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EO12866 NESHAP Major Sources-Industrial Commercial Institutional 

Boiler and Process Heaters RIN 2060-AR13 Proposed Rule –

Reconsideration 20111014

6560-50-P

ENVIRONMENTAL PROTECTION AGENCY

40 CFR Part 63

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

RIN 2060-AR13

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; notice of reconsideration of final rule.

SUMMARY: On March 21, 2011, the EPA promulgated national 

emission standards for the control of hazardous air pollutants 

from new and existing industrial, commercial, and institutional 

boilers and process heaters at major sources of hazardous air 

pollutants. On that same day, the EPA also published a notice to 

reconsider certain provisions of the final rule. The EPA 

subsequently issued a notice on May 18, 2011, to stay the 

effective dates of the final rule until judicial review has been 

completed, or the agency finalizes its reconsideration of the 

standard. In the action to stay the effective dates of the rule, 

the EPA also requested the public to submit data and information 

to support the reconsideration. Following these actions, the 

Administrator received several petitions for reconsideration. In 
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response to the March 21, 2011 notice of reconsideration and the 

petitions submitted, EPA is reconsidering and requesting comment 

on several provisions of the final rule. Additionally, EPA is 

proposing amendments and technical corrections to the final rule 

to clarify definitions, references, applicability, and 

compliance issues raised by stakeholders subject to the final 

rule.

DATES: Comments. Comments must be received on or before

[INSERT DATE 45 DAYS FROM DATE OF PUBLICATION].

Public Hearing. We will hold a public hearing concerning the 

proposed items for reconsideration. Persons interested in 

presenting oral testimony at the hearing should contact Ms. 

Teresa Clemons at (919) 541–7689 or at clemons.teresa@epa.gov by 

[INSERT DATE 10 DAYS FROM DATE OF PUBLICATION]. If no one 

requests to speak at the public hearing by [INSERT DATE 10 DAYS 

FROM DATE OF PUBLICATION], then the public hearing will be 

cancelled. We will specify the date and time of the public 

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

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

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

• www.regulations.gov: Follow the instructions for 

submitting comments.

• Email: Comments may be sent by email to a-and-r-
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Docket@epa.gov, Attention Docket ID No. EPA-HQ-OAR2002-0058. 

• Fax: Fax your comments to: (202) 566-9744, Attention 

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: In person or by courier, deliver 

comments to: EPA Docket Center (2822T), 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 

holidays), and special arrangements should be made for 

deliveries of boxed information.

Instructions: Direct your comments to Docket ID No. EPA-HQ-OAR2002-0058. EPA’s policy is that all comments received will be 
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included in the public docket without change and may be made 

available online at 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 www.regulations.gov or email. The 

www.regulations.gov website 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 email comment directly to EPA without going 

through www.regulations.gov, your email 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. For additional information about EPA’s 
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public docket, visit the EPA Docket Center homepage at 

http://www.epa.gov/epahome/dockets.htm.

Docket: All documents in the docket are listed in the 

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. Publicly available docket materials 

are available either electronically in www.regulations.gov or in 

hard copy at the EPA Docket Center, EPA West Building, 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 Docket Center 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:
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Organization of this Document. The following outline is provided 

to aid in locating information in this preamble. 

I. General Information

A. Does this notice of reconsideration apply to me?

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

C. How do I obtain a copy of this document and other related

information?

II. Background Information

III. Summary of This Proposed Rule

A. What is the source category regulated by this proposed rule?

B. What is the affected source?

C. What are the pollutants regulated by this proposed rule?

D. What emission limits and work practice standards must I meet?

E. What are the requirements during periods of startup, 

shutdown, and malfunction?

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. How should emissions test results be submitted to EPA?

J. What are the proposed compliance dates?

IV. Actions We Are Taking

V. Discussion of Issues for Reconsideration

A. Surrogates and Selected Regulated Pollutants

B. Output-Based Standards

C. Subcategories

D. Monitoring

E. Emission Limits

F. MACT Floor Methodology

G. Tune-up Work Practices

H. Energy Assessment

I. Affirmative Defense Provisions During Malfunctions

J. Work Practices During Startup and Shutdown

K. Applicability

L. Compliance

VI. Technical Corrections and Clarifications

VII. Impacts of This 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 cost impacts?

E. What are the economic impacts?

F. What are the benefits of this proposed rule?
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G. What are the secondary air impacts?

VIII. Relationship of this Proposed Action to Section 112(c)(6) 

of the Clean Air Act

IX. Statutory and Executive Order Reviews

A. Executive Order 12866: Regulatory Planning and Review and

Executive Order 13563: Improving Regulation and Regulatory

Review

B. Paperwork Reduction Act

C. Regulatory Flexibility Act

D. Unfunded Mandates Reform Act

E. Executive Order 13132: Federalism

F. Executive Order 13175: Consultation and Coordination with

Indian Tribal Governments

G. Executive Order 13045: Protection of Children from

Environmental Health Risks and Safety Risks

H. Executive Order 13211: Actions Concerning Regulations That

Significantly Affect Energy Supply, Distribution, or Use

I. National Technology Transfer and Advancement Act

J. Executive Order 12898: Federal Actions to Address

Environmental Justice in Minority Populations and Low-Income

Populations

I. General Information

A. Does this notice of reconsideration apply to me?

The regulated categories and entities potentially affected 

by this action include:

Category

NAICS 

code1

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
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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 

regulated by this reconsideration action. To determine whether 

your facility may be affected by this reconsideration 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 

Institutional Boilers and Process Heaters). If you have any 

questions regarding the applicability of the proposed rule to a 

particular entity, consult either the air permitting authority 
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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?

Submitting CBI. Do not submit information that you consider 

to be CBI electronically through http://www.regulations.gov or 

email. Send or deliver information identified as CBI to only the 

following address: Mr. Robert Morales, c/o OAQPS Document 

Control Officer (Room C404-02), U.S. Environmental Protection 

Agency, Research Triangle Park, North Carolina 27711, Attn: 

Docket ID No. 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. If you submit a disk or CD-ROM that does not 

contain CBI, mark the outside of the disk or CD-ROM clearly that 

it does not contain CBI. Information marked as CBI will not be 

disclosed except in accordance with procedures set forth in 40 

CFR part 2.
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If you have any questions about CBI or the procedures for 

claiming CBI, please consult the person identified in the FOR 

FURTHER INFORMATION CONTACT section.

C. How do I obtain a copy of this document and other related 

information?

Docket. The docket number for this action and the proposed

rule (40 CFR part 63, subpart DDDDD) is Docket ID No. EPA-HQOAR-2002-0058. 

World Wide Web (WWW). In addition to being available in the 

docket, an electronic copy of this action is available on the 

WWW through the Technology Transfer Network (TTN) website. 

Following signature, a copy of this notice will be posted on the 

TTN’s policy and guidance page for newly proposed or promulgated 

rules at http://www.epa.gov/ttn/oarpg. The TTN provides 

information and technology exchange in various areas of air 

pollution control. 

II. Background Information

On March 21, 2011, EPA issued final standards for new and 

existing industrial, commercial, and institutional boilers and 

process heaters, pursuant to its authority under section 112 of 

the Clean Air Act(CAA). On the same day as this final rule was 

issued, EPA also initiated a reconsideration of several 

provisions of the final rule in a separate notice. This 
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reconsideration notice identified several provisions of the 

final rule where additional public comment was appropriate, 

including:

 Revisions to the proposed subcategories.

 Establishing a fuel specification through which gas-fired 

boilers that use a fuel other than natural gas or 

refinery gas may be considered Gas 1 units.

 Establishing a work practice standard for limited use 

units.

 Providing an affirmative defense for malfunction events.

This reconsideration notice also identified several issues 

of central relevance to the rulemaking where reconsideration was 

appropriate under CAA section 307(d), including:

 Revisions to the proposed monitoring requirements for 

carbon monoxide for major source boilers.

 Revisions to the proposed dioxin emission limit and 

testing requirement for major source boilers.

 Establishing a full-load stack test requirement for 

carbon monoxide coupled with continuous oxygen (oxygen 

trim) monitoring.

On May 18, 2011, EPA issued a notice to stay the effective 

dates of this rule. This notice also requested that the public 
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submit additional data and information to EPA by July 15, 2011 

for review and consideration in the reconsideration proceedings. 

Following promulgation of the final rule, EPA received petitions

for reconsideration from the following organizations

(“Petitioners”): Alliance for Industrial Efficiency (AIE), US 

Clean Heat Power Association (USCHPA), Alyeska Pipeline, 

American Chemistry Council (ACC), American Home Furnishings 

Alliance (AHFA), American Iron and Steel Institute (AISI), 

American Coke and Coal Chemicals Institute (ACCCI), American 

Municipal Power Inc. (AMP), American Petroleum Institute (API), 

National Petrochemical and Refiners Association (NPRA), Auto 

Industry Forum (AIF), Citizens Energy Group (CEG), Council of 

Industrial Boiler Owners (CIBO), CraftMaster Manufacturing Inc.

(CMI), District Energy St. Paul, Florida Sugar Industry (FSI), 

Great Plains Synfuels (GPSP), Hovensa L.L.C., Tesoro Hawaii 

Corp., Industry Coalition (AF&PA et. al.), JELD-WEN Inc., 

Michigan State University (MSU), Penn State University (PSU), 

Purdue University, Renovar Energy Corp., Rochester Public 

Utilities (RPU), Sierra Club, Southeastern Lumber Manufacturers 

Association, State of Washington Department of Ecology, The 

Business Council for Sustainable Energy (BCSE), Utility Air 

Regulatory Group (UARG), United States Sugar Corporation (US 

Sugar), Waste Management Inc. (WM), and Wisconsin Electric Power 
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Company. Copies of these petitions are provided in the docket 

(see Docket ID No. EPA-HQ-OAR-2002-0058). Petitioners, pursuant 

to CAA section 307(d)(7)(B), requested that EPA reconsider

numerous provisions in the rules. In this action, the EPA is 

proposing multiple changes to the final rule in response to the 

reconsideration requests and the issues that the EPA previously 

identified as reconsideration issues. The EPA also is soliciting 

comment on several provisions of the final rule for which we are 

not proposing changes, because the public did not previously 

have an opportunity to comment on those provisions.

III. Summary of This Proposed Rule

This section summarizes the requirements of this action.

Section IV below provides a summary of the significant changes 

to this proposed rule.

A. What is the source category regulated by this proposed rule?

This proposed rule regulates industrial, commercial, and 

institutional boilers and process heaters located at major 

sources of hazardous air pollutants (HAP). Waste heat boilers

and process heaters and boilers and process heaters that combust 

solid waste, except for specific exceptions to the definition of 

a solid waste incineration unit outlined in section 129(g)(1), 

are not subject to this proposed rule.

B. What is the affected source?
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This proposed rule affects industrial, commercial, and 

institutional boilers and process heaters. A process heater is 

defined as a unit in which the combustion gases do not directly 

come into contact with process material or gases in the 

combustion chamber (e.g., indirect fired). A boiler is defined 

as an enclosed device using controlled flame combustion and 

having the primary purpose of recovering thermal energy in the 

form of steam or hot water.

C. What are the pollutants regulated by this proposed rule?

This proposed rule regulates hydrogen chloride (HCl) (as a 

surrogate for acid gas HAP), total selected metals (TSM) or 

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

metals), carbon monoxide (CO) (as a surrogate for nondioxin/furan organic HAP), mercury (Hg), and dioxin/furan 

emissions from boilers and process heaters.

D. What emission limits and work practice standards must I meet?

You must meet the emission limits presented in Table 1 of 

this preamble for each subcategory of units listed in the table.

This proposed rule includes 17 subcategories, which are based on 

unit design. New and existing units in 3 of the subcategories 

would be subject to work practices standards in lieu of emission 

limits for all pollutants. Numeric emission limits are being 
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proposed for new and existing sources in each of 14

subcategories, which are shown in Table 1 of this preamble.

Hydrogen chloride and Hg are “fuel-based pollutants” that 

directly result from contaminants in the fuels that are 

combusted. For those pollutants, if your new or existing unit 

combusts at least 10 percent solid fuel on an annual basis, your 

unit is subject to emission limits that are based on data from 

all of the solid fuel-fired combustor designs. If your new or 

existing unit combusts liquid fuel (except as noted in the rule)

and less than 10 percent solid fuel and your facility is located 

in the continental United States, your unit is subject to the 

liquid fuel emission limits for the fuel-based pollutants. If 

your facility is located outside the lower contiguous 48 states

and Alaska (referred to as a non-continental unit for the 

remainder of the preamble and in this proposed rule), and your 

new or existing unit combusts liquid fuel (except as noted in 

the rule) and less than 10 percent solid fuel, your unit is 

subject to the non-continental liquid fuel emission limits for 

the fuel-based pollutants. Finally, for the fuel-based 

pollutants, if your unit combusts gaseous fuel that does not 

qualify as a “Gas 1” fuel, your unit is subject to the Gas 2 

emission limits in Table 1 of this preamble. If your unit is a 

metal process furnace, limited-use unit, or Gas 1 unit (that is, 
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it combusts only natural gas, refinery gas, or other clean gas 

that meets the fuel specification, with limited exceptions for 

gas curtailments and emergencies), your unit is subject to a 

work practice standard that requires an annual tune-up in lieu 

of emission limits.

For the combustion-based pollutants, PM (a surrogate for 

metallic HAP) and CO (a surrogate for non-dioxin organic HAP), 

your unit is subject to the emission limits for the design-based 

subcategories shown in Table 1 of this preamble. We also are 

proposing, as alternatives to the PM limits, total selected 

metals emission limits for subcategories of units that combust 

solid fuels or Gas 2 fuels. If your new or existing boiler or 

process heater burns at least 10 percent biomass on an annual 

average heat input1 basis, the unit is in one of the biomass 

subcategories. If your new or existing boiler or process heater 

burns at least 10 percent coal, on an annual average heat input 

basis, and less than 10 percent biomass, on an annual average 

heat input basis, the unit is in one of the coal subcategories.

If your facility is located in the lower contiguous 48 states or 

Alaska and your new or existing boiler or process heater burns

 

1 Heat input means heat derived from combustion of fuel in a 

boiler or process heater and does not include the heat derived 

from preheated combustion air, recirculated flue gases or 

exhaust gases from other sources (such as stationary gas 

turbines, internal combustion engines, and kilns).
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light liquid fuel (i.e., distillate oil, biodiesel, or vegetable 

oil) and less than 10 percent coal and less than 10 percent 

biomass, on an annual average heat input basis, your unit is in 

the light liquid subcategory. If your facility is located in the 

lower contiguous 48 states or Alaska and your new or existing 

boiler or process heater burns heavy liquid fuel (other liquids 

that are not defined as light liquids) and less than 10 percent 

coal and less than 10 percent biomass, on an annual average heat 

input basis, your unit is in the heavy liquid subcategory. If 

your non-continental new or existing boiler or process heater 

burns liquid fuel and less than 10 percent coal and less than 10 

percent biomass, on an annual average heat input basis, your 

unit is in the non-continental liquid subcategory. Finally, for 

combustion-based pollutants, if your unit combusts gaseous fuel 

that does not qualify as a “Gas 1” fuel, your unit is subject to 

the Gas 2 emission limits in Table 1. If your unit combusts only 

natural gas, refinery gas, or equivalent fuel (other gas that 

qualifies as Gas 1 fuel), with limited exceptions for gas 

curtailment and emergencies, your unit is subject to a work 

practice standard that requires an annual tune-up in lieu of 

emission limits.

