this section.

(i) 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, according to the 

provisions in your site-specific fuel analysis plan developed 

according to §63.7521(b).

(ii) You must determine the new mixture of fuels that will 

have the highest content of mercury.
289

(iii) Recalculate the mercury emission rate from your 

boiler or process heater under these new conditions using 

Equation 11 of §63.7530. The recalculated mercury emission rate 

must be less than the applicable emission limit.

(6) If you demonstrate compliance with an applicable 

mercury emission limit through performance testing, and you plan 

to burn a new type of fuel or a new mixture of fuels, you must 

recalculate the maximum mercury input using Equation 7 of 

§63.7530. If the results of recalculating the maximum mercury 

input using Equation 7 of §63.7530 are higher than the maximum 

mercury input level established during the previous performance 

test, then you must conduct a new performance test within 60 

days of burning the new fuel type or fuel mixture according to 

the procedures in §63.7520 to demonstrate that the mercury 

emissions do not exceed the emission limit. You must also 

establish new operating limits based on this performance test 

according to the procedures in §63.7530(c).

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

you demonstrate continuous compliance using a bag leak detection 

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

bag leak detection system alarm and complete corrective actions 

as soon as practical, and operate and maintain the fabric filter 

system such that the alarm does not sound more than 5 percent of 

the operating time during a 6-month period. You must also keep 
290

records of the date, time, and duration of each alarm, the time 

corrective action was initiated and completed, and a brief 

description of the cause of the alarm and the corrective action 

taken. You must also record the percent of the operating time 

during each 6-month period that the alarm sounds. In 

calculating this operating time percentage, if inspection of the 

fabric filter demonstrates that no corrective action is 

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

required, each alarm shall be counted as a minimum of 1 hour. If 

you take longer than 1 hour to initiate corrective action, the 

alarm time shall be counted as the actual amount of time taken 

to initiate corrective action.

(8) If you are required to install a CEMS according to 

§63.7525(a), then you must meet the requirements in paragraphs 

(a)(8)(i) through (iii) of this section.

(i) You must continuously monitor CO according to 

§§63.7525(a) and 63.7535.

(ii) Maintain a CO emission level below or at your 

applicable CO standard in Tables 1 or 2 to this subpart at all 

times.

(iii) Keep records of CO levels according to §63.7555(b).

(9) The owner or operator of an affected source using a 

CEMS measuring PM emissions to meet requirements of this subpart 

shall install, certify, operate, and maintain the CEMS as 
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specified in paragraphs (a)(9)(i) through (a)(9)(iv) of this 

section.

(i) The owner or operator shall conduct a performance 

evaluation of the CEMS according to the applicable requirements 

of §60.13 of 40 CFR, Performance Specification 11 in appendix B 

of 40 CFR part 60, and procedure 2 in appendix F of 40 CFR part

60.

(ii) During each PM correlation testing run of the CEMS 

required by Performance Specification 11 in appendix B of 40 CFR

part 60, PM and O2 (or CO2) data shall be collected concurrently 

(or within a 30-to 60-minute period) by both the CEMS and

conducting performance tests using Method 5 or 5B of appendix A–

3 of 40 CFR part 60 or Method 17 of appendix A–6 of 40 CFR part

60.

(iii) Quarterly accuracy determinations and daily 

calibration drift tests shall be performed in accordance with

procedure 2 in appendix F of 40 CFR part 60. Relative Response 

Audits must be performed annually and Response

Correlation Audits must be performed every 3 years.

(iv) After December 31, 2011, within 60 days after the date 

of completing each performance evaluation conducted to 

demonstrate compliance with this subpart, the owner or operator 

of the affected facility must submit the test data to EPA by 

successfully entering the data electronically into EPA’s WebFIRE 

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292

database through EPA’s Central Data Exchange. The owner or 

operator of an affected facility shall enter the test data into 

EPA’s data base using the Electronic Reporting Tool (ERT) or 

other compatible electronic spreadsheet. 

(10) You (10) If your boiler or process heater is in either 

the Gas 1 (NG/RG) or Metal Process Furnace subcategories and 

have a heat input capacity of 10 million Btu per hour or 

greater, you must conduct a tune-up of the boiler or process 

heater annually to demonstrate continuous compliance as 

specified in paragraphs (a)(10)(i) through (a)(10)(vi) of this 

section.

(i) Inspect the burner, and clean or replace any 

components of the burner as necessary;

(ii) Inspect the flame pattern and make any adjustments to 

the burner necessary to optimize the flame pattern consistent 

with the manufacturer’s specifications;

(iii) Inspect the system controlling the air-to-fuel 

ratio, and ensure that it is correctly calibrated and 

functioning properly;

(iv) Minimize total emissions of CO consistent with the 

manufacturer’s specifications;

(v) 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
293

(vi) Maintain on-site and submit, if requested by the 

Administrator, an annual report containing the information in 

paragraphs (b)(6)(ia)(10)(vi)(A) through (iiiC) of this section,

(iA) 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;

(iiB) A description of any corrective actions taken as a 

part of the combustion adjustment; and

(iiiC) The type and amount of fuel used over the 12 months 

prior to the annual adjustment.

(11) If your boiler or process heater has a heat input 

capacity of less than 10 million Btu per hour, you must conduct 

a tune-up of the boiler or process heater biennially to 

demonstrate continuous compliance as specified in paragraphs 

(a)(10)(i) through (a)(10)(vi) of this section.

(b) You must report each instance in which you did not meet 

each emission limit and operating limit in Tables 1 through 4 to 

this subpart that apply to you. You must also report each 

instance during a startup, shutdown, or malfunction when you did 

not meet each applicable emission limit and operating limit.

These instances are deviations from the emission limits in this 

subpart. These deviations must be reported according to the 

requirements in §63.7550.

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294

§ 63.7541 How do I demonstrate continuous compliance under the 

emission averaging provision?

(a) Following the compliance date, the owner or operator 

must demonstrate compliance with this subpart on a continuous 

basis by meeting the requirements of paragraphs (a)(1) through 

(5) of this section.

(1) For each calendar month, demonstrate compliance with 

the average weighted emissions limit for the existing units 

participating in the emissions averaging option as determined in 

§63.7522(f) and (g);

(2) You must maintain the applicable opacity limit 

according to paragraphs (a)(2)(i) through (ii) of this section.

(i) For each existing unit participating in the emissions 

averaging option that is equipped with a dry control system and 

not vented to a common stack, maintain opacity at or below the 

applicable limit.

(ii) For each group of units participating in the emissions 

averaging option where each unit in the group is equipped with a 

dry control system and vented to a common stack that does not 

receive emissions from nonaffected units, maintain opacity at or 

below the applicable limit at the common stack;

(3) For each existing unit participating in the emissions 

averaging option that is equipped with a wet scrubber, maintain 
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the 3-hour average parameter values at or below the operating 

limits established during the most recent performance test; and

(4) For each existing unit participating in the emissions 

averaging option that has an approved alternative operating 

plan, maintain the 3-hour average parameter values at or below 

the operating limits established in the most recent performance 

test.

(5) For each existing unit participating in the emissions 

averaging option venting to a common stack configuration 

containing affected units from other subcategories, maintain the 

appropriate operating limit for each unit as specified in Table 

4 to this subpart that applies.

(b) Any instance where the owner or operator fails to 

comply with the continuous monitoring requirements in paragraphs 

(a)(1) through (5) of this section is a deviation.

Notification, Reports, and Records

§ 63.7545 What notifications must I submit and when?

(a) You must submit all of the notifications in §§63.7(b) 

and (c), 63.8 (e), (f)(4) and (6), and 63.9 (b) through (h) that 

apply to you by the dates specified.

(b) As specified in §63.9(b)(2), if you startup your 

affected source before [DATE SIXTY60 DAYS AFTER PUBLICATION OF 

THE FINAL RULE IN THE FEDERAL REGISTER], you must submit an 

Initial Notification not later than 120 days after [DATE SIXTY60
296

DAYS AFTER PUBLICATION OF THE FINAL RULE IN THE FEDERAL 

REGISTER].

(c) As specified in §63.9(b)(4) and (b)(5), if you startup 

your new or reconstructed affected source on or after [DATE 

SIXTY60 DAYS AFTER PUBLICATION OF THE FINAL RULE IN THE FEDERAL 

REGISTER], you must submit an Initial Notification not later 

than 15 days after the actual date of startup of the affected 

source.

(d) If you are required to conduct a performance test you 

must submit a Notification of Intent to conduct a performance 

test at least 30 days before the performance test is scheduled 

to begin.

(e) If you are required to conduct an initial compliance 

demonstration as specified in §63.7530(a), you must submit a 

Notification of Compliance Status according to §63.9(h)(2)(ii). 

