***E.O. 12866 Review – Draft – Do Not Cite, Quote, or Release 

During Review***

EO12866 NESHAP Major Sources-Industrial Commercial Institutional 

Boiler and Process Heaters RIN 2060-AR13 Proposed Rule –

Reconsideration 20111201

The enclosed file presents a redline strikeout comparison between the preamble originally 

submitted to from EPA to OMB on October 14, 2011 and the final file OMB approved on 

December 1, 2011. It also includes a redline strikeout comparison between the rule originally 

submitted to OMB on November 2, 2011 and the final file OMB approved on December 1, 2011. 
Page 2 of 360

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; 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 

announcing its intent to reconsider certain provisions of the 

final rule. The EPA subsequently issued a notice on May 18, 

2011, to postpone the effective dates of the final rule until 

judicial review has been completed, or the agency finalizes its 

reconsideration of the standard, whichever is earlier. In the 

action to postpone the effective dates of the rule, the EPA also 

requested the public to submit data and information to assist

the EPA in its reconsideration. Following these actions, the 

Administrator received several petitions for reconsideration. In 
Page 3 of 360

response to the March 21, 2011, notice announcing its intent to 

initiate reconsideration and the petitions submitted, the EPA is 

reconsidering and requesting comment on several provisions of 

the final rule. Additionally, the 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 60 DAYS FROM DATE OF PUBLICATION IN THE FEDERAL 

REGISTER].

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 IN THE FEDERAL 

REGISTER]. If no one requests to speak at the public hearing by 

[INSERT DATE 10 DAYS FROM DATE OF PUBLICATION IN THE FEDERAL 

REGISTER], 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 
Page 4 of 360

submitting comments.

• Email: Comments may be sent by email to a-and-rDocket@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.
Page 5 of 360

Instructions: Direct your comments to Docket ID No. EPA-HQ-OAR2002-0058. The EPA’s policy is that all comments received will 

be 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 the 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 the 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

the EPA cannot read your comment due to technical difficulties 

and cannot contact you for clarification, the 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 
Page 6 of 360

of any defects or viruses. For additional information about 

EPA’s 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:
Page 7 of 360

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 the 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

M. Other Issues Open for Comment

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?
Page 8 of 360

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

325 Chemical manufacturers
Page 9 of 360

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 

for the entity or your EPA regional representative, as listed in 

40 CFR 63.13 of subpart A (General Provisions).
Page 10 of 360

B. What should I consider as I prepare my comments to the 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 the 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.

If you have any questions about CBI or the procedures for 

claiming CBI, please consult the person identified in the FOR 
Page 11 of 360

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, the 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 stated in a separate notice that it planned 

to initiate a reconsideration of several provisions of the final 

rule. This reconsideration notice identified several provisions 
Page 12 of 360

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 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, the EPA issued a notice to postpone the 

effective dates of the March 21, 2011, final rule. This notice 

also requested that the public submit additional data and 

information to the EPA by July 15, 2011, for review and 
Page 13 of 360

consideration in the reconsideration proceedings. Following 

promulgation of the final rule, the 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 

Company. Copies of these petitions are provided in the docket 
Page 14 of 360

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

to CAA section 307(d)(7)(B), requested that the 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. The issues 

upon which the EPA is soliciting comment are discussed in 

section V of this preamble.

III. Summary of This Proposed Rule

This section summarizes the requirements of this action. Some 

of the requirements are currently found in the final boilers 

rule and are not being proposed to be revised. Section IV below 

provides a summary of the significant changes the EPA is 

proposing to make in its reconsideration of the final rule, and 

on which EPA is soliciting public comment.

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 
Page 15 of 360

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?

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 
Page 16 of 360

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 

proposed for new and existing sources in each of 14

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

HCl 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 this proposed 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 this preamble and in this proposed rule), and your 

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

this 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 
Page 17 of 360

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, 

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 

 

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).
Page 18 of 360

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

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 
Page 19 of 360

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)

Subcategory Filterable 

Particulat

e Matter 

(Filterabl

e PM) (or 

total 

selected 

metals) 

(lb per 

MMBtu of 

heat 

input)a

Hydroge

n 

Chlorid

e (HCl) 

(lb per 

MMBtu 

of heat 

input)a

Mercury

(Hg) 

(lb per 

MMBtu 

of heat 

input)a

Carbon 

Monoxide

(CO)

(ppm @3% 

oxygen)a

Alterna

te CO 

CEMS 

limit,

(ppm 

@3% 

oxygen)b

Existing –

Solid fuel

NA 0.022 3.1E-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 790 410

Existing –

Biomass

Kiln-Dried

Stoker/Slop

0.32 

(0.004)

NA NA 250 ND
Page 20 of 360

ed 

Grate/Other 

Existing -

Biomass 

Fluidized 

Bed 

0.11 

(0.0012)

NA NA 370 180

Existing –

Biomass 

Suspension 

Burner

0.051 

(0.0011)

NA NA 58 1,400

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 1,500 ND

Existing –

Biomass 

Hybrid 

Suspension 

Grate

0.44 

(4.9E-04)

NA NA 3,900 730

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 60d

Existing –

nonContinental 

Liquid

0.0080

c NA NA 18 91e

Existing –

Gas 2 

(Other 

Process 

0.0067 

(2.4E-04)

0.0017 7.9E-06 4 ND
Page 21 of 360

Gases)

New – Solid 

Fuel

NA 0.022 8.6E-07 NA NA

New –Coal 

Stoker 

0.028 

(2.2E-05)

NA NA 19 34

New - Coal 

Fluidized 

Bed

0.0011 

(1.7E-05)

NA NA 17 59

New – CoalBurning 

Pulverized 

Coal

0.0013 

(2.8E-05)

NA NA 9 28

New –

Biomass Wet 

Stoker/Slop

ed 

Grate/Other 

0.029

(2.6E-05)

NA NA 590 410

New –

Biomass 

Kiln-Dried

Stoker/Slop

ed 

Grate/Other 

0.32 

(0.0040)

NA NA 250 ND

New -

Biomass 

Fluidized 

Bed 

0.0098 

(4.2E-05)

NA NA 230 180

New –

Biomass 

Suspension 

Burner

0.051 

(0.0011)

NA NA 58 1,400

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 ND
Page 22 of 360

New –

Biomass 

Hybrid 

Suspension 

Grate

0.026 

(4.9E-04)

NA NA 1,500 730

New –

Liquid

NA 0.0012 4.9E-07 NA NA

New – Heavy 

Liquid

0.013c NA NA 10 18

New – Light 

Liquid

0.0011

c NA NA 3 60d

New – NonContinental 

Liquid

0.0080

c NA NA 18 91e

New – Gas 2 

(Other 

Process 

Gases)

0.0067 

(2.4E-04)

0.0017 7.9E-06 4 ND

NA-Not applicable; ND-No data available

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 1-day block average.

e 3-hour rolling average.

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), the final rule requires a work practice standard for the 

following particular classes of boilers and process heaters: new 
Page 23 of 360

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 

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 final rule includes a 

beyond-the-floor 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? We are not proposing to change the malfunction 

provisions in this rule. See 76 FR 15613. We are proposing 

revised work practice standards for periods of startup and 

shutdown. The final rule required that an owner/operator must 

“Minimize the unit’s startup and shutdown periods following the 

manufacturer’s recommended procedures. If manufacturer’s 

recommended procedures are not available, you must follow 
Page 24 of 360

recommended procedures for a unit of similar design for which 

manufacturer’s recommended procedures are available.”

While we are maintaining a work practice approach for 

startup and shutdown, we are proposing to change the work 

practice standards to better reflect the maximum achievable 

control technology. First, we are proposing definitions of 

startup and shutdown. We are proposing to define startup as the 

period between the state of no combustion in the unit to the 

period where the unit first achieves 25 percent load (i.e., a 

cold start). We are proposing to define shutdown as the period 

that begins when a unit last operates at 25 percent load and 

ending with a state of no fuel combustion in the unit. For 

periods of startup and shutdown, we are proposing the following 

work practice standard: you must employ good combustion 

practices and demonstrate that good combustion practices are 

maintained by monitoring O2 concentrations and optimizing those 

concentrations as specified by the boiler manufacturer; you must 

ensure that boiler operators are trained in startup and shutdown 

procedures, including maintenance and cleaning, safety, control 

device startup, and procedures to minimize emissions; and you 

must maintain records during periods of startup and shutdown and 

include in your compliance reports the O2 conditions/data for 

each startup event, length of startup/shutdown and reason for 
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the startup/shutdown (i.e., normal/routine, problem/malfunction, 

outage). You must comply with all applicable emissions limits at 

all times except for startup and shutdown periods, during which 

times you must comply with these work practices.

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 

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).
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(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 continuous emission monitoring 

systems (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 

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

you must measure pressure drop across the scrubber 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.

(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 
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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., continuous 

opacity monitoring systems (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 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.
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(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. 

(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 
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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 the EPA, as appropriate, 

documentation 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,
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(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 the 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. 

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 the EPA, as 

appropriate, documentation that an energy assessment was 

performed by a qualified energy assessor and documentation of
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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).

(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 
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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, milligrams 

per actual cubic meter, or other instrument output) during all 

other operating hours where 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 
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transmit four reports per year for each PM CPMS to the EPA’s 

WebFIRE database by using the Compliance and Emissions Data 

Reporting Interface, or 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 

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 
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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 

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 
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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.

(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 
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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.

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.
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Records of either continuously monitored parameter data for 

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

continuous monitoring systems (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.

(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 
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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.

(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 

analyses, opacity observations, performance evaluations, or 
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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.

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

The EPA must have performance test data to conduct 

effective reviews of CAA sections 112 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.

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 
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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 

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 
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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).

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 
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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 

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 3 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 
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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.

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 Section V of this action. 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 
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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 TSM

as an alternative to the PM limits in the final rule,

particularly for biomass units, as part of the reconsideration.

After assessing the available data, the EPA determined that 

inclusion of these limits is appropriate for some subcategories, 

and the 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, which directly quantifies the HAP 

metals rather than relying on a surrogate, is a more direct 

measurement of HAP than PM and is, therefore, 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 eight metals, rather than all 

of the HAP metals other than Hg, 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 selection of controls to 
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meet the standards, and the controls that would be used to 

reduce emissions of the eight metals would be equally effective 

in reducing emissions of the other two metals. Therefore, TSM

can serve as a surrogate for all metallic HAP except for Hg, 

which the final rule regulates separately.

For the light liquid, heavy liquid and non-continental 

liquid units subcategories, we are not proposing alternative TSM 

emission limits. Instead, we are proposing that these units meet 

the filterable PM emission limits in all instances. We are not 

proposing the TSM alternative because of the limited emission 

test data for TSM and the large variability in the TSM data for 

these subcategories. Using the EPA’s maximum achievable control 

technology (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 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. If the EPA receives sufficient 

information that supports the alternative TSM standards for 
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units designed to combust liquid fuels, we will consider 

adopting these limits in the final rule.

