32006 Federal Register / Vol. 75, No. 107 / Friday, June 4, 2010 / Proposed Rules 

ENVIRONMENTAL PROTECTION 

AGENCY 

40 CFR Part 63 

[EPA–HQ–OAR–2002–0058; FRL–9148–5] 

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 the 

hazardous 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 costeffective energy conservation measures. 

DATES: Comments must be received on 

or before July 19, 2010. Under the 

Paperwork Reduction Act, comments on 

the information collection provisions 

are best assured of having full effect if 

the Office of Management and Budget 

(OMB) receives a copy of your 

comments on or before July 6, 2010. 

Public Hearing. We will hold a public 

hearing concerning this proposed rule 

and the interrelated proposed Boiler 

area source, CISWI, and RCRA rules, 

discussed in this proposal and 

published in the proposed rules section 

of today’s Federal Register, on June 21, 

2010. Persons requesting to speak at a 

public hearing must contact EPA by 

June 14, 2010. 

ADDRESSES: Submit your comments, 

identified by Docket ID No. EPA–HQ– 

OAR–2002–0058, by one of the 

following methods: 

• http://www.regulations.gov. Follow 

the instructions for submitting 

comments. 

• http://www.epa.gov/oar/ 

docket.html. Follow the instructions for 

submitting comments on the EPA Air 

and Radiation Docket Web site. 

• E-mail: Comments may be sent by 

electronic mail (e-mail) to a-and-rdocket@epa.gov, Attention Docket ID 

No. EPA–HQ–OAR–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 normal 

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

p.m., Monday through Friday, excluding 

legal holiday), and special arrangements 

should be made for deliveries of boxed 

information. 

Instructions: All submissions must 

include agency name and docket 

number or Regulatory Information 

Number (RIN) for this rulemaking. All 

comments will be posted without 

change and may be made available 

online at http://www.regulations.gov, 

including any personal information 

provided, unless the comment includes 

information claimed to be confidential 

business information (CBI) or other 

information whose disclosure is 

restricted by statute. Do not submit 

information that you consider to be CBI 

or otherwise protected through http:// 

www.regulations.gov or e-mail. The 

http://www.regulations.gov Web site is 

an ‘‘anonymous access’’ system, which 

means EPA will not know your identity 

or contact information unless you 

provide it in the body of your comment. 

If you send an e-mail comment directly 

to EPA without going through http:// 

www.regulations.gov, your e-mail 

address will be automatically captured 

and included as part of the comment 

that is placed in the public docket and 

made available on the Internet. If you 

submit an electronic comment, EPA 

recommends that you include your 

name and other contact information in 

the body of your comment and with any 

disk or CD–ROM you submit. If EPA 

cannot read your comment due to 

technical difficulties and cannot contact 

you for clarification, EPA may not be 

able to consider your comment. 

Electronic files should avoid the use of 

special characters, any form of 

encryption, and be free of any defects or 

viruses. 

Public Hearing: We will hold a public 

hearing concerning this proposed rule 

on June 21, 2010. Persons interested in 

presenting oral testimony at the hearing 

should contact Ms. Pamela Garrett, 

Energy Strategies Group, at (919) 541– 

7966 by June 14, 2010. The public 

hearing will be held in the Washington 

DC area at a location and time that will 

be posted at the following Web site: 

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

combustion. Please refer to this Web site 

to confirm the date of the public hearing 

as well. If no one requests to speak at 

the public hearing by June 14, 2010 then 

the public hearing will be cancelled and 

a notification of cancellation posted on 

the following Web site: http:// 

www.epa.gov/airquality/combustion. 

Docket: All documents in the docket 

are listed in the http:// 

www.regulations.gov index. Although 

listed in the index, some information is 

not publicly available, e.g., CBI or other 

information whose disclosure is 

restricted by statute. Certain other 

material, such as copyrighted material, 

will be publicly available only in hard 

copy form. Publicly available docket 

materials are available either 

electronically in http:// 

www.regulations.gov or in hard copy at 

the EPA Docket Center, Room 3334, 

1301 Constitution Ave., NW., 

Washington, DC. The Public Reading 

Room is open from 8:30 a.m. to 4:30 

p.m., Monday through Friday, excluding 

legal holidays. The telephone number 

for the Public Reading Room is (202) 

566–1744, and the telephone number for 

the Air Docket is (202) 566–1742. 

FOR FURTHER INFORMATION CONTACT: 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? 


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B. What should I consider as I prepare my 

comments to EPA? 

C. Where can I get a copy of this 

document? 

D. When would a public hearing occur? 

II. Background Information 

A. What is the statutory authority 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 

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 code 1 Examples of potentially 

regulated entities 

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 

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. 


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32008 Federal Register / Vol. 75, No. 107 / Friday, June 4, 2010 / Proposed Rules 

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 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 World Wide Web (WWW) 

through the Technology Transfer 

Network (TTN). Following signature, a 

copy of the proposed action will be 

posted on the TTN’s policy and 

guidance page for newly proposed or 

promulgated rules at the following 

address: http://www.epa.gov/ttn/oarpg/. 

The TTN provides information and 

technology exchange in various areas of 

air pollution control. 

D. When would a public hearing occur? 

We will hold a public hearing 

concerning this proposed rule on June 

21, 2010. Persons interested in 

presenting oral testimony at the hearing 

should contact Ms. Pamela Garrett, 

Energy Strategies Group, at (919) 541– 

7966 by June 14, 2010. The public 

hearing will be held in the Washington, 

DC area at a location and time that will 

be posted at the following Web site: 

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

combustion. Please refer to this Web site 

to confirm the date of the public hearing 

as well. If no one requests to speak at 

the public hearing by June 14, 2010, 

then the public hearing will be 

cancelled and a notification of 

cancellation posted on the following 

Web site: http://www.epa.gov/ 

airquality/combustion. 

II. Background Information 

A. What is the statutory authority 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 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 

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 (DC 

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 ‘‘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 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 


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relevant to this proceeding because 

some industrial, commercial, or 

institutional boilers and process heaters 

combust secondary materials as 

alternative fuels. If industrial, 

commercial, or institutional boilers or 

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, 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 bestperforming 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 55,233.) 

Accordingly, we established no 

standards. In addition, we set risk-based 

standards, also known as health-based 

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 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 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 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 DC 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 


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EPA considers to be achievable by all 

sources (479 F. 3d at 880–81); 

• 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-thestack 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’ 

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 (DC 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 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 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 

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 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 coalfired, two biomass-fired, and two gasfired 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 


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1See 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. 

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 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, 

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 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 institutional (ICI) boilers, 

accounting for 61 percent of the total 

HAP emissions.1 ICI boilers and process 

heaters also emit lesser amounts of 

hydrogen fluoride, accounting for about 

17 percent of total HAP emissions, and 

metals (arsenic, cadmium, chromium, 

mercury, manganese, nickel, and lead) 

accounting for about 6 percent of total 

HAP emissions. Organic HAP 

(formaldehyde, POM, acetaldehyde, 

benzene) account for about 15 percent of 

total HAP emissions. Exposure to these 

HAP, depending on exposure duration 

and levels of exposures, can be 

associated with a variety of adverse 

health effects. These adverse health 

effects may include, for example, 

irritation of the lung, skin, and mucus 

membranes, effects on the central 

nervous system, damage to the kidneys, 

and alimentary effects such as nausea 

and vomiting. 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. 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 stationary sources located 

within a contiguous area and under 

common control that emits or has the 


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2Heat 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). 

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 at 

least 10 percent coal on an annual 

average heat input 2 basis, the unit is in 

one of the coal subcategories. If your 

new or existing boiler or process heater 

burns at least 10 percent biomass, on an 

annual average heat input basis, and 

less than 10 percent coal, on an annual 

average heat input basis, we are 

proposing that the unit is in one of the 

biomass subcategories. If your new or 

existing boiler or process heater burns at 

least 10 percent liquid fuel (such as 

distillate oil, residual oil), and less than 

10 percent solid fuel, on an annual heat 

input basis, we are proposing that the 

unit is in the liquid subcategory. If your 

new or existing boiler or process heater 

burns gaseous fuel and less than 10 

percent, on an annual average heat 

input basis, 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] 

Subcategory 

Particulate 

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 .02 0 .000003 50 0 .003 

Existing—Coal Fluidized Bed .................................... 0 .02 0 .02 0 .000003 30 0 .002 

Existing—Pulverized Coal .......................................... 0 .02 0 .02 0 .000003 90 0 .004 

Existing—Biomass Stoker .......................................... 0 .02 0 .006 0 .0000009 560 0 .004 

Existing—Biomass Fluidized Bed .............................. 0 .02 0 .006 0 .0000009 250 0 .02 

Existing—Biomass Suspension Burner/Dutch Oven 0 .02 0 .006 0 .0000009 1010 0 .03 

Existing—Biomass Fuel Cells .................................... 0 .02 0 .006 0 .0000009 270 0 .02 

Existing—Liquid ......................................................... 0 .004 0 .0009 0 .000004 1 0 .002 

Existing—Gas (Other Process Gases) ...................... 0 .05 0 .000003 0 .0000002 1 0 .009 

New—Coal Stoker ..................................................... 0 .001 0 .00006 0 .000002 7 0 .003 

New—Coal Fluidized Bed .......................................... 0 .001 0 .00006 0 .000002 30 0 .00003 

New—Pulverized Coal ............................................... 0 .001 0 .00006 0 .000002 90 0 .002 

New—Biomass Stoker ............................................... 0 .008 0 .004 0 .0000002 560 0 .00005 

New—Biomass Fluidized Bed ................................... 0 .008 0 .004 0 .0000002 40 0 .007 

New—Biomass Suspension Burner/Dutch Oven ...... 0 .008 0 .004 0 .0000002 1010 0 .03 

New—Biomass Fuel Cells ......................................... 0 .008 0 .004 0 .0000002 270 0 .0005 

New—Liquid ............................................................... 0 .002 0 .0004 0 .0000003 1 0 .002 

New—Gas (Other Process Gases) ........................... 0 .003 0 .000003 0 .0000002 1 0 .009 

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 three particular 

classes of 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 process 

furnaces subcategory. The work practice 

standard being proposed for these 

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-thefloor standard for all existing major 

source facilities having affected boilers 

or process heaters that would require 

the performance of a one-time energy 

assessment, as described in section III.F 

of this preamble, by qualified personnel, 

on the affected boilers and facility to 

identify any cost-effective energy 

conservation measures. 

E. What are the startup, shutdown, and 

malfunction (SSM) requirements? 

The United States Court of Appeals 

for the District of Columbia Circuit 

vacated portions of two provisions in 

EPA’s CAA Section 112 regulations 

governing the emissions of HAP during 

periods of startup, shutdown, and 

malfunction (SSM). Sierra Club v. EPA, 

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

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

Specifically, the Court vacated the SSM 

exemption contained in 40 CFR 

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

part of a regulation, commonly referred 

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

EPA promulgated under section 112 of 

the CAA. When incorporated into CAA 

Section 112(d) regulations for specific 

source categories, these two provisions 

exempt sources from the requirement to 

comply with the otherwise applicable 

CAA section 112(d) emission standard 

during periods of SSM. 

Consistent with Sierra Club v. EPA, 

EPA has established standards in this 

rule that apply at all times. EPA has 

attempted to ensure that we have not 

incorporated into proposed regulatory 

language any provisions that are 

inappropriate, unnecessary, or 

redundant in the absence of an SSM 

exemption. We are specifically seeking 

comment on whether there are any such 

provisions that we have inadvertently 

incorporated or overlooked. We also 

request comment on whether there are 

additional provisions that should be 

added to regulatory text in light of the 

absence of an SSM exemption and 

provisions related to the SSM 

exemption (such as the SSM plan 

requirement and SSM recordkeeping 

and reporting provisions). 