For each initial compliance demonstration, you must submit the 

Notification of Compliance Status, including all performance 

test results and fuel analyses, before the close of business on 

the 60th day following the completion of the performance test 

and/or other initial compliance demonstrations according to 

§63.10(d)(2). The Notification of Compliance Status report must 

contain all the information specified in paragraphs (e)(1) 

through (9), as applicable.
297

(1) A description of the affected source(s) including 

identification of which subcategory the source is in, the design 

capacity of the source, a description of the add-on controls 

used on the source, description of the fuel(s) burned, including

whether the fuel(s) were determined by you or EPA through a 

petition process to be a non-waste under 40 CFR 241.3, and 

whether the fuel(s) were processed from discarded non-hazardous 

secondary materials within the meaning of 40 CFR 241.3, and 

justification for the selection of fuel(s) burned during the 

performance test.

(2) Summary of the results of all performance tests (stack 

tests and fuel analyses) and calculations conducted to 

demonstrate initial compliance including all established 

operating limits.

(3) A summary of the CO emissions monitoring data and the 

maximum CO emission levels recorded during the performance test 

to show that you have met any applicable emission standard in 

Table 1 or 2 to this subpart.

(4) Identification of whether you plan to demonstrate 

compliance with each applicable emission limit through 

performance stack testing or fuel analysis.

(5) Identification of whether you plan to demonstrate 

compliance by emissions averaging.
298

(6) A signed certification that you have met all applicable 

emission limits and work practice standards.

(7) If you had a deviation from any emission limit, work 

practice standard, or operating limit, you must also submit a 

description of the deviation, the duration of the deviation, and 

the corrective action taken in the Notification of Compliance 

Status report.

(f) If you operate a gaseous fuel unitnatural gas-fired 

boiler or process heater that is subject to the emission limits

specified in Table 1 or 2 to this subpart, and you intend to use 

a fuel other than natural gas or equivalent to fire the affected 

unit, you must submit a notification of alternative fuel use 

within 48 hours of the declaration of a period of natural gas 

curtailment or supply interruption, as defined in §63.7575. The 

notification must include the information specified in 

paragraphs (f)(1) through (5) of this section.

(1) Company name and address.

(2) Identification of the affected unit.

(3) Reason you are unable to use natural gas or equivalent 

fuel, including the date when the natural gas curtailment was 

declared or the natural gas supply interruption began.

(4) Type of alternative fuel that you intend to use.

(5) Dates when the alternative fuel use is expected to 

begin and end.
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§ 63.7550 What reports must I submit and when?

(a) You must submit each report in Table 9 to this subpart 

that applies to you.

(b) Unless the EPA Administrator has approved a different 

schedule for submission of reports under §63.10(a), you must 

submit each report by the date in Table 9 to this subpart and 

according to the requirements in paragraphs (b)(1) through (5) 

of this section.

(1) The first compliance report must cover the period 

beginning on the compliance date that is specified for your 

affected source in §63.7495 and ending on June 30 or December 

31, whichever date is the first date that occurs at least 180 

days after the compliance date that is specified for your source 

in §63.7495.

(2) The first compliance report must be postmarked or 

delivered no later than July 31 or January 31, whichever date is 

the first date following the end of the first calendar half 

after the compliance date that is specified for your source in 

§63.7495.

(3) Each subsequent compliance report must cover the 

semiannual reporting period from January 1 through June 30 or 

the semiannual reporting period from July 1 through December 31.

(4) Each subsequent compliance report must be postmarked or 

delivered no later than July 31 or January 31, whichever date is 
300

the first date following the end of the semiannual reporting

period.

(5) For each affected source that is subject to permitting 

regulations pursuant to 40 CFR part 70 or 40 CFR part 71, and if 

the permitting authority has established dates for submitting 

semiannual reports pursuant to 40 CFR 70.6(a)(3)(iii)(A) or 40 

CFR 71.6(a)(3)(iii)(A), you may submit the first and subsequent 

compliance reports according to the dates the permitting 

authority has established instead of according to the dates in 

paragraphs (b)(1) through (4) of this section.

(c) The compliance report must contain the information 

required in paragraphs (c)(1) through (11) of this section.

(1) Company name and address.

(2) Statement by a responsible official with that 

official's name, title, and signature, certifying the truth, 

accuracy, and completeness of the content of the report.

(3) Date of report and beginning and ending dates of the 

reporting period.

(4) The total fuel use by each affected source subject to 

an emission limit, for each calendar month within the semiannual 

reporting period, including, but not limited to, a description 

of the fuel, including whether the fuel has received a non-waste 

determination by youEPA or EPAyour basis for concluding that the 
301

fuel is not a waste, and the total fuel usage amount with units 

of measure.

(5) A summary of the results of the annual performance 

tests and documentation of any operating limits that were 

reestablished during this test, if applicable. If you are 

conducting stack tests once every three years consistent with 

section 63.7515(b) or (c), the date of the last three stack 

tests, a comparison of the emission level you achieved in the 

last three stack tests to the 90 percent emission limit 

threshold required in section 63.7515(b) or (c), and a statement 

as to whether there have been any operational changes since the 

last stack test that could increase emissions.

(6) A signed statement indicating that you burned no new 

types of fuel. Or, if you did burn a new type of fuel, you must 

submit the calculation of chlorine input, using Equation 5 of 

§63.7530, that demonstrates that your source is still within its 

maximum chlorine input level established during the previous 

performance testing (for sources that demonstrate compliance 

through performance testing) or you must submit the calculation 

of HCl emission rate using Equation 9 of §63.7530 that 

demonstrates that your source is still meeting the emission 

limit for HCl emissions (for boilers or process heaters that 

demonstrate compliance through fuel analysis). If you burned a 

new type of fuel, you must submit the calculation of mercury 
302

input, using Equation 7 of §63.7530, that demonstrates that your 

source is still within its maximum mercury input level 

established during the previous performance testing (for sources 

that demonstrate compliance through performance testing), or you 

must submit the calculation of mercury emission rate using 

Equation 11 of §63.7530 that demonstrates that your source is 

still meeting the emission limit for mercury emissions (for 

boilers or process heaters that demonstrate compliance through 

fuel analysis).

(7) If you wish to burn a new type of fuel and you can not 

demonstrate compliance with the maximum chlorine input operating 

limit using Equation 5 of §63.7530 or the maximum mercury input 

operating limit using Equation 7 of §63.7530, you must include 

in the compliance report a statement indicating the intent to 

conduct a new performance test within 60 days of starting to 

burn the new fuel.

(8) The hours of operation for each boiler and process 

heater that is subject to an emission limit for each calendar 

month within the semiannual reporting period. This requirement 

applies only to limited use boilers and process heaters.

(9 (8) If there are no deviations from any emission 

limits or operating limits in this subpart that apply to you, a 

statement that there were no deviations from the emission limits

or operating limits during the reporting period.
303

(109) If there were no deviations from the monitoring 

requirements including no periods during which the CMSs, 

including CEMS, COMS, and CPMS, were out of control as specified 

in §63.8(c)(7), a statement that there were no deviations and no 

periods during which the CMS were out of control during the 

reporting period.

(d) For each deviation from an emission limit or operating

limit in this subpart that occurs at an affected source where 

you are not using a CMS to comply with that emission limit or

operating limit, the compliance report must additionally contain 

the information required in paragraphs (d)(1) through (4) of 

this section. This includes periods of startup, shutdown, and 

malfunction.

(1) The total operating time of each affected source during 

the reporting period.

(2) A description of the deviation and which emission limit

or operating limit from which you deviated.

(3) Information on the number, duration, and cause of 

deviations (including unknown cause), as applicable, and the 

corrective action taken.

(4) A copy of the test report if the annual performance 

test showed a deviation from the emission limits.

(e) For each deviation from an emission limit, operating 

limit, and monitoring requirement in this subpart occurring at 
304

an affected source where you are using a CMS to comply with that 

emission limit or operating limit, you must include the 

information required in paragraphs (e) (1) through (12) of this 

section. This includes periods of startup, shutdown, and 

malfunction and any deviations from your site-specific 

monitoring plan as required in §63.7505(d).

(1) The date and time that each malfunction deviation 

started and stopped and description of the nature of the 

deviation ( i.e. ,., what you deviated from).

(2) The date and time that each CMS was inoperative, except 

for zero (low-level) and high-level checks.

(3) The date, time, and duration that each CMS was out of 

control, including the information in §63.8(c)(8).

(4) The date and time that each deviation started and 

stopped, and whether each deviation occurred during a period of 

startup, shutdown, or malfunction or during another period.

(5) A summary of the total duration of the deviation during 

the reporting period and the total duration as a percent of the 

total source operating time during that reporting period.

(6) An analysis of the total duration of the deviations 

during the reporting period into those that are due to startup, 

shutdown, control equipment problems, process problems, other 

known causes, and other unknown causes.
305

(7) A summary of the total duration of CMSs downtime during 

the reporting period and the total duration of CMS downtime as a 

percent of the total source operating time during that reporting 

period.

(8) An identification of each parameter that was monitored 

at the affected source for which there was a deviation.

(9) A brief description of the source for which there was a 

deviation.

(10) A brief description of each CMS for which there was a 

deviation.