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 method detection level (a level at which 

the pollutant is known to be present but is not accurately 

quantified) is about 55 percent, which is 10 percent lower than 

the percentage for electric utilities. However, in addition to 

the high percentage of measurements below the method detection 

level, a very high percentage of measurements are below the 

level that can be accurately measured (see section V.E.3 of this 
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preamble) for each subcategory. Those percentage are as follows: 

coal stoker-100 percent; coal fluidized bed-89 percent;

pulverized 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 liquid96 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. Based on the percentages 

of data below the method detection limit coupled with the 

percentage of data below the level that can be accurately 

quantified, the EPA concludes that emissions from industrial 

boilers and process heaters cannot practicably be measured, and

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 
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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 at or near current detection level capabilities, and we are 

not aware of any emissions controls that are demonstrated to 

reduce dioxin emissions from the low levels indicated by the 

available data for boilers and process heaters.

B. Output-Based Standards

1. Revisions to Boiler Efficiency Analysis. Petitioners 

requested that the EPA reassess the calculation of boiler 

efficiency, which is the key calculation in the development of 

output-based standards, because the 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 the EPA had 

disregarded feedwater temperature (industry average being 280 

degrees F). The inclusion of feedwater temperature provides the 

correct assessment of boiler efficiency because it accounts for 

the heat energy that is supplied by steam from the boiler to 

heat the feedwater. The steam used to heat the feedwater is 

supplied by the boiler and was reported by facilities as part of 

the boiler “steam output,” but was not accounted for in the 

final rule efficiency calculations. Thus, the EPA has modified
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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 

to the EPA’s information gathering efforts. For all best 

performing units reporting this steam energy output data, we

calculated boiler efficiencies, as well as corresponding inputto-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 proposed 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
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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. Averaging of output based 

limits was not included in the final rule due to time 

constraints, but there is no technical reason why averaging of 

output-based limits is inappropriate. The output-based limits 

are equivalent to the input-based limits and promote energy 

efficiency, and, therefore, EPA is proposing to allow averaging 

for units that elect to comply with the output-based standards.

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, the 

EPA is proposing to add language to the definition of “Steam 

output” that addresses boilers that only produce electricity.

The language provides fuel-specific conversion factors for 

electricity generating units that result in output-based 

standards in units of pounds per megawatt-hour.

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 
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to the input-based standards. The EPA is proposing regulatory 

text to make 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 

consistent with the CAA as promulgated. Therefore, no changes 

are being proposed. However, we are specifically requesting 

comment on: (1) the overall concept of the emission credit 

provision, (2) how to administer it consistently across the 

country, and (3) available guidelines to inform the delegated 

authority's decision to approve the implementation plan.

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 specification, and EPA is 

now soliciting comments on these portions of the final rule, 
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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 the 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-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 
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combustion-based pollutant. Differences in PM particle size, 

applicability of air-pollution 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 the EPA 

reconsider the liquid unit subcategories and include separate 

subcategories for units designed to combust light liquids and 

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. 
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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 Hg and HCl, 

which are the fuel-based pollutants. 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 

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 
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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, the EPA is now soliciting comments on the noncontinental 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 necessitate 

supplementing the available refinery gas. The petitioners 

requested that, in the absence of data from non-continental 

units, emission limits for non-continental units be based on 

data from liquid units that combust residual oil. The EPA agrees 
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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 non-continental 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 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 
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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 kiln-dried wood and for 

hybrid suspension grate boilers designed to 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.
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a. Boilers Designed to Combust Kiln-Dried Wood. With respect 

to a separate subcategory for boilers designed to combust kilndried 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 “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 
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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.

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 regarding the design and other differences 
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between dutch ovens and suspension boilers 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, the 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 the 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 the fuel 

specification on levels of contaminants in either natural gas or 

refinery gas. Petitioners further pointed out that a fuel 

specification for hydrogen sulfide (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 Hg and that the H2S fuel specification that 

was finalized does not provide a direct indication of potential 

HAP from combustion of gaseous fuel. Accordingly, the EPA is 

proposing a fuel specification based only on the Hg level in the 
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gaseous fuel, and that level is the same level that the EPA 

included in the March 2011 final rule. The rationale for the Hg

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 the fuel 

specification for Hg will have demonstrated that its fuel

contains an amount of Hg 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.
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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 the CAA. Therefore, the 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 
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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 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 
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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 units. The technical concerns 

include the fact that PM CEMS are calibrated and certified to 

measure emissions from a single fuel type. A change in fuel 

would require a change in the calibration curve of the PM CEMS 

instrument. The unpredictable variety of biomass fuel 

constituents as well as biomass fuel moisture content make 

relying on a single calibration point problematic in terms of 

compliance assessment when these fuel components change. 

Furthermore, it is impracticable to replicate, during 

performance testing, all of the varying fuel conditions 

necessary for calibrating the monitor. For all of these reasons, 

it is impractical to appropriately apply PM CEMS to provide the 

accuracy necessary for compliance assessment. Accordingly, we 

are proposing to remove the PM CEMS requirement for biomass 
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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 options in the proposed rule for the use of Hg CEMS. We

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

rule.
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4. Use of sulfur dioxide (SO2) CEMS for demonstrating 

continuous compliance with HCl emission limits. A petitioner 

requested that the 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 with the condition noted above.

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 

reasonable minimum data availability limitation allowing for CMS 

downtime. We have not included any specific minimum data 
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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. The final rule clarified 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 exceptions to CMS data 

collection that are already allowed in the rule. Given the 

existing regulatory requirements and the clarifications in this 
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rule about how to apply those requirements, we believe the rule 

provides allowances sufficient for CMS operational flexibility

and are therefore not proposing any revisions on this issue.

6. Averaging Times. The EPA has determined that a 30-day 

rolling average for parameter monitoring and demonstration of 

continuous compliance with operating limits is appropriate for 

this rule. This would be a change from the final rule, which 

generally included 12-hour block averages that corresponded to 

the expected length of the longest duration 3-run emission test 

that was required to demonstrate initial compliance with the 

emission limits. 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 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 
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variability, we believe it appropriate to propose 30-day 

averages in order to provide a means for the source operator to 

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 Hg 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, 

the EPA received fuel analyses for 3 facilities and over 51,000 

hours of CO CEMS data from 3 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).”
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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 

additional quality assurance. These test reports document the 

test results for the summary test data that were submitted to 

the EPA as part of the 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 
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paragraphs. We are soliciting comment on the procedures 

described below.

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 
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when in fact it is absent. Such a probability is also 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 test-specific 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.
Page 75 of 360

 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 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 
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detection levels as the 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 

upper prediction limit (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 procedure 
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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. In response to 

these requests, the EPA has calculated a CO CEMS-based MACT 
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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 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 
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to burn wet biomass fuel, suspension burners designed to burn 

biomass/bio-based 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/biobased solids, biomass dry stoker units, 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 light 

liquid fuel and 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 1-day 

block average basis for light liquid units and a 3-hour rolling

average basis for non-continental liquid units, as discussed 

below. If sufficient additional data are provided by March 1, 

2012, the EPA will consider adjusting the averaging times

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 Floor 

Analysis (October 2011) for the Industrial, Commercial, and 

Institutional Boilers and Process Heaters National Emission 
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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 ppmvd. 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 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 
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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 rank CO CEMS data based on each units minimum 10-day 

rolling average CO CEMS value and then determining the best 

performers for each subcategory. For the three subcategories 

where we have CEMS data for units that are part of the stack 

test-based MACT floors, we included the CEMS data from those 

units in the CEMS-based floors because those units are 

demonstrated best performers for CO. We discuss two exceptions

below, where the data did not allow the use of a 10-day 

averaging period. Within each subcategory, we ranked the minimum 

10-day rolling averages from lowest to highest to determine the 

best performing 12 percent. Then, we identified any best 

performers based on the CO stack test data that provided CO CEMS 

data, and we included those data in the MACT floor pool. 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 light liquid fuels, the data 

were insufficient to calculate 10-day rolling averages. Based on 

the available data, the averaging basis selected was 1 day. For 
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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 non-continental 

liquid units. Only one of the non-continental boilers submitted 

CO CEMS data, with a total of 24 hourly 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. The EPA also is 

requesting comment on the approach used to calculate the UPLbased MACT floors.

Ranking the dataset according to the minimum 10-day rolling 

average does not necessarily correlate with the ranking used to 
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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 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 units 

identified as best performers based on the CEMS data are 

comparable to the units identified as best performers based on 

the stack test data. 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 
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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 be higher than 

the existing source, so the value reverts to the existing source 

value.

The 99 percent UPL calculations for CO CEMS used the following 

statistical formula:

 

Where:

n = the number of daily averages (or hourly averages for noncontinental 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 
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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 (November 2011) for the Industrial, Commercial, and 

Institutional Boilers and Process Heaters National Emission 

Standards for Hazardous Air Pollutants – Major Source” for 

further details about the calculations.

For each subcategory the analysis showed that the datasets 

were lognormally distributed. Given the rolling-average 

compliance metric, many of the datasets also exhibit varying 

degrees of autocorrelation. Autocorrelation describes the 

correlation between values of the process at different points in 

time. Although the UPL calculation is affected by 

autocorrelation, no adjustments were made to incorporate 

autocorrelation in this dataset. Depending on the final 

compliance metric selected, EPA may adjust the dataset for the 

promulgated rule to better address autocorrelation. The EPA is 

requesting comment on incorporating autocorrelation into the 

analysis.

The EPA considered, but is not proposing, an additional 

final step for establishing the CO CEMS-based floors. When we 

compared the performance of the units in the top half of the 
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MACT floor pool (usually a single unit) to the UPL-based floor 

level, it was revealed that the calculated UPL-based floor level 

resulted in the best performing units in some subcategories not 

meeting the limit up to about 25 percent of the time. The 

following final step in the floor setting process for CEMS-based 

limits could be used to adjust the CO CEMS-based limits to 

reflect the level achieved at all times by the best performing 

sources (i.e., the top half of the MACT floor units). In those 

instances where the best 6 percent of units did not meet the 

calculated limit at all times, the limit was adjusted to reflect 

the actual level that was demonstrated to be achieved at all 

times by those units (the highest 10-day, 1-day, or 3-hour 

average, as applicable, from the best 6 percent of units). The 

CO CEMS-based emission limits based on this approach are shown 

in Table 2 of this preamble. The EPA is requesting comment on

whether this final step is appropriate for developing CO CEMSbased MACT floors for boilers and process heaters.

Table 2. Alternative Approach CO CEMS-Based Emission Limits for 

Boilers and Process Heaters

Subcategory Alternate CO CEMS limit,

(ppm @3% oxygen)

New and Existing – Coal Stoker 34

New and Existing - Coal Fluidized 

Bed

78

New and Existing – Coal-Burning 

Pulverized Coal

35
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New and Existing – Biomass Wet 

Stoker/Sloped Grate/Other 

920

New and Existing – Biomass KilnDried Stoker/Sloped Grate/Other No Data

New and Existing - Biomass 

Fluidized Bed 

480

New and Existing – Biomass 

Suspension Burner

2,300

New and Existing – Biomass Dutch 

Ovens/Pile Burners

440

New and Existing – Biomass Fuel 

Cells

No Data

New and Existing – Biomass Hybrid 

Suspension Grate

1,400

New and Existing – Heavy Liquid 18

New and Existing – Light Liquid 60

New and Existing – non-Continental 

Liquid

120

New and Existing – Gas 2 (Other 

Process Gases)

No Data

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 reassessed 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 
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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 

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 non-continental liquid units. 
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Additional data were submitted to EPA for PM and CO from noncontinental 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, and we therefore 

are proposing Hg and HCl emission limits that are based on the 

available data for all liquid units. The EPA requests comment on 

this approach, and to the extent that other approaches are 

suggested, the EPA requests data and rationale to support any 

suggested alternative approaches.