In establishing the standards in this 

rule, EPA has taken into account startup 

and shutdown periods and, for the 


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reasons explained below, has not 

established different standards for those 

periods. The standards that we are 

proposing are daily or monthly 

averages. Continuous emission 

monitoring data obtained from best 

performing units, and used in 

establishing the standards, include 

periods of startup and shutdown. 

Boilers, especially solid fuel-fired 

boilers, do not normally startup and 

shutdown more the once per day. Thus, 

we are not establishing a separate 

emission standard for these periods 

because startup and shutdown are part 

of their routine operations and, 

therefore, are already addressed by the 

standards. Periods of startup, normal 

operations, and shutdown are all 

predictable and routine aspects of a 

source’s 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 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. 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. 

In the event that a source fails to 

comply with the applicable CAA section 

112(d) standards as a result of a 

malfunction event, EPA would 

determine an appropriate response 

based on, among other things, the good 

faith efforts of the source to minimize 

emissions during malfunction periods, 

including preventative and corrective 

actions, as well as root cause analyses 

to ascertain and rectify excess 

emissions. EPA would also consider 

whether the source’s failure to comply 

with the CAA section 112(d) standard 

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

reasonably preventable’’ and was not 

instead ‘‘caused in part by poor 

maintenance or careless operation.’’ 40 

CFR 63.2 (definition of malfunction). 

F. What are the 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). 

(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 sitespecific 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 we are proposing to 

be established for the various types of 

the following units: 

(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 site-specific 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 run 

averages established during the 

performance tests would be your sitespecific minimum sorbent injection rate 

operating limit. If different sorbents 

and/or injection rates are used during 

the mercury, HCl, and D/F tests, the 

average value for each sorbent becomes 

your site-specific 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 site-specific pH, pressure drop, 

and liquid flowrate operating limits for 

the wet scrubber. Furthermore, the 

fabric filter must be operated such that 


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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 run. 

The average of the three test run 

averages would establish your sitespecific 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, 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, 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 

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 

and 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 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 costeffective energy conservation measures 

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 

(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. 

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 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 

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 


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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 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 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. 

(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. 

(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. 

(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 determinations. 

In conducting these required reviews, 

we have found it ineffective 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. Owners and 

operators of boilers and process heaters 

will be required to submit to an EPA 

electronic database an electronic copy of 

reports of certain performance tests 

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 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. 

The requirement to submit source test 

data electronically to EPA will not 


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3 Indirect-fired process heaters are combustion 

devices in which the combustion gases do not 

directly come into contact with process materials. 

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. The Web 

site 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 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. The information to be reported is 

already required for 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 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 

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 and incorporating 

data for most performance tests will 

ensure that emissions factors, when 

updated, 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. 

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 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. 

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 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 

units.3 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 source categories of industrial 

boilers 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, 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 residential-type 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. 

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 


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4See Memorandum ‘‘Development of Baseline 

Emission Factors for Boilers and Process Heaters at 

Commercial, Industrial, and Institutional Facilities’’ 

located in the docket. 

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 data base are indicated to cofire liquids or 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 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 

propose 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 

systems that, while having a minor 

effect on fuel-related HAP emissions, 

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 11 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, 

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 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 at 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 at 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 at 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 at 

least 90 percent natural gas and/or 

refinery gas (on an annual heat input 

basis) as being in 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 differently 

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 fire 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. This 

results in emissions characteristics 

different from the process heaters used 

in other industries. The process heaters 

used in metal processing are natural gasfired and include annealing furnaces, 

preheat furnaces, reheat furnaces, aging 

furnaces, and heat treat furnaces. 

Therefore, we propose to identify 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 


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5For 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. 

6Based 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. 

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 

regulations 5 and allows easy 

comparison between such requirements. 

Additionally, this proposed rule 

contains an option to monitor inlet 

chlorine and 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, nondioxin 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 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 for 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 necessary 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). 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 nonmetallic 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 such 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 nondioxin 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 also 

proposing separate emission limits for 

D/F. For non-dioxin 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 

coal-fired units is benzene, which 

accounts for about 20 percent of the 

organic HAP while the principal organic 

HAP emitted from biomass-fired units is 

formaldehyde, which accounts for 34 

percent of the organic HAP.6 Limiting 

CO as a surrogate for only non-dioxin 

organic HAP will eliminate 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. 

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 percent of existing 


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7See 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. 

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 

floors for existing units? 

EPA must consider available 

emissions information to determine the 

MACT floors. 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. 

We first considered whether fuel 

switching would be an appropriate 

control option for sources in each 

subcategory. We considered the 

feasibility of fuel switching to other 

fuels used in the subcategory and to 

fuels from other subcategories. This 

consideration included determining 

whether switching fuels would achieve 

lower HAP emissions. A second 

consideration was whether fuel 

switching could be technically achieved 

by boilers 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 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. 

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 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 

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 

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 (DC Cir 2004) (holding 

EPA may consider emission variability 

in estimating performance achieved by 

best-performing sources and may set the 

floor at level that best-performing 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 


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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, contain the next (or some 

other pre-specified) randomly selected 

observation from a population. In other 

words, the prediction interval estimates 

what future values will be, based upon 

present or past background samples 

taken. Given this definition, the UPL 

represents the value which we can 

expect the mean of 3 future observations 

(3-run average) to fall below, based 

upon the results of an independent 

sample from the same population. 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 bestperforming 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. 

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) 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 logtransformed 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. 

Since the compliance with the MACT 

floor emission limit is based on the 

average of a three run test, the UPL is 

calculated by: 

UPL x +t ,n s

n m

= −× × + ⎛

⎝

⎜ ⎞

⎠

⎟ (0.99 2 1 1 1 )

Where: 

n = the number of test runs 

m = the number of test runs in the 

compliance average 

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%) × 

TINV(2 × probability, n-1 degrees of 

freedom)*SQRT((1/n)+(1⁄3))], for a 

one-tailed t-value (with 2 × 

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%) × TINV(2 × 

probability, n-1 degrees of 

freedom)* SQRT((1/n)+(1⁄3))]}, for a 

one-tailed t-value (with 2 × 

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 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 data base 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 


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8American Society of Mechanical Engineers, 

Reference Method Accuracy and Precision 

(ReMAP): Phase 1, Precision of Manual Stack 

Emission Measurements, CRTD Vol. 60, February 

2001. 

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 level.8 One 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 

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 fuelrelated HAP of the best performing 

units, may not reflect the variability of 

fuel-related HAP from the best 

performing units over the long term. 

Based on fuel-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, fuelrelated 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 fuel-related 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 fuelrelated 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 use data 

on the fuel-related HAP inputs in the 

fuels used by the best performing units, 

obtained as part of our information 

collection effort under the authority of 

CAA section 114, on long-term fuelrelated 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 99th 

percentile) as described earlier from the 

average performance of the best 

performing units, Students t-factor, and 

the variability of the best performing 

units. 

This approach reasonably ensures that 

the emission limit selected as the MACT 

floor adequately represents the level of 

emissions 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 FuelRelated HAP 

In developing the proposed MACT 

floor for the fuel-related HAP (nonmercury metals, acid gases, 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 2 of this preamble 

presents the number of units in each of 

the five subcategories, along with the 


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9The 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. 

number of units from which we have 

collected emission data. Table 2 also 

presents for each subcategory and fuelrelated 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 Mercury HCl 

Units designed for Coal firing ............................... No. of sources in subcategory ............................. 578 578 578 

No. of sources with data ...................................... 366 285 318 

No. in MACT floor ................................................ 44 35 39 

Avg of top 12%, lb/MMBtu ................................... 7.24E–03 5.95E–07 4.23E–03 

99% UPL of top 12% (test runs), lb/MMBtu ........ 0.0179 1.64E–06 7.38E–03 

99% UPL with fuel variability of top 12%, lb/ 

MMBtu.

.................... 2.88E–06 1.11E–02 

Units designed for Biomass firing ......................... No. of sources in subcategory ............................. 420 420 420

No. of sources with data ...................................... 192 91 92 

No. in MACT floor ................................................ 24 11 12 

Avg of top 12%, lb/MMBtu ................................... 6.06E–03 3.46E–07 4.34E–03 

99% UPL of top 12% (test runs), lb/MMBtu ........ 0.0162 7.52E–07 6.00E–03 

99% UPL with fuel variability of top 12%, lb/ 

MMBtu.

.................... 8.88E–07 ....................

Units designed for Liquid Fuel firing ..................... No. of sources in subcategory ............................. 826 826 826

No. of sources with data ...................................... 91 177 190 

No. in MACT floor ................................................ 11 22 23 

Avg of top 12%, lb/MMBtu ................................... 1.40E–03 1.91E–06 2.59E–04 

99% UPL of top 12% (test runs), lb/MMBtu ........ 0.00323 2.78E–06 3.26E–04 

99% UPL with fuel variability of top 12%, lb/ 

MMBtu.

.................... 3.97E–06 8.04E–04 

Units designed for other gas firing ....................... No. of sources in subcategory ............................. 199 199 199

No. of sources with data ...................................... 13 8 8 

No. in MACT floor ................................................ 2 1 1 

Avg of top 12%, lb/MMBtu ................................... 0.011 8.25E–08 1.70E–06 

99% UPL of top 12% (test runs), lb/MMBtu ........ 0.045 1.86E–07 2.50E–06 

For three 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 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, 

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. 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 or 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 this 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 nondioxin 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 presents for each subcategory (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. 


erowe on DSK5CLS3C1PROD with PROPOSALS5
Federal Register / Vol. 75, No. 107 / Friday, June 4, 2010 / Proposed Rules 32023 

TABLE 3—SUMMARY OF MACT FLOOR RESULTS FOR THE ORGANIC HAP SUBCATEGORIES

Subcategory Parameter CO Dioxin/Furan (TEQ) 

Stoker—Coal ....................... No. of sources in subcategory ...................................... 361 ..................................... 361. 

No. of sources with data ............................................... 61 ....................................... 14. 

No. in MACT floor ......................................................... 8 ......................................... 2. 

Avg of top 12% .............................................................. 21.4 ppm @ 3% O2 ........... 0.00182 ng/dscm @ 7% 

O2. 

99% UPL of top % (test runs) ....................................... 48.8 ppm @ 3% O2 ........... 0.00274 ng/dscm @ 7% 

O2. 

Fluidized Bed—Coal ............ No. of sources in subcategory ...................................... 31 ....................................... 31. 

No. of sources with data ............................................... 17 ....................................... 12. 

No. in MACT floor ......................................................... 3 ......................................... 2. 

Avg of top 12% .............................................................. 12.5 ppm @ 3% O2 ........... 0.000471 ng/dscm @ 7% 

O2. 

99% UPL of top % (test runs) ....................................... 21.4 ppm @ 3% O2 ........... 0.00168 ng/dscm @ 7% 

O2. 

PC—Coal ............................. No. of sources in subcategory ...................................... 186 ..................................... 186. 

No. of sources with data ............................................... 41 ....................................... 10. 

No. in MACT floor ......................................................... 5 ......................................... 2. 

Avg of top 12% .............................................................. 19.2 ppm @ 3% O2 ........... 0.00158 ng/dscm @ 7% 

O2. 

99% UPL of top % (test runs) ....................................... 82.8 ppm @ 3% O2 ........... 0.00307 ng/dscm @ 7% 

O2. 

Stoker—Biomass ................. No. of sources in subcategory ...................................... 320 ..................................... 320. 

No. of sources with data ............................................... 119 ..................................... 16. 

No. in MACT floor ......................................................... 15 ....................................... 2. 

Avg of top 12% .............................................................. 203 ppm @ 3% O2 ............ 0.000819 ng/dscm @ 7% 

O2. 

99% UPL of top % (test runs) ....................................... 551 ppm @ 3% O2 ............ 0.00339 ng/dscm @ 7% 

O2. 

Fluidized Bed—Biomass ..... No. of sources in subcategory ...................................... 12 ....................................... 12. 

No. of sources with data ............................................... 7 ......................................... 6. 

No. in MACT floor ......................................................... 5 ......................................... 5. 