Table 1. Emission Limits for Boilers and Process Heaters

(lb/MMBtu heat input basis unless noted; alternative output 

based limits are not shown in the summary table below)
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Subcategory Particulat

e Matter 

(PM) (or 

total 

selected 

metals) 

(lb per 

MMBtu of 

heat 

input)a

Hydroge

n 

Chlorid

e (HCl) 

(lb per 

MMBtu 

of heat 

input)

Mercury

(Hg) 

(lb per 

MMBtu 

of heat 

input)

Carbon 

Monoxide

(CO)

(ppm @3% 

oxygen)a

Alterna

te CO 

CEMS 

limit,

(ppm 

@3% 

oxygen)b

Existing –

Solid fuel

NA 0.026 5.2E-06 NA NA

Existing –

Coal Stoker 

0.028 

(8.3E-05)

NA NA 220 34

Existing -

Coal 

Fluidized 

Bed

0.088 

(1.7E-05)

NA NA 56 59

Existing –

CoalBurning 

Pulverized 

Coal

0.044 

(5.9E-05)

NA NA 41 28

Existing –

Biomass Wet 

Stoker/Slop

ed 

Grate/Other 

0.029 

(5.7E-05)

NA NA 730 450

Existing –

Biomass

Kiln-Dried

Stoker/Slop

ed 

Grate/Other 

0.32 

(0.004)

NA NA 250 NA

Existing -

Biomass 

Fluidized 

Bed 

0.11 

(0.0012)

NA NA 370 180

Existing – 0.051 NA NA 58 1400
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Biomass 

Suspension 

Burner

(0.0011)

Existing –

Biomass 

Dutch 

Ovens/Pile 

Burners

0.036 

(2.4E-04)

NA NA 810 440

Existing –

Biomass 

Fuel Cells

0.033

(4.9E-05)

NA NA 1500 NA

Existing –

Biomass 

Hybrid 

Suspension 

Grate

0.44 

(4.9E-04)

NA NA 3900 730

Existing –

Liquid

NA 0.0012 2.6E-05 NA NA

Existing –

Heavy 

Liquid

0.062c NA NA 10 18

Existing –

Light 

Liquid

0.0034c NA NA 7 NA

Existing –

nonContinental 

Liquid

0.008c NA NA 18 91d

Existing –

Gas 2 

(Other 

Process 

Gases)

0.0067 

(2.4E-04)

0.0017 7.9E-06 4 NA

New – Solid 

Fuel

NA 0.026 8.6E-07 NA NA

New –Coal 

Stoker 

0.028 

(2.2E-05)

NA NA 16 34

New - Coal 0.0011 NA NA 17 59
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Fluidized 

Bed

(1.7E-05)

New – CoalBurning 

Pulverized 

Coal

0.0013 

(2.8E-05)

NA NA 9 28

New –

Biomass Wet 

Stoker/Slop

ed 

Grate/Other 

0.0048 

(2.6E-05)

NA NA 430 460

New –

Biomass 

Kiln-Dried

Stoker/Slop

ed 

Grate/Other 

0.32 

(0.004)

NA NA 250 NA

New -

Biomass 

Fluidized 

Bed 

0.0098 

(4.2E-05)

NA NA 230 26

New –

Biomass 

Suspension 

Burner

0.051 

(0.0011)

NA NA 58 1400

New –

Biomass 

Dutch 

Ovens/Pile 

Burners

0.036 

(4.1E-05)

NA NA 810 440

New –

Biomass 

Fuel Cells

0.011 

(4.9E-05)

NA NA 210 NA

New –

Biomass 

Hybrid 

Suspension 

Grate

0.026 

(4.9E-04)

NA NA 1500 730

New –

Liquid

NA 0.0012 4.9E-07 NA NA
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New – Heavy 

Liquid

0.013c NA NA 10 18

New – Light 

Liquid

0.0013c NA NA 3 NA

New – NonContinental 

Liquid

0.008c NA NA 18 91d

New – Gas 2 

(Other 

Process 

Gases)

0.0067 

(2.4E-04)

0.0017 7.9E-06 4 NA

a 3-run average, unless otherwise noted.

b 10-day rolling average, unless otherwise noted.

c Total selected metals alternative limits are not available to 

units in any of the liquid subcategories.

d 3-hour average based on continuous emission monitoring (CEM).

The emission limits in Table 1 apply only to new and 

existing boilers and process heaters that have a designed heat 

input capacity of 10 million British thermal units per hour 

(MMBtu/hr) or greater. We also are providing optional outputbased standards in this proposed rule. Pursuant to CAA section 

112(h), we are requiring a work practice standard for the 

following particular classes of boilers and process heaters: new 

and existing units that have a designed heat input capacity of 

less than 10 MMBtu/hr, new and existing units in the Gas 1 

(natural gas/refinery gas) subcategory and in the metal process 

furnaces subcategory, and new and existing limited-use units.

The work practice standard for these boilers and process heaters 
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requires the implementation of a tune-up program. We also are 

proposing a work practice standard for dioxin/furan emissions 

from all subcategories. Finally, the rule includes 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 IV of this preamble, of the affected boilers and 

facility to identify any cost-effective energy conservation 

measures.

E. What are the requirements during periods of startup, 

shutdown, and malfunction? The startup, shutdown, and 

malfunction provisions in the rule have not changed. See 76 FR 

15613.

F. What are the testing and initial compliance requirements? We 

are requiring that the owner or operator of a new or existing 

boiler or process heater conduct performance tests to 

demonstrate compliance with all applicable emission limits. An 

owner or operator of any affected unit would be required to 

conduct the following compliance tests as applicable: 

(1) Conduct initial and annual stack tests to determine

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

or conduct initial and annual stack tests to determine 
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compliance with the TSM emission limits using EPA Method 29 for 

those subcategories with alternate TSM limits.

(2) Conduct initial and annual stack tests to determine 

compliance with the Hg emission limits using EPA Method 29, 30B,

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 are in the 

sample).

(4) Use EPA Method 19 to convert measured concentration 

values to pound per million Btu values.

(5) Conduct initial and annual tests to determine 

compliance with the CO emission limits using EPA Method 10 or 

install operate and maintain CO CEMS to determine compliance 

with the alternate CO CEMS-based emission limits.

As part of the initial compliance demonstration, we are 

requiring that you monitor specified operating parameters during 

the initial performance tests that you would conduct to 

demonstrate compliance with the PM or TSM (as appropriate), Hg, 

HCl, and CO emission limits. You must calculate the average 

hourly parameter values measured during each test run over the 

three-run performance test. The lowest or highest hourly 

parameter average measured during the three test runs (depending 
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on the parameter measured) for each applicable parameter would 

establish the site-specific operating limit. The applicable 

operating parameters for which operating limits would be 

required to be established are based on the emissions limits 

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

on the unit. The following is a summary of the operating limits 

that we are requiring to be established for the various types of 

the following units:

(1) For boilers and process heaters with wet PM scrubbers, 

you must measure pressure drop and liquid flow rate of the 

scrubber during the performance test, and calculate the average 

hourly values during each test run. The lowest hourly average 

determined during the three test runs establishes your minimum 

site-specific pressure drop and liquid flow rate operating 

levels.

(2) If you are complying with an HCl emission limit using a 

wet acid gas scrubber, you must measure pH and liquid flow rate 

of the scrubber sorbent during the performance test, calculate 

the average hourly values during each test run of the 

performance test for HCl and determine the lowest hourly average 

of the pH and liquid flow rate for each test run for the 

performance test. This establishes your minimum pH and liquid 

flow rate operating limits.
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(3) For boilers and process heaters with sorbent 

injection, you must measure the sorbent injection rate for each 

acid gas sorbent used during the performance tests for HCl and 

for activated carbon for Hg and calculate the hourly average for 

each sorbent injection rate during each test run. The lowest 

hourly average measured during the performance tests becomes 

your site-specific minimum sorbent injection rate operating 

limit. If different acid gas sorbents and/or injection rates are 

used during the HCl test, the lowest hourly average value for 

each sorbent becomes your site-specific operating limit. When 

your unit operates at lower loads, multiply your sorbent 

injection rate by the load fraction (operating heat input 

divided by the average heat input during your last compliance 

test for the appropriate pollutant) to determine the required 

injection rate operating limit value.

(4) For boilers and process heaters with fabric filters not 

subject to PM Continuous Parametric Monitoring System (PM CPMS) 

or continuous compliance with an opacity limit (i.e., COMS), you 

must operate the fabric filter 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 CPMS is installed to 

monitor PM control. For the purposes of the rule, we define a PM 

CPMS as a continuous parametric monitoring device based on a
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detection principle of light scatter, light scintillation, beta

attenuation, or mass accumulation detection of PM in the exhaust 

gas or representative exhaust gas sample, installed and operated 

on the effluent stack or duct downstream of any particulate 

control device(s), and programmed to provide a continuous 

electronic signal representative of ongoing particulate matter 

control device performance.

(5) For boilers and process heaters with electrostatic 

precipitators (ESP) not subject to PM CPMS or continuous 

compliance with an opacity limit (i.e., COMS), you must measure 

the secondary voltage and secondary current of the ESP 

collection fields during the Hg and PM performance test. You 

then calculate the average total secondary electric power value 

from these parameters for each test run. The lowest hourly 

average total secondary electric power measured during the three 

test runs establishes your site-specific minimum operating limit 

for the ESP on a 12-hour block average basis.

(6) For boilers and process heaters that choose to 

demonstrate compliance with the Hg emission limit by fuel 

analysis, you must measure the Hg content of the inlet fuel that 

was burned during the Hg performance test. This value is your 

maximum fuel Hg content operating limit. 
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(7) For boilers and process heaters that choose to 

demonstrate compliance with the HCl emission limit by fuel 

analysis, you must measure the chlorine content of the inlet 

fuel that was burned during the HCl performance test. This value 

is your maximum fuel chlorine content operating limit.

(8) For boilers and process heaters that choose to 

demonstrate compliance with the total selected metals emission 

limit on the basis of fuel analysis, you are required to measure 

the total selected metals content of the inlet fuel that was 

burned during the total selected metals performance test. This 

value is your maximum fuel total selected metals content 

operating limit.

(9) For boilers and process heaters that are subject to a 

CO emission limit, you must record the oxygen concentration 

representative of your boiler operation (e.g., oxygen trim)

during the initial performance test

These operating limits do not apply to owners or operators 

of boilers or process heaters having a heat input capacity of 

less than 10 MMBtu/hr or boilers or process heaters of any size 

which combust natural gas or other clean gas, metal process 

furnaces, or limited-use units. Instead, if requested, owners or 

operators of such boilers and process heaters shall submit to 

the delegated authority or EPA, as appropriate, documentation 
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that a tune-up meeting the requirements of this final rule was 

conducted. In order to comply with the work practice standard, a 

tune-up procedure must include the following actions:

(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 the system is correctly calibrated and 

functioning properly,

(4) Optimize total emissions of CO consistent with the 

manufacturer’s specifications,

(5) Measure the concentration in the effluent stream of CO 

in parts per million by volume dry (ppmvd), before and after any

adjustments related to the tune-up are made,

(6) Submit to the delegated authority or EPA an annual 

report containing the concentrations of CO in the effluent 

stream in ppmvd and oxygen in percent dry basis, both measured 

before and after the adjustments of the unit; 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 adjustment. 
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Further, all owners or operators of major source facilities 

having boilers and process heaters subject to this final rule 

are required to submit to the delegated authority or EPA, as 

appropriate, documentation that an energy assessment was 

performed by a qualified energy assessor and documentation of

the cost-effective energy conservation measures indentified by 

the energy assessment.

G. What are the continuous compliance requirements?

To demonstrate continuous compliance with the emission 

limitations, we are requiring the following:

(1) For units combusting coal or residual fuel oil (i.e., 

No 4, 5 or 6 fuel oil) with average annual heat input rate of 

less than 250 MMBtu/hr (from the combustion of those fuels) or 

any units in the biomass subcategories and all biomass units

that do not use a wet scrubber, opacity levels must be 

maintained to less than 10 percent (daily average) for existing 

and new units with applicable emission limits. If the unit is 

controlled with a fabric filter, instead of being subject to 

continuous opacity monitoring, 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 CPMS is used).
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(2) For units combusting coal or residual oil with heat 

input capacities of 250 MMBtu/hr or greater from the combustion 

of those fuels, the EPA is proposing the collection of data 

using a PM CPMS at all times that the unit is subject to numeric 

emission limits, with the exception of periods of PM CPMS

repair, malfunction, scheduled maintenance, or QA/QC related 

activities. The operating unit will prepare, and submit for 

approval, a site-specific monitoring plan that addresses the PM 

CPMS design, data collection, and the QA/QC elements outlined in 

63.8(d), including the performance criteria and design 

specifications for the monitoring system equipment, the sample 

interface location, frequency of quality control checks, 

frequency of system performance evaluations, ongoing operation 

and maintenance procedures as well as ongoing reporting and 

recordkeeping procedures. An annual deviation report must be 

submitted detailing data collected during periods of boiler 

startup, shutdown, or malfunction and PM CPMS malfunction, 

repair, or other QA/QC related activity. Records of these data 

must be available on site for inspection, including corrective 

actions necessary to return the PM CPMS to operation consistent 

with the site specific monitoring plan. The operating unit will 

use output data collected from the CPMS (milliamps, mg/acm, or 

other instrument output) during all other operating hours where 
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numeric emission limits apply to assess compliance with the 

operating limit. An arithmetic average of the measurement output 

values collected during each hour will be calculated, and for 

each operating day the arithmetic average of all hourly 

measurement output values will be calculated for the previous 30

operating days. You must transmit four reports per year for each 

PM CPMS to the EPA’s WebFIRE database by using the Compliance 

and Emissions Data Reporting Interface (CEDRI) that is accessed 

through the EPA’s Central Data Exchange (CDX)(www.epa.gov/cdx). 

Complete reports must be submitted within 60 days after March 

31st, June 30th, September 30th, and December 31st. Complete 

reports contain daily PM CPMS rolling 30 day average values for 

the periods that end with each of the 4 previously mentioned 

dates.

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

you must monitor pressure drop and liquid flow rate of the 

scrubber and maintain the 30 day rolling averages at or above 

the operating limits established during the performance test to 

demonstrate continuous compliance with the PM emission limits.

(4) For boilers and process heaters with wet acid gas 

scrubbers, you must monitor the pH and liquid flow rate of the 

scrubber and maintain the 30 day rolling average at or above the 

operating limits established during the most recent performance 
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test to demonstrate continuous compliance with the HCl emission 

limits.

(5) For boilers and process heaters with dry scrubbers, you 

must continuously monitor the sorbent injection rate and 

maintain the hourly average at or above the operating limits, 

which include an adjustment for load, established during the 

performance tests. When your unit operates at lower loads, 

multiply your sorbent injection rate by the load fraction 

(operating load divided by the load during your last compliance 

test for the appropriate pollutant) to determine the required 

parameter value.

(6) For boilers and process heaters not required to install 

a CPMS and having an ESP installed, you must monitor the voltage 

and current of the ESP collection plates and maintain the 30-day

rolling average total secondary electric power at or above the 

operating limits established during the Hg, PM, or TSM

performance test.

(7) For units that choose to comply with either the Hg 

emission limit, the HCl emission limit, or TSM emission limit 

(solid fuel units only) based on fuel analysis rather than on 

performance testing, you must maintain monthly fuel records that 

demonstrate that you burned no new fuels or fuels from a new 

supplier such that the Hg content, chlorine content, or TSM 
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content of the inlet fuel was maintained at or below your 

maximum fuel Hg content operating limit, your chlorine content 

operating limit, or your TSM content operating limit set during 

the performance tests. If you plan to burn a new fuel, a fuel 

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

what was burned during the initial performance tests, then you 

must recalculate the maximum Hg input, maximum chlorine input, 

and/or maximum TSM input anticipated from the new fuels based on 

supplier data or own fuel analysis, using the methodology 

specified in Table 6 of this final 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.

(8) For all boilers and process heaters, except those that 

are exempt from the incinerator standards under section 129 

because they are qualifying facilities burning a homogeneous 

waste stream, you must maintain records of fuel use that 

demonstrate that your fuel was not solid waste.

(9) For boilers and process heaters, you must install, 

calibrate, and operate an oxygen trim system in order to ensure 

efficient combustion and compliance with the CO standards.
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(10) For boilers and process heaters that demonstrate 

compliance using a performance test. You must maintain an 

operating load no greater than 110 percent of the operating load 

established during the performance test.

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

other than the ones specified in this section to comply with 

this final rule, the owner or 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 are required to comply with 

certain requirements of the General Provisions (40 CFR part 63, 

subpart A), which are identified in Table 10 of this final rule. 

The General Provisions include specific requirements for 

notifications, recordkeeping, and reporting.

Each owner or operator is required to submit a notification 

of compliance status report, as required by §63.9(h) of the 

General Provisions. This final rule requires the owner or 

operator to include certifications of compliance with rule 

requirements in the notification of compliance status report.
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This proposed rule would require records to demonstrate 

compliance with each emission limit, operating limit, and work 

practice standard, as specified in the General Provisions. 

Owners or operators of sources with units with heat input 

capacity of less than 10 MMBtu/hr, units combusting natural gas 

or other clean gas, metal process furnaces, and limited use 

units 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 

CMS data are required.

You are required to keep the following records:

(1) All reports and notifications submitted to comply with 

the rule.

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

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

limit and each operating limit (i.e., deviations from the 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.
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(6) Calculations and supporting information of chlorine 

fuel input, as required in the rule, for each affected source 

with an applicable HCl emission limit.

(7) Calculations and supporting information of Hg fuel 

input, as required in the rule, for each affected source with an 

applicable Hg emission limit.

(8) A paragraph that discusses calculations and supporting 

information of TSM fuel input, as required in the rule, for each 

affected source with an applicable total selected metals

emission limit.

(9) A signed statement, as required in the 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.

(10) A signed statement, as required in the rule, 

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

or that the recalculation of Hg fuel input demonstrated that the 

new fuel or new fuel mixture still meets the Hg fuel input 

levels, for each affected source with an applicable Hg emission 

limit.
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(11) A signed statement, as required in the rule, 

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

or that the recalculation of total selected metals fuel input 

demonstrated that the new fuel or new fuel mixture still meets 

the total selected metals fuel input levels, for each affected 

source with an applicable total selected metals emission limit.

(12) 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 the rule.

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

developed for the rule as specified in 63 CFR 63.8(e), if 

applicable.

(14) A copy of your fuel analysis plan at least 60 days 

prior to demonstrating initial compliance.

You also are required to 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, even if you submitted 

an initial notification for the vacated standards that were 

promulgated in 2004.
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(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 to occur.

(4) Notification of Compliance Status 60 calendar days 

following completion of the performance test and/or compliance 

demonstration.

(5) Compliance reports semi-annually.