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

the 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 
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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 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 the 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. 
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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 liquid-fired 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 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. 
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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.

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, the EPA is proposing that the initial tuneup after startup must be completed within one year of startup.

H. Energy Assessment
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1. Scope. Petitioners requested that the 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 

the energy assessment include energy use systems located offsite. We are proposing to revise the definition of “Energy 

assessment” to clarify our intent.

2. Compliance Date. Petitioners requested that the 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

the EPA reconsider the stated “maximum time” to conduct the 

energy assessment because the maximum times were not included in 
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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 

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 1 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
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1. 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 proposing to amend the work practice 

standard so that manufacturers’ recommended procedures are no 

longer referenced, although the EPA expects that facilities will 

follow such procedures for both the boiler system and any air 

pollution control devices. The EPA is proposing to amend the 

work practice standard as described in section III.E of this 

preamble. The rationale for justifying work practice standards 

for periods of startup and shutdown is described in the preamble 

to the final rule. See 76 FR 15642. Additionally, we do not have 

emissions data for startup and shutdown periods sufficient to 

establish numeric emissions standards for these periods. The 

only available data is limited CO emissions data, which is 

unlikely to reflect actual emissions of the best performing 

units during startup and shutdown. The rationale for the 

proposed changes to the work practice standard is discussed 

below. The EPA is now proposing to define startup and shutdown 

periods and is proposing more specific requirements than those 

in the final rule. The definitions of startup and shutdown would 
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provide clarity regarding which periods of operation are subject 

to the work practice standards rather than numeric emission 

limits and the associated requirements. The proposed definitions 

specify that only the periods of time between a complete 

shutdown of a unit (no fuel being combusted) and the time that a 

unit first reaches 25 percent load qualify as startup, and only 

the periods of time between the time that a unit last reaches 25 

percent load and the time when a unit is completely shut down 

(no fuel being combusted) qualify as shutdown. These definitions 

are intended to ensure that units cannot cycle in and out of 

startup or shutdown. The EPA recognizes that it may be necessary 

to establish a maximum time period to ensure that units cannot 

operate in startup or shutdown mode for extended periods of 

time, and is soliciting comment on the appropriate time period 

or time periods for the various unit designs. The EPA believes 

that a work practice standard that applies during such periods 

should require more than a general duty to reduce emissions, 

which is essentially what was required in the final rule. 

General duty requirements do not constitute appropriate work 

practice standards under section 112(h). We are soliciting 

comment on the rationale for work practice standards during 

periods of startup and shutdown as well as the proposed work 

practice standard and the rationale for proposing changes to the 
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standard. We also are soliciting comment on whether other work 

practices should be required during startup and shutdown, 

including requirements to operate using specific fuels to reduce 

emissions during such periods. Because the EPA did not propose 

work practice standards for startup and shutdown periods in the 

June 4, 2010, proposed rule, members of the public did not have 

the opportunity to comment on those standards or the rationale 

for the standards prior to issuance of the final rule.

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.

K. Applicability

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

final rule, the 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 

another subpart. Petitioners requested that EPA extend the 

exemption to units that serve as control devices for EPA 
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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, the 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.

2. Waste Heat Boilers and Process Heaters. Petitioners 

requested that the EPA clarify that waste heat process heaters, 

like waste heat boilers, are not subject to the standards. 

Petitioners are correct that the EPA intended to exempt waste 
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heat process heaters from the rule, and the 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

the 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 EEE), which 

includes boilers and process heaters that burn RCRA hazardous 

waste. Therefore, boilers and process heaters burning comparable 
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fuels are covered by the NESHAP for industrial, commercial, and 

institutional boilers and process heaters.

4. Residential Unit Exemption. During the initial phases of 

implementation of the area source boiler rule, stakeholders 

requested clarification from the 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, the 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., university campus, military base, church

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

L. Compliance
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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 this 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 

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 
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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 the EPA 

announced the reconsideration and postponed the effective date, 

it indicated 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 the EPA has now determined can be accurately measured 

using the 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 
Page 103 of 360

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. 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 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, 3 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 
Page 104 of 360

essentially provide less than 2 years for sources to meet the 

final standards, whose stringency will not be determined until 

the reconsideration is final. For all of the reasons discussed 

above, the EPA is proposing that the compliance date for 

existing sources is three years after the date of publication of 

the final reconsideration rule. The EPA is requesting comment on 

the proposed changes to the compliance dates.

2. Reduced Testing Frequency and Detection Levels. In the 

final rule, the 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 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 
Page 105 of 360

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 the 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 the 

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.

M. Other Issues Open for Comment

1. Stakeholders asked the EPA to consider, for units that are 

retrofitted to switch to natural gas as a compliance option, 

allowing those units to average emissions with units of the 

original unit design. These parties suggested that continuing to 

allow such averaging would be consistent with EPA’s general 

approach of specifying emission standards for affected

facilities, but otherwise allowing the facilities to comply 

however they see fit. They also pointed out that this may allow 

for more effective controls overall. For example, they suggested 
Page 106 of 360

that without allowing for averaging of units that switch to 

cleaner fuels as a compliance option, natural gas conversion is 

a less attractive option than if such averaging was allowed, 

because a facility would not have the ability to offset 

emissions using that unit. In this case, these stakeholders 

believe that installing controls that result in fewer emissions 

reductions than switching to natural gas may be a perverse 

outcome. They suggested that continuing to allow averaging 

across subcategories in cases where fuel switching has been used 

to achieve compliance would instead encourage fuel switching to 

cleaner fuels, which is environmentally beneficial. The EPA is 

requesting comment on the potential benefit of this suggested

approach, and how such an approach could be justified and 

incorporated into the rule.

2. Stakeholders requested that EPA consider creating a subcategory 

for units that are installed and used in place of flares that 

are currently used to combust process gases. The EPA is 

requesting comment on how such a subcategory could be justified 

and incorporated into the rule. The stakeholders also suggested 

that it would be appropriate to assume that the emissions from 

process gases diverted from flares to boilers have “zero 

emissions” for the purposes of classifying the boiler they are 

combusted in. Since the process gases must be combusted in 
Page 107 of 360

either event, they requested that the EPA develop an approach 

where we use a concept similar to the emissions averaging 

provisions, for example, to simply assume that combustion of 

such process gases in a boiler rather than a flare should not be 

counted as emissions from the boiler because there is no net 

increase in emissions. The EPA requests comment on how such an

approach could be justified and incorporated into the rule.

VI. Technical Corrections and Clarifications

We are proposing several technical corrections. These amendments 

are being proposed to correct inaccuracies and 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 3

of this preamble. We request comment on all of these proposed 

changes.

Table 3. Miscellaneous Proposed Technical Corrections to 40 CFR 

Part 63, Subpart DDDDD

Section of subpart DDDDD Description of Proposed correction

40 CFR 63.7491(m) Clarify the language in this 

paragraph to use the word “unit” 

instead of “boiler.”

40 CFR 63.7495(b) Revise this paragraph to include a 

provision in §63.6(i)

40 CFR 63.7499 (f)-(s) Revise and add new paragraphs to 

accommodate the addition of new 

subcategories of boilers and 

process heaters.

40 CFR 63.7499(d) Revise the term “stokers” to 
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“stokers/sloped grate/other units” 

consistent with how the data for 

this rule was analyzed. 

40 CFR 63.7500(d) Revise 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) Revise terms in this paragraph to 

correct spelling errors.

40 CFR 63.7505(c) Revise this paragraph by removing 

the reference to Table 12; this 

table is not included because this 

is a proposed rule.

40 CFR 63.7510(a) Revise this paragraph to create 

four subparagraphs (1)-(4) to 

clarify our intent on fuel 

analysis requirements for gaseous 

fuels.

40 CFR 63.7510(b) Revise this paragraph to clarify 

that certain fuels are not subject 

to the fuel analysis requirements 

and that units using a continuous 

emission monitoring system for 

mercury or hydrogen chloride are 

exempt from the performance 

testing and operating limit 

requirements.

40 CFR 63.7510(c) Revise this paragraph to clarify 

that units using a continuous 

emission monitoring system for 

carbon monoxide are exempt from 

the performance testing and 

operating limit requirements.

40 CFR 63.7510(d) Revise this paragraph to clarify 

that owners and operators electing 

to comply with the alternative 

total selected metals limit are 

not required to install a PM CPMS.

40 CFR 63.7510(g) and (h) Insert a new paragraph (g) and 

renumber (g) to (h). Paragraph 

(g) will clarify the compliance 
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provisions for new sources with 

respect to the work practice and 

tune-up provisions

40 CFR 63.7510(f),

63.7515(f), and 63.7520(d)

Revise these paragraphs by 

removing the references to Table 

12; this table is not included 

because this is a proposed rule.

40 CFR 63.7521(a) Revise this paragraph to clarify 

that fuel analysis cannot be used 

with gaseous fuels to demonstrate 

compliance with the limits for 

total selected metals or hydrogen 

chloride given method limitations. 

We are also proposing to revise 

this paragraph to clarify that a 

fuel gas system consisting of 

multiple gaseous fuels collected 

and mixed with each other is 

considered a single fuel type and 

sampling and analysis is only 

required of the combined fuel gas 

system.

40 CFR 63.7521(b) Revise this paragraph to clarify 

that the fuel monitoring plan is 

needed only if you are required to 

conduct fuel analyses.

40 CFR 63.7521(b)(1) Revise this paragraph to add a 

cross reference to the section 

describing the initial compliance 

demonstration.

40 CFR 63.7521(b)(2)(ii) 

through (iv)

Revise the subparagraphs to 

clarify that the requirements 

apply to each anticipated fuel 

type.

40 CFR 63.7521(c)(1)(ii) Revise this paragraph by changing 

wording from “1-hour” to “onehour”.

Clarify the different sampling 

circumstances for performance 

stack testing and monthly 

sampling.

40 CFR 63.7521(c)(2)(ii) and Revise this paragraph by 
Page 110 of 360

63.7521(d)(2) clarifying wording describing 

sampling requirements to provide 

more flexibility for automated 

sampling and reduce overly 

prescriptive language.

40 CFR 63.7521(e) Reference equations 7, 8, and 9 

within this paragraph to add 

clarity.

40 CFR 63.7521(f) Add three sub-paragraphs to this 

paragraph to organize exemptions 

from fuel specification analyses.

40 CFR 63.7521(g)(1) Revise this paragraph to add a 

cross reference to the section 

describing the initial compliance 

demonstration.

40 CFR 63.7521(g)(2)(ii) 

through (iv)

Revise the subparagraphs to 

clarify that the requirements 

apply to each anticipated fuel 

type.

40 CFR 63.7522(b) Revise this paragraph to add 

several subparagraphs to clarify 

that emissions averaging may not 

include units using CEMS or PM 

CPMS; that averaging may only be 

within units in a subcategory 

subject to the same numerical 

emission limit; and that emissions 

averaging is not allowed for 

certain subcategories of units for 

certain emission limits.