Avg of top 12% .............................................................. 97.1 ppm @ 3% O2 ........... 0.00507 ng/dscm @ 7% 

O2. 

99% UPL of top 12% (test runs) ................................... 245 ppm @ 3% O2 ............ 0.0127 ng/dscm @ 7% O2. 

Suspension Burner/Dutch 

Oven.

No. of sources in subcategory ...................................... 62 ....................................... 62. 

No. of sources with data ............................................... 17 ....................................... 3. 

No. in MACT floor ......................................................... 3 ......................................... 1. 

Avg of top 12% .............................................................. 362 ppm @ 3% O2 ............ 0.00952 ng/dscm @ 7% 

O2. 

99% UPL of top 12% (test runs) ................................... 1010 ppm @ 3% O2 .......... 0.0279 ng/dscm @ 7% O2. 

Fuel Cell—Biomass ............. No. of sources in subcategory ...................................... 26 ....................................... 26. 

No. of sources with data ............................................... 16 ....................................... 7. 

No. in MACT floor ......................................................... 5 ......................................... 5. 

Avg of top 12% .............................................................. 130 ppm @ 3% O2 ............ 0.00552 ng/dscm @ 7% 

O2. 

99% UPL of top 12% (test runs) ................................... 262 ppm @ 3% O2 ............ 0.0148 ng/dscm @ 7% O2. 

Units designed for Liquid 

fuel firing.

No. of sources in subcategory ...................................... 826 ..................................... 826. 

No. of sources with data ............................................... 116 ..................................... 17. 

No. in MACT floor ......................................................... 14 ....................................... 3. 

Avg of top 12% .............................................................. 0.443 ppm @ 3% O2 ......... 0.000733 ng/dscm @ 7% 

O2. 

99% UPL of top 12% (test runs) ................................... 0.911 ppm @ 3% O2 ......... 0.00182 ng/dscm @ 7% 

O2. 

Units designed for other 

gases firing.

No. of sources in subcategory ...................................... 199 ..................................... 199. 

No. of sources with data ............................................... 75 ....................................... 5. 

No. in MACT floor ......................................................... 9 ......................................... 1. 

Avg of top 12% .............................................................. 0.0737 ppm @ 3% O2 ....... 0.00267 ng/dscm @ 7% 

O2. 

99% UPL of top 12% (test runs) ................................... 0.134 ppm @ 3% O2 ......... 0.00828 ng/dscm @ 7% 

O2. 

For organic HAP, as previously 

discussed above for 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 when operated 


erowe on DSK5CLS3C1PROD with PROPOSALS5
32024 Federal Register / Vol. 75, No. 107 / Friday, June 4, 2010 / Proposed Rules 

10 Memorandum: Methodology for Estimating 

Impacts from Industrial, Commercial, and 

Institutional Boilers and Process Heaters at Major 

Sources of Hazardous Air Pollutant Emissions, 

March 23, 2010. 

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 

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 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, no additional variability due 

to operating load needs to be accounted 

for since the 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, we are proposing to add no 

additional variability factor to account 

for load variability 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 three fueldependent MACT floors, the proposed 

new and existing source MACT floors 

for eight combustion-dependent 

subcategories are almost identical 

because the best performing 12 percent 

of units (for 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 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 analysis 10 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 

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 

700) 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 under 

CAA section 112(h) that it is not feasible 

to enforce emission standards for a 

particular class of existing 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. 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 must increase to maintain 


erowe on DSK5CLS3C1PROD with PROPOSALS5
Federal Register / Vol. 75, No. 107 / Friday, June 4, 2010 / Proposed Rules 32025 

11Tune-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. 

constant energy output. 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 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 State 

regulations and permits. The work 

practices listed in State regulations 

includes tune-ups (10 States), operator 

training (1 State), periodic inspections 

(2 States), and operation in accordance 

with manufacturer specifications (1 

State). Of the 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 

subcategories are subject to a tune-up 

requirement. Therefore, the proposed 

work practice of a tune-up 11 program 

does establish the MACT floor for HAP 

emissions from existing units with a 

heat input capacity of less than 10 

MMBtu/h. 

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). 

This work practice standard is being 

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. 

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. The projected 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 HAP for existing natural 

gas-fired and refinery gas-fired boilers 

and process heaters. 

We request comments on whether the 

emission limits listed in Table 4 of this 

preamble for 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 4—SUMMARY OF MACT FLOOR RESULTS FOR THE GAS 1 AND METAL PROCESS FURNACE SUBCATEGORIES

Subcategory Parameter PM Mercury HCl CO Dioxin/furan 

(total TEQ) 

Units designed for 

NG/RG firing.

No. of sources in 

subcategory.

10,783 ................. 10,783 ................. 10,783 ................. 10,783 ................. 10,783. 

No. of sources 

with data.

144 ...................... 14 ........................ 11 ........................ 754 ...................... 8. 

No. in MACT floor 18 ........................ 2 .......................... 2 .......................... 91 ........................ 1. 

Avg of top 12% ... 0.00388 lb/MMBtu 1.1E–07 lb/MMBtu 1.01E–04 lb/ 

MMBtu.

1.45 ppm @ 3% 

oxygen.

0.0026 ng/dscm 

@ 7% oxygen. 

99% UPL of top 

12% (test runs).

0.03 lb/MMBtu ..... 2.0E–07 lb/MMBtu 0.0002 lb/MMBtu 20 ppm @ 3% oxygen.0.01 ng/dscm @ 

7% oxygen. 

Metal Process Furnaces.No. of sources in 

subcategory.

749 ...................... 749 ...................... 749 ...................... 749 ...................... 749. 

No. of sources 

with data.

9 .......................... 7 .......................... 9 .......................... 15 ........................ 7. 

No. in MACT floor 2 .......................... 1 .......................... 2 .......................... 2 .......................... 1. 

Avg of top 12% ... 0.0047 lb/MMBtu 3.3E–08 lb/MMBtu 1.92E–04 lb/ 

MMBtu.

0.38 ppm @ 3% 

oxygen.

0.0026 ng/dscm 

@ 7% oxygen. 

99% UPL of top 

12% (test runs).

0.02 lb/MMBtu ..... 2.0E–07 lb/MMBtu 0.0004 lb/MMBtu 2 ppm @ 3% oxygen.0.004 ng/dscm @ 

7% oxygen. 


erowe on DSK5CLS3C1PROD with PROPOSALS5
32026 Federal Register / Vol. 75, No. 107 / Friday, June 4, 2010 / Proposed Rules 

E. How did EPA consider beyond-thefloor 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 Process Heaters National 

Emission Standards for Hazardous Air 

Pollutants’’ in the docket. 

We could not identify better HAP 

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 an option 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 billion under the floor 

approach. The emission reduction 

associated with fuel switching was 

estimated to be 4,296 tons per year for 

metallic HAP, 8 tons per year for 

mercury, and 50,332 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 beyond-the-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 

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 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 implemented the 

cost-effective energy conservation 

measures identified in the energy 

assessment, 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 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 costeffective measures were economically 

feasible, we are seeking comment on 

this point. 

In this proposed rule, we are defining 

a cost-effective energy conservation 

measure to be any measure that has a 

payback (return of investment) period of 

2 years or less. This payback period was 

selected based on section 

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

Conservation Act which states that there 

is a presumption that an energy 

conservation standard is economically 

justified if the increased installed cost 

for a measure is less than three times the 

value of the first-year energy savings 

resulting from the measure. 

We believe that an energy assessment 

is an appropriate beyond-the-floor 

control technology because it is one of 

the measures identified in CAA section 

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

that ‘‘Emission standards promulgated 

* * * and applicable to new or existing 

sources * * * is achievable * * * 

through application of measures, 

processes, methods, systems or 

techniques including, but not limited to 

measures which * * * reduce the 

volume of, or eliminate emissions of, 

such pollutants through process 

changes, substitution of materials or 

other modifications * * *’’ 

The purpose of an energy assessment 

is to identify energy conservation 

measures (such as, process changes or 

other modifications to the facility) that 

can be implemented to reduce the 

facility energy demand which would 

result in reduced fuel use. Reduced fuel 

use will result in a corresponding 

reduction in HAP, and non-HAP, 

emissions. Thus, an energy assessment, 

in combination with the MACT 

emission limits will result in the 

maximum degree of reduction in 

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

Therefore, we are proposing to require 

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

We are proposing that the energy 

assessment be conducted by energy 

professionals and/or engineers that have 

expertise that cover all energy using 

systems, processes, and equipment. We 

are aware of, at least, two organizations 

that provide certification of specialists 

in evaluating energy systems. We are 

proposing that a qualified 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 


erowe on DSK5CLS3C1PROD with PROPOSALS5
Federal Register / Vol. 75, No. 107 / Friday, June 4, 2010 / Proposed Rules 32027 

12The location of the guidance is: http:// 

www.energystar.gov/ 

index.cfm?c=guidelines.assess_facility_energy. 

13Carbon 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 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.) 

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’’ 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 beyondthe-floor requirement for certain sources 

in the natural gas and refinery gas 

subcategory (i.e., the Gas 1 subcategory). 

Specifically, we considered proposing 

that facilities with boilers or process 

heaters combusting refinery gas install 

and maintain a carbon adsorber bed 

system 13 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 mercury and 

additional mercury reductions can be 

achieved from units combusting refinery 

gas. Consequently, we analyzed the 

mercury emissions reductions and 

additional cost of adopting this work 

practice. The annualized cost of the 

carbon adsorber bed system to treat the 

refinery gas prior to combustion is 

estimated to be about 1.6 billion dollars 

with a mercury emission reduction of 

0.8 tons. The results indicated that 

while 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. 

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 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 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 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 fuel-related 

HAP inputs directly translate to a 

variability of fuel-related HAP stack 

emissions. 

As previously discussed above, we 

account for variability of the bestcontrolled 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 

best-controlled source. 


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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 performance 

achieved by the average of the best 

performing 12 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, for the fuel 

dependent HAP emissions, we 

determined what the best controlled 

source has 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 

best-controlled 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 best-controlled 

source. Once we calculated the fuel 

dependent variability factors, we 

applied these factors to the average 

measured emissions performance of the 

best controlled similar source to derive 

the MACT floor level of control. This 

approach reasonably estimates the best 

source’s level of emissions, adjusted for 

unavoidable variation in fuel 

characteristics which have a direct 

impact on emissions. 

1. Determination of MACT for the FuelRelated 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 5 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 5—SUMMARY OF MACT FLOOR RESULTS FOR THE FUEL-RELATED HAP FOR NEW SOURCES

Subcategory Parameter PM 

Lb/MMBtu 

Mercury 

Lb/MMBtu 

HCl 

Lb/MMBtu 

Units designed for Coal firing ............................... Avg of top performer ............................................ 0.000396 1.18E–07 3.85E–05 

99% UPL of top performer (test runs) ................. 0.000928 3.89E–07 5.21E–05 

Units designed for Biomass firing ......................... Avg of top performer ............................................ 0.00216 9.73E–08 7.85E–04 

99% UPL of top performer (test runs) ................. 0.00711 1.86E–07 3.07E–03 

Units designed for Liquid Fuel firing ..................... Avg of top performer ............................................ 0.000511 5.87E–08 3.99E–04 

99% UPL of top performer (test runs) ................. 0.00154 2.47E–07 9.80E–04 

Units designed for other gas firing ....................... Avg of top performer ............................................ 0.00042 8.25E–08 1.70E–06 

99% UPL of top performer (test runs) ................. 0.0024 1.86E–07 2.50E–06 

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 nondioxin organic HAP. Table 6 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. 