I. How should emissions test results be submitted to EPA?

The EPA must have performance test data to conduct 

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

as for many other purposes including compliance determinations, 

emission factor development, and annual emission rate 

determinations. In conducting these required reviews, the EPA 

has found it ineffective and time consuming, for us, for 

regulatory agencies and for source owners and operators, to 

locate, collect, and submit performance test data because of 

varied locations for data storage and varied data storage 

methods. In recent years, however, stack testing firms have 

typically collected performance test data in electronic format, 

making it possible to move to an electronic data submittal 

system that would increase the ease and efficiency of data 

submittal and improve data accessibility.
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In this proposal, the EPA is presenting a step to improve

the ease and efficiency of data submittal and increase data 

accessibility. Specifically, the EPA is proposing that owners 

and operators of industrial, commercial, and institutional 

boilers and process heaters submit electronic copies of required 

performance test reports to EPA’s WebFIRE database. The WebFIRE 

database was constructed to store performance test data for use 

in developing emission factors. A description of the WebFIRE 

database is available at 

http://cfpub.epa.gov/oarweb/index.cfm?action=fire.main. 

Data entry would be through an electronic emissions test 

report structure called the Electronic Reporting Tool (ERT). The 

ERT would be able to transmit the electronic report through the 

EPA’s CDX network for storage in the WebFIRE database making 

submittal of data very straightforward and easy. A description 

of the ERT can be found at 

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

The proposal to submit performance test data electronically 

to the EPA would apply only to those performance tests conducted 

using test methods that will be supported by the ERT. The ERT 

contains a specific electronic data entry form for most of the 

commonly used EPA reference methods. A listing of the pollutants 

and test methods supported by the ERT is available at 
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http://www.epa.gov/ttn/chief/ert/index.html. We believe that 

industry would benefit from this proposed approach to electronic 

data submittal. With these data, the EPA would be able to 

develop improved emission factors, make fewer information 

requests, and promulgate better regulations. 

One major advantage of the proposed submittal of 

performance 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. Another 

advantage is that the ERT clearly states what testing 

information would be required. Another important proposed 

benefit of submitting these data to the EPA at the time the 

source test is conducted is that it should substantially reduce 

the effort involved in data collection activities in the future. 

If the EPA has performance test data from these submittals, the 

EPA will likely need fewer or less substantial data collection 

requests in conjunction with prospective required residual risk 

assessments or technology reviews. This would reduce the burden 

on both affected facilities (in terms of reduced manpower to 

respond to data collection requests) and the EPA (in terms of 

preparing and distributing data collection requests and 

assessing the results).
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State, local, and tribal agencies could also benefit from 

more streamlined and accurate review of electronic data 

submitted to them. The ERT would allow for an electronic review 

process rather than a manual data assessment, making review and 

evaluation of the source provided data and calculations easier 

and more efficient. Finally, another benefit of the proposed 

data submittal to WebFIRE electronically is that these data 

would greatly improve the overall quality of existing and new 

emissions factors, by supplementing the pool of emissions test 

data for establishing emissions factors and by ensuring that the 

factors are more representative of current industry operational 

procedures. A common complaint from industry and regulators is 

that emission factors are outdated or do not represent a 

particular source category. With timely receipt and 

incorporation of data from most performance tests, the EPA would 

be able to ensure that emission factors, when updated, represent 

the most current range of operational practices. In summary, in 

addition to supporting regulation development, control strategy 

development, and other air pollution control activities, having 

an electronic database populated with performance test data 

would save industry, state, local, tribal agencies, and the EPA 

significant time, money, and effort while also improving the 
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quality of emission inventories and, as a result, air quality 

regulations.

J. What are the proposed compliance dates?

The EPA is proposing to reset the compliance date for 

existing sources to the date three years after the date of 

publication of the final reconsideration rule. For new sources, 

the EPA is proposing to change the compliance date to 60 days 

after the date of publication of the final reconsideration rule

or upon startup, whichever is later. We are not proposing to 

change the date that identifies whether a source is new or 

existing. This date, June 4, 2010, is the publication date of 

the original proposed rule.

IV. Actions We Are Taking

In this notice, we are granting reconsideration of, and 

requesting comment on, issues presented in the March 21, 2011 

reconsideration notice as well as a subset of other issues 

raised by petitioners in their petitions for reconsideration.

Section V of this preamble summarizes these issues and discusses 

our proposed responses to each issue. 

We have revised the rule language to address provisions 

related to the reconsideration and are requesting comment on the 

revised rule text to clarify definitions, applicability, 

compliance, and references to various sections of the rule.
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Finally, we are proposing technical corrections to certain 

applicability and compliance provisions in the final rule.

We are seeking public comment only on the issues 

specifically identified in this notice. We will not respond to 

any comments addressing other aspects of the final rule or any 

other related rulemakings.

V. Discussion of Issues for Reconsideration 

This section of the preamble contains EPA’s basis for our 

responses to certain issues identified in the petitions for 

reconsideration and the changes to the rule that we are 

proposing. We solicit comment on all responses and revisions 

discussed in the following sections:

A. Surrogates and Selected Regulated Pollutants

1. Alternative Total Selected Metals Limit. Multiple petitioners 

requested that EPA include an emission limit for total 

selected metals (TSM), particularly for biomass units, as part 

of the reconsideration. After assessing the available data, 

EPA determined that inclusion of these limits is appropriate

for some subcategories, and EPA is proposing TSM limits for 

each subcategory of units that combust solid fuels or Gas 2 

fuels. Sources will have the option of meeting either the TSM 

limit or the alternative PM limit. The TSM measurement is a 

more direct measurement of HAP than PM and is therefore 
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appropriate as a pollutant group for regulation with numeric 

emission limits. For this rule, TSM includes the following 

eight metals: arsenic, beryllium, cadmium, chromium, lead, 

manganese, nickel, and selenium. The EPA selected these 8 

metals, rather than all of the metals other than mercury, 

because more test data are available for these metals than for 

the other two HAP metals, cobalt and antimony. The use of 8 of 

10 metals should have little or no impact on a facility’s

response to the standards, and the controls that would be 

appropriate for the 8 metals would be equally effective in 

reducing emissions of the other 2 metals. Therefore, TSM can 

serve as a surrogate for all metallic HAP except for mercury, 

which this rule regulates separately.

For the light liquid, heavy liquid, and non-continental 

liquid units subcategories, we considered but are not 

proposing alternative TSM emission limits. Instead, we are 

proposing that these units meet the filterable PM emission 

limits in all instances. The TSM alternative was not selected 

for this proposal because of the limited emission test data

for TSM and the large variability in the TSM data. Using the 

EPA’s MACT floor methodology, the alternative TSM limits 

resulted in MACT floor values which do not appear to represent 

the actual performance of the best performing units. The EPA 
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has sent follow-up inquiries to facilities to confirm these 

data, and is soliciting comment on whether alternative TSM 

limits are appropriate for the subcategories of units designed 

to combust liquid fuels. The EPA also is soliciting comment on 

whether an alternative approach to calculating the TSM MACT 

floors for these units is appropriate.

2. Work Practice for Dioxin/Furan Emissions. Multiple petitioners 

requested that EPA reassess the potential for applying work 

practice standards for dioxins/furans in lieu of numeric 

emission limits. The EPA has re-assessed the dioxin/furan data 

sets and has determined that, similar to data for electric 

utilities for which work practice standards were proposed for 

dioxins/furans, the large majority of the emission 

measurements for all of the subcategories are below the level 

that can be accurately measured using EPA Method 23. While the 

EPA recognized this as an issue prior to issuing the final 

rule, sufficient time was not available to fully analyze the 

issue. For this proposal, the EPA conducted extensive analyses 

to determine the lowest level of emissions that can be 

accurately measured using EPA Method 23. The percentages of 

measurements (test runs) below the level that can be 

accurately measured for each subcategory are as follows: coal 

stoker-100 percent; coal fluidized bed-89 percent; pulverized 
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coal-85 percent; biomass stoker/other-100 percent; biomass 

fluidized bed-100 percent; biomass dutch oven/pile burner-80 

percent; biomass fuel cell-100 percent; heavy liquid-96 

percent; light liquid-100 percent; gas 2 (other process 

gases)-100 percent; non-continental liquid-100 percent (based 

on No. 6 oil data). While data are not available for two of 

the biomass subcategories, there is no reason to believe that 

dioxin emissions for those subcategories would be different 

than for the other biomass-based subcategories. Accordingly, 

the EPA is now proposing work practice standards in place of 

numeric emission limits for dioxin/furan. The work practice 

standards require an annual tune-up to ensure good combustion.

Details on the assessment of the minimum level that can be 

accurately measured can be found in the docket memorandum 

entitled “Updated data and procedure for handling below 

detection level data in analyzing various pollutant emissions 

databases for MACT and RTR emissions limits.” We do not expect 

that the change from numeric emission limits to work practice 

standards will result in less public health protection because 

the levels of dioxin emitted from units in the source category 

are low, and we are not aware of emissions controls that are 

demonstrated to reduce dioxin emissions from the low levels 
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indicated by the available data for boilers and process 

heaters.

B. Output-Based Standards

1. Revisions to Boiler Efficiency Analysis. Petitioners 

requested that EPA reassess the calculation of boiler 

efficiency, which is the key calculation in the development of 

output-based standards, because EPA’s calculations often 

resulted in efficiencies that were unrealistically high, often 

above 100 percent, which is a physical impossibility. The 

petitioners attributed this to the fact that EPA had disregarded 

feedwater temperature (industry average being 280 degrees F). 

The inclusion of feedwater temperature provides a more realistic 

assessment of boiler efficiencies. Thus, the EPA has modified

the development of the revised output-based emission limits to 

include the heat (energy) associated with the feedwater. The 

revised boiler efficiencies of the best performing units for 

each subcategory were determined by the equation:

Boiler Efficiency = (Steam output (Btu) – Feedwater Input 

(Btu) / (Fuel Input (Btu))

To calculate “feedwater input (Btu)”, we used the industry 

average temperature of 280 degrees F and determined a heat 

content value of 249.3 Btu/lb. Unit operators provided the 

“steam output (Btu)” for each best performing unit in response 
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to EPA’s information gathering efforts. For all best performing 

units reporting this steam energy output data, we calculated 

boiler efficiencies, as well as corresponding input-to-output 

conversion factors (CF). We averaged CF from the best performing 

units that have realistic boiler efficiencies averaged and 

assigned a subcategory-specific conversion factor. Finally, we 

applied the revised average CF to the proposed input-based 

emission limits to develop the revised alternate output-based 

limits. The resultant output-based limits provide a compliance 

option that achieves emission reductions equivalent to those 

achieved by the input-based limits and encourage energy 

efficiency.

2. Other Changes to Output-Based Provisions

a. Accommodating Emissions Averaging Provisions. In order to 

allow for emissions averaging for units that elect to comply 

with the output-based emission limits, the EPA is proposing to 

add additional equations to the rule to allow for emissions 

averaging as requested by petitioners.

b. Output-Based Standards for Units that Generate Electricity. 

Petitioners pointed out that the final output-based standards 

were not designed to consider efficiency improvements from 

units that generate electricity only. In response to this 

concern, EPA is proposing to add language to the definition of 
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“Steam output” that addresses boilers that only produce 

electricity.

c. Clarification that output-based standards are alternative 

standards. Petitioners requested that the EPA clarify in the 

tables that the output-based standards are alternative 

standards to the input-based standards. The EPA has made this 

clarification.

d. Legal Authority for Emission Credits. One petitioner 

questioned the legal authority of the emission credit system 

and stated that it should be removed from the final rule. 

However, the petitioner provided no support for its position,

and the EPA continues to believe that the emission credit 

system is legal as promulgated. Therefore, no changes are 

being proposed.

C. Subcategories

In the final rule, the EPA added subcategories for hybrid 

suspension/grate biomass units, limited-use units, solid fuel 

units, and non-continental liquid units. The EPA also added a 

fuel specification to the final rule that would allow units 

combusting gases not defined as “Gas 1” gases to qualify as 

Gas 1 units by demonstrating that the fuels combusted meet a 

fuel specification. Petitioners requested that EPA allow 

comment on these subcategory changes and the fuel 
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specification, and EPA is now soliciting comments on these 

portions of the final rule, including the changes and 

particular issues described in sections [1 through 7] below. 

Petitioners also requested additional subcategories, 

clarification of several subcategory definitions, and changes 

to some of the subcategory definitions.

1. Solid Fuel. The EPA added a solid fuel subcategory to the 

final rule that replaced previously proposed separate 

subcategories for units designed to burn solid fossil-based 

fuels and units designed to burn solid bio-based fuels. The 

solid fuel subcategory applied to pollutants identified in the 

final rule as fuel-based pollutants (PM, HCl, and Hg). 

Standards for combustion-based pollutants (CO and 

dioxin/furan), however, were based on specific subcategories 

for the various types of combustion units, including the 

specific fuel types the units were designed to combust. The 

rationale for the change is presented in the preamble to the 

final rule and EPA is, in this action, soliciting comments on 

the solid fuel subcategory. 

 One significant change is also being proposed related to 

the solid fuel subcategory. Several petitioners provided 

information to support the position that PM should be 

considered a combustion-based pollutant rather than a fuel-
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based pollutant. After assessing the points raised by the 

petitioners, the EPA determined that PM emissions are 

influenced both by fuel type and unit design. Therefore, it is 

appropriate to treat PM as a combustion-based pollutant. 

Differences in PM particle size, applicability of airpollution controls to units combusting various fuels, and the 

lack of demonstration of certain control technologies on 

certain designs of boilers (e.g., fabric filters are not used 

on any hybrid suspension grate boilers) suggest that PM is 

more appropriately classified as a combustion-based pollutant. 

Therefore, the EPA is now proposing separate PM limits for 

each “combustion-based” subcategory. 

 Emission limits for HCl and Hg were developed for the 

same subcategories as presented in the March 21, 2011, final 

rule; the only changes associated with the HCl and Hg emission 

limits are due to new data, corrections to old data, and 

inventory changes.

2. Units Designed to Combust Liquid Fuels. The EPA finalized a 

single subcategory covering liquid fuel-fired units (with 

limited exceptions such as non-continental liquid units and 

limited-used units). Petitioners requested that EPA reconsider 

the liquid unit subcategories and include separate 

subcategories for units designed to combust light liquids and 
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units designed to combust heavy liquids. Petitioners cited 

issues related to achievability of standards and the types of 

controls that are used on liquid units but did not cite design 

differences that could be used to justify a subcategory. 

However, we identified several design differences, including 

the need for steam atomization or high-pressure atomization of 

heavy liquids, the need for heated storage vessels for heavy 

liquids in some climates, and the lack of a demonstration that 

the new source PM limit based on combustion of light liquid 

fuels had been achieved by any unit combusting heavy liquid 

fuels. Therefore, the EPA is proposing separate subcategories 

for heavy liquid-fired and light liquid-fired units for PM and 

CO, pollutants that are dependent on combustor design. Units 

designed to combust light and heavy liquids will continue to 

be grouped together in a liquid fuel subcategory for the fuelbased pollutants, Hg and HCl. Light liquids include distillate 

oil, biodiesel, and vegetable oil. Heavy liquids include all 

other liquid fuels that are combusted in boilers, including 

byproduct liquid fuels generated at industrial facilities and 

residual oil. Units that combust any liquid fuels (and less 

than 10 percent coal/solid fossil fuel and less than 10 

percent biomass/bio-based solid fuel) where at least 10 

percent of the heat input from liquid fuels on an annual heat 
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input basis comes from heavy liquids would be considered heavy 

liquid units. Units that combust any liquid fuels (and less 

than 10 percent coal/solid fossil fuel and less than 10 

percent biomass/bio-based solid fuel) that are not part of the 

unit designed to burn heavy liquid subcategory would be 

considered light liquid units.

3. Non-Continental Liquid Units. The EPA finalized a subcategory 

for non-continental liquid units. Stakeholders did not have 

the opportunity to comment on this subcategory. Therefore, EPA 

is now soliciting comments on the non-continental liquid unit 

subcategory. The preamble to the final rule presents the 

rationale for the establishment of the subcategory. See 76 FR 

15635. The EPA also is proposing to revise several of the 

emission limits for non-continental liquid units due to the 

receipt of new emissions data for PM and CO from these units 

and the development of performance estimates based on the 

combustion of No. 6 fuel oil (rather than all types of liquid

fuels). The rationale for estimating the performance of these 

units based on data from No. 6 oil units is presented below.

Petitioners pointed out that non-continental units do not 

combust distillate oil because of availability issues. While 

non-continental liquid units typically combust refinery gas, 

they combust residual oil when process requirements 
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necessitate supplementing the available refinery gas. The 

petitioners requested that, in the absence of data from noncontinental units, emission limits for non-continental units 

be based on data from liquid units that combust residual oil. 

The EPA agrees that it would be appropriate to make this

change for the combustion-based pollutants due to the design 

of these units and the unique constraints faced by these 

units. We now have data for both CO and PM from noncontinental units, and there are no longer data gaps for these 

pollutants. We are thus able to establish numeric emission 

limits using data from within the subcategory. For fuel-based 

pollutants, Hg and HCl, the EPA determined that, based on the 

very limited data sets and the overlap of data for units 

designed to combust various liquid fuels, it is more 

appropriate to consider all liquid fuel-fired units together 

for the development of MACT emission limits. This is 

consistent with the treatment of Hg and HCl for solid fuel 

units.

4. Liquid Units in Alaska. A petitioner requested that liquid 

units in Alaska be included in the non-continental liquid unit 

subcategory or in a separate, newly created subcategory for 

units in Alaska. The petitioner stated that units in Alaska 

face the same difficulties with respect to the available 
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supply of natural gas or refinery gas as the non-continental 

units. The commenter did not provide specific design 

differences from other types of liquid units. In addition, no 

test data are available for liquid-fired units in Alaska. 