(11) The date of the latest CMS certification or audit for 

the system for which there was a deviation.

(12) A description of any changes in CMSs, processes, or 

controls since the last reporting period for the source for 

which there was a deviation.

(f) Each affected source that has obtained a title V 

operating permit pursuant to 40 CFR part 70 or 40 CFR part 71 

must report all deviations as defined in this subpart in the 

semiannual monitoring report required by 40 CFR 

70.6(a)(3)(iii)(A) or 40 CFR 71.6(a)(3)(iii)(A). If an affected 

source submits a compliance report pursuant to Table 9 to this 

subpart along with, or as part of, the semiannual monitoring 

report required by 40 CFR 70.6(a)(3)(iii)(A) or 40 CFR 

71.6(a)(3)(iii)(A), and the compliance report includes all 
306

required information concerning deviations from any emission 

limit, operating limit, or work practice requirement in this 

subpart, submission of the compliance report satisfies any 

obligation to report the same deviations in the semiannual 

monitoring report. However, submission of a compliance report 

does not otherwise affect any obligation the affected source may 

have to report deviations from permit requirements to the permit 

authority.

(g) In addition to the information required in 

§63.9(h)(2), your notification must include the following 

certification(s) of compliance, as applicable, and signed by a 

responsible official:

(i) “This facility complies with the requirements in 

§63.7540(a)(10) to conduct an annual tune-up of the unit”.

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

according to §63.7530(e).”

(iii) “No secondary materialmaterials that are solid waste 

were combusted in any affected unit.”

(h) After December 31, 2011, within 60 days after the date of 

completing each performance evaluation conducted to demonstrate 

compliance with this subpart, the owner or operator of the 

affected facility must submit the test data to EPA by 

successfully entering the data electronically into EPA’s WebFIRE 

databasedata base through EPA’s Central Data Exchange. The 
307

owner or operator of an affected facility shall enter the test 

data into EPA’s data base using the Electronic Reporting Tool 

(ERT) or other compatible electronic spreadsheet. Only 

performance evaluation data collected using methods compatible 

with ERT are subject to this requirement to be submitted 

electronically into EPA’s WebFIRE database. 

§ 63.7555 What records must I keep?

(a) You must keep records according to paragraphs (a)(1) 

through (3) of this section.

(1) A copy of each notification and report that you 

submitted to comply with this subpart, including all 

documentation supporting any Initial Notification or 

Notification of Compliance Status or semiannual compliance 

report that you submitted, according to the requirements in 

§63.10(b)(2)(xiv).

(2) Records of performance stack tests, fuel analyses, or 

other compliance demonstrations, performance evaluations, and 

opacity observations as required in §63.10(b)(2)(viii).

(b) For each CEMS, CPMS, and COMS, you must keep records 

according to paragraphs (b)(1) through (5) of this section.

(1) Records described in §63.10(b)(2) (vi) through (xi).

(2) Monitoring data for continuous opacity monitoring 

system during a performance evaluation as required in 

§63.6(h)(7)(i) and (ii).
308

(3) Previous ( i.e., superseded) versions of the 

performance evaluation plan as required in §63.8(d)(3).

(4) Request for alternatives to relative accuracy test for 

CEMS as required in §63.8(f)(6)(i).

(5) Records of the date and time that each deviation 

started and stopped, and whether the deviation occurred during a 

period of startup, shutdown, or malfunction or during another 

period.

(c) You must keep the records required in Table 8 to this 

subpart including records of all monitoring data and calculated 

averages for applicable operating limits such as opacity, 

pressure drop, and pH to show continuous compliance with each 

emission limit and operating limit that applies to you.

(d) For each boiler or process heater subject to an 

emission limit, you must also keep the records in paragraphs 

(d)(1) through (5) of this section.

(1) You must keep records of monthly fuel use by each 

boiler or process heater, including the type(s) of fuel and 

amount(s) used.

(2) If any of the fuels you combust received a non-waste 

determination undernon-hazardous secondary materials that have 

been determined not to be solid waste pursuant to 40 CFR 

24141.3,(b)(1), you must keep a record which documents how the 

fuel secondary material meets each of the legitimacy criteria
309

and. If you combust a fuel that has been processed from a 

discarded non-hazardous secondary material pursuant to 

241.3(b)(2), you must keep records as to how the operations that 

produced the fuel satisfies the definition of processing, if 

applicable, consistent with in 40 CFR 241.32. If the fuel did 

not remain within the control of the generator, you must keep a 

copy offuel received a non-waste determination pursuant to the 

petition process submitted under 40 CFR 241.3, and(c), you must 

keep a record which documents how the fuel satisfies the nonwaste determination granted by EPArequirements of the petition 

process.

(3) You must keep records of monthly hours of operation by 

each boiler or process heater. This requirement applies only to 

limited-use boilers and process heaters.

(4) A copy of all calculations and supporting documentation 

of maximum chlorine fuel input, using Equation 5 of §63.7530, 

that were done to demonstrate continuous compliance with the HCl 

emission limit, for sources that demonstrate compliance through 

performance testing. For sources that demonstrate compliance 

through fuel analysis, a copy of all calculations and supporting 

documentation of HCl emission rates, using Equation 9 of 

§63.7530, that were done to demonstrate compliance with the HCl 

emission limit. Supporting documentation should include results 

of any fuel analyses and basis for the estimates of maximum 
310

chlorine fuel input or HCl emission rates. You can use the 

results from one fuel analysis for multiple boilers and process 

heaters provided they are all burning the same fuel type. 

However, you must calculate chlorine fuel input, or HCl emission 

rate, for each boiler and process heater.

(5) A copy of all calculations and supporting documentation 

of maximum mercury fuel input, using Equation 7 of §63.7530, 

that were done to demonstrate continuous compliance with the 

mercury emission limit for sources that demonstrate compliance 

through performance testing. For sources that demonstrate 

compliance through fuel analysis, a copy of all calculations and 

supporting documentation of mercury emission rates, using 

Equation 11 of §63.7530, that were done to demonstrate 

compliance with the mercury emission limit. Supporting 

documentation should include results of any fuel analyses and 

basis for the estimates of maximum mercury fuel input or mercury 

emission rates. You can use the results from one fuel analysis 

for multiple boilers and process heaters provided they are all 

burning the same fuel type. However, you must calculate mercury 

fuel input, or mercury emission rates, for each boiler and 

process heater.

(6) If consistent with 63.7555(b) and (c), you choose to 

stack test less frequently than annually, you must keep annual 

records that document that your emissions in the previous stack 
311

test(s) were less than 90 percent of the applicable emission 

limit, and document that there was no change in source 

operations including fuel composition and operation of air 

pollution control equipment that would cause emissions of the 

relevant pollutant to increase within the past year.

(7) If you operate a gaseous fuel unit that is subject to 

the emission limits specified in Table 1 or 2 to this subpart, 

and you intend to use a fuel other than natural gas or 

equivalent to fire the affected unit, you must keep records of 

the information required by the notification under 63.XXXX7550, 

and records of the total hours per calendar year that liquid 

fuel is burned.

(e) If you elect to average emissions consistent with 

63.7522, you must additionally keep a copy of the emission 

averaging implementation plan required in 63.7522(g), all 

calculations required under 63.7522, including daily records of 

heat input or steam generation, as applicable, and monitoring 

records consistent with 63.7541. 

§ 63.7560 In what form and how long must I keep my records?

(a) Your records must be in a form suitable and readily 

available for expeditious review, according to §63.10(b)(1).

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

for 5 years following the date of each occurrence, measurement, 

maintenance, corrective action, report, or record.
312

(c) You must keep each record on site for at least 2 years 

after the date of each occurrence, measurement, maintenance, 

corrective action, report, or record, according to §63.10(b)(1). 

You can keep the records off site for the remaining 3 years.

OTHER REQUIREMENTS AND INFORMATION

Other Requirements and Information

§ 63.7565 What parts of the General Provisions apply to me?

Table 10 to this subpart shows which parts of the General 

Provisions in §§63.1 through 63.15 apply to you.

§ 63.7570 Who implements and enforces this subpart?

(a) This subpart can be implemented and enforced by U.S. 

EPA, or a delegated authority such as your State, local, or 

tribal agency. If the EPA Administrator has delegated authority 

to your State, local, or tribal agency, then that agency (as 

well as the U.S. EPA) has the authority to implement and enforce 

this subpart. You should contact your EPA Regional Office to 

find out if this subpart is delegated to your State, local, or 

tribal agency.

(b) In delegating implementation and enforcement authority 

of this subpart to a State, local, or tribal agency under 40 CFR 

part 63, subpart E, the authorities listed in paragraphs (b)(1) 

through (5) of this section are retained by the EPA 

Administrator and are not transferred to the State, local, or 
313

tribal agency, however, the U.S. EPA retains oversight of this 

subpart and can take enforcement actions, as appropriate.

(1) Approval of alternatives to the non-opacity emission 

limits and work practice standards in §63.7500(a) and (b) under 

§63.6(g).