TABLE 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 ................................................ 4.29 1.52E–03 

99% UPL of top performer (test runs) ...................... 6.53 2.82E–03 

Fluidized Bed—Coal ................................................. Avg of top performer ................................................ 8.26 9.05E–06 

99% UPL of top performer (test runs) ...................... *39.9 2.54E–05 

PC—Coal .................................................................. Avg of top performer ................................................ 25.0 1.04E–03 

99% UPL of top performer (test runs) ...................... *97.5 1.47E–03 

Stoker—Biomass ...................................................... Avg of top performer ................................................ 920 1.52E–05 

99% UPL of top performer (test runs) ...................... *3730 4.86E–05 

Fluidized Bed—Biomass .......................................... Avg of top performer ................................................ 25.8 2.27E–03 

99% UPL of top performer (test runs) ...................... 34.2 6.48E–03 

Suspension Burner/Dutch Oven. .............................. Avg of top performer ................................................ 352 9.52E–03 

99% UPL of top performer (test runs) ...................... *1050 2.79E–02 

Fuel Cell—Biomass .................................................. Avg of top performer ................................................ 110 2.42E–04 


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TABLE 6—SUMMARY OF MACT FLOOR RESULTS FOR THE ORGANIC HAP FOR NEW SOURCES—Continued 

Subcategory Parameter 

CO 

(ppm @ 3 

percent oxygen) 

Dioxin/Furan 

(TEQ) 

(ng/dscm @ 7 

percent oxygen) 

99% UPL of top performer (test runs) ...................... *264 4.17E–04 

Units designed for Liquid fuel firing .......................... Avg of top performer ................................................ 0.125 1.09E–03 

99% UPL of top performer (test runs) ...................... 0.125 1.52E–03 

Units designed for other gases firing ....................... Avg of top performer ................................................ 0.0129 2.67E–03 

99% UPL of top performer (test runs) ...................... 0.0129 8.28E–03 

* 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 

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 

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

Subcategory Parameter PM 

Lb/MMBtu 

Mercury 

Lb/MMBtu 

HCl 

LB/MMBtu 

CO 

(ppm @ 

3 percent 

oxygen) 

Dioxin/Furan 

(Total TEQ) 

(ng/dscm @ 

7 percent 

oxygen) 

Units designed for NG/RG 

firing.

Avg of top performer .......... 0.00013 9.4E–08 7.3E–05 5 0.0026 

99% UPL of top (test runs) 

= 

0.0005 2.0E–07 0.0002 20 0.01 

Metal Process Furnaces ..... Avg of top performer .......... 0.0065 3.3E–08 8.6E–05 0.5 0.0026 

99% UPL of top (test runs) 

= 

0.02 2.0E–07 0.0002 2 0.004 

I. How did EPA consider beyond-thefloor 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 reduce HAP emissions from nongas-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 


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32030 Federal Register / Vol. 75, No. 107 / Friday, June 4, 2010 / Proposed Rules 

14Memorandum ‘‘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. 

15Before 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. 

16HCl 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 doseresponse relationship. 

availability and technical feasibility of 

fuel switching makes this an 

unreasonable regulatory option that was 

not considered further.14 Nonair quality 

health, environmental impacts, and 

energy effects were not significant 

factors. No beyond-the-floor options for 

gas-fired boilers were identified. 

An energy assessment is a beyondthe-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 existing major source facility 

which would have already conducted 

an 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 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. Consideration of whether to set 

standards for HCl and other acid gases 

under section 112(d)(4) 

We 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 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 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. 

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 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, 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 

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 FR at 18765 

(April 15, 1998), and Lime 

Manufacturing MACT, 67 FR 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 noncarcinogenic 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 section 

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 healthbased emission standard for HCl 


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17EPA 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. 

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. 

19California 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. 

emissions under section 112(d)(4) for 

Portland Cement facilities, 74 FR 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) 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 effects associated 

with acute exposure,19 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. 

With respect to the potential health 

effects of HCl, we know the following: 

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_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=20533). 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 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 

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 short-term increases in 

emissions for these sources and their 

short-term 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 

precondition to establishing healthbased 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, 


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20See S. Rep. No. 101–228, 101st Cong. 1st sess. 

At 172 

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-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. 

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 

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 ‘‘highend’’ 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 

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 340,000 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 directly address only 

HAPs, not criteria pollutants, Congress 

did recognize, in the legislative history 

to section 112(d)(4), that MACT 

standards would have the collateral 

benefit of controlling criteria pollutants 

as well and viewed this as an important 

benefit of the air toxics program.20

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 

discretion under section 112(d)(4). 

Given the limitations of the currently 

available information (i.e., the HAP mix 

where boilers are located, and the 

cumulative health impacts from colocated sources), the environmental 

effects of HCl, and the significant cobenefits 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 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 


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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 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 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 CO testing to 

demonstrate continuous compliance 

with the CO emission limit. In 

evaluating the available cost 

information, we determined that 

requiring CO CEMS for units with heat 

input capacities greater or equal to 100 

MMBtu/hr is reasonable. This proposed 

rule 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. 

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 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 calorific value, mercury, 

sample collection, and sample 


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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 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 a 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 proposed emission 

limits by averaging the emissions from 

an individual affected unit that is 

emitting above the proposed emission 

limits with other affected units at the 

same facility that are emitting below the 

proposed emission limits. 

This proposed rule includes 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 that 

would not lessen the stringency of the 

MACT 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 be no less stringent than unit by 

unit implementation of the MACT floor 

limits. 

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 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 each discrete unit, and the statutory 

requirement 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 

affected source, (3) no averaging 

between individual sources within a 

single major source if 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 

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 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 would not be able 

to approve an emission averaging plan 

containing averaging between emissions 

of different types of pollutants or 

between sources in different 

subcategories. 

This proposed rule would also 

exclude new affected sources from the 

emissions averaging provision. EPA 

believes emissions averaging is not 

appropriate for new sources because it 

is most cost effective to integrate stateof-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 costeffective and technically reasonable 

fashion. This flexibility is not needed 

for new sources because 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 


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caps, these sources 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 

operated less efficiently. By including 

this provision in this proposed rule, we 

would further ensure that emission 

averaging results in environmental 

benefits equivalent to or better than 

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). 

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. 

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 EPAapproved 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 need to incorporate this proposed 

rule into the next renewal of your 

permit. 

P. Alternate Standard for Consideration 

As discussed above, EPA is proposing 

a definition of non-hazardous solid 

waste under RCRA in a concurrent 

notice. The proposed CAA section 

112(d) standards for boilers and process 

heaters were developed considering that 

proposed definition of solid waste. 

Therefore, 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 

definition of solid waste under RCRA. 

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 for defining solid waste under 

RCRA would result in a different, 

smaller population of units being 

covered by Boiler MACT. 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 that alternative 

definition, using the same statistical 

procedures that were used to calculate 

the standards that are being proposed. 

Table 6 reflects that calculation of 

MACT floor limits for the existing 

source subcategories that would be 

changed by the alternative 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 

definition of solid waste on which EPA 

is soliciting comment in the concurrent 

RCRA proposal, and are therefore not 

included in Table 8 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 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] 

Subcategory Particulate 

matter (PM) 

Hydrogen 

chloride (HCl) 

Mercury 

(Hg) 

Carbon 

monoxide 

(CO) (ppm 

@ 3% oxygen) 

Dioxins/ 

Furans 

(total TEQ) 

(ng/dscm) 

commat; 7% O2

Existing—Coal Stoker ...................................................... 0.03 0.02 4.0E–06 40 0 .003 

Existing—Coal Fluidized Bed .......................................... 0.03 0.02 4.0E–06 50 0 .008 

Existing—Pulverized Coal ................................................ 0.03 0.02 4.0E–06 90 0 .004 


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TABLE 8—EXISTING MACT FLOOR LIMITS USING THE ‘‘ALTERNATIVE APPROACH’’ UNDER CONSIDERATION AND COMMENT

IN THE CONCURRENTLY PROPOSED RCRA RULE—Continued 

[Pounds per million British thermal units] 

Subcategory Particulate 

matter (PM) 

Hydrogen 

chloride (HCl) 

Mercury 

(Hg) 

Carbon 

monoxide 

(CO) (ppm 

@ 3% oxygen) 

Dioxins/ 

Furans 

(total TEQ) 

(ng/dscm) 

commat; 7% O2

Existing—Biomass Stoker ................................................ 0.02 0.03 5.0E–07 180 0 .00005 

Existing—Biomass Fluidized Bed .................................... 0.02 0.03 5.0E–07 10,650 0 .1 

Existing—Biomass Suspension Burner/Dutch Oven ....... 0.02 0.03 5.0E–07 1,060 0 .3 

Existing—Biomass Fuel Cells .......................................... 0.02 0.03 5.0E–07 460 0 .02 

Comparing the emissions limits in 

Table 1 (based on the proposed 

definition of solid waste) with those in 

Table 8 (based on the alternative 

definition of solid waste), the MACT 

emission limits for PM and mercury for 

the biomass subcategories would be less 

stringent if they are based on the 

alternative definition of solid waste 

while the HCl emission limits for the 

coal and biomass subcategories would 

be more stringent if they are based on 

the alternative definition. 

The potential emissions reductions if 

the MACT floor limits are calculated 

based on the alternative definition of 

solid waste would be generally lower 

than the potential emissions reductions 

for MACT floors based on the proposed 

definition of solid waste, because 280 

fewer boilers and process heaters would 

be subject to the boiler and process 

heater MACT standards under the 

alternative definition. These units 

would instead be considered CISWI 

units under the alternative definition of 

solid waste. For example, mercury 

emissions reduction would be 7 tons per 

year based on the alternative definition 

of solid waste (compared to 8 tons per 

year based on the proposed definition) 

and HCl emissions reduction would be 

5,100 tons per year based on the 

alternative definition (compared to 

37,000 tons per year based on the 

proposed definition). Most (181) of the 

280 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 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 definition of 

solid waste would be 8.0 billion dollars 

in capital expenditures and 2.4 billion 

dollars per year in total annual costs. 

This compares to $9.5 billion in capital 

costs and $2.9 billion in annual costs 

under the proposed definition of solid 

waste in the RCRA proposed rule. Table 

9 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 9—SUMMARY OF CAPITAL AND ANNUAL COSTS FOR EXISTING SOURCES UNDER THE ALTERNATIVE SOLID WASTE

DEFINITION

Source Subcategory 

Estimated/ 

projected 

number of 

affected units 

Capital 

costs 

(106$) 

Annualized 

cost 

(106$/yr) 

Existing Units .................................... Coal units .......................................... 525 .................................................... 3,861 1,508 

Biomass units ................................... 239 .................................................... 1,250 317 

Liquid units ....................................... 791 .................................................... 1,352 417 

Gas (NG/RG) units ........................... 11,524 ............................................... 75 259 

Gas (other) units ............................... 196 .................................................... 1,476 434 

Energy Assessment .......................... ALL ................................................... 1,551 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 soliciting public comments on 

the emission limits listed in Table 6 of 

this preamble, consistent with EPA’s 

solicitation of comments on the 

alternative definition of solid waste 

concurrently proposed under RCRA. As 

explained above, the MACT floor limits 

proposed today are based on the 

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 MACT 

floor limits would 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 

A. What are the air impacts? 

Table 10 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 

43,000 tons per year for existing units 

and 15 tons per year for new units. 

Emissions of HCl will be reduced by 

37,000 tons per year for existing units 

and 9 tons per year for new units. 

Emissions of mercury will be reduced 

by 8 tons per year for existing units and 

2.6 pounds per year for new units. 