Finally, while units in Alaska may face some unique 

constraints, the design of such units is different from the 

non-continental units because the units are designed to 

combust different fuels (i.e. non-continental units combust 

No. 6 fuel oil, which was not reported as a fuel for any unit 

in Alaska in the responses to the EPA’s information collection 

request). For these reasons, the EPA is not proposing a 

subcategory for liquid units in Alaska and is not including 

these units in the non-continental subcategory. The EPA is, 

however, soliciting comment and supporting rationale on 

whether a subcategory for liquid units in Alaska is 

appropriate, and is requesting stack test data that could be 

used to establish MACT floors if such a subcategory is 

justified.

5. Biomass. Petitioners requested additional biomass 

subcategories and clarifications to the final subcategories. 

Suggestions included separate subcategories (for all 

pollutants) for boilers that are designed to combust kilndried wood and for hybrid suspension grate boilers designed to 
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combust bagasse, clarification of which subcategory covers 

pile burners, and separation of the dutch oven and suspension 

burner subcategories. In addition to soliciting comment on the 

proposed changes described below, the EPA is requesting 

comment on whether additional subcategories are appropriate, 

as well as data and rationale in support of any additional 

subcategories.

a. Boilers Designed to Combust Kiln-Dried Wood. With respect 

to a separate subcategory for boilers designed to combust 

kiln-dried wood, the EPA is proposing a separate 

subcategory for these units based on the design of the 

boilers and the unique nature of the facilities that 

combust this material. These facilities are carefully 

integrated to utilize their available resources on-site, 

and the boilers are designed and sized to efficiently 

combust biomass that has already undergone a drying process 

that enhances the fuel quality. Care is taken within the 

facility to maintain the fuel moisture content at levels 

far lower than virgin biomass materials, typically less 

than 2 percent moisture. The EPA is proposing emission 

limits for PM and CO for this subcategory of units that we 

are calling biomass dry stokers. For HCl and Hg, the final 

rule’s approach of regulating these pollutants under the 
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“solid fuel subcategory” for all solid fuel units has not 

changed.

b. Hybrid Suspension Grate Boilers Designed to Combust

Bagasse. In the final rule, the EPA added a subcategory for 

hybrid suspension/grate boilers, which included boilers 

that are designed to combust very wet biomass fuels such as 

bagasse. The rationale for the establishment of the 

subcategory is presented in the preamble to the final rule.

See 76 FR 15634-15635. Petitioners pointed out that in 

addition to their unique designs that provide fuel drying 

within the combustor, these units are highly integrated 

into the sugar production process and primarily combust 

specific materials that are generated on-site. Petitioners 

emphasized that the particle size profile from these units 

differs significantly from units designed to combust other 

types of fuels. As discussed in section V.C.1 of this

preamble, the EPA is now considering PM to be a “combustion 

based” pollutant. Accordingly, the EPA is proposing 

emission limits for PM (along with an alternate TSM 

standard) and CO for these types of units. For HCl and Hg, 

the final rule’s approach of regulating these pollutants 

under the “solid fuel subcategory” for all solid fuel units 

has not changed.
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c. Clarification of Subcategories for Pile Burners, Dutch 

Ovens, and Suspension Boilers. The final rule did not 

address pile burners, and it established a single 

subcategory that covered dutch ovens and suspension 

boilers. Petitioners pointed out that dutch ovens and 

suspension boilers are inherently different types of 

boilers and requested EPA to create separate subcategories 

for those types of units. Petitioners also pointed out that 

pile burners are very similar to dutch ovens, and, as such, 

should be included in the dutch oven subcategory. The EPA 

evaluated these clarification requests and determined that 

the petitioners’ points are valid. The EPA agrees that

dutch ovens and pile burners should be included in the same 

subcategory and suspension burners should be a separate 

subcategory. Therefore, EPA is proposing separate emission 

limits for the combustion-based pollutants for these 

subcategories. All of these types of units will remain in 

the solid fuel subcategory for the fuel-based pollutants.

6. Gaseous Fuel Specification. Multiple petitioners requested 

reconsideration of the fuel specification that EPA finalized 

but did not propose. Petitioners correctly pointed out that 

the levels of the fuel specification were based only on 

natural gas and suggested that it would be appropriate to base 
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the fuel specification on levels of contaminants in either 

natural gas or refinery gas. Petitioners further pointed out 

that a fuel specification for H2S is not directly related to 

potential HAP emissions from boilers and process heaters and 

the H2S fuel specification should be eliminated from the rule.

The EPA has reexamined the fuel specification and agrees that 

the key contaminant for demonstration of comparability from a 

HAP perspective is mercury and that the H2S fuel specification 

that was finalized does not provide a direct indication of 

potential HAP from combustion of gaseous fuel. Accordingly, 

EPA is proposing a fuel specification based only on the 

mercury level in the gaseous fuel, and that level is the same 

level that EPA included in the March 2011 final rule. The 

rationale for the mercury fuel specification is included in 

the preamble to the final rule. See 76 FR 15639.

One petitioner stated that the inclusion of a fuel 

specification demonstrates that emissions can be measured from 

the units that combust the gaseous fuels, and therefore, the 

units cannot be regulated by a work practice standard. 

Regarding this point, the EPA recognizes that the contaminants 

in the fuel may be able to be measured, but the resulting 

emissions from combustion of the fuel are another matter 

entirely. For instance, a unit that combusts a fuel that meets
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the fuel specification for mercury will have demonstrated that 

it contains an amount of mercury that is comparable to that 

found in natural gas. The emissions data for natural gas-fired 

units show the overwhelming majority of emissions to be below 

the level that can be accurately quantified by the available 

test methods. Therefore, the same is expected of units 

combusting gases with similar contaminant levels to natural 

gas. Thus, a work practice standard is the appropriate 

standard for these units. The EPA also is requesting comment 

on whether additional parameters should be included in the 

fuel specification.

7. Work Practices for Limited-Use Units. The EPA added a 

subcategory for limited-use units in the final rule, and 

petitioners requested an opportunity to comment on the 

creation of the subcategory and the definition of the 

subcategory. Specifically, multiple petitioners requested that 

rather than defining the subcategory to include units that 

operate less than 10 percent of the hours in a year, the EPA 

define the subcategory to include units that operate with a 

capacity factor of 10 percent or less. The petitioners believe 

that such a change would provide more flexibility, but 

petitioners did not provide support that such a subcategory 

would qualify for work practice standards under section 112 
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the CAA. Therefore, EPA is not proposing a change to the final 

approach but is requesting comment on how a subcategory 

defined with a 10 percent capacity factor would qualify for 

work practice standards in lieu of emission limits. The EPA 

also is requesting comment on the limited-use subcategory as 

finalized, and the rationale for the creation of that 

subcategory can be found in the preamble to the final rule. 

See 76 FR 15634.

D. Monitoring

1. Oxygen monitoring. Petitioners requested reconsideration of

the requirement for installation of oxygen monitoring systems 

on the outlet of the boiler combustion chamber for numerous 

technical reasons. Several parties expressed concern regarding 

this location as it is known to be highly stratified, making 

it very difficult to find a representative location and

certify the instrumentation. In reviewing alternatives to this 

requirement we find that rather than requiring monitoring of 

oxygen levels in the stack that follows a combustion unit, a 

better way to ensure good combustion is by requiring the 

installation, calibration, monitoring and use of oxygen trim 

systems to optimize air to fuel ratio and combustion 

efficiency. We agree with petitioners that use of the data 

from such devices is not only an appropriate control for 
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efficient combustion and a less burdensome alternative to 

monitoring stack oxygen concentration but also is a better 

system for many types of units that experience significant 

load swings and operate with high levels of excess air. Many

units are already fitted with these controls, and this 

proposed change will reduce the monitoring burden for affected 

units. These systems will provide adequate combustion control 

to maintain compliance with the CO emission levels 

demonstrated during the performance test. We seek comment on 

the appropriateness of using these controls operated as, and 

for the purposes, described.

2. PM CEMS. Petitioners requested reconsideration of the use of 

PM CEMS as compliance monitors for coal, biomass, and residual 

oil units with heat input capacity greater than 250 MMBtu/hr.

Petitioners emphasized that PM CEMS are not demonstrated for 

biomass units and requested EPA to remove the requirement 

because of technical issues related to PM particle size and 

the inability of PM CEMS effectively measure PM from biomass 

units. Petitioners also stated that PM CEMS are not 

demonstrated at the low levels that are required by the rule.

The EPA agrees that PM CEMS are not demonstrated for biomass 

units and that significant technical concerns exist regarding

the technology’s ability to monitor emissions from biomass 
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units. Accordingly, we are proposing to remove the PM CEMS 

requirement for biomass units.

 Relative to application for other boiler units, several 

parties expressed concern over the state of readiness of 

current PM CEMS technology, certification methodology, and the 

technical effort and cost required for the recertification 

necessary to handle changing fuel and control operating 

conditions. In our reevaluation of this technology we find 

that PM monitoring technology would best be employed as 

parametric monitors (PM CPMS) and used to determine compliance 

with operating limits rather than emissions limits. This 

approach reduces the burden of certification of the monitor 

which can be a substantial annual cost, and maintains our 

goals of seeking continuous data monitoring of the source 

particulate mass emission rate as a 30-day rolling average. We 

seek comment on the use of these monitors as described in the 

rule.

3. CEMS Alternative for Hg. Petitioners requested reconsideration 

of the absence of an option to use Hg CEMS for compliance 

demonstration and monitoring for units subject to Hg limits 

whose operators do not want to rely on periodic testing, fuel 

sampling analysis, and parameter monitoring. We have included 
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options in the rule for the use of Hg CEMS. We seek comment on 

the use of these monitors as described in the rule.

4. Use of SO2 CEMS for demonstrating continuous compliance with 

HCl emission limits. A petitioner requested that EPA consider 

adding a provision to the rule to allow for the use of SO2

CEMS for demonstration of continuous compliance with the HCl

emission limits for sources that are equipped with acid gas 

controls. While the EPA does not have enough information to 

propose specific requirements, we believe that a reasonable 

approach would be to allow for the use of SO2 CEMS provided 

that the source demonstrates a correlation between SO2 control 

and control of other acid gases emitted from each specific 

unit that chooses to use SO2 CEMS. Such a relationship is 

expected because the available add-on controls for acid gases 

would provide better control efficiencies for the acid gas HAP 

than for SO2, and, therefore, demonstration of SO2 control 

using CEMS would provide assurance that the acid gas HAP are 

being controlled. Therefore, the EPA is soliciting comment on 

the use of SO2 CEMS for demonstrating continuous compliance 

with the HCl emission limits.

5. Minimum Data Availability Provisions. Petitioners noted that 

the requirement to operate any CMS and collect data at all 

times is unrealistic and that the Agency should include a 
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reasonable minimum data availability limitation allowing for 

CMS downtime. We have not included any specific minimum data 

availability requirement for CEMS or other monitoring in the 

final rule. We disagree with petitioners that we are 

establishing unreasonable monitoring operating requirements 

with this rule. Instead, we believe that we are reiterating 

the source owner’s responsibility to operate and maintain the 

CMS in accordance with existing rules. For example, section 

63.8(c) already requires that the source operate the CMS 

consistent with good air pollution control practices and that 

the CMS be in continuous operation in accordance with a 

written quality control program. This rule clarifies that 

continuous operation does not include periods when the process 

is not operating and the requirements delineated in the rule 

otherwise mirror other existing requirements in the MACT 

general provisions. We do agree with petitioners that a CMS 

must undergo periodic system inspections, preventive 

maintenance, and parts replacements in order to continue good 

operation. It is clear that these events are among normal 

scheduled quality control events that would be included in the 

site-specific quality control program that is required under 

section 63.8(d)(2)(iii) to which the source owner is subject. 

We also agree that such periods are to be categorized as 
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exceptions to CMS data collection that are already allowed in 

the rule. Given the existing regulatory requirements and the 

clarifications in this rule about how to apply those 

requirements, we believe the rule provides allowances 

sufficient for CMS operational flexibility.

6. Averaging Times. The EPA has determined the 30 day rolling 

average for parameter monitoring and compliance with operating 

limits is appropriate for this rule. The operating limits 

established through performance testing in this rule represent 

short term process and control operating conditions 

representative of compliance. Concerns of variability outside 

the operators control such as fuel content, seasonal factors, 

load cycling, and infrequent hours of needed operation 

prompted us to look at longer averaging periods on which to 

base operating compliance determination. We are aware from 

studies of emissions over long averaging periods [<<place 

holder to reference docket item of RTI Study MEMO here>>] that 

long term (e.g., 30 day) average emissions for a operating in 

compliance will have a variability of about half of that 

represented by the results of short term testing. Given that 

short term tests are representative of distinct points along a 

continuum of that inherent operational variability, we believe 

it appropriate to provide a means for the source operator to 
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account for that variability by applying a long term average 

for establishing compliance. We expect more problematic

control system variability (e.g. ESP transformer failure or 

scrubber venturi fan failure) to result in deviations from a 

30-day average relative to compliance almost as much as for a 

shorter term average.

E. Emission Limits

1. Additional Data Received. The EPA received additional data 

from stakeholders and incorporated all of the data into the 

MACT database. The new data include 36 mercury test runs, 168 

PM test runs, 24 dioxin/furan test runs, 133 CO test runs, 63 

HCl test runs, and 22 TSM test runs. In addition to the stack 

test data, EPA received fuel analyses for three facilities and 

over 51,000 hours of CO CEMS data from three facilities. 

Finally, stakeholders submitted corrections to data and to 

descriptions of combustion units. We have incorporated these 

corrections into the project database. For details on the new 

data and data corrections, see the memorandum in the docket 

entitled “Revised Handling and Processing of Corrections and 

New Data in the EPA ICR Databases (October 2011).”

2. Quality Assurance Activities on Best Performers. The EPA 

requested copies of all of the emission test reports for the 

best performing units in each subcategory in order to perform 
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additional quality assurance. These test reports document the 

test results for the summary test data that were submitted to 

EPA as part of EPA’s Phase 1 information collection request.

This review resulted in multiple changes to data and

invalidation of some emission tests. Overall, this effort 

improved the quality of the data provided by industry. For 

details on the quality assurance effort, see the memorandum in 

the docket entitled “Data Quality Review of Best Performers 

for PM, Hg, HCl, CO, and Dioxin/Furan Emissions from ICI 

Boilers and Process Heaters at Major Sources of HAP (October 

2011).”

3. Incorporation of Minimum Detection Levels and Measurement 

Imprecision. In developing the final rule, the EPA 

incorporated procedures to ensure that the available 

measurement methods would provide accurate emissions 

measurements at the levels set for the various standards. The

preamble to the final rule described these procedures, but 

stakeholders did not have an opportunity to comment on them. 

The EPA has made minor adjustments to the methods used to 

account for measurement imprecision and presents the rationale

in the following paragraphs. We are soliciting comment on the 

procedures described below.
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Test method measurement imprecision is a contributor to 

the variability of a set of emissions data. One element is 

associated with method detection capabilities, and a second is 

a function of the measurement value. Measurement imprecision 

is proportionally highest for values measured below or near a 

method’s detection level; measurement imprecision

proportionally decreases for values measured above the method 

detection level. 

The probability procedures applied in calculating the 

floor or an emission limit inherently and reasonably account 

for emissions data variability, including measurement 

imprecision, when the database includes multiple tests from 

multiple emissions units for which all data are measured 

significantly above the method detection level. This is less 

true when the database includes emissions occurring below 

method detection capabilities that are reported as the method 

detection level values.

The EPA’s guidance to data collection respondents for 

reporting pollutant emissions specified the criteria for 

determining test-specific method detection levels. Under those 

criteria, about a 1 percent probability of an error exists 

that a pollutant measured at the method detection level is 

present when in fact it is absent. Such a probability is also 
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called a false positive or the alpha, Type I, error. Because 

of sample and emissions matrix effects, laboratory techniques,

sample size, and other factors, method detection levels 

normally vary from test to test for any specific test method 

and pollutant measurement. The expected measurement 

imprecision is 50 percent or greater. 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.2

Also in accordance with our guidance, source owners 

identified emissions data which were measured below the method 

detection level and reported those values as equal to the 

method detection level as determined for that test. One effect 

of reporting data in this manner is that the resulting 

database is somewhat truncated at the lower end of the 

measurement range (i.e., no values reported below the testspecific method detection level). A floor or emissions limit 

that is based on a truncated database or otherwise includes

values measured near the method detection level may not 

adequately account for the effects of measurement imprecision 

on the data variability.

 

2 American Society of Mechanical Engineers, Reference Method Accuracy and Precision (ReMAP): Phase 1, 

Precision of Manual Stack Emission Measurements, CRTD Vol. 60, February 2001.
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 We applied the following procedures to account for the 

effect of measurement imprecision associated with a database 

that includes method detection level data. In response to the 

comments and internal concerns about the quality of 

measurements at very low emissions limits especially for new 

sources, we revised the procedure for identifying a 

representative method detection level (RDL). The procedure for 

determining an RDL starts with identifying all of the 

available reported pollutant specific method detection levels 

for the best performing units regardless of any subcategory 

(e.g., existing or new, fuel type, etc.). From that combined 

pool of data, we calculate the arithmetic mean value. By 

limiting the data set to those tests used to establish the 

floor or emissions limit (i.e., from the best performers), the 

result also represents the best performing testing companies 

and laboratories, and data from underperforming laboratories 

are effectively removed from the floor analysis. The outcome 

should minimize the effect of a test(s) with an inordinately 

high method detection level (because, for example, 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). We then call 

the resulting mean of the method detection levels as the 
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representative detection level (RDL) as characteristic of 

accepted source emissions measurement performance. 