(2) Approval of alternative opacity emission limits in 

§63.7500(a) under §63.6(h)(9).

(3) Approval of major change to test methods in Table 5 to 

this subpart under §63.7(e)(2)(ii) and (f) and as defined in 

§63.90, and alternative analytical methods requested under 

63.7521(b)(2).

(4) Approval of major change to monitoring under §63.8(f) 

and as defined in §63.90, and approval of alternative operating 

parameters under 63.7500(a)(2) and 63.7522(g)(2).

(5) Approval of major change to recordkeeping and reporting 

under §63.10(fe) and as defined in §63.90.

§ 63.7575 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 a group of instruments that 

are 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, 
314

triboelectric, light scattering, light transmittance, or other 

principle to monitor relative particulate matter loadings.

Biomass fuel means but is not limited to, wood residue, and 

wood products ( e.g. ,., trees, tree stumps, tree limbs, bark, 

lumber, sawdust, sanderdust, chips, scraps, slabs, millings, and 

shavings); animal littermanure, including litter and other 

bedding materials; vegetative agricultural and silvicultural 

materials, such as logging residues (slash), nut and grain hulls 

and chaff ( e.g. ,., almond, walnut, peanut, rice, and wheat), 

bagasse, orchard prunings, corn stalks, coffee bean hulls and 

grounds. This definition of biomass fuel is not intended to 

suggest that these materials are or not solid waste.

Blast furnace gas fuel-fired boiler or process heater means 

an industrial/commercial/institutional boiler or process heater 

that receives 90 percent or more of its total heat input (based 

on an annual average) from blast furnace gas.

Boiler means an enclosed device using controlled flame 

combustion and having the primary purpose of recovering 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 
315

fuel system (including burners), blowdown system, combustion 

control system, and energy consuming systems. 

Coal means all solid fuels classifiable as anthracite, 

bituminous, sub-bituminous, or lignite by the American Society 

for Testing and Materials in ASTM D388–991.1 , “Standard 

Specification for Classification of Coals by Rank1 ” 

(incorporated by reference, see §63.14(b)), coal refuse, and 

petroleum coke. Synthetic fuels derived from coal for the 

purpose of creating useful heat including but not limited to, 

solvent-refined coal, coal-oil mixtures, and coal-water 

mixtures, for the purposes of this subpart. Coal derived gases 

are excluded from this definition.

Coal refuse means any by-product of coal mining or coal 

cleaning operations with an ash content greater than 50 percent 

(by weight) and a heating value less than 13,900 kilojoules per 

kilogram (6,000 Btu per pound) on a dry basis.

Commercial/institutional boiler means a boiler used in 

commercial establishments or institutional establishments such 

as medical centers, research centers, institutions of higher 

education, hotels, and laundries to provide electricity, steam, 

and/or hot water.

Common Stack means the exhaust of emissions from two or 

more affected units through a single flue.
316

Cost-effective energy conservation measure means a measure 

that is implemented to improve the energy efficiency of the 

boiler or facility that has a payback (return of investment) 

period of three or fewertwo years or less. 

Deviation. (1) Deviation means any instance in which an 

affected source subject to this subpart, or an owner or operator 

of such a source:

(i) Fails to meet any requirement or obligation established 

by this subpart including, but not limited to, any emission 

limit, operating limit, or work practice standard; or

(ii) Fails to meet any term or condition that is adopted to 

implement an applicable requirement in this subpart and that is 

included in the operating permit for any affected source 

required to obtain such a permit.

(2) A deviation is not always a violation. 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.

Distillate oil means fuel oils, including recycled oils, 

that comply with the specifications for fuel oil numbers 1 and 

2, as defined by the American Society for Testing and Materials 

in ASTM D396–02a, “Standard Specifications for Fuel Oils1 ” 

(incorporated by reference, see §63.14(b)).
317

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 and process 

heaters are included in this definition.

Dutch oven means a unit having a refractory-walled cell 

connected to a conventional boiler setting. Fuel materials are 

introduced through an opening in the roof of the Dutch oven and 

burn in a pile on its floor.

Electric utility steam generating unit means a fossil fuelfired combustion unit of more than 25 megawatts that serves a 

generator that produces electricity for sale. A fossil fuelfired unit that cogenerates steam and electricity and supplies 

more than one-third of its potential electric output capacity 

and more than 25 megawatts electrical output to any utility 

power distribution system for sale is considered an electric 

utility steam generating unit.

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.
318

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 6 to subpart DDDDD:

(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.
319

(4) An equivalent procedure for determining heat content 

means a published VCS or EPA method to obtain gross calorific 

(or higher heating) value.

(5) An equivalent procedure for determining fuel moisture 

content means a published VCS or EPA method to obtain moisture 

content. If the sample analysis plan calls for determining 

metals (especially the mercury, selenium, or arsenic) using an 

aliquot of the dried sample, then the drying temperature must be 

modified to prevent vaporizing these metals. On the other hand, 

if metals analysis is done on an “as received” basis, a separate 

aliquot can be dried to determine moisture content and the 

metals concentration mathematically adjusted to a dry basis.

(6) An equivalent pollutant (mercury) determinative or 

analytical procedure means a published VCS or EPA method that 

clearly states that the standard, practice, or method is 

appropriate for the pollutant and the fuel matrix and has a 

published detection limit equal or lower than the methods listed 

in Table 6 to subpart DDDDD 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 parts 60 and 61, requirements within any 
320

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, residual oil. Individual fuel types received from 

different suppliers are not considered new fuel types. 

Fluidized Bed Boiler means a boiler utilizing a fluidized 

bed combustion process. 

Fluidized bed combustion means a process where a fuel is 

burned in a bed of granulated particles which are maintained in 

a mobile suspension by the forward flow of air and combustion 

products.

Fuel cell means a boiler type in which the fuel is dropped 

onto suspended fixed grates and is fired in a pile. The 

refractory-lined fuel cell uses combustion air preheating and 

positioning of secondary and tertiary air injection ports to 

improve boiler efficiency.

Gaseous fuel includes, but is not limited to, natural gas, 

process gas, landfill gas, coal derived gas, refinery gas, and 

biogas. Blast furnace gas is exempted from this definition.

Heat input means heat derived from combustion of fuel in a 

boiler or process heater and does not include the heat input 
321

from preheated combustion air, recirculated flue gases, or 

exhaust gases from other sources such as gas turbines, internal 

combustion engines, kilns, etc.

Hot water heater means a closed vessel with a capacity of 

no more than 120 U.S. gallons in which water is heated by 

combustion of gaseous or liquid fuel and is withdrawn for use 

external to the vessel at pressures not exceeding 160 psig, 

including the apparatus by which the heat is generated and all 

controls and devices necessary to prevent water temperatures 

from exceeding 210 °F (99 °C).

Industrial boiler means a boiler used in manufacturing, 

processing, mining, and refining or any other industry to 

provide steam, hot water, and/or electricity.

Liquid fuel subcategory includes any boiler or process 

heater of any design that does not burn any solid fuel and burns 

any liquid fuel either alone or in combination with gaseous 

fuels. Gaseous fuel boilers and process heaters that burn 

liquid fuel during periods of gas curtailment, gas supply 

emergencies or for periodic testing of liquid fuel not to exceed 

a combined total of 48 hours during any calendar year are not 

included in this definitionburns more than 10 percent liquid 

fuel and less than 10 percent solid fuel, on an annual heat 

input basis.
322

Liquid fuel includes, but is not limited to, distillate 

oil, residual oil, on-spec used oil, and process 

liquidsbiodiesel.

Metal process furnaces include natural gas-fired annealing 

furnaces, preheat furnaces, reheat furnaces, aging furnaces, and 

heat treat furnaces.

Minimum pressure drop means 90 percent of the test average 

pressure drop measured according to Table 7 to this subpart 

during the most recent performance test demonstrating compliance 

with the applicable emission limit.

Minimum scrubber effluent pH means 90 percent of the test 

average effluent pH measured at the outlet of the wet scrubber 

according to Table 7 to this subpart during the most recent 

performance test demonstrating compliance with the applicable 

hydrogen chloride emission limit.

Minimum scrubber flow rate means 90 percent of the test 

average flow rate measured according to Table 7 to this subpart 

during the most recent performance test demonstrating compliance 

with the applicable emission limit.

Minimum sorbent flowinjection rate means 90 percent of the 

test average sorbent (or activated carbon) flowinjection rate

for each sorbent measured according to Table 7 to this subpart 

during the most recent performance test demonstrating compliance 

with the applicable emission limits.
323

Minimum voltage or amperage means 90 percent of the test 

average voltage or amperage to the electrostatic precipitator 

measured according to Table 7 to this subpart during the most 

recent performance test demonstrating compliance with the 

applicable emission limits.