40 CFR 63.7522(e)(2) Add the units for emission limits 

to add clarity (pounds per million 

Btu).

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) Remove a reference to Table 12; 

this table is not included because 

this is a proposed rule.

40 CFR 63.7525(b)(3) Change language from 

“concentrations” to “rates” to 
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provide clarity.

40 CFR 63.7525(b)(5) Revise this paragraph by changing 

wording from “1-hour” to “onehour”.

40 CFR 63.7525(d)(3) 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) Change from the 12-hour block 

average to 30-day rolling average 

as specified in the revised Table 

8 to subpart DDDDD.

40 CFR 63.7530(b) Revise this paragraph to clarify 

which fuels are exempt from 

analysis by cross-referencing 40 

CFR 63.7510(a)(2), instead of 

repeating the information in that 

paragraph.

40 CFR 63.7530(b)(4)

[formerly (b)(3)]

Revise this paragraph to: 1. 

Clarify that you are not required 

to establish and comply with the 

operating parameter limits when 

you are using a CEMS to monitor 

and demonstrate compliance with 

the applicable emission limit.

2. Clarify in the subparagraphs 

which parameters are applicable to 

specific types of control devices.

3. Add a new subparagraph to 

address PM controls used in 

conjunction with a PM CPMS. 

4. Add a new paragraph to address 

particulate wet scrubbers as 

distinct from acid-gas wet 

scrubbers.

40 CFR 63.7530(c)(2) Revise the references to Equation 

9 to be Equation 10, to 

accommodate the change in 

numbering of equations.

40 CFR 63.7530(c)(3) Revise the references to Equation 

9 to be Equation 10, to 

accommodate the change in 
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numbering of equations.

40 CFR 63.7530(c)(4) Revise the references to Equation 

9 to be Equation 10, to 

accommodate the change in 

numbering of equations.

40 CFR 63.7530(h) Remove a reference to Table 12; 

this table is not included because 

this is a proposed rule.

40 CFR 63.7533(b)(2) 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), 

(c)(1)(i), and (c)(3)

Amend these paragraphs to change 

the date after which energy 

conservation measures can be used 

to generate credits from January 

14, 2011, to January 1, 2008. 

January 1, 2008 is the same cutoff date for using a pre-existing 

energy assessment to satisfy the 

energy assessment requirement in 

Table 3 to subpart DDDDD.

40 CFR 63.7533(c)(2)(i) and 

(c)(3)

Revise the reference to Equation 

12 to Equation 14, to accommodate 

the change in numbering of 

equations.

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

(f)

Revise the names and definitions 

of the terms in Equations 12 and 

13 to be consistent. 

40 CFR 63.7533(c)(f) Revise the paragraph to remove the 

reference to (f)(1) and (2) 

because there is no paragraph (2) 
Page 113 of 360

and only a single paragraph is 

needed.

Change the reference to Equation 

13 to Equation 15, to accommodate 

the change in numbering of 

equations.

40 CFR 63.7535 Revise the title of this section

to add clarity.

40 CFR 63.7535(b) Add language to the paragraph to 

clarify that you must operate 

monitoring systems while the unit 

is operating and compliance is 

required. Add “scheduled CMS 

maintenance” to the list of 

periods during which you are not 

required to collect data from a 

monitoring system. 

40 CFR 63.7535(c) Amend this paragraph to clarify 

that operators must record results 

of CMS performance audits, dates 

and duration of periods when the 

CMS is out of control to 

completion of the corrective 

actions necessary to return the 

CMS to normal operation. Also 

adding language to clarify that 

all collected data must be used to 

assess compliance.

40 CFR 63.7535(d) Revise the paragraph to remove 

references to “out-of-control 

periods” and to add “system 

accuracy audits” to the list of 

periods during which data do not 

need to be collected.

40 CFR 63.7540(a) Add references to Tables 1, 2, 3, 

and 4 to add clarity.

40 CFR 63.7540(a)(2) Split this paragraph into two 

subparagraphs for clarity.

40 CFR 63.7540(a)(3) Revise the paragraph to clarify 

that fuel analysis for hydrogen 

chloride is applicable for only 

solid and liquid fuels, and to 
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clarify that certain fuels are not 

subject to the fuel analysis 

requirements.

40 CFR 63.7540(a)(3) and 

(a)(3)(iii)

Change the references to Equation 

9 to Equation 11 to accommodate 

the change in numbering of 

equations. 

40 CFR 63.7540(a)(4), 

(a)(5), and (a)(6)

Revise these paragraphs to clarify 

that certain fuels are not subject 

to the fuel analysis requirements.

40 CFR 63.7540(a)(5) and 

(a)(5)(iii)

Change the reference to Equation 

11 to Equation 12 to accommodate 

the change in numbering of 

equations.

40 CFR 63.7540(a)(9) Revise this paragraph and the 

subparagraphs to remove the 

references to the EPA performance 

specifications for a PM CEMS, and 

replace them a reference to the PM 

CPMS provisions in the facility’s 

site-specific monitoring plan 

required by 40 CFR 63.7505.

40 CFR 63.7540(a)(10)(i) and 

(a)(12)

Revise this paragraph to specify 

that required burner inspections 

be done at the next burner 

shutdown, whether it is scheduled 

or unscheduled.

40 CFR 63.7541 (a)(3) and 

(4)

Change the 3-hour parameter 

averages to 30-day rolling 

parameter averages to match Table 

8 to subpart DDDDD.

40 CFR 63.7545(e)(3) Remove a reference to Table 12 

(this table is not included 

because this is a proposed rule), 

and adding language to clarify 

that this applies to facilities 

“not using a CO CEMS to 

demonstrate compliance.”

40 CFR 63.7545(f) 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) Change the reference to Equation 
Page 115 of 360

10 to Equation 11, to accommodate 

the change in numbering of 

equations.

40 CFR 63.7550(h), (i), and 

(j)

Revise paragraph (h) and adding 

paragraphs (i) and (j) to provide 

additional instruction on 

submitting data to EPA from 

performance emission tests, CEMS 

performance evaluations, and 

quarterly data from CEMS and CPMS 

consistent with the proposed 

monitoring requirements.

40 CFR 63.7555(d) Remove a reference to Table 12; 

this table is not included because 

this is a proposed rule.

40 CFR 63.7555(d)(2) Correct an inaccurate reference to 

40 CFR 241.3(b)(1)and (2), and to 

add a sentence to clarify that 

certain units exempt from the 

incinerator standards under 

section 129(g)(1) of the Clean Air 

Act do not need to maintain the 

records described in this 

paragraph. 

40 CFR 63.7555(d)(4) Change the reference to Equation 

10 to Equation 11, to accommodate 

the change in numbering of 

equations.

40 CFR 63.7555(d)(5) Change the reference to Equation 

11 to Equation 12, to accommodate 

the change in numbering of 

equations.

40 CFR 63.7555(h) Revise the paragraph to include 

units that burn “gaseous fuel 

subject to another subpart of this 

part” to add clarity.

40 CFR 63.7575 Revise the definition of process 

heater to include units heating 

hot water as a process heat 

transfer medium.

Edit the definition of each solid 

fuel combustor design-based 
Page 116 of 360

subcategory to establish a 

hierarchy and assisted affected 

sources by clarifying 

applicability for units with 

multiple combustor types. 

Revise the definition of “dutch 

oven” to clarify that fluidized 

bed boilers are not part of the 

dutch oven design category.

Revise the definition of “energy 

assessment” to clarify the length 

days for each category of 

facilities.

Revise the definition of 

“equivalent” to remove references 

to hydrogen sulfide.

Revise the definition of 

“fluidized bed boiler” to clarify 

that pulverized coal boilers are 

not included.

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 asfired basis” and “Fluidized bed, 

dutch oven, and pile burner 

designs are not part of the hybrid 

suspension grate boiler design 

category.”

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.”

Revise the definition of “liquid 

fuel” to include vegetable oil.
Page 117 of 360

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.

Revise the definition of “steam 

output” to include a description 

of the total energy output for a 

boiler that generates only 

electricity.

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.”

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 units are 

not part of the suspension burner 

subcategory.”

Revise the definition of “waste 

heat boiler” to clarify that the 

definition includes fired and 

unfired waste heat boilers.

Revise the definition of “waste 

heat process heater to clarify 

that the definition includes fired 

and unfired waste heat process 

heaters.

Add new definitions of “30-day 

rolling average”, “average annual 

heat input rate”, “biodiesel”, 
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“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 

kiln dried 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”.

Remove the definition of “liquid 

fuel subcategory.”

Tables 1 and 2 to subpart 

DDDDD

Revise the sampling volumes 

collected and also the prescribed 

span values associated with the 

emission measurement methods to 

account for changes in the 

numerical emission limits and to 

be consistent with the proposed 

emission limits.

Table 3 to subpart DDDDD Revise items 1, 2, and 3 to 

account for the proposed changes 

in the tune-up requirements.

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.”

Revise item 5 to remove the

reference to Table 12; this table 

is not included because this is a 

proposed rule.

Table 4 to subpart DDDDD Revise the operating limits for 

items 1 and 2 to read “one-hour” 

instead of “1-hour”.
Page 119 of 360

Revise certain items in the table 

to clarify the applicability of 

the parameter operating limits, 

and to reflect that replace PM 

CEMS with PM CPMS requirements.

Revise items 1, 2, and 4 in the 

table to reflect the fact that we 

are proposing that compliance with 

the operating limits is based on a 

30-day rolling average.

Table 6 to subpart DDDDD Revise items 1, 2, and 3 to 

provide additional instruction on 

demonstrating compliance.

Revise item 4 to replace the 

requirements for hydrogen sulfide 

in other gas 1 fuels with 

requirements for total selected 

metals in solid fuels. 

Table 7 to subpart DDDDD Revise item 1 to include total 

selected metals with PM and 

mercury, and to clarify the 

applicability of the operating 

limits described in that item.

Table 8 to subpart DDDDD Include provisions for 

demonstrating continuous 

compliance with a PM CPMS, to 

reflect proposed changes elsewhere 

in the rule.

Revise various items to reflect 

the proposed change from 12-hour 

block averages to 30-day rolling 

averages for demonstrating 

compliance.

Revise the operating load 

compliance provisions to be 

consistent with the operating 

limit in Table 4 to subpart DDDDD.

Table 11 to subpart DDDDD Delete Table 11 to subpart DDDDD 

to be consistent with the proposal 

to remove the numerical emission 
Page 120 of 360

limits for dioxin/furan emissions.

Table 12 to subpart DDDDD Remove Table 12 to subpart DDDDD 

because this is a proposed rule 

and Table 12 was needed only 

because the rule published on 

March 21, 2011 (76 FR 15608) was a 

final rule.

VII. Impacts of this Proposed Rule

A. What are the air impacts?

Table 4 of this preamble illustrates, for each basic fuel 

subcategory, the emissions reductions achieved by the proposed 

rule (i.e., the difference in emissions between a boiler or 

process heater controlled to the floor level of control and 

boilers or process heaters at the current baseline) for new and 

existing sources. Nationwide emissions of selected HAP (i.e., 

HCl, HF, Hg, metals, and volatile organic compound (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 Hg 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, 
Page 121 of 360

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.