The second step in the process is to calculate three times 

the RDL to compare with the calculated floor or emissions 

limit. This step is similar to what have used before including 

for the Portland cement MACT determination. We use the 

multiplication factor of three to approximate a 99 percent 

upper confidence interval for a data set of seven or more 

values. For comparing to the floor, if three times the RDL 

were less than the calculated floor or emissions limit (e.g., 

calculated from the UPL), we would conclude that measurement 

variability was adequately addressed. The calculated floor or 

emissions limit would need no adjustment. If, on the other 

hand, the value equal to three times the RDL is greater than 

the UPL, we would conclude that the calculated floor or 

emissions limit does not account entirely for measurement 

variability. In this situation, we substituted the value equal 

to three times the RDL for the calculated floor or emissions 

limit.

We determined the RDL for each pollutant using data from 

tests of all the best performers for all of the final 

regulatory subcategories (i.e., pooled test data). We applied 

the same pollutant-specific RDL and emissions limit adjustment 
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procedure to all subcategories for which we established 

emissions limits. We believe that emissions limits adjusted in 

this manner better ensure that measurement variability is 

adequately addressed relative to compliance determinations 

than did the procedure applied for calculations in the June 4, 

2010, proposed rule that may have been based on data sets 

smaller than seven tests and as few as one test. We also 

believe that the emissions testing procedures and technologies 

available now and in the future will be adequate to provide 

the measurement certainty sufficient for sources to 

demonstrate compliance at the levels of the adjusted emissions 

limits.

4. CO CEMS-Based Alternative Emission Limits and Monitoring. As 

an alternative to CO stack testing and oxygen monitoring, we 

are proposing a compliance option that allows the use of CO

CEMS. Some petitioners noted that some affected sources 

currently use CO CEMS and that installing additional 

monitoring equipment should not be required if a unit elects 

to comply using existing CO CEMS equipment. In addition, 

petitioners stated that due to the highly variable nature of 

CO emissions, an emission limit based on CO CEMS data from 

boilers over time would more adequately capture the true 

variability in CO emissions over various operating conditions. 
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In response to these requests, EPA has calculated a CO CEMSbased MACT floor for each subcategory for which data were 

available. Facilities would have the option to comply with the 

alternative CO CEMS-based limits through monitoring with CO 

CEMS. 

Through the Section 114 Information Collection Requests 

and additional voluntary data submittals, a limited amount of 

CEMS data was available to compute CO CEMS limits. Most 

sources that reported CEMS data had 30 days of data either 

reported as hourly or daily averages. Given this limited 

length of time, we selected a 10-day rolling averaging period 

in order to allow us to compute multiple data points from each 

source’s dataset. If sources reported CEMS data on both an 

hourly and daily average basis, we first computed daily 

averages from the hourly data. Next, we combined the two 

datasets, sorted the data in sequential calendar data order 

and computed a series of 10-day rolling averages from each 

unit. CEMS data on a 10-day rolling average basis could be 

calculated for the following subcategories: fluidized bed 

units designed to burn coal/solid fossil fuel, pulverized coal 

boilers designed to burn coal/solid fossil fuel, stokers 

designed to burn coal/solid fossil fuel, dutch ovens/pile 

burners designed to burn biomass/bio-based solids, fluidized 
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bed units designed to burn biomass/bio-based solids, hybrid 

suspension grate boiler designed to burn biomass/bio-based 

solids, stokers/sloped grate/others designed to burn wet 

biomass fuel, suspension burners designed to burn biomass/biobased solids, and units design to burn heavy liquids. CO CEMS 

data on a 10-day rolling average basis data were not available 

for the fuel cell units designed to burn biomass/bio-based 

solids, biomass dry stoker units, units designed to burn light 

liquids, and units designed to burn gas 2 (other) gases.

Alternate CO CEMS-based limits are not being proposed for 

these units, but if data are provided for those subcategories 

prior to March 1, 2012, those data will be considered for use 

in the final rule. A very limited amount of CEMS data were

available from units designed to burn liquid fuel located in 

non-continental States and territories, but not enough data 

points were available to compute a 10-day rolling average. We 

do have data sufficient to develop CO CEMS-based limits on a 

3-hour average basis, as discussed below. If sufficient 

additional data are provided by March 1, 2012, the EPA will 

consider adjusting the averaging time similar to the other 

emission limits.

In most cases, only one or two units in each subcategory 

have CO CEMS data available. The memorandum “CO CEMS MACT 
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Floor Analysis (October 2011) for the Industrial, Commercial, 

and Institutional Boilers and Process Heaters National 

Emission Standards for Hazardous Air Pollutants – Major 

Source” provides a complete breakdown of the CO CEMS data that 

were available. The EPA is requesting the submittal of 

additional CO CEMS data to achieve a more robust dataset for 

the purposes of revising the CO CEMS MACT floor calculations. 

Please provide your dataset in an electronic spreadsheet or 

database format with the data reduced to hourly CO averages 

reported as parts per million by volume, dry basis. You should 

include the oxygen associated with each measurement or report 

the data at a standardized oxygen concentration, preferably 

adjusted to 3 percent oxygen. The EPA is expecting to receive 

additional CEMS data before the final rule and to incorporate

those data if received in time. The data will likely change 

the CO CEMS floors, and may also result in different averaging 

times, depending on the extent of the data.

In order to identify the dataset that would be used to 

compute a CO CEMS MACT floor emission limit, the EPA first 

identified all of the units identified as best performers 

based on their reported stack test results that had 10-day 

rolling average CO CEMS data available. Refer to the memo 

“Revised MACT Floor Analysis (October 2011) for the 
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Industrial, Commercial, and Institutional Boilers and Process 

Heaters National Emission Standards for Hazardous Air 

Pollutants – Major Source,” for more information on how the 

best performing CO stack tests were identified for each 

subcategory. However, there was very little overlap in the 

number of best performing units that had both stack test and 

CO CEMS data available. After comparing the data, only three 

subcategories would have best performing units with both stack 

test and applicable CEMS data. Given these data gaps, we opted 

to select CO CEMS data by ranking each unit according to its 

minimum 10-day rolling average CO CEMS value and then 

determining the best performers for each subcategory. We 

discuss one exception below. Within each subcategory, we 

ranked the minimum 10-day rolling averages from lowest to 

highest to determine the best performing 12 percent. Next, we 

used all of the daily averages from the best performing units 

to compute a MACT floor based on a 99 percent UPL. For the 

units designed to burn liquid fuel in the non-continental 

liquid units subcategory, the data were insufficient to 

calculate 10-day rolling averages. Based on the available 

data, the averaging basis selected was 3 hours for noncontinental liquid units. Only one of the non-continental 

boilers submitted CO CEMS data, with a total of 24 hourly 
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averages. In this case, we used each of the hourly averages 

from this unit to compute a MACT floor based on a 99 percent 

UPL. The EPA is aware that the averaging time selection and 

whether rolling or block averaging is selected impacts the UPL 

calculation and ability to demonstrate compliance. We believe 

that the averaging times selected for this proposal are 

reasonable and note that, to some extent, they are dictated by 

the limited datasets. The EPA is requesting comment on the 

most appropriate averaging time (e.g., hourly, daily) and 

length of rolling period (e.g., 10-day, 30-day) to use when 

calculating the CO CEMS MACT floors and requests specific 

discussion and new data to support your comments. The length 

of the averaging time will be affected by the available data 

in each subcategory. 

Ranking the dataset according to the minimum 10-day 

rolling average does not necessarily correlate with the 

ranking used to identify the best performing 12 percent of 

units with CO stack test data used to calculate the stack 

test-based floors for CO. Separate sets of units in the stack 

test and CEMS data sets create the possibility of incongruent 

results between the two compliance options. To evaluate 

whether our selection of the units identified as best 

performers for CO CEMS data correlates to the units identified 
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as best performers for stack test data, we compared the CEMS 

data and the computed stack test CO MACT floor for each 

subcategory. Each unit identified as a best performing unit in 

the CO CEMS analysis had at least one 3-hour CEMS average at 

or below the corresponding stack test CO MACT floor for the 

subcategory, which suggests that the CEMS floors are 

reasonable. The EPA specifically requests comment on the 

ranking methodology which should be used, with discussion on

whether CO CEMS best performers should be selected from units 

also identified as best performers from their stack test data,

or if a value other than the minimum 10-day rolling average 

should be used as the basis for ranking the data.

Given the limited data available, the proposed new source 

CO CEMS floors are similar to existing source floors since the 

existing source CO CEMS UPL for each subcategory was 

determined using data from a single unit, with two exceptions. 

The fluidized bed units designed to burn biomass/bio-based 

solids and stokers/sloped grate/others designed to burn wet 

biomass fuel each have two units in the existing source floor 

calculations, whereas the new source floor would be based on 

the single best performer. In the case of wet biomass

stoker/sloped grate/other, the computed new source floor would 
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be higher than the existing source, so the value reverts to 

the existing source value.

The 99% UPL calculations for CO CEMS used the following 

statistical formula:

 

Where:

n = the number of daily averages (or hourly averages for 

non-continental units)

m = the number of test runs in the compliance average

In this case, m equals 10 given the 10-day rolling average 

compliance period for all subcategories except for noncontinental liquid, where m equals 3 for the 3-hour averaging 

period. Similar to previous analysis of the distribution of 

the dataset for stack test data MACT floor calculations, the 

distribution of each CEMS dataset was classified as either a 

normal distribution or log-normal distribution. In the case of 

the CEMS datasets from each of the best performers, the 

datasets were each log-normally distributed. See the “CO CEMS 

MACT Floor Analysis (October 2011) for the Industrial, 

Commercial, and Institutional Boilers and Process Heaters 
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National Emission Standards for Hazardous Air Pollutants –

Major Source” for further details about the calculations.

F. MACT Floor Methodology

1. Standards for Dioxin/Furans. Petitioners requested that EPA 

revise the procedure used to calculate the final emission 

limits for dioxin/furans, with the primary issue being the low 

levels and how detection limits should be considered. The EPA 

re-assessed the lowest level that can be accurately measured 

for dioxin/furan emissions from boilers and process heaters. 

When we compared those levels to the levels of emissions from 

all of the units that had test data available, we found that 

for all subcategories of units, emissions were below the value 

that can be accurately measured. Details on the establishment 

of the level that can be accurately measured are provided in 

the docket memorandum entitled: Updated data and procedure for 

handling below detection level data in analyzing various 

pollutant emissions databases for MACT and RTR emissions 

limits. As discussed in section V.A.2 of this preamble, the 

EPA is now proposing to regulate dioxin/furan emissions with a 

work practice standard in lieu of numeric emission limits.

2. Filling Data Gaps for Non-Continental Liquid Units. The EPA 

included numeric emission limits for non-continental liquid 

units in the final rule. However, data were not available for 
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all of the regulated pollutants, and EPA relied on the MACT 

floors for liquid units to establish some of the emission 

limits. Petitioners requested that in cases where data gaps 

exist, a more appropriate substitution would be to establish 

floors based on units that combust No. 6 fuel oil, which is 

the fuel that the non-continental units are designed to 

combust. While the EPA agrees that for estimating emission 

from these units, use of data from No. 6 oil-fired units may 

be appropriate even though some design differences have been 

identified (see FR 76 15635, March 21, 2011), we are proposing 

a different approach for setting emission limits for noncontinental liquid units. Additional data were submitted to 

EPA for PM and CO from non-continental units, and the proposed 

PM and CO limits are based on these data from within the 

subcategory. For HCl and Hg, which are considered fuel-based 

pollutants that are not dependent on combustor design, the EPA 

is proposing to base limits for all liquid units on the entire 

data set from liquid-fired units. The currently available data 

and information do not indicate that Hg and HCl should be 

considered separately for liquid units designed to combust 

various types of liquids. The EPA requests comment on this 

approach, and to the extent that other approaches are 
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suggested, EPA requests data and rationale to support any 

suggested approaches.

3. Selection of Confidence Level for CO. In the final rule, EPA 

selected the use of a 99.9 percent confidence interval for 

calculating the MACT floor for CO emissions. A petitioner 

requested reconsideration of this selection given the fact 

that the EPA used a 99 percent confidence interval for all of 

the other emission limits in the final rule. The petitioner 

pointed out that if the data are highly variable, the 99 

percent confidence interval should adequately reflect the 

variability of emissions as well as for the data sets for 

other pollutants. In the development of the final rule, the 

99.9 percent confidence interval was selected in part because 

the standards covered periods of startup and shutdown, while 

the data did not reflect CO emissions during those periods. 

While the EPA finalized work practice standards for startup 

and shutdown periods, the selection of the confidence interval 

was not revisited due to time constraints. The EPA is now 

proposing to use a 99 percent confidence interval in order to 

maintain a consistent methodology with the development of the 

MACT floors for other pollutants, and because optional CO 

CEMS-based limits are being proposed that would allow sources 
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additional flexibility in meeting the requirements of the 

rule.

G. Tune-up Work Practices

1. Requirements for Small and Limited-Use Units. Petitioners 

requested that EPA reconsider the tune-up work practices for a 

subset of very small units. Specifically, petitioners requested 

that small natural gas- and light oil-fired units (petitioners 

defined “small” at various levels between 2 MMBtu/hr and 10 

MMBtu/hr) be exempted from the rule. While the EPA disagrees 

that small units should be exempt from the rule, the EPA agrees 

that for the smallest natural gas-, refinery gas, other clean 

gas (that meets the fuel specification) and light liquid-fired 

units, decreased tune-up frequency is appropriate. The large 

number of small units that can be located at an individual 

facility, particularly an institution, provides logistical 

issues with completion of tune-ups on an annual basis. For 

instance, one institution has over 700 identical small natural 

gas-fired units that would, under the final rule, each be 

subject to a biennial tune-up requirement. We are proposing to 

change that requirement for natural gas-, refinery gas, other 

clean gas (that meets the fuel specification) and light liquidfired units equal to or less than 5 MMBtu/hr to a tune-up once 

every 5 years, with the initial tune-up required by the 
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compliance date and subsequent tune-ups being required at 

intervals no greater than 5 years from the previous tune-up.

2. Clarifications of Certain Tune-up Provisions. Petitioners 

requested several changes to the tune-up requirements and timing 

of completing the various aspects of tune-ups. The issues and 

the EPA’s proposed responses, are presented in the following 

paragraphs.

First, petitioners questioned the requirement that burner 

inspections (part of the tune-up) must be completed at least 

once every 36 months, even if this requirement causes a unit to 

be shut down that otherwise would not have been. The EPA agrees 

that the burner inspection should not cause units to shut down 

and is proposing to remove the “every 36 months” requirement. 

Instead, we are proposing that burner inspections that cannot be 

completed during a tune-up can be delayed until the next 

scheduled shutdown.

Second, petitioners requested that CO adjustments that are 

required as part of a tune-up be allowed to be completed within 

30 days of the tune-up in order to allow for multiple 

adjustments and optimization of CO emissions. The EPA agrees 

that this is a reasonable change and is proposing to allow 30 

days from the date the tune-up is completed.
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Third, the EPA included a burner inspection requirement 

that is difficult or impossible for certain units to meet. The 

EPA is proposing to clarify this provision so as not to require 

a physical inspection that cannot reasonably be completed.

3. Conducting Initial Tune-ups at New Sources. Petitioners 

requested that the EPA clarify the timing of tune-ups with 

respect to the compliance dates for existing and new sources. 

For new units, the EPA recognizes that, as petitioners pointed 

out, units are generally tuned as part of installation, but a 

learning curve exists for how to most efficiently operate new 

units. Accordingly, EPA is proposing that the initial tune-up 

after startup must be completed within one year of startup.

H. Energy Assessment

1. Scope. Petitioners requested that EPA clarify the scope of the 

energy assessment. Specifically, petitioners requested that 

the scope be clearly limited to only those energy use systems 

that are located on-site and associated with the affected 

boilers and process heaters. The final definition for “Energy 

use system” was intended only to list examples of potential 

systems that may use the energy generated by affected boilers 

and process heaters. We did not intend that the energy 

assessment would include energy use systems using electricity 

purchased from an off-site source. We also did not intend that 
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the energy assessment include energy use systems located offsite. We have revised the definition of “Energy assessment” to 

clarify our intent.

2. Compliance Date. Petitioners requested that EPA clarify the 

due date of the energy assessment. All emission standards must 

be met by the compliance date, even if compliance 

demonstrations are sometimes allowed after the compliance 

date. In order to meet the requirements of the rule, energy 

assessments must, therefore, be completed by the compliance 

date for existing sources.

3. Maximum Duration Requirements. Petitioners requested that EPA 

reconsider the stated “maximum time” to conduct the energy 

assessment because the maximum times were not included in the 

proposal, and stakeholders had no opportunity to comment. The 

concern raised by petitioners is that, as the final definition 

of “Energy assessment” is worded, a deviation and a potential 

violation could occur if the energy assessment effort exceeds 

these time limits. Our intent for including the “maximum time” 

in the final rule definition was to minimize the burden on the 

smaller fuel use facilities, many of which are likely small 

entities, by limiting the extent of the energy assessment. Our 

concern was that if there was no time limit, these small 

facilities would have no means to limit the time/effort of an 
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outside energy assessor that is contracted to perform the 

energy assessment. We have revised the definition of “Energy 

assessment” to change the maximum time from one day to 8 

technical hours and from three days to 24 technical hours. 