Natural gas means:

(1) A naturally occurring mixture of hydrocarbon and 

nonhydrocarbon gases found in geologic formations beneath the 

earth's surface, of which the principal constituent is methane; 

or

(2) Liquid petroleum gas, as defined by the American 

Society for Testing and Materials in ASTM D1835–03a, “Standard 

Specification for Liquid Petroleum Gases” (incorporated by 

reference, see §63.14(b)).

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.

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 
324

gas does not constitute a period of natural gas curtailment or 

supply interruption.

Process heater means an enclosed device using controlled 

flame, that is not a boiler, and the unit's primary purpose is 

to transfer heat indirectly to a process material (liquid, gas, 

or solid) or to a heat transfer material for use in a process 

unit, instead of generating steam. Process heaters are devices 

in which the combustion gases do not directly come into contact 

with process materials. A device combusting solid waste, as 

defined in 40 CFR 241.3, is not a process heater. Process 

heaters do not include units used for comfort heat or space 

heat, food preparation for on-site consumption, or autoclaves.

Pulverized coal boiler means a boiler in which pulverized 

coal is introduced into an air stream that carries the coal to 

the combustion chamber of the boiler where it is fired in 

suspension.

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 

Manager certified by the Association of Energy Engineers, or the 

equivalent.

Residual oil means crude oil, and all fuel oil numbers 4, 5 

and 6, as defined by the American Society for Testing and 
325

Materials in ASTM D396–02a, “Standard Specifications for Fuel 

Oils1 ” (incorporated by reference, see §63.14(b)).

Responsible official means responsible official as defined 

in 40 CFR 70.2.

Stoker means a unit consisting of a mechanically operated 

fuel feeding mechanism, a stationary or moving grate to support 

the burning of fuel and admit undergrate air to the fuel, an 

overfire air system to complete combustion, and an ash discharge 

system. There are two general types of stokers: underfeed and 

overfeed. Overfeed stokers include mass feed and spreader 

stokers.

Suspension boiler means a unit designed to feed the fuel by 

means of fuel distributors. The distributors inject air at the 

point where the fuel is introduced into the boiler in order to 

spread the fuel material over the boiler width. The drying (and 

much of the combustion) occurs while the material is suspended 

in air. The combustion of the fuel material is completed on a 

grate or floor below. Suspension boilers almost universally are 

designed to have high heat release rates to quickly dry the wet 

fuel as it is blown into the boilers.

Temporary boiler means any gaseous or liquid fuel boiler 

that is designed to, and is capable of, being carried or moved 

from one location to another. A temporary boiler that remains 

at a location for more than 180 consecutive days is no longer 
326

considered to be a temporary boiler. Any temporary boiler that 

replaces a temporary boiler at a location and is intended to 

perform the same or similar function will be included in 

calculating the consecutive time period.

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.

Unit designed to burn biomass subcategory includes any 

boiler or process heater that burns at least 10 percent biomass, 

but less than 10 percent coal, on a heat input basis on an 

annual average, either alone or in combination with liquid fuels 

or gaseous fuels.

Unit designed to burn coal subcategory includes any boiler 

or process heater that burns any coal alone or at least 10 

percent coal on a heat input basis on an annual average either

alone or in combination with biomass, liquid fuels, or gaseous 

fuels.

Unit designed to burn gas 1 (NG/RG) subcategory includes 

any boiler or process heater that burns at least 90 percent

natural gas and/or refinery gas on a heat input basis on an 

annual average.

Unit designed to burn gas 2 (other) subcategory includes 

any boiler or process heater that burns gaseous fuels other than 
327

natural gas and/or refinery gas not combined with any solid or 

liquid fuels.

Unit designed to burn oil subcategory includes any boiler 

or process heater that burns any liquid fuel, but less than 10 

percent solid fuel on a heat input basis on an annual average, 

either alone or in combination with gaseous fuels. Gaseous fuel 

boilers and process heaters that burn liquid fuel during periods 

of gas curtailment, gas supply emergencies or for periodic 

testing of liquid fuel not to exceed a combined total of 48 

hours during any calendar year are not included in this 

definition.

Voluntary Consensus Standards or VCS mean technical 

standards ( e.g. , materials specifications, test methods, 

sampling procedures, business practices) developed or adopted by 

one or more voluntary consensus bodies. EPA/OAQPS has by 

precedent only used VCS that are written in English. Examples of 

VCS bodies are: American Society of Testing and Materials 

(ASTM), American Society of Mechanical Engineers (ASME), 

International Standards Organization (ISO), Standards Australia 

(AS), British Standards (BS), Canadian Standards (CSA), European 

Standard (EN or CEN) and German Engineering Standards (VDI). The 

types of standards that are not considered VCS are standards 

developed by: the U.S. states, e.g. , California (CARB) and 

Texas (TCEQ); industry groups, such as American Petroleum 
328

Institute (API), Gas Processors Association (GPA), and Gas 

Research Institute (GRI); and other branches of the U.S. 

government, e.g. Department of Defense (DOD) and Department of 

Transportation (DOT). This does not preclude EPA from using 

standards developed by groups that are not VCS bodies within 

their rule. When this occurs, EPA has done searches and reviews 

for VCS equivalent to these non-EPA methods.

Waste heat boilersboiler means a device that recovers 

normally unused energy and converts it to usable heat. Waste 

heat recovery 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.

Waste heat process heater means an enclosed device that 

recovers normally unused energy and converts it to usable heat. 

Waste heat process heaters 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 process heater 

are not considered waste heat process heaters, but are 

considered process heaters. Waste heat process heaters are also 

referred to as recuperative process heaters.
329

Wet scrubber means any add-on air pollution control device 

that mixes an aqueous stream or slurry with the exhaust gases 

from a boiler or process heater to control emissions of 

particulate matter and/or to absorb and neutralize acid gases, 

such as hydrogen chloride.

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.

TABLES TO SUBPARTTables to Subpart DDDDD OF PARTof Part 63

Table 1 to Subpart DDDDD of Part 63—Emission Limits for New or 

Reconstructed Boilers and Process Heaters

As stated in §63.7500, you must comply with the following 

applicable emission limits:

If your boiler or 

process heater is 

in this 

subcategory ...

For the following 

pollutants . . .

You must meet the following emission 

limits and work practice standards . 

. .

1. Pulverized 

coal a. Particulate Matter 0.0009001 lb per MMBtu of heat input.

 b. Hydrogen Chloride 0.0000500006 lb per MMBtu of heat 

input.

 c. Mercury

0.00000072.0E-06 lb per MMBtu of heat 

input.

 d. CO

190 ppm by volume on a dry basis 

corrected to 3 percent oxygen (30-day 

rolling average for units 100 

MMBtu/hr or greater, 3-run average 

for units less than 100 MMBtu/hr).

e. Dioxin/Furan 0.002 ng/dscm (TEQ) corrected to 7 

percent oxygen.

2. Stokers 

designed to burn 

coal

a. Particulate Matter 0.0009001 lb per MMBtu of heat input.

 b. Hydrogen Chloride 0.0000500006 lb per MMBtu of heat 

input.

 c. Mercury 0.00000072.0E-06 lb per MMBtu of heat 

Formatted Table
330

input.

 d. CO

7 ppm by volume on a dry basis 

corrected to 3 percent oxygen (30-day 

rolling average for units 100 

MMBtu/hr or greater, 3-run average 

for units less than 100 MMBtu/hr). 

e. Dioxin/Furan 0.003 ng/dscm (TEQ) corrected to 7 

percent oxygen.

3. Fluidized bed 

units designed to 

burn coal

a. Particulate Matter 0.0009001 lb per MMBtu of heat input.

 b. Hydrogen Chloride 0.0000500006 lb per MMBtu of heat 

input.

 c. Mercury 0.00000072.0E-06 lb per MMBtu of heat 

input.

d. CO

4030 ppm by volume on a dry basis 

corrected to 3 percent oxygen (30-day 

rolling average for units 100 

MMBtu/hr or greater, 3-run average 

for units less than 100 MMBtu/hr).

e. Dioxin/Furan 0.00003 ng/dscm (TEQ) corrected to 7 

percent oxygen.

4. Stokers 

designed to burn 

biomass

a. Particulate Matter 0.007008 lb per MMBtu of heat input.

 b. Hydrogen Chloride 0.0006004 lb per MMBtu of heat input.

 c. Mercury 0.000000072.0E-07 lb per MMBtu of 

heat input.

d. CO

780560 ppm by volume on a dry basis 

corrected to 3 percent oxygen (30-day 

rolling average for units 100 

MMBtu/hr or greater, 3-run average 

for units less than 100 MMBtu/hr).

e. Dioxin/Furan 0.00005 ng/dscm (TEQ) corrected to 7 

percent oxygen.

5. Fluidized bed 

units designed to 

burn biomass

a. Particulate Matter 0.007008 lb per MMBtu of heat input.

 b. Hydrogen Chloride 0.0006004 lb per MMBtu of heat input.

 c. Mercury 0.000000072.0E-07 lb per MMBtu of 

heat input.

d. CO

40 ppm by volume on a dry basis 

corrected to 3 percent oxygen (30-day 

rolling average for units 100 

MMBtu/hr or greater, 3-run average 

for units less than 100 MMBtu/hr).

e. Dioxin/Furan 0.007 ng/dscm (TEQ) corrected to 7 

percent oxygen.