Table 4. 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
Page 122 of 360

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 Hg 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, Commercial, 

Institutional Boilers and Process Heaters National Emission 

Standards for Hazardous Air Pollutants – Major Source" for a 

description of the two methods for estimating Hg 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.
Page 123 of 360

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 Hg 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.

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 
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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. The 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 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 
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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 Hg control; electrostatic 

precipitators for units meeting Hg 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 

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 Hg 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 
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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 5

of this preamble shows the capital and annual cost impacts for 

each subcategory. Costs include testing and monitoring costs, 

but not recordkeeping and reporting costs.

Table 5. 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) 

11,911 77 0.9 (295)
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units

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

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.
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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?

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 agency’s 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 

increase in US trade deficit 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 
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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 

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. These estimated 

annual employment changes compared to the baseline employment,

and are for the time period for which the annualized cost 

applies (2015 to 2029).

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?
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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 HAP

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 Hg, and 2,200

tons of other metals. Please refer to the full description in 

the final Boiler RIA of the unquantified benefits as well as 

technical details of the analysis and its limitations and 

uncertainties. These monetized benefits are approximately 23

percent higher than the final rule benefits due to the increase 

in SO2 emission reductions associated with the additional units 

affected by the rule and the revised HCl limit. 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 6 of this preamble. A summary of the 

avoided health incidences is provided in Table 7 of this 

preamble.

Table 6. Summary of the Monetized Benefits Estimates for the 

Final Boiler MACT (millions of 2008$)1
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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

Total $27,000 to $67,000 $25,000 to $61,000

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 $5.8 to $75 million depending on the 

discount rate. These benefits reflect existing boilers and new 

boilers anticipated to come online by 2015.

Table 7. 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.
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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 nitrogen 

oxide (NOx), CO and SO2 and an increase in carbon dioxide (CO2)

emissions. Since NOx and SO2 are covered by capped emissions 

trading programs, these pollutants do not contribute disbenefits

from additional electricity demand. Additional CO2 emissions from 

increased electricity consumption are estimated to be 931,000

tons per year from existing units and 79,700 tons per year from 

new units. Energy disbenefits due to increased CO2 emissions 

range from $5.8 million to $75 million depending on the discount 

rate, and thus do not affect the rounded monetized benefits.

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

of the Clean Air Act

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,” 
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“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: 

polycyclic organic matter(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,” “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 Hg. 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 
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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 

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).
Page 135 of 360

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 

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, the 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 
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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 

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 OMB under the 
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Paperwork Reduction Act, 44 U.S.C. 3501 et seq. The Information 

Collection Request (ICR) document prepared by the 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 

authorized by section 114 of the CAA (42 U.S.C. 7414). All 

information submitted to the 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.
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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 

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 
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numbers for the 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, the 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 the EPA and OMB. See ADDRESSES

section at the beginning of this notice for where to submit 

comments to the EPA. Send comments to OMB at the Office of 

Information and Regulatory Affairs, Office of Management and 

Budget, 725 17th Street, NW, Washington, DC 20503, Attention: 

Desk Office for the 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 
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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.

3 The 

RFA also allows an agency to “consider a series of closely 

related rules as one rule for the purposes of sections” 603 

(initial regulatory flexibility analysis) and 604 (final 

regulatory flexibility analysis) in order to avoid “duplicative 

action.” 5 U.S.C. § 605(c). This proposed rule is closely 

related to the final major source rule, which the EPA signed on 

February 21, 2011. The EPA prepared initial regulatory 

flexibility analyses in connection with the major source rule.

Therefore, pursuant to § 605(c), the EPA is not required to 

complete an initial regulatory flexibility analysis for this 

rule.

The EPA has been concerned with potential small entity 

impacts since it began developing the major source rule. The EPA 

conducted outreach to small entities and, pursuant to § 609 of

RFA, convened a Small Business Advocacy Review Panel to obtain 

advice and recommendations from small entity representatives.

 

3

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 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 notfor-profit enterprise which is independently owned and operated and is not dominant in its field.
Page 141 of 360

Pursuant to the RFA, the EPA used the Panel’s report and 

prepared both an initial regulatory flexibility analysis and a 

final regulatory flexibility analysis in connection with the 

closely related major source rule. Convening an additional Panel

and preparing an additional initial regulatory flexibility 

analysis would be procedurally duplicative and is unnecessary 

given that the issues here are within the scope of those 

considered by the Panel. In addition, this reconsideration 

proposal would decrease capital and annualized costs on small 

entities by about 3 percent and 10 percent, respectively, 

relative to the closely related final rule. We invite comments 

on the aspects of the proposal outlined in section V of this 

preamble and their impacts on small entities.

D. Unfunded Mandates Reform Act

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 
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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 

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 
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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 HCl, 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 fine particulate matter (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 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
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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 

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.
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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 UMRA 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.

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)” and two 

memoranda that are included in the docket, entitled “Health 

Benefits for Boiler MACT Reconsideration Proposal” and 

“Regulatory Impact Results for the Reconsideration Proposal for 

National Emission Standards for Hazardous Air Pollutants for 

Industrial, Commercial, and Institutional Boilers and Process 

Heaters at Major Sources,” which update the RIA analyses. This 
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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 UMRA 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 from numerous 

individual companies, institutions, environmental groups, 

consultants and vendors, labor unions, and other interested 
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parties. We have added materials to the docket to document these 

meetings.

Consistent with section 205, the 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 

on the distribution of power and responsibilities among the 

various levels of government, as specified in Executive Order 
Page 148 of 360

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 the EPA and state 

and local governments, the 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

The EPA interprets Executive Order 13045 (62 FR 19885, 

April 23, 1997) as applying only to those regulatory actions 
Page 149 of 360

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 

that is now projected. Overall, the projected energy use 

increased slightly but would not change the analysis that was 
Page 150 of 360

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 the 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 the EPA to provide 

Congress, through OMB, explanations when the agency decides not 

use available and applicable voluntary consensus standards. The 

EPA is not proposing the use of any additional EPA test methods, 

and, therefore, the NTTAA discussion in the March 21, 2011, 

final rule is still valid. See 76 FR 15660-15662.

J. Executive Order 12898: Federal Actions to Address 

Environmental Justice in Minority Populations and Low-Income 

Populations
Page 151 of 360

Executive Order 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. 

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.
*** E.O. 12866 and 13563 Review – Draft – Do Not Cite, Quote, or 

Release During Review ***

National Emission Standards for Hazardous Air Pollutants for 

Major Sources: Industrial, Commercial, and Institutional Boilers 

and Process Heaters--Page 152 of 360

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.
Page 153 of 360

For the reasons cited in the preamble, title 40, chapter I, part 

63 of the Code of Federal Regulations is proposed to be amended

as follows:

PART 63--[AMENDED]

Subpart DDDDD--National Emission Standards for Hazardous Air 

Pollutants for Major Sources: Industrial, Commercial, and 

Institutional Boilers and Process Heaters

Sec.

What this Subpart Covers

§63.7480 What is the purpose of this subpart?

§63.7485 Am I subject to this subpart?

§63.7490 What is the affected source of this subpart?

§63.7491 Are any boilers or process heaters not subject to this 

subpart?

§63.7495 When do I have to comply with this subpart?

Emission Limitations and Work Practice Standards

§63.7499 What are the subcategories of boilers and process 

heaters?

§63.7500 What emission limitations, work practice standards, 

and operating limits must I meet?

§63.7501 How can I assert an affirmative defense if I exceed an 

emission limitations during a malfunction?

General Compliance Requirements

§63.7505 What are my general requirements for complying with 

this subpart?

Testing, Fuel Analyses, and Initial Compliance Requirements

§63.7510 What are my initial compliance requirements and by 

what date must I conduct them?

§63.7515 When must I conduct subsequent performance tests, fuel 

analyses, or tune-ups?

§63.7520 What stack tests and procedures must I use?

§63.7521 What fuel analyses, fuel specification, and procedures 

must I use?

§63.7522 Can I use emissions averaging to comply with this 

subpart?

§63.7525 What are my monitoring, installation, operation, and 

maintenance requirements?

§63.7530 How do I demonstrate initial compliance with the 

emission limitations, fuel specifications and work practice 

standards?
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§63.7533 Can I use emission credits earned from implementation 

of energy conservation measures to comply with this subpart?

Continuous Compliance Requirements

§63.7535 Is there a minimum amount of monitoring data I must 

obtain?

§63.7540 How do I demonstrate continuous compliance with the 

emission limitations, fuel specifications and work practice 

standards?

§63.7541 How do I demonstrate continuous compliance under the 

emissions averaging provision?

Notification, Reports, and Records

§63.7545 What notifications must I submit and when?

§63.7550 What reports must I submit and when?

§63.7555 What records must I keep?

§63.7560 In what form and how long must I keep my records?

Other Requirements and Information

§63.7565 What parts of the General Provisions apply to me?

§63.7570 Who implements and enforces this subpart?

§63.7575 What definitions apply to this subpart?

Tables to Subpart DDDDD of Part 63

Table 1 to Subpart DDDDD of Part 63—Emission Limits for New or 

Reconstructed Boilers and Process Heaters

Table 2 to Subpart DDDDD of Part 63—Emission Limits for Existing 

Boilers and Process Heaters (Units with heat input capacity of 

10 million Btu per hour or greater) 

Table 3 to Subpart DDDDD of Part 63—Work Practice Standards

Table 4 to Subpart DDDDD of Part 63—Operating Limits for Boilers 

and Process Heaters

Table 5 to Subpart DDDDD of Part 63—Performance Testing 

Requirements

Table 6 to Subpart DDDDD of Part 63—Fuel Analysis Requirements

Table 7 to Subpart DDDDD of Part 63—Establishing Operating 

Limits

Table 8 to Subpart DDDDD of Part 63—Demonstrating Continuous 

Compliance

Table 9 to Subpart DDDDD of Part 63—Reporting Requirements

Table 10 to Subpart DDDDD of Part 63—Applicability of General 

Provisions to Subpart DDDDD

What this Subpart Covers

§63.7480 What is the purpose of this subpart?
Page 155 of 360

This subpart establishes national emission limitations and 

work practice standards for hazardous air pollutants (HAP) 

emitted from industrial, commercial, and institutional boilers 

and process heaters located at major sources of HAP. This 

subpart also establishes requirements to demonstrate initial and 

continuous compliance with the emission limitations and work 

practice standards.

§63.7485 Am I subject to this subpart? 

You are subject to this subpart if you own or operate an 

industrial, commercial, or institutional boiler or process 

heater as defined in §63.7575 that is located at, or is part of, 

a major source of HAP, except as specified in §63.7491. For 

purposes of this subpart, a major source of HAP is as defined in 

§63.2, except that for oil and natural gas production 

facilities, a major source of HAP is as defined in §63.761 

(subpart HH of this part, National Emission Standards for 

Hazardous Air Pollutants from Oil and Natural Gas Production 

Facilities).

§63.7490 What is the affected source of this subpart?

(a) This subpart applies to new, reconstructed, and

existing affected sources as described in paragraphs (a)(1) and 

(2) of this section.

(1) The affected source of this subpart is the collection 

at a major source of all existing industrial, commercial, and 
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institutional boilers and process heaters within a subcategory 

as defined in §63.7575.