Emissions of filterable PM will be 

reduced by 50,100 tons per year for 

existing units and 130 tons per year for 

new units. Emissions of non-mercury 


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metals (i.e., antimony, arsenic, 

beryllium, cadmium, chromium, cobalt, 

lead, manganese, nickel, and selenium) 

will be reduced by 3,200 tons per year 

for existing units and will be reduced by 

0.6 ton per year for new units. In 

addition, emissions of SO2 are estimated 

to be reduced by 340,000 tons per year 

for existing sources and 500 tons per 

year for new sources. Emissions of 

dioxin/furans, on a total mass basis, will 

be reduced by 722 grams per year for 

existing units and 1 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 10—SUMMARY OF EMISSIONS REDUCTIONS FOR EXISTING AND NEW SOURCES

[Tons/yr] 

Source Subcategory HCl PM 

Non 

mercury 

metals a

Mercury VOC 

Existing Units ................................ Coal units ...................................... 35,450 17,000 770 7.1 490 

Biomass units ............................... 520 22,500 230 0.2 760 

Liquid units ................................... 840 10,400 2,200 0.00005 290 

Gas 1 (NG/RG) units .................... 9 130 1.2 0.01 72 

Gas 2 (other) units ....................... 220 0 0 0.2 170 

New Units ..................................... Coal units ...................................... 0 0 0 0 0 

Biomass units ............................... 0 0 0 0 0 

Liquid units ................................... 9 130 0.6 0.0007 3 

Gas 1 units ................................... 0.01 0.1 0.001 0.000008 0.01 

Gas 2 units ................................... 1 4 0.01 0.0006 1 

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

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 2,400 

million gallons per year for existing 

sources and 200,000 gallons per year for 

new sources. In addition to the 

increased water usage, an additional 730 

million gallons per year of wastewater 

would be produced for existing sources 

and 140,000 gallons per year for new 

sources. The annual costs of treating the 

additional wastewater are $4.0 million 

for existing sources and $774 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 81,000 

tons per year for existing sources and 

149,800 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 $3.4 million for existing 

sources and $6.3 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 2.995 million kilowatt 

hours (kWh) in national annual energy 

usage as a result of the proposed rule. 

Of this amount, 2,944 million kWh 

would be from existing sources and 11 

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 42 trillion BTU 

each year from existing sources and an 

additional 100,000 million BTU each 

year. This fuel savings estimate includes 

only those fuel savings resulting from 

gas, liquid, and coal fuels and it is based 

on the 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 

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 9.5 billion dollars in capital 

expenditures and 3.2 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 2.9 billion dollars. The total 

capital and annual costs include costs 

for control devices, work practices, 

testing and monitoring. Table 11 of this 

preamble shows the capital and annual 


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32038 Federal Register / Vol. 75, No. 107 / Friday, June 4, 2010 / Proposed Rules 

cost impacts for each subcategory. Costs 

include testing and monitoring costs, 

but not recordkeeping and reporting 

costs. 

TABLE 11—SUMMARY OF CAPITAL AND ANNUAL COSTS FOR NEW AND EXISTING SOURCES

Source Subcategory 

Estimated/ 

projected 

number of 

affected 

units 

Capital 

costs 

(106$) 

Testing and 

monitoring 

annualized 

costs 

(106$/yr) 

Annualized 

cost 

(106$/yr) 

(considering 

fuel savings) 

Existing Units .......................................... Coal units ................................................ 578 4,468 62 .4 1,619 

Biomass units ......................................... 420 2,003 35 .5 609 

Liquid units ............................................. 826 1,389 27 .4 419 

Gas (NG/RG) units ................................. 11,532 75 0 (260 ) 

Gas (other) units ..................................... 199 1,554 10 .4 459 

Energy Assessment ................................ ALL ......................................................... .................... .................... ...................... 26 

New Units ............................................... Coal units ................................................ 0 0 0 0 

Biomass units ......................................... 0 0 0 0 

Liquid units ............................................. 11 12 0 .5 6.1 

Gas (NG/RG) units ................................. 33 0.2 0 0.01 

Gas (other) units ..................................... 2 5.5 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 17 million dollars in capital 

expenditures and 6.2 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. 

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 0.04 percent. 

Social costs are estimated to also be 

$2.9 billion in 2008 dollars. This is 

estimated to be made up of a $0.8 

billion loss in domestic consumer 

surplus, a $2.5 billion loss in domestic 

producer surplus, a $0.1 billion increase 

in rest of the world surplus, and a $0.4 

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 the screening 

analysis. EPA has prepared an Initial 

Regulatory Flexibility Analysis (IRFA) 

that discusses alternative regulatory or 

policy options that minimize the rule’s 

small entity impacts. It includes key 

information about key results from the 

Small Business Advocacy Review 

(SBAR) panel. 

Precise job effect estimates cannot be 

estimated with certainty. Morgenstern et 

al. (2002) identify three economic 

mechanisms by which pollution 

abatement activities can indirectly 

influence jobs: 

• Higher production costs raise 

market prices, higher prices reduce 

consumption, and employment within 

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

• Pollution abatement activities 

require additional labor services to 

produce the same level of output (‘‘cost 

effect’’); and 

• Post regulation production 

technologies may be more or less labor 

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

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

Several empirical studies, including 

Morgenstern et al. (2002), suggest the 

net employment decline is zero or 

economically small (e.g., Cole and 

Elliot, 2007; Berman and Bui, 2001). 

However, others show the question has 

not been resolved in the literature 

(Henderson, 1996; Greenstone, 2002). 

Morgenstern’s paper uses a six-year 

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

prices, inputs (including labor), outputs, 

and environmental expenditures) to 

econometrically estimate the production 

technologies and industry-level demand 

elasticities. Their identification strategy 

leverages repeat plant-level observations 

over time and uses plant-level and year 

fixed effects (e.g., plant and time 

dummy variables). After estimating their 

model, Morgenstern show and compute 

the change in employment associated 

with an additional $1 million ($1987) in 

environmental spending. Their 

estimates covers four manufacturing 

industries (pulp and paper, plastics, 

petroleum, and steel) and Morgenstern, 

et al. present results separately for the 

cost, factor shift, and demand effects, as 

well as the net effect. They also estimate 

and report an industry-wide average 

parameter that combines the four 

industry-wide estimates and weighting 

them by each industry’s share of 

environmental expenditures. 

EPA has most often estimated 

employment changes associated with 

plant closures due to environmental 

regulation or changes in output for the 

regulated industry (EPA, 1999a; EPA, 

2000). This analysis goes beyond what 

EPA has typically done in two ways. 

First, because the multimarket model 

provides estimates for changes in output 

for sectors not directly regulated, we 

were able to estimate a more 

comprehensive ‘‘demand effect.’’ 

Secondly, parameters estimated in the 

Morgenstern paper were used to 

estimate all three effects (‘‘demand,’’ 

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

of results from the Morgenstern study is 

uncertain but avoids ignoring the ‘‘cost 

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

We calculated ‘‘demand effect’’ 

employment changes by assuming that 

the number of jobs changes 

proportionally with multi-market 

model’s simulated output changes. 

These results were calculated for all 


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21Since 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). 22Roman 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. 

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 ($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 Morgenstern paper to estimate 

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

effects (Table 1). Although using the 

Morgenstern parameters to estimate 

these ‘‘cost’’ and ‘‘factor-shift’’ 

employment changes is uncertain, it is 

helpful to compare the potential job 

gains from these effects to the job losses 

associated with the ‘‘demand’’ effect. 

Table 1 shows that using the 

Morgenstern point estimates of 

parameters to estimate the ‘‘cost’’ and 

‘‘factor shift’’ employment gains may be 

greater than the employment losses 

using either of the two ways of 

estimating ‘‘demand’’ employment 

losses. The 95 percent confidence 

intervals are shown for all of the 

estimates based on the Morgenstern 

parameters. As shown, at the 95% 

confidence level, we cannot be certain 

if net employment changes are positive 

or negative. 

Although the Morgenstern paper 

provides additional information about 

the potential job effects of 

environmental protection programs, 

there are several qualifications EPA 

considered as part of the analysis. First, 

EPA has used the weighted average 

parameter estimates for a narrow set of 

manufacturing industries (pulp and 

paper, plastics, petroleum, and steel). 

Absent other data and estimates, this 

approach seems reasonable and the 

estimates come from a respected peerreviewed source. However, EPA 

acknowledges the proposed rule covers 

a broader set of industries not 

considered in original empirical study. 

By transferring the estimates to other 

industrial sectors, we make the 

assumption that estimates are similar in 

size. In addition, EPA assumes also that 

Morgenstern et al.’s estimates derived 

from the 1979–1991 still applicable for 

policy taking place in 2013, almost 20 

years later. Second, the multi-market 

model only considers near term 

employment effects in a U.S. economy 

where production technologies are 

fixed. As a result, the modeling system 

places more emphasis on the short term 

‘‘demand effect’’ whereas the 

Morgenstern paper emphasizes other 

important long term responses. For 

example, positive job gains associated 

with ‘‘factor shift effects’’ are more 

plausible when production choices 

become more flexible over time and 

industries can substitute labor for other 

production inputs. Third, the 

Morgenstern paper estimates rely on 

sector demand elasticities that are 

different from the demand elasticity 

parameters used in the multi-market 

model. As a result, the demand effects 

are not directly comparable with the 

demand effects estimated by the multimarket model. Fourth, Morgenstern 

identifies the industry average as 

economically and statistically 

insignificant effect (i.e., the point 

estimates are small, measured 

imprecisely, and not distinguishable 

from zero.) EPA acknowledges this fact 

and has reported the 95 percent 

confidence intervals in Table 1. Fifth, 

Morgenstern’s methodology assumes 

large plants bear most of the regulatory 

costs. By transferring the estimates, EPA 

assumes a similar distribution of 

regulatory costs by plant size and that 

the regulatory burden does not 

disproportionately fall on smaller 

plants. 

TABLE 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. What are the social costs and benefits 

of this proposed rule? 

We estimate the monetized benefits of 

this proposed regulatory action to be 

$17 billion to $41 billion (2008$, 3 

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 $37 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 A 

summary of the monetized benefits 

estimates at discount rates of 3 percent 

and 7 percent is in Table 13 of this 

preamble. 


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32040 Federal Register / Vol. 75, No. 107 / Friday, June 4, 2010 / Proposed Rules 

23Fann, 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. 

24Pope 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. 

25Laden et al., 2006. ‘‘Reduction in Fine 

Particulate Air Pollution and Mortality.’’ American 

Journal of Respiratory and Critical Care Medicine. 

173:667–672. 

26U.S. Environmental Protection Agency, 2006. 

Final Regulatory Impact Analysis: PM2.5 NAAQS. 

Prepared by Office of Air and Radiation. October. 

Available on the Internet at http://www.epa.gov/ttn/ 

ecas/ria.html. 

TABLE 13—SUMMARY OF THE MONETIZED BENEFITS ESTIMATES FOR THE PROPOSED BOILER MACT FOR MAJOR

SOURCES IN 2013 

[Billions of 2008$] 1

Estimated 

emission 

reductions 

(tons per 

year) 

Total monetized benefits 

(3% discount rate) 

Total monetized benefits 

(7% discount rate) 

PM2.5 ......................................................... 29,020 $6.6 to $16 ................................................ $6.0 to $15. 

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. 

1All estimates are for the implementation year (2013), and are rounded to two significant figures so numbers may not sum across rows. All fine 

particles are assumed to have equivalent health effects, but the benefit-per-ton estimates vary between precursors because each ton of precursor reduced has a different propensity to form PM2.5. Benefits from reducing hazardous air pollutants (HAPs) are not included. 

These benefits estimates represent the 

total monetized human health benefits 

for populations exposed to less PM2.5 in 

2013 from controls installed to reduce 

air pollutants in order to meet these 

standards. These estimates are 

calculated as the sum of the monetized 

value of avoided premature mortality 

and morbidity associated with reducing 

a ton of PM2.5 and PM2.5 precursor 

emissions. To estimate human health 

benefits derived from reducing PM2.5

and PM2.5 precursor emissions, we 

utilized the general approach and 

methodology 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 

propensity to form PM2.5. For example, 

SOX has a lower benefit-per-ton estimate 

than direct PM2.5 because it does not 

form as much PM2.5, thus the exposure 

would be lower, and the monetized 

health benefits would be lower. 

For context, it is important to note 

that the magnitude of the PM benefits is 

largely driven by the concentration 

response function for premature 

mortality. Experts have advised EPA to 

consider a variety of assumptions, 

including estimates based both on 

empirical (epidemiological) studies and 

judgments elicited from scientific 

experts, to characterize the uncertainty 

in the relationship between PM2.5

concentrations and premature mortality. 