This would allow sources to perform longer assessments at 

their discretion.

I. Affirmative Defense Provisions During Malfunctions

The EPA finalized affirmative defense provisions for 

malfunctions. As part of this reconsideration proposal, we are 

soliciting comments on the affirmative defense provisions that 

were included in the final rule. The rationale for the 

affirmative defense provisions is provided in the preamble to 

the final rule. See 76 FR 15642.

J. Work Practices During Startup and Shutdown

1. Alternative Site-Specific Work Practices. The EPA finalized a 

work practice standard for periods of startup and shutdown 

that requires facilities to minimize emissions consistent with 

manufacturers’ recommended procedures. Petitioners requested 

that the EPA clarify whether the requirement applies to the 

boiler or the control device manufacturer. The EPA is 

clarifying that all components of the affected source related 

to emissions are subject to this requirement. The EPA also is 

proposing to allow sources to develop their own procedures to 
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minimize emissions, in the absence of or in lieu of 

manufacturers’ recommendations. Such procedures must be 

approved by the implementing authority.

2. Operating Parameters and Opacity Limits. Petitioners requested 

that EPA clarify that the operating limits and opacity limits 

do not apply during periods of startup and shutdown. Having 

finalized work practice standards for these periods of time, 

EPA agrees that the requested clarification is what was 

intended in the final rule.

3. Overall Approach to Startup and Shutdown. The EPA finalized a 

work practice standard for periods of startup and shutdown 

that requires facilities to minimize emissions consistent with 

manufacturer’s recommended procedures. The rationale for the 

work practice is presented in the preamble to the final rule.

See 76 FR 15642. We are soliciting comment on this approach 

because stakeholders did not have the opportunity to comment 

on this approach prior to issuance of the final rule.

K. Applicability

1. Exemption for Units Serving as Control Devices. In the final 

rule, EPA exempted any boiler or process heater that is used 

as a control device to comply with another subpart of part 63, 

provided that at least 50 percent of the heat input to the 

boiler is provided by the gas stream that is regulated under 
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another subpart. Petitioners requested that EPA extend the 

exemption to units that serve as control devices for EPA 

standards issued under parts 60 or 61 of the CAA. We recognize 

that part 61 is another part relevant to the NESHAP program 

and should be treated the same as the exemption provided for 

part 63. Although part 60 does not regulate HAP, EPA does want 

to continue to use combustion controls for organic pollutants 

that part 60 addresses, as it provides a pollution prevention 

strategy and reduces the need for facilities to install other 

combustion equipment to serve as dedicated control devices for 

NSPS and NESHAP regulated gas streams (e.g., thermal oxidizers

and flares). In addition, many of the potential add-on 

combustion technologies do not recover energy, and the 

resulting combustion using these technologies would emit 

approximately the same level of contaminants as a boiler 

without the added benefit of energy recovery. Therefore, the 

EPA is now proposing to exempt any boiler or process heater 

that is used as a control device to comply with standards 

issued under part 60, part 61, or part 63 of the CAA, provided 

that at least 50 percent of the heat input to the boiler is 

provided by a gas stream that is subject to standards under 

those parts.
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2. Waste Heat Boilers and Process Heaters. Petitioners requested 

that EPA clarify that waste heat process heaters, like waste 

heat boilers, are not subject to the standards. Petitioners 

are correct that EPA intended to exempt waste heat process 

heaters from the rule, and EPA is amending the definition of 

process heater to exclude waste heat process heaters. We also 

are clarifying that waste heat boilers and process heaters can 

include supplemental burners as long as those burners combust 

only Gas 1 fuels, up to 50 percent of their heat input.

3. Units Firing Comparable Fuels. Petitioners requested that EPA 

clarify whether boilers and process heaters burning comparable 

fuels, as defined under the Resource Conservation and Recovery 

Act (RCRA), are subject to the NESHAP for industrial, 

commercial, and institutional boilers and process heaters.

Section 261.38 states that hazardous secondary materials 

(i.e., spent materials, sludges and byproducts) that have fuel 

value and whose hazardous constituent levels are comparable to 

those found in fuel oil that could be burned in their place 

are not solid wastes and hence not hazardous wastes under 

Subtitle C of RCRA. These materials are called comparable 

fuels. Since comparable fuels are not hazardous waste, boilers 

and process heaters burning comparable fuels are not subject 

to the NESHAP for hazardous waste combustors (part 63, Subpart 
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EEE), which includes boilers and process heaters that burn 

RCRA hazardous waste. Therefore, boilers and process heaters 

burning comparable fuels are covered by the NESHAP for 

industrial, commercial, and institutional boilers and process

heaters.

L. Residential Unit Exemption. During the initial phases of 

implementation of the area source boiler rule, stakeholders 

requested clarification from EPA on the applicability of the 

area source rule to residential boilers, particularly those 

units at individual residences located at institutional 

facilities. The EPA’s intent was not to cover such units, and 

during reconsideration, the EPA is amending the area source 

rule accordingly. Similarly, the final major source rule could 

be interpreted to cover residential boilers at large 

institutions, which was not the intent of the rule. 

Accordingly, EPA is proposing to exempt residential boilers 

from the rule and is proposing the following definition of 

residential boiler to the major source rule: Residential 

boiler means a boiler, used in a dwelling containing four or 

fewer family units, to provide heat and/or hot water. This 

definition includes boilers used primarily to provide heat 

and/or hot water for a dwelling containing four or fewer 

families located at an institutional facility (e.g., 
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university campus, military base, church grounds) or 

commercial/industrial facility (e.g., farm).

M. Compliance

1. Extending Compliance Dates. On May 18, 2011, the EPA issued a 

stay of the effective date of the final rule. The EPA is 

proposing several revisions to the standards in today’s rule. 

As such, we are proposing to revise the compliance date for 

existing sources to three years after the date of publication 

of the final reconsideration rule. This date is being proposed 

in order to enable facilities sufficient time to install 

controls and make compliance-related decisions. For new 

sources, the EPA is proposing that the compliance date is 60 

days after the date of publication of the final 

reconsideration rule, or upon startup, whichever is later. 

This date assumes that the final reconsideration rule will be 

subject to the Congressional Review Act, which will delay the 

effective date of the rule by 60 days.

We are proposing to extend the compliance dates for all 

standards for several reasons. First, the proposed changes to 

the emission limits for units in every subcategory and the 

proposed use of work practice standards for dioxin/furan 

emissions for all subcategories will have a significant impact 

on the compliance strategies that are selected by the affected 
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sources. For instance, the proposed changes in PM emission 

limits for existing biomass fluidized bed, hybrid suspension 

grate, and the newly proposed dry stoker subcategories would 

require different PM control selections than the emission 

limits finalized in March 2011. The proposed changes in Hg, 

HCl, and PM emission limits for units designed to burn liquid 

fuels are likely to result in different compliance responses 

and control selections for all of these pollutants. For coal 

stoker units, the increased stringency of the proposed PM and 

HCl emission limits would require increased control 

efficiencies that, while not necessarily changing the types of 

controls needed, may impact the design of those controls. 

Second, when EPA announced the reconsideration and issued the 

stay of the effective date, a signal was sent to industry that 

requirements could change significantly. The resulting 

uncertainty has limited the ability of affected sources to 

begin making appropriate selections of control technologies 

and other compliance decisions. Even if significant changes 

were not being proposed, an extended compliance date would 

likely be necessary to provide enough time for facilities to 

achieve compliance. Third, most of the dioxin emission limits 

that were finalized in March 2011 were below the level that 

EPA has now determined can be accurately measured using the 
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required test method. This was pointed out by stakeholders who 

petitioned the EPA to move to a work practice approach because 

the levels of dioxin/furan were too low to accurately measure 

and resulted in a high degree of uncertainty regarding how to 

meet the limits. The uncertainty resulted in the inability of 

sources to select dioxin/furan control technology, and also 

prevented sources from selecting controls for other pollutants 

because the emission controls must be designed to work 

properly when operated together. For instance, if a source 

required an ESP for PM control but needed carbon injection to 

potentially meet a very low dioxin/furan emission limit, the 

source may choose a fabric filter for PM control instead of an 

ESP. Alternatively, if a source no longer needed carbon 

injection, the particulate loading to the PM control device 

would be decreased, which may result in a different design or 

possibly a selection of a different control technology. For 

all of the reasons discussed above, the EPA has determined EPA 

is proposing that the compliance date for existing sources is 

three years after the date of publication of the final 

reconsideration rule. Finally, the EPA has received comments 

that the availability of control equipment and vendors to 

install control equipment for boilers is in question due to 

the large number of units requiring controls in conjunction 
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with the parallel rulemaking for electric generating units 

that will require controls from many of the same vendors. 

While the EPA believes that the maximum time allotted under 

section 112, three years after promulgation along with an 

additional year for installation of controls that must be 

approved on a case-by-case basis by the permitting authority, 

provides enough time for boilers to achieve compliance, the 

EPA recognizes that maintaining the compliance dates from the 

March 2011 final rule would essentially provide less than 2 

years for sources to meet the final standards, whose 

stringency will not be determined until the reconsideration is 

final. The EPA is requesting comment on the proposed changes 

to the compliance dates.

2. Reduced Testing Frequency and Detection Levels. In the final 

rule, EPA changed the stack testing requirements to allow 

units that demonstrate compliance for a particular pollutant 

at a level at or below 75 percent of the emission limit for 2 

consecutive years to forego stack testing for up to 37 months. 

The EPA is maintaining this provision for most of the emission 

limits and is soliciting comment on this provision. The EPA 

also included, in the final rule analyses, a method to ensure 

that emission limits are set at levels that can be measured by 

the available test methods. During the development of the 
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rule, the EPA carefully considered comments regarding the very 

low levels of some of the finalized emission limits that were 

based on a level no less than 3 times the “representative 

detection limit” or RDL. In cases where the calculated MACT 

floors were lower than the 3 times the RDL value, the 

calculated floor value was replaced by the 3 times the RDL 

value. For these values, which again represent the lowest 

level that can be measured, units can qualify for skip testing 

by meeting the limit rather than a level that cannot be 

accurately measured.

3. Fuel Analysis of Gaseous Fuels at Co-Fired Units. Petitioners 

requested that EPA clarify the fuel analysis requirements for 

co-fired units that combust Gas 1 fuels along with either 

solid or liquid fuels. The EPA is clarifying that Gas 1 fuels 

are not included in the fuel analysis requirement.

4. Coal Sampling Techniques. Petitioners requested that EPA allow 

for automated coal sampling systems. The EPA did not intend to 

exclude these techniques in the final rule and is adding 

clarifying language to allow for automated coal sampling 

techniques.

VI. Technical Corrections and Clarifications

We are proposing several technical corrections. These 

amendments are being proposed to correct inaccuracies and 
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oversights that were promulgated in the final rule and to make 

the rule language consistent with provisions addressed through 

this reconsideration. These proposed changes are described in 

Table 2 of this preamble. We request comment on all of these 

proposed changes.

Table 2. Miscellaneous Technical Corrections to 40 CFR Part 63, 

Subpart DDDDD

Section of subpart 

DDDDD

Description of correction

40 CFR 63.7491(m) We are proposing to clarify the language in 

this paragraph to use the “unit” instead of 

“boiler”, and to provide an exemption stating 

“unless such units do not combust hazardous 

waste and combust comparable fuels”.

40 CFR 63.7495(b) We are proposing to edit this paragraph to 

include a provision in §63.6(i)

40 CFR 63.7499 (f)-(s) We are proposing to edit the labels for each 

paragraph to accommodate the addition of 

paragraphs to this section.

40 CFR 63.7499(d) We are proposing to revise the term “stokers” 

to “stokers/sloped grate/other units” 

consistent with how the data for this rule was 

analyzed.

40 CFR 63.7500(d) We are proposing to edit this paragraph by 

adding a new paragraph (d) to clarify that the 

emission standards apply at all times, except 

during startup and shutdown, during which time 

you must comply only with Table 3. 

40 CFR 63.7501(b) We are proposing to edit terms in this 

paragraph to correct spelling errors.

40 CFR 63.7505(c) We are proposing to edit this paragraph by 

removing a reference to Table 12, which is 

being removed from the proposal since we are 

reconsidering.

40 CFR 63.7510(a) We are proposing to edit this paragraph to 

create four subparagraphs (1)-(4) to clarify 

our intent on fuel analysis requirements for 

gaseous fuels.

40 CFR 63.7510(f) We are proposing to edit this paragraph to 

remove references to Table 12, which is being 

removed from the proposal.
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40 CFR 63.7515(f) We also propose to remove a reference to Table 

12, which is being removed from the proposal.

40 CFR 63.7520(d) We are proposing to remove a reference to Table 

12, which is being removed from the proposal.

40 CFR 

63.7521(c)(1)(ii)

We are proposing to edit this paragraph by 

changing wording from “1-hour” to “one-hour”.

We are also proposing to clarify the different 

sampling circumstances for performance stack 

testing and monthly sampling.

40 CFR 

63.7521(c)(2)(ii)

40 CFR 63.7521(d)(2)

We are proposing to edit this paragraph by 

clarifying wording describing sampling 

requirements to provide more flexibility for 

automated sampling and reduce overly 

prescriptive language. 

40 CFR 63.7521(e) We are proposing to reference equations 7, 8, 

and 9 within this paragraph to add clarity. 

40 CFR 63.7521(f) We are proposing to add three sub-paragraphs to 

this paragraph to organize exemptions from fuel 

specification analyses.

40 CFR 63.7522(e)(2) We are proposing to add the units for emission 

limits to add clarity (pounds per million Btu).

We are proposing to revise the definition of 

the term “Sm” in Equation 2 to clarify that 

maximum steam generation is in units of pounds 

per hour. 

40 CFR 63.7525(a) We are proposing to remove a reference to Table

12, which is being removed from the proposal.

40 CFR 63.7525(b)(3) We are proposing to change language from 

“concentrations” to “rates” to provide clarity.

40 CFR 63.7525(b)(5) We are proposing to edit this paragraph by 

changing wording from “1-hour” to “one-hour”.

40 CFR 63.7525(d)(3) We are proposing to revise the paragraph to add 

a reference to 65.7535(d) to replace a 

description of other situations that constitute 

a monitoring deviation.

40 CFR 63.7525(d)(4) We are proposing changes to correct the 12-hour 

block average in 63.7525(d)(4) as specified in 

Table 8.

Second, we are proposing to update and explain 

the averaging times for operating limits in 

63.7525(d)(4).

40 CFR 63.7530(c)(2) We are proposing to edit the references to 

Equation 9 to be Equation 10, to accommodate 

the change in numbering of equations.

40 CFR 63.7530(c)(3) We are proposing to edit the references to 

Equation 9 to be Equation 10, to accommodate 
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the change in numbering of equations.

40 CFR 63.7530(c)(4) We are proposing to edit the references to 

Equation 9 to be Equation 10, to accommodate 

the change in numbering of equations.

40 CFR 63.7530(h) We are proposing to remove a reference to Table 

12, which is being removed from the proposal.

40 CFR 63.7533(b)(2) We are proposing to amend this paragraph to 

clarify that the use of emission credits from 

implementation of energy conservation measures 

can only be used by existing units, and that 

these credits can be used to demonstrate 

initial and on-going compliance.

40 CFR 63.7533(c)(2)(i) We are proposing to edit the reference to 

Equation 12 to Equation 14, to accommodate the 

change in numbering of equations.

40 CFR 63.7533(c)(3) We are proposing to edit the reference to 

Equation 12 to Equation 14, to accommodate the 

change in numbering of equations.

40 CFR 63.7533(c)(3)(i) We are proposing changes to Equation 12 in this 

section to clarify the summation to be 

performed in that equation, and to clarify that 

the energy credits are expressed as a decimal 

fraction of the baseline energy input. 40 CFR 

63.7533(c)(3)

40 CFR 63.7533(c)(3)(i) 

and (f)

We are revising the names and definitions of 

the terms in Equations 12 and 13 to be 

consistent. 

40 CFR 63.7533(c)(f) We are revising the paragraph to remove the 

reference to (f)(1) and (2) because there is no 

paragraph (2) and only a single paragraph is 

needed.

We are proposing to change the reference to 

Equation 13 to Equation 15, to accommodate the 

change in numbering of equations.

40 CFR 63.7535 We are revising the title of this section to 

add clarity.

40 CFR 63.7535(b) We are adding language to the paragraph to 

clarify that you must operate monitoring 

systems while the unit is operating and 

compliance is required.

40 CFR 63.7535(d) We are revising the paragraph to remove 

references to “out-of-control periods”.

40 CFR 63.7540(a) We are adding references to Tables 1, 2, 3, and 

4 to add clarity.

40 CFR 63.7540(a)(3) We are proposing to change the reference to 

Equation 9 to Equation 11 to accommodate the 

change in numbering of equations.
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40 CFR 

63.7540(a)(3)(iii)

We are proposing to change the reference to 

Equation 9 to Equation 11 to accommodate the 

change in numbering of equations.

40 CFR 63.7540(a)(5) We are proposing to change the reference to 

Equation 11 to Equation 12 to accommodate the 

change in numbering of equations.

40 CFR 

63.7540(a)(5)(iii)

We are proposing to change the reference to 

Equation 11 to Equation 12 to accommodate the 

change in numbering of equations.

40 CFR 63.7540(a)(9)(i) We are proposing to correct the reference to 

60.13 to 63.8.