6. Suspension 

burners/Dutch a. Particulate Matter 0.007008 lb per MMBtu of heat input.

Formatted Table

Formatted Table

Formatted Table
331

Ovens designed to 

burn biomass

 b. Hydrogen Chloride 0.0006004 lb per MMBtu of heat input.

c. Mercury 0.000000072.0E-07 lb per MMBtu of 

heat input.

d. CO

4601,010 ppm by volume on a dry basis 

corrected to 3 percent oxygen (30-day 

rolling average for units 100

MMBtu/hr or greater, 3-run average 

for units less than 100 MMBtu/hr).

e. Dioxin/Furan 0.03 ng/dscm (TEQ) corrected to 7 

percent oxygen.

7. Fuel cells 

designed to burn 

biomass

a. Particulate Matter 0.007008 lb per MMBtu of heat input.

b. Hydrogen Chloride 0.0006004 lb per MMBtu of heat input.

c. Mercury 0.000000072.0E-07 lb per MMBtu of 

heat input.

d. CO

270 ppm by volume on a dry basis 

corrected to 3 percent oxygen (30-day 

rolling average for units 100 

MMBtu/hr or greater, 3-run average 

for units less than 100 MMBtu/hr).

e. Dioxin/Furan 0.00040005 ng/dscm (TEQ) corrected to 

7 percent oxygen.

8. Units designed 

to burn liquid 

fuel

a. Particulate Matter 0.002 lb per MMBtu of heat input.

b. Hydrogen Chloride 0.00010004 lb per MMBtu of heat 

input.

c. Mercury 0.00000033.0E-07 lb per MMBtu of heat 

input.

d. CO

1 ppm by volume on a dry basis 

corrected to 3 percent oxygen (30-day 

rolling average for units 100 

MMBtu/hr or greater, 3-run average 

for units less than 100 MMBtu/hr).

e. Dioxin/Furan 0.000005002 ng/dscm (TEQ) corrected 

to 7 percent oxygen.

9. Units designed 

to burn natural 

gas/refinery 

gasother gases

a. Particulate Matter 0.0004003 lb per MMBtu of heat input.

b. Hydrogen Chloride 0.00023.0E-06 lb per MMBtu of heat 

input.

c. Mercury 0.0000000022.0E-07 lb per MMBtu of 

heat input.

 d. CO

201 ppm by volume on a dry basis 

corrected to 3 percent oxygen (30-day 

rolling average for units 100 

Formatted Table

Formatted Table
332

MMBtu/hr or greater, 3-run average 

for units less than 100 MMBtu/hr).

 e. Dioxin/Furan 0.001009 ng/dscm (TEQ) corrected to 7 

percent oxygen.

10. Units 

designed to burn 

other gases

a. 

Particulate 

Matter

0.002 lb per MMBtu of heat 

input.

b. Hydrogen 

Chloride

0.000003 lb per MMBtu of heat 

input.

c. Mercury 0.0000002 lb per MMBtu of 

heat input.

d. CO

1 ppm by volume on a dry 

basis corrected to 3 percent 

oxygen (30-day rolling 

average for units 100 

MMBtu/hr or greater, 3-run 

average for units less than 

100 MMBtu/hr).

e. 

Dioxin/Furan

0.008 ng/dscm (TEQ) corrected 

to 7 percent oxygen.

11. Metal 

processing 

furnaces

a. 

Particulate 

Matter

0.02 lb per MMBtu of heat 

input.

b. Hydrogen 

Chloride

0.0002 lb per MMBtu of heat 

input.

c. Mercury 0.0000002 lb per MMBtu of 

heat input.

d. CO

2 ppm by volume on a dry 

basis corrected to 3 percent 

oxygen (30-day rolling 

average for units 100 

MMBtu/hr or greater, 3-run 

average for units less than 

100 MMBtu/hr).

e. 

Dioxin/Furan

0.004 ng/dscm (TEQ) corrected 

to 7 percent oxygen.

Table 2 to Subpart DDDDD of Part 63 — Emission Limits for 

Existing Boilers and Process Heaters (Units with heat input 

capacity of 10 million Btu per hour or greater) 

As stated in §63.7500, you must comply with the following 

applicable emission limits:

If your boiler or 

process heater is in 

this subcategory ...

For the following 

pollutants . . .

You must meet the following emission 

limits and work practice standards . 

. .

1. Pulverized coal a. Particulate 0.02 lb per MMBtu of heat input.

Formatted Table
333

Matter 

 b. Hydrogen Chloride 0.00602 lb per MMBtu of heat input.

 c. Mercury 0.0000033.0E-06 lb per MMBtu of heat 

input.

 d. CO

7090 ppm by volume on a dry basis 

corrected to 3 percent oxygen (30-

day rolling average for units 100 

MMBtu/hr or greater, 3-run average 

for units less than 100 MMBtu/hr).

e. Dioxin/Furan 0.003004 ng/dscm (TEQ) corrected to 

7 percent oxygen 

2. Stokers designed 

to burn coal

a. Particulate 

Matter 0.02 lb per MMBtu of heat input.

 b. Hydrogen Chloride 0.00602 lb per MMBtu of heat input.

 c. Mercury 0.0000033.0E-06 lb per MMBtu of heat 

input.

 d. CO

4050 ppm by volume on a dry basis 

corrected to 3 percent oxygen (30-

day rolling average for units 100 

MMBtu/hr or greater, 3-run average 

for units less than 100 MMBtu/hr).

e. Dioxin/Furan 0.003 ng/dscm (TEQ) corrected to 7 

percent oxygen

3. Fluidized bed 

units designed to 

burn coal

a. Particulate 

Matter 0.02 lb per MMBtu of heat input.

 b. Hydrogen Chloride 0.00602 lb per MMBtu of heat input.

 c. Mercury 0.0000033.0E-06 lb per MMBtu of heat 

input.

d. CO

4030 ppm by volume on a dry basis 

corrected to 3 percent oxygen (30-

day rolling average for units 100 

MMBtu/hr or greater, 3-run average 

for units less than 100 MMBtu/hr).

e. Dioxin/Furan 0.002 ng/dscm (TEQ) corrected to 7 

percent oxygen

4. Stokers designed 

to burn biomass

a. Particulate 

Matter 0.0702 lb per MMBtu of heat input.

 b. Hydrogen Chloride 0.0006006 lb per MMBtu of heat 

input.

 c. Mercury 0.00000079.0E-07 lb per MMBtu of 

heat input.

d. CO

780560 ppm by volume on a dry basis 

corrected to 3 percent oxygen (30-

day rolling average for units 100 

MMBtu/hr or greater, 3-run average 

for units less than 100 MMBtu/hr).

e. Dioxin/Furan 0.003004 ng/dscm (TEQ) corrected to 

7 percent oxygen.

5. Fluidized bed a. Particulate 0.0702 lb per MMBtu of heat input.

Formatted Table
334

units designed to 

burn biomass

Matter

 b. Hydrogen Chloride 0.0006006 lb per MMBtu of heat 

input.

 c. Mercury 0.00000079.0E-07 lb per MMBtu of 

heat input.

d. CO

230250 ppm by volume on a dry basis 

corrected to 3 percent oxygen (30-

day rolling average for units 100 

MMBtu/hr or greater, 3-run average 

for units less than 100 MMBtu/hr).

e. Dioxin/Furan 0.02 ng/dscm (TEQ) corrected to 7 

percent oxygen.

6. Suspension 

burners/Dutch Ovens 

designed to burn 

biomass

a. Particulate 

Matter 0.0702 lb per MMBtu of heat input.

 b. Hydrogen Chloride 0.0006006 lb per MMBtu of heat 

input.

c. Mercury 0.00000079.0E-07 lb per MMBtu of 

heat input.

d. CO

4601,010 ppm by volume on a dry 

basis corrected to 3 percent oxygen 

(30-day rolling average for units 

100 MMBtu/hr or greater, 3-run 

average for units less than 100 

MMBtu/hr).

e. Dioxin/Furan 0.03 ng/dscm (TEQ) corrected to 7 

percent oxygen.

7. Fuel cells 

designed to burn 

biomass

a. Particulate 

Matter 0.0702 lb per MMBtu of heat input.

b. Hydrogen Chloride 0.0006006 lb per MMBtu of heat 

input.

c. Mercury

0.00000079.0E-07 lb per MMBtu of 

heat input.

d. CO

270 ppm by volume on a dry basis 

corrected to 3 percent oxygen (30-

day rolling average for units 100 

MMBtu/hr or greater, 3-run average 

for units less than 100 MMBtu/hr).

e. Dioxin/Furan 0.02 ng/dscm (TEQ) corrected to 7 

percent oxygen.