For this proposed rule we cite two key 

empirical studies, one based on the 

American Cancer Society cohort 

study 24 and the extended Six Cities 

cohort study.25 In the RIA for this 

proposed rule, which is available in the 

docket, we also include benefits 

estimates derived from expert 

judgments and other assumptions. 

This analysis does not include the 

type of detailed uncertainty assessment 

found in the 2006 PM2.5 NAAQS RIA 

because we lack the necessary air 

quality input and monitoring data to run 

the benefits model. However, the 2006 

PM2.5 NAAQS benefits analysis 26

provides an indication of the sensitivity 

of our results to various assumptions. 

It should be emphasized that the 

monetized benefits estimates provided 

above do not include benefits from 

several important benefit categories, 

including reducing other air pollutants, 

ecosystem effects, and visibility 

impairment. The benefits from reducing 

carbon monoxide and hazardous air 

pollutants have not been monetized in 

this analysis, including reducing 

330,000 tons of carbon monoxide, 

37,000 tons of HCl, 1,000 tons of HF 

each year, 7.5 tons of mercury, 3,200 

tons of other 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. 

The social costs of this proposed 

rulemaking are estimated to be $2.9 

billion (2008$) in the implementation 

year, and the monetized benefits are $17 

billion to $41 billion (2008$, 3 percent 

discount rate) for that same year. The 

benefits at a 7 percent discount rate are 

$15 billion to $37 billion (2008$). Thus, 

net benefits of this rulemaking are 

estimated at $14 billion to $38 billion 

(2008$, 3 percent discount rate) and $12 

billion to $34 billion (2008$, 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. 


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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 Benefits 2 ...................................................................... $17 to $41 ..................................... $15 to $37. 

Total Social Costs 3 ................................................................................. $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 Benefits 2 ...................................................................... $3.1 to $7.7 ................................... $2.8 to $6.9. 

Total Social Costs 3 ................................................................................. $2.2 ................................................ $2.2. 

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. 

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

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

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

for both discount rates. 

For more information on the benefits 

analysis, please refer to the RIA for this 

rulemaking, which is available in the 

docket. 

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 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 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. 


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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 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 postcombustion 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. 

In lieu of establishing numerical 

emissions limits for pollutants such as 

POM, we regulate surrogate substances. 

While we have not identified specific 

numerical limits for POM, we believe 

CO serves as an effective surrogate for 

this HAP, because CO, like POM, is 

formed as a 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 encourages 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, 

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 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 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 


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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. 

The public is invited to submit 

comments or identify peer-reviewed 

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 that alternative 

was not adopted. Before we establish 

any regulatory requirements that may 

significantly or uniquely affect small 

governments, including tribal 

governments, we must develop a small 

government agency plan under section 

203 of the UMRA. The plan must 

provide for notifying potentially 

affected small governments, enabling 

officials of affected small governments 

to have meaningful and timely input in 

the development of regulatory proposals 

with significant Federal 

intergovernmental mandates, and 

informing, educating, and advising 

small governments on compliance with 

the regulatory requirements. 

We have determined that this 

proposed rule contains a Federal 

mandate that may result in expenditures 

of $100 million or more for State, local, 

and Tribal governments, in the 

aggregate, or the private sector in any 1 

year. Accordingly, we have prepared a 

written statement entitled ‘‘Unfunded 

Mandates Reform Act Analysis for the 

Proposed Industrial Boilers and Process 

Heaters NESHAP’’ under section 202 of 

the UMRA which is summarized below. 

1. Statutory Authority 

As discussed in section I of this 

preamble, the statutory authority for this 

proposed rulemaking is section 112 of 

the CAA. Title III of the CAA 

Amendments was enacted to reduce 

nationwide air toxic emissions. Section 

112(b) of the CAA lists the 188 

chemicals, compounds, or groups of 

chemicals deemed by Congress to be 

HAP. These toxic air pollutants are to be 

regulated by NESHAP. 

Section 112(d) of the CAA 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. 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 $2.9 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 

29 thousand tons of PM2.5 and 340 

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 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 a range from $17 billion 

(2008 dollars) to $41 billion (2008 

dollars) when using a 3 percent 

discount rate (or from $15 billion (2008 

dollars) to $37 billion (2008 dollars) 

when using a 7 percent discount rate). 

This estimate, at a 3 percent discount 

rate, is about $14 billion (2008 dollars) 

to $38 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 

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 


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(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 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 

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 utilities. In these 

latter two industries, the size standard 

is 1,500 employees and a mass 

throughput of 75,000 barrels/day or less, 

and 4 million kilowatt-hours of 

production or less, respectively; (2) a 

small governmental jurisdiction that is a 

government of a city, county, town, 

school district or special district with a 

population of less than 50,000; and (3) 

a small organization that is any not-forprofit enterprise which is independently 

owned and operated and is not 

dominant in its field. 

Because an initial screening analysis 

for impact on small entities indicated a 

likely significant impact for substantial 

numbers, EPA convened a SBAR Panel 

to obtain advice and recommendation of 

representatives of the small entities that 

potentially would be subject to the 

requirements of this rule. 

(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 Information and 

Regulatory Affairs within the Office of 

Management and Budget. 

As part of the SBAR Panel process we 

conducted outreach with 

representatives from 14 various small 

entities that would be affected by this 

rule. The small entity representatives 

(SERs) included associations 

representing schools, churches, hotels/ 

motels, wood product facilities and 

manufacturers of home furnishings. We 

met with these SERs to discuss the 

potential rulemaking approaches and 

potential options to decrease the impact 

of the rulemaking on their industries/ 

sectors. We distributed outreach 

materials to the SERs; these materials 

included background on the 

rulemaking, possible regulatory 

approaches, preliminary cost and 

economic impacts, and possible 

rulemaking alternatives. The Panel met 

with SERs from the industries that will 

be impacted directly by this rule on 

February 10, 2009 to discuss the 

outreach materials and receive feedback 

on the approaches and alternatives 

detailed in the outreach packet. (EPA 

also met with SERs on November 13, 

2008 for an initial outreach meeting.) 

The Panel received written comments 

from the SERs following the meeting in 

response to discussions at the meeting 

and the questions posed to the SERs by 

the Agency. The SERs were specifically 

asked to provide comment on regulatory 

alternatives that could help to minimize 

the rule’s impact on small businesses. 

(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 


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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 tune-up methods 

targeted at smaller boiler operators. The 

panel further recommended that EPA 

take comment on the efficacy of energy 

assessments/audits at improving 

combustion efficiency and the cost of 

performing the assessments, especially 

to smaller boiler operators. 

A work practice standard, instead of 

MACT emission limits, may be 

proposed if it can be justified under 

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 assessments and 

implementation of assessment findings. 

The basis of these concerns rested upon 

the uncertainty that there is no 

guarantee that there are available funds 

to implement a particular assessment’s 

findings. 

(b) Subcategorization 

The Panel recommended that EPA 

allow subcategorizations suggested by 

the SERs, unless EPA finds that a 

subcategorization is inconsistent with 

the Clean Air Act. 

SERs commented that 

subcategorization is a key concept that 

could ensure that like boilers are 

compared with similar boilers so that 

MACT floors are more reasonable and 

could be achieved by all units within a 

subcategory using appropriate emission 

reduction strategies. SERs commented 

that EPA should subcategorize based on 

fuel type, boiler type, duty cycle, and 

location. 

(c) 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 

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. 

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. 2028.05). 

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 

effective date of the standards) is 

estimated to be $87.6 million. This 

includes 208,832 labor hours per year at 

a total labor cost of $19.8 million per 

year, and total non-labor capital costs of 

$67.8 million per year. This estimate 

includes initial and annual performance 

test, conducting and documenting an 

energy assessment, conducting and 

documenting a tune-up, semiannual 

excess emission reports, maintenance 

inspections, developing a monitoring 

plan, notifications, and recordkeeping. 

Monitoring, testing, tune-up and energy 

assessment costs 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 93,648 hours per year at 

a total labor cost of $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 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 


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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 June 4, 2010, a comment to 

OMB is best assured of having its full 

effect if OMB receives it by July 6, 2010. 

The final rule will respond to any OMB 

or public comments on the information 

collection requirements contained in 

this proposal. 

H. National Technology Transfer and 

Advancement Act 

Section 12(d) of the National 

Technology Transfer and Advancement 

Act (NTTAA) of 1995 (Pub. L. 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 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,’’ 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 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. 

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 


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include the following: (1) Sensitivity of 

the method; (2) acceptable levels of 

analyzer calibration error; (3) 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. 

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-ofstack 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 120°C 

and 134°C, and not just ‘‘above the acid 

dew-point;’’ (2) detailed specifications 

for measuring and monitoring the filter 

holder 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 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 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 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. 


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27U.S. GAO (Government Accountability Office). 

Demographics of People Living Near Waste 

Facilities. Washington DC: Government Printing 

Office; 1995. 

28Mohai P, Saha R. ‘‘Reassessing Racial and 

Socio-economic Disparities in Environmental 

Justice Research’’. Demography. 2006;43(2): 383– 

399. 

29Mennis 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. 

30Bullard RD, Mohai P, Wright B, Saha R, et al. 

Toxic Waste and Race at Twenty 1987–2007. United 

Church of Christ. March, 2007. 

31The results of the demographic analysis are 

presented in ‘‘Review of Environmental Justice 

Impacts’’, April 2010, a copy of which is available 

in the docket. 

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 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 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. 

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 13,555 

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. Adverse 

health effects from these pollutants 

include cancer, irritation of the lungs, 

skin, and mucus membranes; effects on 

the central nervous system, damage to 

the kidneys, and other acute health 

disorders. The rule will also result in 

substantial reductions of criteria 

pollutants such as carbon monoxide 

(CO), nitrogen oxides (NOX), particulate 

matter (PM), and sulfur dioxide (SO2). 

Sulfur dioxide and NO2 are precursors 

for the formation of 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 different sociodemographic groups in the locations of 

the expected emission reductions from 

this rule. The review identified those 

census blocks within a circular distance 

of 3 miles of affected sources and 

determined the demographic and socioeconomic 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 

sources.27 28 29 30 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). 

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.31 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. 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 


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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 

listservs, and the Internet, including the 

Office of Policy, Economics, and 

Innovation’s (OPEI) Rulemaking 

Gateway Web site (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 with interested 

communities. In addition, state and 

federal permitting requirements will 

provide state and local governments and 

members of affected communities the 

opportunity to provide 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: April 29, 2010. 

Lisa P. Jackson, 

Administrator. 

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 revising 

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 is the affected source of this 

subpart? 

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, work 

practice standards, and operating limits 

must I meet? 

General Compliance Requirements 

63.7505 What are my general requirements 

for complying with this subpart? 

Testing, Fuel Analyses, and Initial 

Compliance Requirements 

63.7510 What are my initial compliance 

requirements and by what date must I 

conduct them? 

63.7515 When must I conduct subsequent 

performance tests or fuel analyses? 

63.7520 What stack tests and 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 

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) 

Table 3 to Subpart DDDDD of Part 63—Work 

Practice Standards 

Table 4 to Subpart DDDDD of Part 63— 

Operating Limits for Boilers and Process 

Heaters 

Table 5 to Subpart DDDDD of Part 63— 

Performance Testing Requirements 

Table 6 to Subpart DDDDD of Part 63—Fuel 

Analysis Requirements 

Table 7 to Subpart DDDDD of Part 63— 

Establishing Operating Limits 

Table 8 to Subpart DDDDD of Part 63— 

Demonstrating Continuous Compliance 

Table 9 to Subpart DDDDD of Part 63— 

Reporting Requirements 

Table 10 to Subpart DDDDD of Part 63— 

Applicability of General Provisions to 

Subpart DDDDD 

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 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, and 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 June 4, 

2010, and you meet the applicability 


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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 June 4, 2010, and you meet the 

applicability criteria at the time you 

commence reconstruction. 