40 CFR 63.7541 (a)(3) 

and (4)

We are proposing changes to correct the 12-hour 

block average in 63.7541(a)(3) and (4) as 

specified in Table 8.

40 CFR 63.7545(e)(3) We are proposing to remove a reference to Table 

12, which is being removed from the proposal, 

and adding language to clarify that this 

applies to facilities “not using a CO CEMS to 

demonstrate compliance.”

40 CFR 63.7545(f) We are proposing to revise the paragraph to 

include units that burn “gaseous fuel subject 

to another subpart of this part” to add 

clarity.

40 CFR 63.7550(c)(6) We are proposing to change the reference to 

Equation 10 to Equation 11, to accommodate the 

change in numbering of equations.

40 CFR 63.7555(d) We are proposing to remove a reference to Table 

12, which is being removed from the proposal.

40 CFR 63.7555(d)(4) We are proposing to change the reference to 

Equation 10 to Equation 11, to accommodate the 

change in numbering of equations.

40 CFR 63.7555(d)(5) We are proposing to change the reference to 

Equation 11 to Equation 12, to accommodate the 

change in numbering of equations.

40 CFR 63.7555(h) We are proposing to revise the paragraph to 

include units that burn “gaseous fuel subject 

to another subpart of this part” to add 

clarity.

40 CFR 63.7575 We are proposing to revise the definition of 

process heater to include units heating hot 

water as a process heat transfer medium.

We also included a hierarchy of combustor 

designs to clarify applicability for units with 

multiple combustor types. 

We are proposing to revise the definition of 

“dutch oven” to clarify that fluidized bed 

boilers are not part of the dutch oven design 
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category.

We are proposing to revise the definition of 

“energy assessment” to clarify the length days 

for each category of facilities.

We are proposing to revise the definition of 

“equivalent” to remove references to hydrogen 

sulfide.

We are proposing to revise the definition of 

“fluidized bed boiler” to clarify that 

pulverized coal boilers are not included.

We are proposing to revise the definition of 

“hybrid suspension grate boiler” to clarify 

that “the fuel combusted in these units exceed 

a moisture content of 40 percent on an as-fired 

basis” and “Fluidized bed, dutch oven, and pile 

burner designs are not part of the hybrid 

suspension grate boiler design category.”

We are proposing to revise the definition of 

“fuel cell” to clarify that “fluidized bed, 

dutch oven, pile burner, hybrid suspension 

grate, and suspension burners are not part of 

the fuel cell subcategory.”

We are proposing to revise the definition of 

“liquid fuel” to include vegetable oil.

We are proposing to revise the definition of 

“process heater” to include “units heating hot 

water as a process heat transfer medium” and to 

clarify that “waste heat process heaters are 

excluded from this definition” similar to the 

exemption allowed for waste heat boilers.

We are proposing to revise the definition of 

“steam output” to include a description of the 

total energy output for a boiler that generates 

only electricity.

We are proposing to revise the definition of 

“stoker” to clarify that “fluidized bed, dutch 

oven, pile burner, hybrid suspension grate, 

suspension burners, and fuel cells are not 

considered to be a stoker design.”

We are proposing to revise the term “suspension 

boiler” to instead be “suspension burner”, to 

provide consistent terminology throughout the 

rule and to clarify that “fluidized bed, dutch 

oven, pile burner, and hybrid suspension grate 
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units are not part of the suspension burner 

subcategory.”

We are proposing to revise the definition of 

“waste heat boiler” to clarify that the 

definition includes fired and unfired waste 

heat boilers.

We are proposing to revise the definition of 

“waste heat process heater to clarify that the 

definition includes fired and unfired waste 

heat process heaters.

We are proposing to add new definitions of “12-

hour block average”, “actual heat rate”, 

“average annual heat input rate”, “biodiesel”, 

“daily block average”, “heavy liquid”, “light 

liquid”, “other combustor”, “oxygen analyzer”, 

“oxygen trim system”, “pile burner”, 

“residential boiler”, “sloped grate”, 

“stoker/sloped grate/other unit designed to 

burn dry biomass”, “stoker/sloped grate/other 

unit designed to burn wet biomass”, “total 

selected metals”, “unit designed to burn heavy 

liquid subcategory”, “unit designed to burn 

light liquid subcategory”, and “vegetable oil”.

We are proposing to remove the definition of 

“liquid fuel subcategory”

Table 3 We are proposing to revise item 4c to clarify 

the major systems “consuming energy from 

affected boilers and process heaters and which 

are under the control of the boiler/process 

heater owner/operator.”

We are proposing to edit item 5 to remove the 

reference to Table 12, which is being removed 

from the proposal.

Table 4 We are proposing editing the operating limits 

for items 1 and 2 to read “one-hour” instead of 

“1-hour”.

VII. Impacts of this Proposed Rule

A. What are the air impacts?

Table 3 of this preamble illustrates, for each basic fuel 

subcategory, the emissions reductions achieved by the proposed 
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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 45,000

tons per year for existing units and 19 tons per year for new 

units. Emissions of HCl will be reduced by 37,000 tons per year 

for existing units and 0 tons per year for new units. Emissions 

of mercury will be reduced between 0.5 to 1.8 tons per year for 

existing units and 20.2 pounds per year for new units. Emissions 

of filterable PM will be reduced by 41,200 tons per year for 

existing units and 1,500 tons per year for new units. Emissions 

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

cadmium, chromium, cobalt, lead, manganese, nickel, and 

selenium) will be reduced by 2,200 tons per year for existing 

units and 19 tons per year for new units. In addition, emissions 

of SO2 are estimated to be reduced by 558,400 tons per year for 

existing sources and 0 tons per year for new sources. A 

discussion of the methodology used to estimate emissions and 

emissions reductions is presented in “Revised (November 2011) 

Methodology for Estimating Cost and Emission Impacts for 

Industrial, Commercial, and Institutional Boilers and Process 

Heaters NESHAP - Major Source” in the docket.
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Table 3. Summary of Emissions Reductions for Existing and New 

Sources (tons/yr)

Source Subcategory HCl PM Non 

Mercury 

Metalsa

Mercury

b

VOC

Existing 

Units

Limited Use 1 2 0.45 2.2E-04 1

Solid units 34,815 34,830 271 0.4 to 

1.4

2,487

Liquid units 2,039 6,240 1,905 0.04 to 

0.3

1,815

NonContinental 

Liquid units

158 29 4 0.001 

to 0.01

169

Gas 1 

(NG/RG) 

units

21 118 0.9 0.01 85

Gas 1 

Metallurgica

l Furnaces

0.4 3 0.02 0.001 23

Gas 2 

(other)units

4 11 0.07 0.004 

to 

0.005

138

New 

Units

Solid units 0 1,462 19 0.01 0

Liquid units 0 0 0 0 0

Gas 1 units 0 0 0 0 0

Gas 1 

Metallurgica

l Furnaces

0 0 0 0 0

Gas 2 

(other) 

units

0 0 0 0 0

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

manganese, nickel, and selenium.

b Mercury reductions are presented as a range due to adjustments on reported 

fractions and limits of detection. See memorandum entitled "Revised (November 

2011) Methodology for Estimating Cost and Emissions Impacts for Industrial, 
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Commercial, Institutional Boilers and Process Heaters National Emission 

Standards for Hazardous Air Pollutants – Major Source" for a description of 

the two methods for estimating mercury reductions.

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 1.2 billion gallons per year for existing 

sources and 0 gallons per year for new sources. In addition to 

the increased water usage, an additional 416 million gallons per 

year of wastewater would be produced for existing sources and 0

gallons per year for new sources. The annual costs of treating 

the additional wastewater are $2.3 million for existing sources 

and $0 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 286,000 tons 

per year for existing sources and 1,700 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 $12.0

million for existing sources and $70,600 for new sources. These 

costs are also accounted for in the control costs estimates.
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A discussion of the methodology used to estimate impacts is 

presented in “Revised (November 2011) Methodology for Estimating 

Cost and Emission Impacts for Industrial, Commercial, and 

Institutional Boilers and Process Heaters NESHAP - Major Source” 

in the Docket.

C. What are the energy impacts?

The EPA expects an increase of approximately 1.5 billion

kilowatt hours (kWh) in national annual energy usage as a result 

of the proposed rule. Of this amount, 1.4 billion kWh would be 

from existing sources and 120 million kWh 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 47.3 trillion BTU each 

year from existing sources. EPA did not estimate fuel savings 

and efficiency improvements on new boilers since new boilers are 

expected to be tuned-up up upon installation and will not 

achieve additional fuel savings in the first year. This fuel 

savings estimate includes only those fuel savings resulting from 

gas 1, liquid, and coal fuels and it is based on the assumption 
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that the work practice standards will achieve 1 percent 

improvement in efficiency.

D. What are the cost impacts?

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 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 or total selected metals 

limits; wet scrubbers or fabric filters with dry injection to 

meet the HCl limits; tune-ups, replacement burners, combustion 

controls, and oxidation catalysts for CO and organic HAP 
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control; and tune-ups 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 5.4 billion dollars 

in capital expenditures and 1.9 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 1.5 billion dollars. The total 

capital and annual costs include costs for control devices, work 

practices, testing and monitoring. While these costs are higher 

than the costs estimated for the final rule, these estimates are 

based on an inventory that includes 300 additional units that 

were identified after the final rule was completed. The costs 

associated with the final rule inventory are just under $5.0 

billion in capital expenditures and $1.75 billion in total 

annual costs ($1.35 billion considering fuel savings). Table 4

of this preamble shows the capital and annual cost impacts for 

each subcategory. Costs include testing and monitoring costs, 

but not recordkeeping and reporting costs.
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Table 4. Summary of Capital and Annual Costs for New and 

Existing Sources

Source Subcategory Estimated/

Projected 

No. of 

Affected 

Units

Capital 

Costs 

(106$)

Testing 

and 

Monitoring 

Annualized 

Costs

(106$/yr)

Annualized 

Cost 

(106

$/yr)(cons

idering 

fuel 

savings)

Existing 

Units

Coal units 616 2,713 46 953

Biomass 

units

508 639 33 169

Heavy 

Liquid 

units

322 769 8.4 264

Light 

Liquid 

units

581 930 5.1 277

NonContinental 

Liquid 

units

44 181 1.5 42

Gas 1 

(NG/RG) 

units

11,911 77 0.9 (295)

Gas 2 

(other) 

units

129 132 2.3 55

Energy 

Assessmen

t

ALL 1,704 

(Facilities)

N/A N/A 28

New Units Coal units 0 0 0 0

Biomass 

units

82 381 5.6 99a

Liquid 

units

0 0 0 0
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Gas 1 

(NG/RG) 

units

1,762 11 0 5.1a

Gas 2 

(other) 

units

0 0 0 0

a Total annualized costs for new units do not account for fuel 

savings since no fuel savings are estimated in the first year 

for new units.

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 for new boilers in the 

3rd year is 393 million dollars in capital expenditures and 104

million dollars per year in total annual costs. 

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 “Revised (November 2011) Methodology for 

Estimating Cost and Emission Impacts for Industrial, Commercial, 

and Institutional Boilers and Process Heaters NESHAP - Major 

Source” in the Docket.

E. What are the economic impacts?
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The EPA analyzed the economic impacts of this proposed rule 

using the methodology that was discussed in the final rule RIA 

and in the preamble to the final rule. See FR 76 15651.

The market impact results are very similar to the results 

presented in the final rule and the RIA. The agencies economic 

model suggests the average national price increases for 

industrial sectors are less than 0.01 percent, while average 

annual domestic production may fall by less than 0.01 percent. 

Because of higher domestic prices, imports slightly rise. The 

change in US surplus is now -1.93 billion dollars (2006$). For 

the RIA, it was -1.86 billion dollars (2006$).

The results for sales tests for small businesses were 

somewhat reduced. For the sales tests using small companies 

identified in the Combustion Survey, the mean cost to receipts 

dropped from 4 percent in the RIA to 2 percent for this proposed 

rule and the median was 0.2 percent for both. The number of 

parent companies with sales tests exceeding 3 percent dropped 

from 8 in the RIA to 6 for this proposed rule. There was no 

change in the results for small public entities. Median cost is 

still about $1.1 million and representative small major public 

entities would have cost-to-revenue ratios above 10 percent.

The change in employment estimates between the RIA and the 

proposal is minimal. In the RIA for the final rule, we estimated 
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employment changes ranging between −3100 to +6,500 employees, 

with a central estimate of +1,700. For this proposal, we 

estimate employment changes ranging between −3000 to +6,300 

employees, with a central estimate of +1,600.

The benefits estimates increased for this proposal. In the 

RIA for the final rule, we estimated benefits ranging from $22 

billion (2008$) to 54 billion (2008$) at a 3 percent discount 

rate. For this proposal, we estimate benefits ranging from $27 

billion (2008$) to 67 billion (2008$) at a 3 percent discount 

rate. The range for the RIA was $20 billion (2008$) to 49 

billion (2008$) at a 7 percent discount rate. The range for this

proposal is $25 billion (2008$) to 61 billion (2008$) at a 7

percent discount rate.

F. What are the benefits of this proposed rule?

We calculated health benefits using the methodology 

described in the RIA prepared for the March 21, 2011, final 

rule. We incorporated the revised emission reductions estimated 

for this reconsideration proposal into the analysis. We were 

unable to estimate the benefits from reducing exposure to HAPs 

and ozone, ecosystem impairment, and visibility impairment, 

including reducing 187,000 tons of carbon monoxide, 37,000 tons 

of HCl, 1,000 tons of HF, 1,000 to 3,600 pounds of mercury, and 
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2,200 tons of other metals. Please refer to the full description

in the final Boiler RIA of the unquantified benefits as well as 

analysis limitations and uncertainties. These monetized benefits 

are approximately 23 percent higher than the final rule benefits

due to the increase in SO2 emission reductions. We estimate the 

total monetized benefits of this proposed regulatory action to 

be $27 billion to $67 billion (2008$, 3 percent discount rate) 

in the implementation year (2015). A summary of the monetized 

benefits estimates at discount rates of 3 percent and 7 percent 

is provided in Table 4 of this preamble. A summary of the 

avoided health incidences is provided in Table 5 of this 

preamble.

Table 4. Summary of the Monetized Benefits Estimates for the 

Final Boiler MACT (millions of 2008$)1

Pollutant

Emissions 

Reductions 

(tons)

Total Monetized 

Benefits (at 3% 

discount rate)

Total Monetized 

Benefits (at 7% 

discount rate)

PM2.5-related benefits

Direct PM2.5 25,601 $1,800 to $4,500 $1,700 to $4,100

SO2 558,430 $25,000 to $63,000 $23,000 to $57,000

1All estimates are for the implementation year (2015), and are 

rounded to two significant figures so numbers may not sum across 

rows. All fine particles are assumed to have equivalent health 

effects. Benefits from reducing hazardous air pollutants (HAP) 

are not included. These estimates do not include energy 

disbenefits valued at $22 million. These benefits reflect 

existing boilers and new boilers anticipated to come online by 

2015.
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Table 5. Summary of the Avoided Health Incidences for the Final 

Boiler MACT1

Avoided Health 

Incidences

Avoided Premature Mortality 3,100 to 8,000

Avoided Morbidity

Chronic Bronchitis 2,000

Acute Myocardial Infarction 4,900

Hospital Admissions, Respiratory 750

Hospital Admissions, Cardiovascular 1,600

Emergency Room Visits, Respiratory 3,000

Acute Bronchitis 4,600

Work Loss Days 390,000

Asthma Exacerbation 51,000

Minor Restricted Activity Days 2,300,000

Lower Respiratory Symptoms 55,000

Upper Respiratory Symptoms 41,000

1All estimates are for the implementation year (2015), and are 

rounded to two significant figures. All fine particles are 

assumed to have equivalent health effects. Benefits from 

reducing HAP are not included. These benefits reflect existing 

boilers and new boilers anticipated to come online by 2015.

G. What are the secondary air impacts?

For units adding controls to meet the proposed emission 

limits, we anticipate very minor secondary air impacts. The 

combustion of fuel needed to generate additional electricity 

would yield slight increases in emissions, including NOx, CO, PM 

and SO2 and an increase in CO2 emissions. Since NOx and SO2 are 

covered by capped emissions trading programs, and methodological 

limitations prevent us from quantifying the change in CO and PM, 

we do not estimate an increase in secondary air impacts for this 
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final rule from additional electricity demand. We do estimate 

greenhouse gas impacts, which result from increased electricity 

consumption, to be 931,000 tons per year from existing units and 

79,700 tons per year from new units.

VIII. Relationship of this Proposed Action to Section 112(c)(6) 

of the CAA

Section 112(c)(6) of the CAA requires the 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). The 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 emit two of the seven CAA Section 112(c)(6) pollutants: 

POM and Hg. (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), the EPA identified “Industrial 

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

Wood/Wood Residue Combustion,” “Commercial Coal Combustion,” 
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“Commercial Oil Combustion,” and “Commercial Wood/Wood Residue 

Combustion” as source categories “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.

For Hg, the 112(c)(6) requirement is directly met through 

the proposed emission limits for mercury. Through these emission 

limits, the types of boilers and process heaters listed in 

section 112(c)(6) are subject to regulation.