(2) The affected source of this subpart is each new or 

reconstructed industrial, commercial, or institutional boiler or 

process heater, as defined in §63.7575, located at a major 

source.

(b) A boiler or process heater is new if you commence 

construction of the boiler or process heater after June 4, 2010, 

and you meet the applicability criteria at the time you commence 

construction.

(c) A boiler or process heater is reconstructed if you meet 

the reconstruction criteria as defined in §63.2, you commence 

reconstruction after June 4, 2010, and you meet the 

applicability criteria at the time you commence reconstruction.

(d) A boiler or process heater is existing if it is not new 

or reconstructed.

§63.7491 Are any boilers or process heaters not subject to this 

subpart?

The types of boilers and process heaters listed in 

paragraphs (a) through (n) of this section are not subject to 

this subpart.

(a) An electric utility steam generating unit.

(b) A recovery boiler or furnace covered by subpart MM of 

this part.
Page 157 of 360

(c) A boiler or process heater that is used specifically 

for research and development. This does not include units that 

provide heat or steam to a process at a research and development 

facility.

(d) A hot water heater as defined in this subpart.

(e) A refining kettle covered by subpart X of this part.

(f) An ethylene cracking furnace covered by subpart YY of 

this part.

(g) Blast furnace stoves as described in EPA–453/R–01–005

(incorporated by reference, see §63.14).

(h) Any boiler or process heater that is part of the 

affected source subject to another subpart of this part (i.e., 

another National Emission Standards for Hazardous Air Pollutants

in 40 CFR part 63).

(i) Any boiler or process heater that is used as a control 

device to comply with another subpart of this part, or part 60 

or part 61 of this chapter provided that at least 50 percent of 

the heat input to the boiler or process heater is provided by 

the gas stream that is regulated under another subpart.

(j) Temporary boilers as defined in this subpart.

(k) Blast furnace gas fuel-fired boilers and process 

heaters as defined in this subpart.
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(l) Any boiler specifically listed as an affected source in 

any standard(s) established under section 129 of the Clean Air 

Act.

(m) A unit that burns hazardous waste covered by Subpart 

EEE of this part. A unit that is exempt from Subpart EEE as 

specified in §63.1200(b) is not covered by Subpart EEE.

(n) Residential boilers as defined in this subpart.

§63.7495 When do I have to comply with this subpart? 

(a) If you have a new or reconstructed boiler or process 

heater, you must comply with this subpart by [INSERT THE DATE 60 

DAYS AFTER THE FINAL RULE IS PUBLISHED IN THE FEDERAL REGISTER]

or upon startup of your boiler or process heater, whichever is 

later.

(b) If you have an existing boiler or process heater, you 

must comply with this subpart no later than [INSERT THE DATE 3 

YEARS AFTER PUBLICATION OF THE FINAL RULE IN THE FEDERAL 

REGISTER], except as provided in §63.6(i).

(c) If you have an area source that increases its emissions 

or its potential to emit such that it becomes a major source of 

HAP, paragraphs (c)(1) and (2) of this section apply to you.

(1) Any new or reconstructed boiler or process heater at 

the existing source must be in compliance with this subpart upon 

startup.
Page 159 of 360

(2) Any existing boiler or process heater at the existing 

source must be in compliance with this subpart within 3 years 

after the source becomes a major source.

(d) You must meet the notification requirements in §63.7545 

according to the schedule in §63.7545 and in subpart A of this 

part. Some of the notifications must be submitted before you are 

required to comply with the emission limits and work practice 

standards in this subpart.

(e) If you own or operate an industrial, commercial, or 

institutional boiler or process heater and would be subject to 

this subpart except for the exemption in §63.7491(l) for 

commercial and industrial solid waste incineration units covered 

by part 60, subpart CCCC or subpart DDDD, and you cease 

combusting solid waste, you must be in compliance with this 

subpart on the effective date of the switch from waste to fuel.

Emission Limitations and Work Practice Standards

§63.7499 What are the subcategories of boilers and process 

heaters?

The subcategories of boilers and process heaters, as 

defined in §63.7575 are:

(a) Pulverized coal/solid fossil fuel units.

(b) Stokers designed to burn coal/solid fossil fuel.

(c) Fluidized bed units designed to burn coal/solid fossil 

fuel.
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(d) Stokers/sloped grate/other units designed to burn kiln 

dried biomass/bio-based solids.

(e) Stokers/sloped grate/other units designed to burn wet 

biomass/bio-based solids.

(f) Fluidized bed units designed to burn biomass/bio-based 

solid.

(g) Suspension burners designed to burn biomass/bio-based 

solid.

(h) Dutch ovens/pile burners designed to burn biomass/biobased solid.

(i) Fuel cells designed to burn biomass/bio-based solid.

(j) Hybrid suspension/grate burners designed to burn wet 

biomass/bio-based solid.

(k) Units designed to burn solid fuel.

(l) Units designed to burn liquid fuel.

(m) Units designed to burn heavy liquid fuel.

(n) Units designed to burn light liquid fuel.

(o) Units designed to burn liquid fuel in non-continental 

states or territories.

(p) Units designed to burn natural gas, refinery gas or 

other gas 1 fuels. 

(q) Units designed to burn gas 2 (other) gases.

(r) Metal process furnaces.

(s) Limited-use boilers and process heaters.
Page 161 of 360

§63.7500 What emission limitations, work practice standards, 

and operating limits must I meet?

(a) You must meet the requirements in paragraphs (a)(1) 

through (3) of this section, except as provided in paragraphs 

(b), (c), and (d) of this section. You must meet these 

requirements at all times, except as provided in paragraph (e) 

of this section.

(1) You must meet each emission limit and work practice 

standard in Tables 1 through 3 to this subpart that applies to 

your boiler or process heater, for each boiler or process heater 

at your source, except as provided under §63.7522. The outputbased emission limits (i.e., in units of pounds per million Btu 

of steam output) in Tables 1 or 2 to this subpart are an 

alternative applicable only to boilers that generate steam. The 

output-based emission limits are not applicable to process 

heaters that do not generate steam.

(2) You must meet each operating limit in Table 4 to this 

subpart that applies to your boiler or process heater. If you 

use a control device or combination of control devices not 

covered in Table 4 to this subpart, or you wish to establish and 

monitor an alternative operating limit and alternative 

monitoring parameters, you must apply to the EPA Administrator 

for approval of alternative monitoring under §63.8(f).
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(3) At all times, you must operate and maintain any 

affected source, including associated air pollution control 

equipment and monitoring equipment, in a manner consistent with 

safety and good air pollution control practices for minimizing 

emissions. Determination of whether such operation and 

maintenance procedures are being used will be based on 

information available to the Administrator that may include, but 

is not limited to, monitoring results, review of operation and 

maintenance procedures, review of operation and maintenance 

records, and inspection of the source.

(b) As provided in §63.6(g), EPA may approve use of an 

alternative to the work practice standards in this section.

(c) Limited-use boilers and process heaters must complete a 

biennial tune-up as specified in §63.7540. They are not subject 

to the emission limits in Tables 1 and 2 to this subpart, the 

annual tune-up requirement in Table 3 to this subpart, or the 

operating limits in Table 4 to this subpart. Major sources that 

have limited-use boilers and process heaters must complete an 

energy assessment as specified in Table 3 to this subpart if the 

source has other existing boilers subject to this subpart that 

are not limited-use boilers.

(d) Boilers and process heaters with a heat input capacity 

of less than 5 million Btu per hour in the units designed to 

burn natural gas, refinery gas or other gas 1 fuels subcategory; 
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units designed to burn gas 2 (other) fuels subcategory, or units 

designed to burn light liquid fuels subcategory must complete a 

tune-up every 5 years as specified in §63.7540.

(e) These standards apply at all times, except during 

periods of startup and shutdown, during which time you must 

comply only with Table 3 to this subpart.

§63.7501 How can I assert an affirmative defense if I exceed an 

emission limitations during a malfunction? 

In response to an action to enforce the emission 

limitations and operating limits set forth in §63.7500 you may 

assert an affirmative defense to a claim for civil penalties for 

exceeding such standards that are caused by malfunction, as 

defined at §63.2. Appropriate penalties may be assessed, 

however, if you fail to meet your burden of proving all of the 

requirements in the affirmative defense. The affirmative defense 

shall not be available for claims for injunctive relief.

(a) To establish the affirmative defense in any action to 

enforce such a limit, you must timely meet the notification 

requirements in paragraph (b) of this section, and must prove by 

a preponderance of evidence that:

(1) The excess emissions: 

(i) Were caused by a sudden, infrequent, and unavoidable 

failure of air pollution control and monitoring equipment, 
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process equipment, or a process to operate in a normal or usual 

manner, and

(ii) Could not have been prevented through careful 

planning, proper design or better operation and maintenance 

practices; and

(iii) Did not stem from any activity or event that could 

have been foreseen and avoided, or planned for; and

(iv) Were not part of a recurring pattern indicative of 

inadequate design, operation, or maintenance; and

(2) Repairs were made as expeditiously as possible when the 

applicable emission limitations were being exceeded. Off-shift 

and overtime labor were used, to the extent practicable to make 

these repairs; and

(3) The frequency, amount and duration of the excess 

emissions (including any bypass) were minimized to the maximum 

extent practicable during periods of such emissions; and

(4) If the excess emissions resulted from a bypass of 

control equipment or a process, then the bypass was unavoidable 

to prevent loss of life, personal injury, or severe property 

damage; and

(5) All possible steps were taken to minimize the impact of 

the excess emissions on ambient air quality, the environment and 

human health; and
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(6) All emissions monitoring and control systems were kept 

in operation if at all possible, consistent with safety and good 

air pollution control practices; and

(7) All of the actions in response to the excess emissions 

were documented by properly signed, contemporaneous operating 

logs; and

(8) At all times, the facility was operated in a manner 

consistent with good practices for minimizing emissions; and

(9) A written root cause analysis has been prepared, the 

purpose of which is to determine, correct, and eliminate the 

primary causes of the malfunction and the excess emissions 

resulting from the malfunction event at issue. The analysis 

shall also specify, using best monitoring methods and 

engineering judgment, the amount of excess emissions that were 

the result of the malfunction. 

(b) Notification. The owner or operator of the facility 

experiencing an exceedance of its emission limitation(s) during 

a malfunction shall notify the Administrator by telephone or 

facsimile (fax) transmission as soon as possible, but no later 

than 2 business days after the initial occurrence of the 

malfunction, if it wishes to avail itself of an affirmative 

defense to civil penalties for that malfunction. The owner or 

operator seeking to assert an affirmative defense shall also 

submit a written report to the Administrator within 45 days of 
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the initial occurrence of the exceedance of the standard in 

§63.7500 to demonstrate, with all necessary supporting 

documentation, that it has met the requirements set forth in 

paragraph (a) of this section. The owner or operator may seek an 

extension of this deadline for up to 30 additional days by 

submitting a written request to the Administrator before the 

expiration of the 45 day period. Until a request for an

extension has been approved by the Administrator, the owner or 

operator is subject to the requirement to submit such report 

within 45 days of the initial occurrence of the exceedance. 

General Compliance Requirements

§63.7505 What are my general requirements for complying with 

this subpart?

(a) You must be in compliance with the emission limits, 

work practice standards, and operating limits in this subpart. 