8. Units designed to 

burn liquid fuel

a. Particulate 

Matter 0.004 lb per MMBtu of heat input.

b. Hydrogen Chloride 0.00030009 lb per MMBtu of heat 

input.

c. Mercury 0.0000084.0E-06 lb per MMBtu of heat 

input.

d. CO 1 ppm by volume on a dry basis 

Formatted Table

Formatted Table
335

corrected to 3 percent oxygen (30-

day rolling average for units 100 

MMBtu/hr or greater, 3-run average 

for units less than 100 MMBtu/hr).

e. Dioxin/Furan 0.002 ng/dscm (TEQ) corrected to 7 

percent oxygen.

9. Units designed to 

burn natural 

gas/refinery 

gasother gases

a. Particulate 

Matter 0.05 lb per MMBtu of heat input.

b. Hydrogen 

Chloride

c. Mercury

0.000000002 lb per MMBtu 

of heat input, applicable 

to only refinery gas-fired 

units.

 d. CO

 e. 

Dioxin/Furan

10. Units designed 

to burn other gases

a. Particulate 

Matterb. Hydrogen 

Chloride

0.053.0E-06 lb per MMBtu of heat 

input.

b. Hydrogen 

Chloridec. Mercury

0.0000032.0E-07 lb per MMBtu of heat 

input.

c. Mercury 0.0000002 lb per MMBtu of 

heat input.

d. C0

1 ppm by volume on a dry basis 

corrected to 3 percent oxygen (30-

day rolling average for units 100 

MMBtu/hr or greater, 3-run average 

for units less than 100 MMBtu/hr).

e. Dioxin/Furan 0.008009 ng/dscm (TEQ) corrected to 

7 percent oxygen.

Table 3 to Subpart DDDDD of Part 63 — Work Practice Standards

As stated in §§63.11202 and 63.11203, you must comply with the 

following applicable work practice standards:

If your boiler is... You must meet the following...

1. An existing 

boiler or process 

heater with heat 

input capacity of 

less than 10 million 

Btu per hour 

Conduct a tune-up of the boiler 

annuallybiennially as specified 

in §63.7540.

2. AnA new or

existing boiler or 

Conduct a tune-up of the boiler 

annually as specified in 
336

process heater in 

either the Gas 1 or 

Metal Process 

Furnace subcategory

with heat input 

capacity of 10 

million Btu per hour

or greater

§63.7540.

3. An existing 

boiler or process 

heaters located at a 

major source

facility

Must have an energy assessment

performed on the major source 

facility 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, and

(7) a comprehensive report detailing 

the ways to improve efficiency, the 

cost of specific improvements, 

benefits, and the time frame for 

recouping those investments, and

(8) implement cost-effective 

findings.(8) a facility energy 

management program developed 

according to the ENERGY STAR 

guideline for energy management.

4. An existing 

boiler or process 

heater in the Gas 1 

combusting refinery 

gas

Install, operate, and maintain a 

carbon adsorber bed system to remove 

mercury from the refinery gas.
337

Table 4 to Subpart DDDDD of Part 63 — Operating Limits for 

Boilers and Process Heaters

As stated in §63.7500, you must comply with the applicable 

operating limits:

If you demonstrate 

compliance using . 

. . You must meet these operating limits . . .

1. Wet scrubber 

control

a. Maintain the minimum pressure drop and liquid flow-rate 

at or above the operating levels established during the 

performance test according to §63.7530(c) and Table 7 to 

this subpart.

2. Fabric filter 

control

a. Install and operate a bag leak detection system 

according to §63.7525 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; or

 b. This option is for boilers and process heaters that 

operate dry control systems. Existing and new boilers and 

process heaters must maintain opacity to less than or equal 

to 10 percent (daily block average).

3. Electrostatic 

precipitator 

control

a. This option is for boilers and process heaters that 

operate dry control systems. Existing and new boilers and 

process heaters must maintain opacity to less than or equal 

to 10 percent opacity (daily block average); or

 b. This option is only for boilers and process heaters that 

operate additional wet control systems. Maintain the 

minimum voltage and secondary current or total power input 

of the electrostatic precipitator at or above the operating 

limits established during the performance test according to 

§63.7530(c) and Table 7 to this subpart.

4. 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 according to §63.7530(c) and Table 7 to 

this subpart.

5. Any other 

control type

This option is for boilers and process heaters that operate 

dry control systems. Existing and new boilers and process 

heaters must maintain opacity to less than or equal to 10 

percent opacity (daily block average).

6. Fuel analysis Maintain the fuel type or fuel mixture such that the 

applicable emission rates calculated according to 

§63.7530(d)(3),(4) and/or(5) is less than the applicable 

emission limits.

Table 5 to Subpart DDDDD of Part 63—Performance Testing 

Requirements

Formatted Table
338

As stated in §63.7520, you must comply with the following 

requirements for performance test for existing, new or 

reconstructed affected sources:

To conduct a 

performance test for 

the following 

pollutant . . . You must . . . Using . . .

1. Particulate 

Matter

a. Select sampling 

ports location and the 

number of traverse 

points

Method 1 in appendix A to part 60 

of this chapter.

 b. Determine velocity 

and volumetric flowrate 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 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 per 

MMBtu emission rates

Method 19 F-factor methodology in 

appendix A to part 60 of this 

chapter.

2. Hydrogen chloride 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 flowrate 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 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 hydrogen 

chloride emission 

concentration

Method 26 or 26A in appendix A to 

part 60 of this chapter.

Formatted Table
339

 f. Convert emissions 

concentration to lb per 

MMBtu emission rates

Method 19 F-factor methodology in 

appendix A to part 60 of this 

chapter.

3. 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 flowrate 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 ASME 

PTC 19, Part 10 (1981) (IBR, see 

§62.14(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 per 

MMBtu emission rates

Method 19 F-factor methodology in 

appendix A to part 60 of this 

chapter.

4. CO 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 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)).

 c. Measure the moisture 

content of the stack 

gas

Method 4 in appendix A to part 60 

of this chapter.

 d. Measure the CO

emission concentration

Method 10 in appendix A to part 

60 of this chapter.

5. Dioxin/Furan 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 oxygen and 

carbon dioxide 

concentrations of the 

Method 3A or 3B in appendix A to 

part 60 of this chapter, or ASTM 

D6522–00 (IBR, see §63.14(b)), or 
340

stack gas ASME PTC 19, Part 10 (1981) (IBR, 

see §63.14(i)).

c. Measure the moisture 

content of the stack 

gas

Method 4 in appendix A to part 60 

of this chapter.

d. Measure the 

dioxin/furans emission 

concentration

Method __ in appendix A to part 

60 of this chapter.

Table 6 to Subpart DDDDD of Part 63—Fuel Analysis Requirements

As stated in §63.7521, you must comply with the following 

requirements for fuel analysis testing for existing, new or 

reconstructed affected sources. However, equivalent methods may 

be used in lieu of the prescribed methods at the discretion of 

the source owner or operator:

To conduct a 

fuel

analysis for 

the 

following

pollutant 

* * * You must * * * Using * * *

1. Mercury 

* * *

a. Collect fuel samples 

* * *

Procedure in §63.7521(c) or ASTM D2234–

D2234M–03(for coal) (IBR, see 

§63.14(b)) or ASTM D6323–98 (2003) (for 

biomass) (IBR, See §63.14(b)) or 

equivalent.

 b. Composite fuel samples 

* * *

Procedure in §63.7521(d) 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 

§63.24(b)) or ASTM E711–87 (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 

§6314(b)) or SW–846–7471A (for solid 

samples) or SW–846–7470A (for liquid 

samples or equivalent.

Formatted Table
341

 g. Convert concentration 

into units of pounds of 

pollutant per MMBtu of 

heat content.

2. Hydrogen 

Chloride 

* * *

a. Collect fuel samples 

* * *

Procedure in §63.7521(c) or ASTM D2234–

D2234M–03(for coal) (IBR, see 

§63.14(b)) or ASTM D6323–98 (2003) (for 

biomass) (IBR, see §63.14(b)) or 

equivalent.

 b. Composite fuel samples 

* * *

Procedure in §63.7521(d) 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) or equivalent.

 f. Measure chlorine 

concentration in fuel 

sample * * *

SW–846–9250 or ASTM D6721–01 (for coal) 

or ASTM E776–87 (1996) (for biomass) 

(IBR, see §63.14(b)) or equivalent.

 g. Convert concentrations 

into units of pounds of 

pollutant per MMBtu of 

heat content.

[ 71 FR 70663, Dec. 6, 2006]

Table 7 to Subpart DDDDD of Part 63—Establishing Operating 

Limits

As stated in §63.7520, you must comply with the following 

requirements for establishing operating limits:

If you have 

an 

applicable 

emission 

limit for . 

. .

And your 

operating limits 

are based on . . 

. You must . . . Using . . .

According to the 

following 

requirements

1. 