For POM, which are byproducts of combustion, the formation 

of POM is effectively reduced by the combustion and postcombustion practices required to comply with the CAA Section 112 

standards. The tune-up requirement for all major source units 

and the CO emission limits will ensure that good combustion 

practices are followed, thus minimizing emissions of organic 

HAP, including POM. Any POM that do form during combustion would 

be reduced by the various post-combustion controls. The add-on 

PM control systems (either fabric filter or wet scrubber) and 

activated carbon injection in the fabric filter-based systems 

would reduce emissions of these organic pollutants. It is, 

therefore, reasonable to conclude that POM emissions will be 

substantially controlled. Thus, while this final rule does not 

identify specific numerical emission limits for POM, emissions 
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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, CO 

serves as an effective surrogate for this HAP, because CO, like 

POM, is formed as a byproduct of combustion, and both would 

increase with an increase in the level of incomplete combustion. 

Consequently, we have concluded that the emissions limits 

for CO function as a surrogate for control of POM, such that it 

is not necessary to require numerical emissions limits for POM 

with respect to boilers and process heaters to satisfy CAA 

Section 112(c)(6).

To further address POM and Hg emissions, this final rule 

also includes an energy assessment provision that encourage 

modifications to the facility to reduce energy demand that lead 

to these emissions.

IX. Statutory and Executive Order Reviews

A. Executive Order 12866: Regulatory Planning and Review and 

Executive Order 13563: Improving Regulation and Regulatory 

Review

Under section 3(f)(1) of Executive Order 12866 (58 FR 

51735, October 4, 1993), this action is an "economically 
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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 Executive 

Orders 12866 and 13563 (76 FR 3821, January 21, 2011) and any 

changes made in response to OMB recommendations have been 

documented in the docket for this action.

Because this action is proposing changes to a final rule 

and does not increase costs by an amount that would qualify the 

proposed rule, by itself, as a major rule, the EPA did not 

prepare a new RIA for this action. Instead, the EPA prepared an 

assessment of the changes in the costs and benefits of this 

proposed rule compared to the costs and benefits associated with 

the March 21, 2011, final rule. Overall, the costs and impacts 

are estimated to be similar to the costs and impacts associated 

with the final rule, although the distribution is somewhat 

different and the number of affected units in the inventory has 

increased by about 300 units. When comparing the costs using 

only those sources that were part of the final rule inventory, 

the costs have decreased. The EPA re-ran the multimarket model 
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to assess changes in economic impacts, and this analysis 

confirmed that the overall economic impacts are similar to the 

final rule. The benefits are projected to increase by about 23 

percent because of the increase in the estimated SO2 reductions.

A summary of the costs and benefits of the final rule is 

provided in the preamble to the final rule (see 76 FR 15658) and 

the detailed analysis for the final rule is provided in the RIA 

for the final rule. In addition, memoranda are provided in the 

docket to document the changes in costs, economic impacts, and 

benefits associated with this proposed rule. 

B. Paperwork Reduction Act

The information collection requirements in this proposed 

rule will be submitted for approval to the Office of Management 

and Budget (OMB) under the Paperwork Reduction Act, 44 U.S.C. 

3501 et seq. The Information Collection Request (ICR) document 

prepared by EPA has been assigned EPA ICR number 2028.07. The 

information collection requirements are not enforceable until 

OMB approves them.

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 
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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.

This 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 aside 

from a notification of intent to commence burning solid waste 

materials and notification of alternative fuel use for those 

units that are in the Gas 1 subcategory but burn liquid fuels 

for periodic testing, or during periods of gas curtailment or 

gas supply emergencies. 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 $96.2 

million. This includes 324,954 labor hours per year at a total 

labor cost of $30.7 million per year, and total non-labor 

capital costs of $65.5 million per year. This estimate includes 

initial and annual performance test, conducting an documenting 

an energy assessment, conducting fuel specifications for Gas 1 

units, repeat testing under worst-case conditions for solid fuel 
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units, 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 VII.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 97,613 hours per year at a total labor cost of $5.1 million 

per year. Burden is defined at 5 CFR 1320.3(b).

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

required to respond to, a collection of information unless it 

displays a currently valid OMB control number. The OMB control 

numbers for EPA's regulations in 40 CFR are listed in 40 CFR 

part 9. 

To comment on the Agency's need for this information, the 

accuracy of the provided burden estimates, and any suggested 

methods for minimizing respondent burden, EPA has established a 

public docket for this rule, 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 notice for where to submit comments to EPA. 

Send comments to OMB at the Office of Information and Regulatory 
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Affairs, Office of Management and Budget, 725 17th Street, NW, 

Washington, DC 20503, Attention: Desk Office for EPA. Since OMB 

is required to make a decision concerning the ICR between 30 and 

60 days after [INSERT DATE OF PUBLICATION IN THE FEDERAL 

REGISTER], a comment to OMB is best assured of having its full 

effect if OMB receives it by [INSERT DATE 30 DAYS AFTER 

PUBLICATION IN THE FEDERAL REGISTER]. The final rule will 

respond to any OMB or public comments on the information 

collection requirements contained in this proposal.

C. Regulatory Flexibility Act

The Regulatory Flexibility Act (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 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 
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for the affected industries ranges from 500 to 1,000 employees, 

except for petroleum refining and electric utilities. In these 

latter two industries, the size standard is 1,500 employees and 

a mass throughput of 75,000 barrels/day or less, and 4 million 

kilowatt-hours of production or less, respectively; (2) a small 

governmental jurisdiction that is a government of a city, 

county, town, school district or special district with a 

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

that is any not-for-profit enterprise which is independently 

owned and operated and is not dominant in its field. 

Pursuant to section 603 of the RFA, EPA prepared a final

regulatory flexibility analysis (FRFA) that examined the impact 

of the March 21, 2011 final rule on small entities along with 

regulatory alternatives that could reduce that impact. The FRFA

was included in the RIA for the final rule and is available for 

review in the docket. This reconsideration proposal would

decrease capital and annualized costs on small entities by about 

3 percent and 10 percent, respectively. Therefore, we are 

relying on the FRFA from the final rule as a conservative 

assessment of impacts on small entities. See 76 FR 15656-15658.

We invite comments on the proposed changes and their

impacts on small entities.

D. Unfunded Mandates Reform Act
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Title II of the Unfunded Mandates Reform Act of 1995 (UMRA), 

2 U.S.C. 1531-1538, requires Federal agencies, unless otherwise 

prohibited by law, to assess the effects of their regulatory 

actions on State, local, and tribal governments and the private 

sector. This March 21, 2011, final rule contained 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 one year. Accordingly, the EPA prepared 

under section 202 of the UMRA a written statement for the final 

rule. The discussion below has been updated to reflect the 

proposed changes.

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 
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to all ICI boilers and process heaters located at major sources 

of HAP emissions.

2. Social Costs and Benefits

The regulatory impact analysis prepared for the final rule, 

which we have not revised for this proposed rule, including the 

Agency’s assessment of costs and benefits, is detailed in the 

“Regulatory Impact Analysis for the Final Industrial Boilers and 

Process Heaters MACT (2011)” in the docket. Based on estimated 

compliance costs associated with this proposed rule and the 

predicted change in prices and production in the affected 

industries, the estimated social costs of this proposed rule are 

$1.49 billion (2008 dollars).

 It is estimated that 3 years after implementation of this 

proposed rule, HAP would be reduced by 45,000 tons per year, 

including reductions in hydrochloric acid, hydrogen fluoride, 

metallic HAP including Hg, 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 annual reductions in PM2.5 and in SO2 that would 

occur, including 25,000 thousand tons of PM2.5 and 558 thousand 

tons of SO2. These reductions occur within 3 years after the 
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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 2015 associated with the implementation of 

the proposed alternative range from $27 billion (2008 dollars) 

to $67 billion (2008 dollars) when using a 3 percent discount 

rate (or from $25 billion (2008 dollars) to $61 billion (2008 

dollars) when using a 7 percent discount rate). This estimate, 

at a 3 percent discount rate, is about $25 billion (2008 

dollars) to $65 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 
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this preamble. For more detailed information on the benefits 

estimated for the rulemaking, refer to the RIA and the memos 

updating the impacts and benefits in the docket.

3. Future and Disproportionate Costs

The UMRA requires that we estimate, where accurate 

estimation is reasonably feasible, future compliance costs 

imposed by this proposed rule and any disproportionate budgetary 

effects. Our estimates of the future compliance costs of the 

rule are discussed previously in this preamble.

We do not believe that there will be any disproportionate 

budgetary effects of this proposed rule on any particular areas 

of the country, State or local governments, types of communities 

(e.g., urban, rural), or particular industry segments. See the 

results of the “Regulatory Impact Analysis for the Final

Industrial Boilers and Process Heaters MACT (2011).”

4. Effects on the National Economy

The Unfunded Mandates Act requires that we estimate the 

effect of this 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.
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The nationwide economic impact of this proposed rule is 

presented in the “Regulatory Impact Analysis for the Final

Industrial Boilers and Process Heaters MACT (2011)” in the 

docket. This analysis provides estimates of the effect of this 

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 this 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. We 

consulted with State and local air pollution control officials

during the development of the final rule. We have also held 

meetings on this proposed rule with many of the stakeholders 
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from numerous individual companies, institutions, environmental 

groups, consultants and vendors, labor unions, and other 

interested parties. We have added materials to the docket to 

document these meetings.

Consistent with section 205, EPA has 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 emission limits 

in this proposed rule are based represents the MACT floors for 

all subcategories and, as a result, it is the least costly and 

least burdensome alternative.

This rule is not subject to the requirements of section 203 

of UMRA because it contains no regulatory requirements that 

might significantly or uniquely affect small governments. While 

some small governments may have some sources affected by this 

proposed rule, the impacts are not expected to be significant.

Therefore, this proposed rule is not subject to the requirements 

of section 203 of the UMRA.

E. Executive Order 13132: Federalism

This action 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 
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on the distribution of power and responsibilities among the 

various levels of government, as specified in Executive Order 

13132. This proposed rule will not impose direct compliance 

costs on state or local governments, and will not preempt state 

law. Thus, Executive Order 13132 does not apply to this action.

In the spirit of Executive Order 13132, and consistent with 

EPA policy to promote communications between EPA and state and 

local governments, EPA specifically solicits comment on this 

proposed action from state and local officials.

F. Executive Order 13175: Consultation and Coordination with 

Indian Tribal Governments

This action 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. Thus, Executive Order 13175 does not 

apply to this action.

The EPA specifically solicits additional comment on this 

proposed action from tribal officials.

G. Executive Order 13045: Protection of Children from 

Environmental Health Risks and Safety Risks
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EPA interprets Executive Order 13045 (62 FR 19885, April 

23, 1997) as applying only to those regulatory actions that 

concern health or safety risks, such that the analysis required 

under section 5-501 of the Executive Order has the potential to 

influence the regulation. This action is not subject to 

Executive Order 13045 because it is based solely on technology 

performance. 

H. Executive Order 13211: Actions Concerning Regulations That 

Significantly Affect Energy Supply, Distribution, or Use

This action is not a “significant energy action” as defined 

in Executive Order 13211 (66 FR 28355, May 22, 2001), because it 

is not likely to have a significant adverse effect on the 

supply, distribution, or use of energy. For the March 21, 2011, 

final rule, we estimated a 0.05 percent price increase for the 

energy sector and a -0.02 percent percentage change in 

production. We estimated a 0.09 percent increase in energy 

imports. For more information on the estimated energy effects, 

please refer to the “Regulatory Impact Analysis for the Final

Industrial Boilers and Process Heaters MACT (2011).” The 

analysis is available in the public docket. While we did not 

redo the RIA for this proposed action, the energy impacts for 

existing sources decreased slightly, and the energy impacts for 

new source increased due to the increased number of new sources 
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that is now projected. Overall, the projected energy use 

increased slightly but would not change the analysis that was 

conducted for the final rule. Therefore, we conclude that the 

proposed rule when implemented is not likely to have a 

significant adverse effect on the supply, distribution, or use 

of energy.

I. National Technology Transfer and Advancement Act

Section 12(d) of the National Technology Transfer and 

Advancement Act of 1995 (NTTAA), Public Law No. 104-113,(15 

U.S.C. 272 note) directs EPA to use voluntary consensus 

standards in its regulatory 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, and 

business practices) that are developed or adopted by voluntary 

consensus standards bodies. NTTAA directs EPA to provide 

Congress, through OMB, explanations when the Agency decides not 

use available and applicable voluntary consensus standards.

This proposed rulemaking involves technical standards. EPA 

proposes to use EPA Methods 1, 2, 2F, 2G, 3A, 3B, 4, 5, 5D, 17, 

19, 23, 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 
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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 
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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 
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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 
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Dioxide, Carbon Monoxide, Sulphur Dioxide, and Oxides of 

Nitrogen in Enclosed Combustion Flue Gas Streams,” is 

unacceptable as a substitute for EPA Method 3A since it does not 

include quantitative specifications for measurement system 

performance, most notably the calibration procedures and 

instrument performance characteristics. The instrument 

performance characteristics that are provided are nonmandatory 

and also do not provide the same level of quality assurance as 

the EPA methods. For example, the zero and span/calibration 

drift is only checked weekly, whereas the EPA methods requires 

drift checks after each run.

Two very similar voluntary consensus standards, ASTM D5835-

95 (2001), “Standard Practice for Sampling Stationary Source 

Emissions for Automated Determination of Gas Concentration,” and 

ISO 10396:1993, “Stationary Source Emissions: Sampling for the 

Automated Determination of Gas Concentrations,” are impractical 

alternatives to EPA Method 3A for the purposes of the proposed 

rule because they lack in detail and quality assurance/quality 

control requirements. Specifically, these two standards do not 

include the following: (1) sensitivity of the method; 

(2) acceptable levels of analyzer calibration error; (3) 

acceptable levels of sampling system bias; (4) zero drift and 

calibration drift limits, time span, and required testing 
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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 
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because ASTM PTC-38-80 is not specific about equipment 

requirements, and instead presents the options available and the 

pro’s and con’s of each option. The key specific differences 

between ASME PTC-38-80 and the EPA methods are that the ASME 

standard: (1) allows in-stack filter placement as compared to 

the out-of-stack filter placement in EPA Methods 5 and 17; 

(2) allows many different types of nozzles, pitots, and 

filtering equipment; (3) does not specify a filter weighing 

protocol or a minimum allowable filter weight fluctuation as in 

the EPA methods; and (4) allows filter paper to be only 

99 percent efficient, as compared to the 99.95 percent 

efficiency required by the EPA methods. 

The voluntary consensus standard ASTM D3685/D3685M-98, 

“Test Methods for Sampling and Determination of Particulate 

Matter in Stack Gases,” is similar to EPA Methods 5 and 17, but 

is lacking in the following areas that are needed to produce 

quality, representative particulate data: (1) requirement that 

the filter holder temperature should be between 120oC and 134oC, 

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 
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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 
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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. 
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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 
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because of the low sampling rate of the bubblers (up to 3 liters 

per minute, maximum). Also, only two bubblers (or impingers) are 

required by EN 13211, whereas EPA Method 29 require the use of 

six impingers. In addition, EN 13211 does not include many of 

the quality control procedures of EPA Method 29, especially for 

the use and calibration of temperature sensors and controllers, 

sampling train assembly and disassembly, and filter weighing.

Two of the 15 voluntary consensus standards identified in 

this search were not available at the time the review was 

conducted for the purposes of the proposed rule because they are 

under development by a voluntary consensus body: ASME/BSR MFC 

13M, “Flow Measurement by Velocity Traverse,” for EPA Method 2 

(and possibly 1); and ASME/BSR MFC 12M, “Flow in Closed Conduits 

Using Multiport Averaging Pitot Primary Flowmeters,” for EPA 

Method 2. 

Section 63.7520 and Tables 4A through 4D to subpart DDDDD, 

40 CFR part 63, list the EPA testing methods included in the 

proposed rule. Under §63.7(f) and §63.8(f) of subpart A of the 

General Provisions, a source may apply to EPA for permission to 

use alternative test methods or alternative monitoring 

requirements in place of any of the EPA testing methods, 

performance specifications, or procedures.
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EPA welcomes comments on this aspect of the proposed 

rulemaking and, specifically, invites the public to identify 

potentially-applicable voluntary consensus standards and to 

explain why such standards should be used in this regulation.

J. Executive Order 12898: Federal Actions to Address 

Environmental Justice in Minority Populations and Low-Income 

Populations

Executive Order (EO) 12898 (59 FR 7629, February 16, 1994) 

establishes federal executive policy on environmental justice. 

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 and low-income populations in 

the United States.

For the March 2011 final rule, the EPA determined that rule

would not have disproportionately high and adverse human health 

or environmental effects on minority or low-income populations

because it increases the level of environmental protection for 

all affected populations without having any disproportionately 

high and adverse human health or environmental effects on any 

population, including any minority or low-income population. 
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Compared to the final rule, while the proposed amendments are 

somewhat less stringent for some subcategories of units and more 

stringent for some others, the overall increased health benefits 

demonstrate that the conclusions from the environmental justice

analysis conducted for the final rule are still valid.
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National Emission Standards for Hazardous Air Pollutants for 

Major Sources: Industrial, Commercial, and Institutional Boilers 

and Process Heaters--Page 146 of 147

List of Subjects in 40 CFR Part 63

Environmental protection, Administrative practice and 

procedure, Air pollution control, Hazardous substances, 

Intergovernmental relations, Reporting and Recordkeeping 

requirements.

Dated:

Lisa P. Jackson,

Administrator.
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For the reasons cited in the preamble, title 40, chapter I, 

part 63 of the Code of Federal Regulations is proposed to be 

replaced as follows:

PART 63--[AMENDED]

[AMENDATORY TEXT]