These limits apply to you at all times except for the periods 

noted in §63.7500(e).

(b) [Reserved]

(c) You must demonstrate compliance with all applicable 

emission limits using performance testing, fuel analysis, or 

continuous monitoring systems (CMS), including a continuous 

emission monitoring system (CEMS), continuous opacity monitoring 

system (COMS), continuous parameter monitoring system (CPMS), or 

particulate matter continuous parameter monitoring system (PM 
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CPMS), where applicable. You may demonstrate compliance with the 

applicable emission limit for hydrogen chloride, mercury, or 

total selected metals using fuel analysis if the emission rate 

calculated according to §63.7530(c) is less than the applicable 

emission limit. (For gaseous fuels, you may not use fuel 

analyses to comply with the total selected metals alternative 

standard or the hydrogen chloride standard.) Otherwise, you must 

demonstrate compliance for hydrogen chloride, mercury, or total 

selected metals using performance testing, if subject to an 

applicable emission limit listed in Table 1 or 2 to this 

subpart. 

(d) If you demonstrate compliance with any applicable 

emission limit through performance testing and subsequent 

compliance with operating limits (including the use of CPMS), or 

with a CEMS, or COMS, you must develop a site-specific 

monitoring plan according to the requirements in paragraphs 

(d)(1) through (4) of this section for the use of any CEMS, 

COMS, or CPMS. This requirement also applies to you if you 

petition the EPA Administrator for alternative monitoring 

parameters under §63.8(f).

(1) For each CMS required in this section (including CEMS, 

COMS, or CPMS), you must develop, and submit to the delegated 

authority for approval upon request, a site-specific monitoring 

plan that addresses design, data collection, and the quality 
Page 168 of 360

assurance and quality control elements outlined in §63.8(d) and 

the elements described in paragraphs (d)(1)(i) through (iii) of 

this section. You must submit this site-specific monitoring 

plan, if requested, at least 60 days before your initial 

performance evaluation of your CMS. This requirement to develop 

and submit a site specific monitoring plan does not apply to 

affected sources with existing monitoring plans that apply to 

CEMS and COMS prepared under appendix B to part 60 of this 

chapter and that meet the requirements of §63.7525. Using the 

process described in §63.8(f)(4), you may request approval of 

alternative monitoring system quality assurance and quality 

control procedures in place of those specified in this paragraph 

and, if approved, include the alternatives in your site-specific 

monitoring plan.

(i) Installation of the CMS sampling probe or other 

interface at a measurement location relative to each affected 

process unit such that the measurement is representative of 

control of the exhaust emissions (e.g., on or downstream of the 

last control device);

(ii) Performance and equipment specifications for the 

sample interface, the pollutant concentration or parametric 

signal analyzer, and the data collection and reduction systems; 

and
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(iii) Performance evaluation procedures and acceptance 

criteria (e.g., calibrations, accuracy audits, analytical 

drift).

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

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

(i) Ongoing operation and maintenance procedures in 

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

(c)(3), and (c)(4)(ii);

(ii) Ongoing data quality assurance procedures in 

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

(iii) Ongoing recordkeeping and reporting procedures in 

accordance with the general requirements of §63.10(c) (as 

applicable in Table 10 to this subpart), (e)(1), and (e)(2)(i).

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

in accordance with your site-specific monitoring plan.

(4) You must operate and maintain the CMS in continuous 

operation according to the site-specific monitoring plan.

Testing, Fuel Analyses, and Initial Compliance Requirements

§63.7510 What are my initial compliance requirements and by 

what date must I conduct them?

(a) For affected sources that are required to or elect to 

demonstrate compliance with any of the applicable emission 

limits in Tables 1 or 2 of this subpart through performance 
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testing, your initial compliance requirements include all the 

following:

(1) Conduct performance tests according to §63.7520 and 

Table 5 to this subpart.

(2) Conduct a fuel analysis for each type of fuel burned in 

your boiler or process heater according to §63.7521 and Table 6 

to this subpart, except as specified in paragraphs (a)(2)(i) 

through (iii) of this section. 

(i) For affected sources that burn a single type of fuel, 

you are not required to conduct a fuel analysis for each type of 

fuel burned in your boiler or process heater according to 

§63.7521 and Table 6 to this subpart. For purposes of this 

subpart, units that use a supplemental fuel only for startup, 

unit shutdown, and transient flame stability purposes still 

qualify as affected sources that burn a single type of fuel, and 

the supplemental fuel is not subject to the fuel analysis 

requirements under §63.7521 and Table 6 to this subpart.

(ii) When natural gas, refinery gas, other gas 1 fuels are 

co-fired with other fuels, you are not required to conduct a 

fuel analysis of those fuels according to §63.7521 and Table 6 

to this subpart. If gaseous fuels other than natural gas, 

refinery gas, or other gas 1 fuels are co-fired with other fuels 

and those gaseous fuels are subject to another subpart of this 
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part, you are not required to conduct a fuel analysis of those 

fuels according to §63.7521 and Table 6 to this subpart.

(iii) You are not required to conduct a chlorine fuel 

analysis for any gaseous fuels. You must still conduct a fuel 

analysis for mercury on gaseous fuels unless the fuel is 

exempted in paragraphs (a)(2)(i) through (iii) of this section.

(3) Establish operating limits according to §63.7530 and 

Table 7 to this subpart.

(4) Conduct CMS performance evaluations according to 

§63.7525. 

(b) For affected sources that elect to demonstrate 

compliance with the applicable emission limits in Tables 1 or 2 

of this subpart for hydrogen chloride, mercury or total selected 

metals through fuel analysis, your initial compliance 

requirement is to conduct a fuel analysis for each type of fuel 

burned in your boiler or process heater according to §63.7521 

and Table 6 to this subpart and establish operating limits 

according to §63.7530 and Table 8 to this subpart. The fuels 

described in paragraph (a)(2)(i) through (iii) of this section 

are exempt from these fuel analysis and operating limit 

requirements. Boilers and process heaters that use a CEMS for 

mercury or hydrogen chloride are exempt from the performance 

testing and operating limit requirements specified in paragraph 

(a) of this section.
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(c) If your boiler or process heater is subject to a carbon 

monoxide limit, your initial compliance demonstration for carbon 

monoxide is to conduct a performance test for carbon monoxide 

according to Table 5 to this subpart, or conduct a performance 

evaluation of your continuous carbon monoxide monitor, if 

applicable, according to §63.7525(a). Boilers and process 

heaters that use a continuous emission monitoring system for 

carbon monoxide are exempt from the initial carbon monoxide 

performance testing and oxygen concentration operating limit 

requirements specified in paragraph (a) of this section.

(d) If your boiler or process heater subject to a PM limit 

has an average annual heat input rate greater than 250 MMBtu per 

hour from solid fossil fueland/or residual oil, your initial 

compliance demonstration for PM is to conduct a performance test 

in accordance with §63.7520 and Table 5 to this subpart. Owners 

of boilers and process heaters who elect to comply with the 

alternative total selected metals limit are not required to 

install a CPMS.

(e) For existing affected sources, you must complete the 

initial compliance demonstration, as specified in paragraphs (a) 

through (d) of this section, no later than 180 days after the 

compliance date that is specified for your source in §63.7495 

and according to the applicable provisions in §63.7(a)(2) as 

cited in Table 10 to this subpart. You must complete an initial 
Page 173 of 360

tune-up by following the procedures described in 

§63.7540(a)(10)(i) through (vi) and complete the one-time energy 

assessment specified in Table 3 to this subpart, both no later 

than the compliance date specified in §63.7495.

(f) For new or reconstructed affected sources, you must 

complete the initial compliance demonstration with the emission 

limits no later than [INSERT THE DATE 240 DAYS AFTER PUBLICATION 

OF THE FINAL RULE IN THE FEDERAL REGISTER] or within 180 days 

after startup of the source, whichever is later. 

(g) For new or reconstructed affected sources, you must 

demonstrate initial compliance with the applicable work practice 

standards in Table 3 to this subpart no later than the 

compliance date that is specified in §63.7595 and according to 

the applicable provisions in §63.7(a)(2). You must conduct the 

initial tune-up within 365 days after startup of the source. 

Thereafter, you are required to complete the applicable annual, 

biennial, or 5-year tune-up as specified in §63.7540(a).

(h) For affected sources that ceased burning solid waste 

consistent with §63.7495(e) and for which your initial 

compliance date has passed, you must demonstrate compliance 

within 60 days of the effective date of the waste-to-fuel 

switch. If you have not conducted your compliance demonstration 

for this subpart within the previous 12 months, you must 
Page 174 of 360

complete all compliance demonstrations for this subpart before 

you commence or recommence combustion of solid waste.

§63.7515 When must I conduct subsequent performance tests, fuel 

analyses, or tune-ups?

(a) You must conduct all applicable performance tests 

according to §63.7520 on an annual basis, except as specified in 

paragraphs (b) through (e) of this section. Annual performance 

tests must be completed no more than 13 months after the 

previous performance test, except as specified in paragraphs (b) 

through (e) of this section. 

(b) You can conduct performance tests less often for a 

given pollutant if your performance tests for the pollutant for 

at least 2 consecutive years show that your emissions are at or 

below 75 percent of the emission limit (or, in limited instances 

as specified in Tables 1 and 2 to this subpart, at or below the 

emission limit) and if there are no changes in the operation of 

the affected source or air pollution control equipment that 

could increase emissions. In this case, you do not have to 

conduct a performance test for that pollutant for the next 2 

years. You must conduct a performance test during the third year 

and no more than 37 months after the previous performance test. 

If you elect to demonstrate compliance using emission averaging 

under §63.7522, you must continue to conduct performance tests 

annually. 
Page 175 of 360

(c) If your boiler or process heater continues to meet the 

emission limit for the pollutant, you may choose to conduct 

performance tests for the pollutant every third year if your 

emissions are at or below 75 percent of the emission limit (or, 

in limited instances as specified in Tables 1 and 2 to this 

subpart, at or below the emission limit) and if there are no 

changes in the operation of the affected source or air pollution 

control equipment that could increase emissions, but each such 

performance test must be conducted no more than 37 months after 

the previous performance test. If you elect to demonstrate 

compliance using emission averaging under §63.7522, you must 

continue to conduct performance tests annually. The requirement 

to test at maximum chloride input level is waived unless the 

stack test is conducted for hydrogen chloride. The requirement 

to test at maximum mercury input level is waived unless the 

stack test is conducted for mercury. The requirement to test at 

maximum total selected metals input level is waived unless the 

stack test is conducted for total selected metals.

(d) If a performance test shows emissions exceeded the 

emission limit or 75 percent of the emission limit (as specified 

in Tables 1 and 2) for a pollutant, you must conduct annual 

performance tests for that pollutant until all performance tests 

over a consecutive 2-year period meet the required level (either 
Page 176 of 360

75 percent of the emission or the emission limit, as specified 

in Tables 1 and 2).