(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 

(j) of this section are not subject to this 

subpart. 

(a) An electric utility steam generating 

unit. 

(b) A recovery boiler or furnace 

covered by 40 CFR part 63, subpart MM. 

(c) 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. 

(d) A hot water heater as defined in 

this subpart. 

(e) A refining kettle covered by 40 

CFR part 63, subpart X. 

(f) An ethylene cracking furnace 

covered by 40 CFR part 63, subpart YY. 

(g) 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). 

(h) Any boiler or process heater 

specifically listed as an affected source 

in another standard(s) under 40 CFR 

part 63. 

(i) Temporary boilers as defined in 

this subpart. 

(j) 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]. 

(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 

§ 63.7499 What are the subcategories of 

boilers and process heaters? 

(a) 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, 

(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, 

(10) Units designed to burn other 

gases, and 

(11) Metal process furnaces. 

(b) 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). 

(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 

§ 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. 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 

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 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 


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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 

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 

§ 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. 

(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) 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. 

(f) If your new or reconstructed 

affected source commenced 

construction or reconstruction between 

June 4, 2010 and [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 limits no later than 180 days 

after [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). 

(g) If your new or reconstructed 

affected source commenced 

construction or reconstruction between 

June 4, 2010, and [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 

[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. 

(h) If your new or reconstructed 

affected source commences construction 

or reconstruction after [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 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 at or below 75 percent of 

the emission limit, and if there are no 

changes in the operation of the affected 

source or air pollution control 

equipment that could increase 

emissions. In this case, you do not have 

to conduct a performance test for that 

pollutant for the next 2 years. You must 

conduct a performance test during the 

third year and no more than 36 months 

after the previous performance test. 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 at or below 75 percent of 

the emission limit, and if there are no 

changes in the operation of the affected 

source or air pollution control 

equipment that could increase 

emissions, but each such performance 

test must be conducted no more than 36 

months after the previous performance 

test. 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. 


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(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) If you are required to meet an 

applicable work practice standard, you 

must conduct annual performance tuneups according to § 63.7520. Each annual 

tune-up must be conducted between 10 

and 12 months after the previous tuneup. 

(f) 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. 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 

heater. You must still meet all 

applicable continuous compliance 

requirements in § 63.7540. 

(g) 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 must 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 must 

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 has 

the highest content of chlorine and 

mercury, and you must demonstrate 

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. 

(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. 

(vi) If you will be using fuel analysis 

from a fuel supplier in lieu of sitespecific 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 crosssection of the stopped belt to obtain a 

minimum two pounds of sample. You 

must collect all the material (fines and 

coarse) in the full cross-section. You 

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. 

(ii) At each sampling site, you must 

dig into the pile to a depth of 18 inches. 

You 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) You must transfer all samples to 

a clean plastic bag for further 

processing. 

(d) You must prepare each composite 

sample according to the procedures in 

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

section. 

(1) You must thoroughly mix and 

pour the entire composite sample over 

a clean plastic sheet. 

(2) You must break sample pieces 

larger than 3 inches into smaller sizes. 

(3) You must make a pie shape with 

the entire composite sample and 

subdivide it into four equal parts. 

(4) You 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 onequarter subset from this sample. 

(6) You must grind the sample in a 

mill. 

(7) You must use the procedure in 

paragraph (d)(3) of this section to obtain 

a one-quarter subsample for analysis. If 

the quarter sample is too large, 

subdivide it further using the same 

procedure. 

(e) You must determine the 

concentration of pollutants in the fuel 

(mercury and/or chlorine) in units of 


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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. 

(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 [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 [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. 

AveWeightedEmissions =× ×÷

= =

0 90 ∑ ∑ 1 1. (Er Hm) Hm

i

n

i

n

(Eq. 1)

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. 

AveWeightedEmissions = × ×× ÷ ×

= =

0 90 ∑ ∑ 1 1. (Er Sm ) Sm

i

n

i

n

Cfi Cfi (Eq. 2)

Where: 

Ave Weighted Emissions = Average weighted 

emission level for PM, 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. 

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. 

AveWeightedEmissions = × ×÷

= =

0 90 ∑ ∑ 1 1. (Er Hb) Hb

i

n

i

n

(Eq. 3)

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 

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. 


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32054 Federal Register / Vol. 75, No. 107 / Friday, June 4, 2010 / Proposed Rules 

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. 

AveWeightedEmissions = × ×× ÷ ×

= =

0 90 ∑ ∑ 1 1. (Er Sa ) Sa

i

n

i

n

Cfi Cfi (Eq. 4)

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 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. 

Eavg = ERi

i

n

÷

=

∑ 12

1

(Eq. 5)

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: 

(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 [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: 

(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 

(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 


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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. 

En = ×÷

= =

∑ ∑ (ELi Hi) Hi

i

n

i

n

1 1

(Eq. 6)

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 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. 

(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 combusts 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. 

(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 

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 sitespecific monitoring plan procedures and 

acceptance criteria for operating and 

maintaining each COMS according to 

the requirements in § 63.8(d). At a 

minimum, the monitoring plan must 

include a daily calibration drift 

assessment, a quarterly performance 

audit, and an annual zero alignment 

audit of each COMS. 

(6) You must operate and maintain 

each COMS according to the 

requirements in the monitoring plan 

and the requirements of § 63.8(e). 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 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 


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32056 Federal Register / Vol. 75, No. 107 / Friday, June 4, 2010 / Proposed Rules 

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. 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-ofcontrol and data are not available for 

required calculations constitutes a 

deviation from the monitoring 

requirements. 

(4) You must determine the 3-hour 

block average of all recorded readings, 

except as provided in paragraph (c)(3) of 

this section. 

(5) You 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) You must locate the flow sensor 

and other necessary equipment in a 

position that provides a representative 

flow. 

(2) You must use a flow sensor with 

a measurement sensitivity of 2 percent 

of the flow rate. 

(3) You must reduce swirling flow or 

abnormal velocity distributions due to 

upstream and downstream disturbances. 

(4) You 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. 

(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 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. 

(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 


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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. 

(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. 

Clinpunt i i)

i

n

= ×

=

∑(C Q

1

(Eq. 7)

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 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. 

Mercuryinput i i)

i

n

= ×

=

∑(HG Q

1

(Eq. 8)

Where: 

Mercuryinput = Maximum amount of mercury 

entering the boiler or process heater 

through fuels burned in units of pounds 

per million Btu. 

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 three-run 

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 input), as defined in § 63.7575, as 

your operating limits during the threerun 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 for each 

fuel type using the one-sided z-statistic 

test described in Equation 9 of this 

section. 

P SD t 90 = +× mean ( ) (Eq. 9)

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. 


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32058 Federal Register / Vol. 75, No. 107 / Friday, June 4, 2010 / Proposed Rules 

HCl i

i

n

= ××

=

∑( .) C iQ 90 1 028

1

(Eq. 10)

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 

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. 

Mercury i i

i

n

= ×

=

∑(HG Q 90

1

) (Eq. 11)

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 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 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 sitespecific 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 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 must 

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 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 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 


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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. 

(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 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 

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 

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) 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 

(vi) Maintain on-site and submit, if 

requested by the Administrator, an 

annual report containing the 

information in paragraphs (a)(10)(vi)(A) 

through (C) of this section, 

(A) 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; 

(B) A description of any corrective 

actions taken as a part of the 

combustion adjustment; and 

(C) 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. These instances are deviations 

from the emission limits in this subpart. 

These deviations must be reported 

according to the requirements in 

§ 63.7550. 

§ 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 


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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 

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 60 DAYS AFTER PUBLICATION 

OF THE FINAL RULE IN THE FEDERAL 

REGISTER], you must submit an Initial 

Notification not later than 120 days after 

[DATE 60 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 60 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) of this section, as applicable. 

(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, whether the fuel(s) 

were processed from discarded nonhazardous 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. 

(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 natural gas-fired 

boiler or process heater that is subject 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. 

§ 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 the first date 

following the end of the semiannual 

reporting period. 


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(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 (9) 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, whether the fuel has received a 

non-waste determination by EPA or 

your basis for concluding that the 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 § 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 

§ 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 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 cannot 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) 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. 

(9) 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. 

(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 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 any 

deviations from your site-specific 

monitoring plan as required in 

§ 63.7505(d). 

(1) The date and time that each 

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 (lowlevel) 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. 

(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 required information 

concerning deviations from any 


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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: 

(1) ‘‘This facility complies with the 

requirements in § 63.7540(a)(10) to 

conduct an annual tune-up of the unit’’. 

(2) ‘‘This facility has had an energy 

assessment performed according to 

§ 63.7530(e).’’ 

(3) ‘‘No secondary materials 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 entering the data 

electronically into EPA’s WebFIRE data 

base 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 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) and (2) 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). 

(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 you combust non-hazardous 

secondary materials that have been 

determined not to be solid waste 

pursuant to 40 CFR 41.3(b)(1), you must 

keep a record which documents how the 

secondary material meets each of the 

legitimacy criteria. If you combust a fuel 

that has been processed from a 

discarded non-hazardous secondary 

material pursuant to 40 CFR 241.3(b)(2), 

you must keep records as to how the 

operations that produced the fuel 

satisfies the definition of processing in 

40 CFR 241.2. If the fuel received a nonwaste determination pursuant to the 

petition process submitted under 40 

CFR 241.3(c), you must keep a record 

which documents how the fuel satisfies 

the requirements 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 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 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 § 63.7550, 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 


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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. 

(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 

§ 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 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(e) and as defined in § 63.90. 

§ 63.7575 What definitions apply to this 

subpart? 

Terms used in this subpart are 

defined in the Clean Air Act (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, 

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 manure, including litter and 

other bedding materials; vegetative 

agricultural and silvicultural materials, 

such as logging residues (slash), nut and 

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

walnut, peanut, rice, and wheat), 

bagasse, orchard prunings, corn stalks, 

coffee bean hulls and grounds. This 

definition of biomass fuel is not 

intended to suggest that these materials 

are or are 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 fuel system (including 

burners), blowdown system, combustion 

control system, and energy consuming 

systems. 

Coal means all solid fuels classifiable 

as anthracite, bituminous, subbituminous, or lignite by the American 

Society for Testing and Materials in 

ASTM D388–991.1, ‘‘Standard 

Specification for Classification of Coals 

by Rank’’ 1 (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. 

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 two 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 

Oils’’ 1 (incorporated by reference, see 

§ 63.14(b)). 

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 


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32064 Federal Register / Vol. 75, No. 107 / Friday, June 4, 2010 / Proposed Rules 

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 fuel-fired combustion 

unit of more than 25 megawatts that 

serves a generator that produces 

electricity for sale. A fossil fuel-fired 

unit that cogenerates steam and 

electricity and supplies more than onethird 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. 

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. 

(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 to 

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 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 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 includes, but is not 

limited to, distillate oil, residual oil, onspec used oil, and biodiesel. 

Liquid fuel subcategory includes any 

boiler or process heater of any design 

that burns more than 10 percent liquid 

fuel and less than 10 percent solid fuel, 

on an annual heat input basis. 

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 injection rate 

means 90 percent of the test average 

sorbent (or activated carbon) injection 

rate for each sorbent measured 

according to Table 7 to this subpart 

during the most recent performance test 


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demonstrating compliance with the 

applicable emission limits. 

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 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 means 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 

Materials in ASTM D396–02a, 

‘‘Standard Specifications for Fuel Oils 1’’ 

(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 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 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 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 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 boiler 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. 


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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. 

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 Subpart DDDDD of Part 63 

As stated in § 63.7500, you must 

comply with the following applicable 

emission limits: 

TABLE 1 TO SUBPART DDDDD OF PART 63—EMISSION LIMITS FOR NEW OR RECONSTRUCTED BOILERS AND PROCESS

HEATERS

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 ...................... 0.001 lb per MMBtu of heat input. 

b. Hydrogen Chloride .................... 0.00006 lb per MMBtu of heat input. 

c. Mercury ...................................... 2.0E–06 lb per MMBtu of heat input. 

d. CO ............................................. 90 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 ...................... 0.001 lb per MMBtu of heat input. 

b. Hydrogen Chloride .................... 0.00006 lb per MMBtu of heat input. 

c. Mercury ...................................... 2.0E–06 lb per MMBtu of heat 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 ......................

b. Hydrogen Chloride ....................