Particulate 

a. Wet scrubber 

operating 

i. Establish a 

site-specific 

(1) Data from 

the pressure 

(a) You must 

collect pressure 

Formatted Table
342

matter or

mercury

parameters minimum 

pressure drop 

and minimum 

flow rate 

operating 

limit 

according to 

§63.7530(c)

drop and 

liquid flow 

rate monitors 

and the 

particulate 

matter or

mercury 

performance 

test

drop and liquid 

flow-rate data 

every 15 minutes 

during the entire 

period of the 

performance tests;

 (b) Determine the 

average pressure 

drop and liquid 

flow-rate for each 

individual test 

run in the threerun performance 

test by computing 

the average of all 

the 15-minute 

readings taken 

during each test 

run.

 b. Electrostatic 

precipitator 

operating 

parameters 

(option only for 

units with 

additional wet 

scrubber 

control)

i. Establish a 

site-specific 

minimum 

voltage and 

secondary 

current or 

total power 

input 

according to 

§63.7530(c)

(1) Data from 

the pressure 

drop and 

liquid flow 

rate monitors 

and the 

particulate 

matter or

mercury

performance 

test

(a) You must 

collect voltage 

and secondary 

current or total 

power input data 

every 15 minutes 

during the entire 

period of the 

performance tests;

 (b) Determine the 

average voltage 

and secondary 

current or total 

power input for 

each individual 

test run in the 

three-run 

performance test 

by computing the 

average of all the 

15-minute readings 

taken during each 

test run.

2. Hydrogen 

Chloride

a. Wet scrubber 

operating 

parameters

i. Establish a 

site-specific 

minimum 

pressure drop 

and minimum 

flow rate 

(1) Data from 

the pH, 

pressure drop, 

and liquid 

flow-rate 

monitors and 

(a) You must 

collect pH, 

pressure drop, and 

liquid flow-rate 

data every 15 

minutes during the 
343

operating 

limit 

according to 

§63.7530(c)

the hydrogen 

chloride 

performance 

test

entire period of 

the performance 

tests;

 (b) Determine the 

average pH, 

pressure drop, and 

liquid flow-rate 

for each 

individual test 

run in the threerun performance 

test by computing 

the average of all 

the 15-minute 

readings taken 

during each test 

run.

 b. Dry scrubber 

operating 

parameters

i. Establish a 

site-specific 

minimum 

sorbent 

injection rate 

operating 

limit 

according to 

§63.7530(c)

(1) Data from 

the sorbent 

injection rate 

monitors and 

hydrogen 

chloride 

performance 

test

(a) You must 

collect sorbent 

injection rate 

data every 15 

minutes during the 

entire period of 

the performance 

tests;

 (b) Determine the 

average sorbent 

injection rate for 

each individual 

test run in the 

three-run 

performance test 

by computing the 

average of all the 

15-minute readings 

taken during each 

test run.

Table 8 to Subpart DDDDD of Part 63—Demonstrating Continuous 

Compliance

As stated in §63.7540, you must show continuous compliance with 

the emission limitations for affected sources according to the 

following:

If you must meet the 

following operating limits 

or work practice

standards . . .

You must demonstrate continuous compliance by . . 

.

Formatted Table
344

1. Opacity a. Collecting the opacity monitoring system data 

according to §§63.7525(b) and 63.7535; and

 b. Reducing the opacity monitoring data to 6-

minute averages; and

 c. Maintaining opacity to less than or equal to 10 

percent (daily block average).

2. Fabric Filter Bag Leak 

Detection Operation

Installing and operating a bag leak detection 

system according to §63.7525 and operating the 

fabric filter such that the requirements in 

§63.7540(a)(9) are met.

3. Wet Scrubber Pressure 

Drop and Liquid Flow-rate

a. Collecting the pressure drop and liquid flow 

rate monitoring system data according to §§63.7525 

and 63.7535; and

 b. Reducing the data to 12-hour block averages; 

and

 c. Maintaining the 12-hour average pressure drop 

and liquid flow-rate at or above the operating 

limits established during the performance test 

according to §63.7530(c).

4. Wet Scrubber pH a. Collecting the pH monitoring system data 

according to §§63.7525 and 63.7535; and

 b. Reducing the data to 12-hour block averages; 

and

 c. Maintaining the 12-hour average pH at or above

the operating limit established during the 

performance test according to §63.7530(c).

5. Dry Scrubber Sorbent or 

Carbon Injection Rate

a. Collecting the sorbent or carbon injection rate 

monitoring system data for the dry scrubber 

according to §§63.7525 and 63.7535; and

 b. Reducing the data to 12-hour block averages; 

and

 c. Maintaining the 12-hour average sorbent or 

carbon injection rate at or above the operating 

limit established during the performance test 

according to §§63.7530(c).

6. Electrostatic 

Precipitator Secondary 

Current and Voltage or 

Total Power Input

a. Collecting the secondary current and voltage or 

total power input monitoring system data for the 

electrostatic precipitator according to §§63.7525 

and 63.7535; and

 b. Reducing the data to 12-hour block averages; 

and

 c. Maintaining the 12-hour average secondary 

current and voltage or total power input at or 

above the operating limits established during the 

performance test according to §§63.7530(c).
345

7. Fuel Pollutant Content a. Only burning the fuel types and fuel mixtures 

used to demonstrate compliance with the applicable 

emission limit according to §63.7530(c) or (d) as 

applicable; and

 b. Keeping monthly records of fuel use according 

to §63.7540(a).

Table 9 to Subpart DDDDD of Part 63—Reporting Requirements

As stated in §63.7550, you must comply with the following 

requirements for reports:

You must submit a(n) The report must contain . . .

You must submit the 

report . . .

1. Compliance report a. Information required in 

§63.7550(c)(1) through (11); 

and

Semiannually 

according to the 

requirements in 

§63.7550(b).

 b. If there are no deviations 

from any emission limitation 

(emission limit and operating 

limit) that applies to you and 

there are no deviations from 

the requirements for work 

practice standards in Table 8 

to this subpart that apply to 

you, a statement that there 

were no deviations from the 

emission limitations and work 

practice standards during the 

reporting period. If there 

were no periods during which 

the CMSs, including continuous 

emissions monitoring system, 

continuous opacity monitoring 

system, and operating 

parameter monitoring systems, 

were out-of-control as 

specified in §63.8(c)(7), a 

statement that there were no 

periods during which the CMSs 

were out-of-control during the 

reporting period; and

 c. If you have a deviation 

from any emission limitation 

(emission limit and operating 

limit) or work practice 

standard during the reporting 

period, the report must 

contain the information in 

§63.7550(d). If there were 

Formatted Table
346

periods during which the CMSs, 

including continuous emissions 

monitoring system, continuous 

opacity monitoring system, and 

operating parameter monitoring 

systems, were out-of-control, 

as specified in §63.8(c)(7), 

the report must contain the 

information in §63.7550(e); 

and

 d. If you had a startup, 

shutdown, or malfunction 

during the reporting period 

and you took actions 

consistent with your startup, 

shutdown, and malfunction 

plan, the compliance report 

must include the information 

in §63.10(d)(5)(i)

2. An immediate startup, 

shutdown, and malfunction 

report if you had a 

startup, shutdown, or 

malfunction during the 

reporting period that is 

not consistent with your 

startup, shutdown, and 

malfunction plan, and the 

source exceeds any 

applicable emission

limitation in the relevant 

emission standard

a. Actions taken for the 

event; and

i. By fax or 

telephone within 2 

working days after 

starting actions 

inconsistent with 

the plan; and

 b. The information in 

§63.10(d)(5)(ii)

ii. By letter 

within 7 working 

days after the end 

of the event unless 

you have made 

alternative 

arrangements with 

the permitting 

authority.

Table 10 to Subpart DDDDD of Part 63—Applicability of General 

Provisions to Subpart DDDDD

As stated in §63.7565, you must comply with the applicable 

General Provisions according to the following:

Citation Subject Applies to subpart DDDDD
347

§63.1 Applicability Yes.

§63.2 Definitions Yes. Additional terms 

defined in §63.7575

§63.3 Units and 

Abbreviations

Yes.

§63.4 Prohibited 

Activities and 

Circumvention

Yes.

§63.5 Preconstruction 

Review and 

Notification 

Requirements

Yes

§63.6(a), (b)(1)-

(b)(5), (b)(7), 

(c), (f)(2)-(3), 

(g), (h)(2)-

(h)(9), (i), (j)

Compliance with 

Standards and 

Maintenance 

Requirements

Yes.

§63.6(e)(1), 

(e)(3), (f)(1), 

and(h)(1)

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 §63.7520.

§63.8 Monitoring 

Requirements

Yes.

§63.9 Notification 

Requirements

Yes. 
348

§63.10(a), 

(b)(1), 

(b)(2)(i)-(iii),

(b)(2)(vi)(xiv),

(c), (d)(1)-(2), 

(e), and (f) 

Recordkeeping and 

Reporting 

Requirements

Yes.

§63.10(b)(2)(iv)-

(v),(b)(3),and 

(d)(3)-(5)

No

§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