0.001 lb per MMBtu of heat input. 

0.00006 lb per MMBtu of heat input. 

c. Mercury ...................................... 2.0E–06 lb per MMBtu of heat input. 

d. CO ............................................. 30 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 ......................

b. Hydrogen Chloride ....................

c. Mercury ......................................

d. CO .............................................

0.008 lb per MMBtu of heat input. 

0.004 lb per MMBtu of heat input. 

2.0E–07 lb per MMBtu of heat input. 

560 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 ......................

b. Hydrogen Chloride ....................

0.008 lb per MMBtu of heat input. 

0.004 lb per MMBtu of heat input. 

c. Mercury ...................................... 2.0E–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 

Ovens designed to burn biomass.

a. Particulate Matter ......................

b. Hydrogen Chloride ....................

c. Mercury ......................................

d. CO .............................................

0.008 lb per MMBtu of heat input. 

0.004 lb per MMBtu of heat input. 

2.0E–07 lb per MMBtu of heat input. 

1,010 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 ......................

b. Hydrogen Chloride ....................

c. Mercury ......................................

d. CO .............................................

0.008 lb per MMBtu of heat input. 

0.004 lb per MMBtu of heat input. 

2.0E–07 lb per MMBtu of heat input. 

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 .............................. 0.0005 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 .................... 0.0004 lb per MMBtu of heat input. 

c. Mercury ...................................... 3.0E–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 .............................. 0.002 ng/dscm (TEQ) corrected to 7 percent oxygen. 


erowe on DSK5CLS3C1PROD with PROPOSALS5
Federal Register / Vol. 75, No. 107 / Friday, June 4, 2010 / Proposed Rules 32067 

TABLE 1 TO SUBPART DDDDD OF PART 63—EMISSION LIMITS FOR NEW OR RECONSTRUCTED BOILERS AND PROCESS

HEATERS—Continued 

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 . . . 

9. Units designed to burn other 

gases.

a. Particulate Matter ......................

b. Hydrogen Chloride ....................

c. Mercury ......................................

d. CO .............................................

0.003 lb per MMBtu of heat input. 

3.0E–06 lb per MMBtu of heat input. 

2.0E–07 lb per MMBtu of heat input. 

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 .............................. 0.009 ng/dscm (TEQ) corrected to 7 percent oxygen. 

As stated in § 63.7500, you must 

comply with the following applicable 

emission limits: 

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] 

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 ...................... 0.02 lb per MMBtu of heat input. 

b. Hydrogen Chloride .................... 0.02 lb per MMBtu of heat input. 

c. Mercury ...................................... 3.0E–06 lb per MMBtu of heat input. 

d. CO ............................................. 90 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. 

2. Stokers designed to burn coal .... a. Particulate Matter ...................... 0.02 lb per MMBtu of heat input. 

b. Hydrogen Chloride .................... 0.02 lb per MMBtu of heat input. 

c. Mercury ...................................... 3.0E–06 lb per MMBtu of heat input. 

d. CO ............................................. 50 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 ......................

b. Hydrogen Chloride ....................

0.02 lb per MMBtu of heat input. 

0.02 lb per MMBtu of heat input. 

c. Mercury ...................................... 3.0E–06 lb per MMBtu of heat input. 

d. CO ............................................. 30 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 ......................

b. Hydrogen Chloride ....................

c. Mercury ......................................

d. CO .............................................

0.02 lb per MMBtu of heat input. 

0.006 lb per MMBtu of heat input. 

9.0E–07 lb per MMBtu of heat input. 

560 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. 

5. Fluidized bed units designed to 

burn biomass.

a. Particulate Matter ......................

b. Hydrogen Chloride ....................

0.02 lb per MMBtu of heat input. 

0.006 lb per MMBtu of heat input. 

c. Mercury ...................................... 9.0E–07 lb per MMBtu of heat input. 

d. CO ............................................. 250 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 ......................

b. Hydrogen Chloride ....................

0.02 lb per MMBtu of heat input. 

0.006 lb per MMBtu of heat input. 

c. Mercury ...................................... 9.0E–07 lb per MMBtu of heat input. 

d. CO ............................................. 1,010 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 ......................

b. Hydrogen Chloride ....................

c. Mercury ......................................

d. CO .............................................

0.02 lb per MMBtu of heat input. 

0.006 lb per MMBtu of heat input. 

9.0E–07 lb per MMBtu of heat input. 

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. 


erowe on DSK5CLS3C1PROD with PROPOSALS5
32068 Federal Register / Vol. 75, No. 107 / Friday, June 4, 2010 / Proposed Rules 

TABLE 2 TO SUBPART DDDDD OF PART 63—EMISSION LIMITS FOR EXISTING BOILERS AND PROCESS HEATERS— 

Continued 

[Units with heat input capacity of 10 million Btu per hour or greater] 

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 . . . 

8. Units designed to burn liquid fuel a. Particulate Matter ...................... 0.004 lb per MMBtu of heat input. 

b. Hydrogen Chloride .................... 0.0009 lb per MMBtu of heat input. 

c. Mercury ...................................... 4.0E–06 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 .............................. 0.002 ng/dscm (TEQ) corrected to 7 percent oxygen. 

9. Units designed to burn other 

gases.

a. Particulate Matter ......................

b. Hydrogen Chloride ....................

c. Mercury ......................................

d. CO .............................................

0.05 lb per MMBtu of heat input. 

3.0E–06 lb per MMBtu of heat input. 

2.0E–07 lb per MMBtu of heat input. 

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 .............................. 0.009 ng/dscm (TEQ) corrected to 7 percent oxygen. 

As stated in §§ 63.11202 and 

63.11203, you must comply with the 

following applicable work practice 

standards: 

TABLE 3 TO SUBPART DDDDD OF PART 63—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 biennially as specified in § 63.7540. 

2. A new or existing boiler or process heater in 

either the Gas 1 or Metal Process Furnace 

subcategory with heat input capacity of 10 

million Btu per hour or greater.

Conduct a tune-up of the boiler annually as specified in § 63.7540. 

3. An existing boiler located at a major source 

facility.

Must have an energy assessment performed on the major source facility by qualified personnel which includes: 

(a) a visual inspection of the boiler system. 

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

(c) identify major energy consuming systems, 

(d) a review of available architectural and engineering plans, facility operation and maintenance procedures and logs, and fuel usage, 

(e) a list of major energy conservation measures, 

(f) the energy savings potential of the energy conservation measures identified, and 

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

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

(h) a facility energy management program developed according to the ENERGY STAR 

guideline for energy management. 

As stated in § 63.7500, you must 

comply with the applicable operating 

limits: 

TABLE 4 TO SUBPART DDDDD OF PART 63—OPERATING LIMITS FOR BOILERS AND PROCESS HEATERS

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 


erowe on DSK5CLS3C1PROD with PROPOSALS5
Federal Register / Vol. 75, No. 107 / Friday, June 4, 2010 / Proposed Rules 32069 

TABLE 4 TO SUBPART DDDDD OF PART 63—OPERATING LIMITS FOR BOILERS AND PROCESS HEATERS—Continued 

If you demonstrate compliance using . . . You must meet these operating limits . . . 

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. 

As stated in § 63.7520, you must 

comply with the following requirements 

for performance test for existing, new or 

reconstructed affected sources: 

TABLE 5 TO SUBPART DDDDD OF PART 63—PERFORMANCE TESTING REQUIREMENTS

To conduct a performance test for 

the following pollutant . . . You must . . . Using . . . 

1. Particulate Matter ..................... a. Select sampling ports location and 

the number of traverse points.

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

b. Determine velocity and volumetric 

flow-rate of the stack gas.

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

c. Determine oxygen and carbon dioxide concentrations of the stack gas.Method 3A or 3B in appendix A to part 60 of this chapter, or 

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 

flow-rate of the stack gas.

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

c. Determine oxygen and carbon dioxide concentrations of the stack gas.Method 3A or 3B in appendix A to part 60 of this chapter, or 

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. 

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 

flow-rate of the stack gas.

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

c. Determine oxygen and carbon dioxide concentrations of the stack gas.Method 3A or 3B in appendix A to part 60 of this chapter, or 

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. 


erowe on DSK5CLS3C1PROD with PROPOSALS5
32070 Federal Register / Vol. 75, No. 107 / Friday, June 4, 2010 / Proposed Rules 

TABLE 5 TO SUBPART DDDDD OF PART 63—PERFORMANCE TESTING REQUIREMENTS—Continued 

To conduct a performance test for 

the following pollutant . . . You must . . . Using . . . 

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 dioxin/furans emission 

concentration.

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

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: 

TABLE 6 TO SUBPART DDDDD OF PART 63—FUEL ANALYSIS REQUIREMENTS

To conduct a fuel analysis for the 

following pollutant . . . You must . . . Using . . . 

1. Mercury ..................................... a. Collect fuel samples .......................... Procedure in § 63.7521(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. 

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.

As stated in § 63.7520, you must 

comply with the following requirements 

for establishing operating limits: 


erowe on DSK5CLS3C1PROD with PROPOSALS5
Federal Register / Vol. 75, No. 107 / Friday, June 4, 2010 / Proposed Rules 32071 

TABLE 7 TO SUBPART DDDDD OF PART 63—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 matter or 

mercury.

a. Wet scrubber operating 

parameters.

i. Establish a site-specific 

minimum pressure drop 

and minimum flow rate 

operating limit 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 pressure 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 

three-run 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 

operating limit according 

to § 63.7530(c).

(1) Data from the pH, 

pressure drop, and liquid 

flow-rate monitors and 

the hydrogen chloride 

performance test.

(a) You must collect pH, 

pressure drop, and liquid 

flow-rate data every 15 

minutes during the entire 

period of the performance tests; 

(b) Determine the average 

pH, pressure drop, and 

liquid flow-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. 

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. 

As stated in § 63.7540, you must show 

continuous compliance with the 

emission limitations for affected sources 

according to the following: 


erowe on DSK5CLS3C1PROD with PROPOSALS5
32072 Federal Register / Vol. 75, No. 107 / Friday, June 4, 2010 / Proposed Rules 

TABLE 8 TO SUBPART DDDDD OF PART 63—DEMONSTRATING CONTINUOUS COMPLIANCE

If you must meet the following operating limits 

or work practice 

standards . . . 

You must demonstrate continuous compliance by . . . 

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). 

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). 

As stated in § 63.7550, you must 

comply with the following requirements 

for reports: 

TABLE 9 TO SUBPART DDDDD OF PART 63—REPORTING REQUIREMENTS

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 


erowe on DSK5CLS3C1PROD with PROPOSALS5
Federal Register / Vol. 75, No. 107 / Friday, June 4, 2010 / Proposed Rules 32073 

TABLE 9 TO SUBPART DDDDD OF PART 63—REPORTING REQUIREMENTS—Continued 

You must submit a(n) . . . The report must contain . . . You must submit the report . . . 

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 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 

b. The information in § 63.10(d)(5)(ii) ...............

i. By fax or telephone within 2 working days 

after starting actions inconsistent with the 

plan; and 

ii. By letter within 7 working days after the end 

of the event unless you have made alternative arrangements with the permitting authority. 

As stated in § 63.7565, you must 

comply with the applicable General 

Provisions according to the following: 

TABLE 10 TO SUBPART DDDDD OF PART 63—APPLICABILITY OF GENERAL PROVISIONS TO SUBPART DDDDD 

Citation Subject Applies to subpart DDDDD 

§ 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. 

§ 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. 

[FR Doc. 2010–10827 Filed 6–3–10; 8:45 am] 

BILLING CODE 6560–50–P 


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