(e) If you are required to meet an applicable tune-up work 

practice standard, you must conduct an annual, biennial, or 5-

year performance tune-up according to §63.7540(a)(10), (a)(11), 

or (a)(12), respectively. Each annual tune-up specified in 

§63.7540(a)(10) must be no more than 13 months after the 

previous tune-up. Each biennial tune-up specified in 

§63.7540(a)(11) must be conducted no more than 25 months after 

the previous tune-up. Each 5-year tune-up specified in 

§63.7540(a)(12) must be conducted no more than 61 months after 

the previous tune-up. For a new or reconstructed affected 

source, the first annual, biennial, or 5-year tune-up must be no 

later than 13 months, 25 months, or 61 months, respectively, 

after the initial startup of the new or reconstructed affected 

source.

(f) If you demonstrate compliance with the mercury,

hydrogen chloride, or total selected metals based on fuel 

analysis, you must conduct a monthly fuel analysis according to 

§63.7521 for each type of fuel burned that is subject to an 

emission limit in Table 1 or 2 to this subpart. If you burn a 

new type of fuel, you must conduct a fuel analysis before 

burning the new type of fuel in your boiler or process heater. 

You must still meet all applicable continuous compliance 
Page 177 of 360

requirements in §63.7540. If 12 consecutive monthly fuel 

analyses demonstrate compliance, you may request decreased fuel 

analysis frequency by applying to the EPA Administrator for 

approval of alternative monitoring under §63.8(f).

(g) You must report the results of performance tests and 

the associated initial fuel analyses within 90 days after the 

completion of the performance tests. This report must also 

verify that the operating limits for your affected source have 

not changed or provide documentation of revised operating limits

established according to §63.7530 and Table 7 to this subpart, 

as applicable. The reports for all subsequent performance tests 

must include all applicable information required in §63.7550.

§63.7520 What stack tests and procedures must I use?

(a) You must conduct all performance tests according to 

§63.7(c), (d), (f), and (h). You must also develop a sitespecific stack test plan according to the requirements in 

§63.7(c). You shall conduct all performance tests under such 

conditions as the Administrator specifies to you based on 

representative performance of the affected source for the period 

being tested. Upon request, you shall make available to the 

Administrator such records as may be necessary to determine the 

conditions of the performance tests.

(b) You must conduct each performance test according to the 

requirements in Table 5 to this subpart.
Page 178 of 360

(c) You must conduct each performance test under the 

specific conditions listed in Tables 5 and 7 to this subpart. 

You must conduct performance tests at representative operating 

load conditions while burning the type of fuel or mixture of 

fuels that has the highest content of chlorine and mercury, and 

total selected metals if you are opting to comply with the total 

selected metals alternative standard, and you must demonstrate 

initial compliance and establish your operating limits based on 

these performance tests. These requirements could result in the 

need to conduct more than one performance test. Following each 

performance test and until the next performance test, you must 

comply with the operating limit for operating load conditions 

specified in Table 4 to this subpart.

(d) You must conduct three separate test runs for each 

performance test required in this section, as specified in 

§63.7(e)(3). Each test run must comply with the minimum 

applicable sampling times or volumes specified in Tables 1 and 2 

to this subpart.

(e) To determine compliance with the emission limits, you 

must use the F-Factor methodology and equations in sections 12.2 

and 12.3 of EPA Method 19 at 40 CFR part 60, appendix A-7 of 

this chapter to convert the measured particulate matter 

concentrations, the measured hydrogen chloride concentrations, 

the measured mercury concentrations, and the measured total 
Page 179 of 360

selected metals concentrations that result from the initial 

performance test to pounds per million Btu heat input emission 

rates using F-factors.

§63.7521 What fuel analyses, fuel specification, and procedures 

must I use?

(a) For solid and liquid fuels, you must conduct fuel 

analyses for chloride and mercury according to the procedures in 

paragraphs (b) through (e) of this section and Table 6 to this 

subpart, as applicable. For solid fuels, you must also conduct 

fuel analyses for total selected metals if you are opting to 

comply with the total selected metals alternative standard. For 

gas 2 (other) fuels, you must conduct fuel analysis for mercury 

according to the procedures in paragraphs (b) through (e) of 

this section and Table 6 to this subpart, as applicable. (For 

gaseous fuels, you may not use fuel analyses to comply with the 

total selected metals alternative standard or the hydrogen 

chloride standard.) For purposes of complying with this section, 

a fuel gas system that consists of multiple gaseous fuels 

collected and mixed with each other is considered a single fuel 

type and sampling and analysis is only required on the combined 

fuel gas system that will feed the boiler or process heater. 

Sampling and analysis of the individual gaseous streams prior to 

combining is not required. You are not required to conduct fuel 

analyses for fuels used for only startup, unit shutdown, and 
Page 180 of 360

transient flame stability purposes. You are required to conduct 

fuel analyses only for fuels and units that are subject to 

emission limits for mercury, hydrogen chloride, or total 

selected metals in Tables 1 and 2 to this subpart. Gaseous and 

liquid fuels are exempt from the sampling requirements in 

paragraphs (c) and (d) of this section and Table 6 of this 

subpart. 

(b) You must develop and submit a site-specific fuel 

monitoring plan to the EPA Administrator for review and approval 

according to the following procedures and requirements in 

paragraphs (b)(1) and (2) of this section, if you are required 

to conduct fuel analyses as specified in §63.7510.

(1) You must submit the fuel analysis plan no later than 60 

days before the date that you intend to conduct the initial

compliance demonstration described in §63.7510.

(2) You must include the information contained in 

paragraphs (b)(2)(i) through (vi) of this section in your fuel 

analysis plan.

(i) The identification of all fuel types anticipated to be 

burned in each boiler or process heater.

(ii) For each anticipated fuel type, the notification of 

whether you or a fuel supplier will be conducting the fuel 

analysis.
Page 181 of 360

(iii) For each anticipated fuel type, a detailed 

description of the sample location and specific procedures to be 

used for collecting and preparing the composite samples if your 

procedures are different from paragraph (c) or (d) of this 

section. Samples should be collected at a location that most 

accurately represents the fuel type, where possible, at a point 

prior to mixing with other dissimilar fuel types.

(iv) For each anticipated fuel type, the analytical methods

from Table 6, with the expected minimum detection levels, to be 

used for the measurement of chlorine or mercury.

(v) If you request to use an alternative analytical method 

other than those required by Table 6 to this subpart, you must 

also include a detailed description of the methods and 

procedures that you are proposing to use. Methods in Table 6 

shall be used until the requested alternative is approved.

(vi) If you will be using fuel analysis from a fuel 

supplier in lieu of site-specific sampling and analysis, the 

fuel supplier must use the analytical methods required by Table 

6 to this subpart.

(c) At a minimum, you must obtain three composite fuel

samples for each fuel type according to the procedures in 

paragraph (c)(1) or (2) of this section, or use an automated 

sampling mechanism that provides representative composite fuel 
Page 182 of 360

samples for each fuel type that includes both coarse and fine 

material.

(1) If sampling from a belt (or screw) feeder, collect fuel 

samples according to paragraphs (c)(1)(i) and (ii) of this 

section.

(i) Stop the belt and withdraw a 6-inch wide sample from 

the full cross-section of the stopped belt to obtain a minimum 

two pounds of sample. You must collect all the material (fines 

and coarse) in the full cross-section. You must transfer the 

sample to a clean plastic bag.

(ii) Each composite sample will consist of a minimum of 

three samples collected at approximately equal one-hour

intervals during the testing period for sampling during 

performance stack testing. For monthly sampling, each composite 

sample shall be collected at approximately equal 10-day 

intervals during the month.

(2) If sampling from a fuel pile or truck, you must collect 

fuel samples according to paragraphs (c)(2)(i) through (iii) of 

this section.

(i) For each composite sample, you must select a minimum of 

five sampling locations uniformly spaced over the surface of the 

pile.

(ii) At each sampling site, you must dig into the pile to a 

uniform depth of approximately 18 inches. You must insert a 
Page 183 of 360

clean shovel into the hole and withdraw a sample, making sure 

that large pieces do not fall off during sampling; use the same 

shovel to collect all samples. 

(iii) You must transfer all samples to a clean plastic bag 

for further processing.

(d) You must prepare each composite sample according to the 

procedures in paragraphs (d)(1) through (7) of this section.

(1) You must thoroughly mix and pour the entire composite 

sample over a clean plastic sheet.

(2) You must break large sample pieces (e.g., larger than 3 

inches) into smaller sizes.

(3) You must make a pie shape with the entire composite 

sample and subdivide it into four equal parts.

(4) You must separate one of the quarter samples as the 

first subset.

(5) If this subset is too large for grinding, you must 

repeat the procedure in paragraph (d)(3) of this section with 

the quarter sample and obtain a one-quarter subset from this 

sample.

(6) You must grind the sample in a mill.

(7) You must use the procedure in paragraph (d)(3) of this 

section to obtain a one-quarter subsample for analysis. If the 

quarter sample is too large, subdivide it further using the same 

procedure.
Page 184 of 360

(e) You must determine the concentration of pollutants in 

the fuel (mercury and/or chlorine and/or total selected metals) 

in units of pounds per million Btu of each composite sample for 

each fuel type according to the procedures in Table 6 to this 

subpart, for use in Equations 7, 8, and 9 of this subpart.

(f) To demonstrate that a gaseous fuel other than natural 

gas or refinery gas qualifies as an other gas 1 fuel, as defined 

in §63.7575, you must conduct a fuel specification analyses for 

mercury according to the procedures in paragraphs (g) through 

(i) of this section and Table 6 to this subpart, as applicable, 

except as specified in paragraph (f)(1) through (3) of this 

section. 

(1) You are not required to conduct the fuel specification 

analyses in paragraphs (g) through (i) of this section for 

natural gas or refinery gas.

(2) You are not required to conduct the fuel specification 

analyses in paragraphs (g) through (i) of this section for 

gaseous fuels that are subject to another subpart of this part.

(3) You are not required to conduct the fuel specification 

analyses in paragraphs (g) through (i) of this section on 

gaseous fuels for units that are complying with the limits for 

units designed to burn gas 2 (other) fuels.

(g) You must develop and submit a site-specific fuel 

analysis plan for other gas 1 fuels to the EPA Administrator for 
Page 185 of 360

review and approval according to the following procedures and 

requirements in paragraphs (g)(1) and (2) of this section.

(1) You must submit the fuel analysis plan no later than 60 

days before the date that you intend to conduct the initial

compliance demonstration described in §63.7510.

(2) You must include the information contained in 

paragraphs (g)(2)(i) through (vi) of this section in your fuel 

analysis plan.

(i) The identification of all gaseous fuel types other than 

those exempted from fuel specification analysis under (f)(1) 

through (3) of this section anticipated to be burned in each 

boiler or process heater.

(ii) For each anticipated fuel type, the notification of 

whether you or a fuel supplier will be conducting the fuel 

specification analysis.

(iii) For each anticipated fuel type, a detailed 

description of the sample location and specific procedures to be 

used for collecting and preparing the samples if your procedures 

are different from the sampling methods contained in Table 6 to 

this subpart. Samples should be collected at a location that 

most accurately represents the fuel type, where possible, at a 

point prior to mixing with other dissimilar fuel types. If 

multiple boilers or process heaters are fueled by a common fuel 
Page 186 of 360

stream it is permissible to conduct a single gas specification 

at the common point of gas distribution.

(iv) For each anticipated fuel type, the analytical methods

from Table 6 to this subpart, with the expected minimum 

detection levels, to be used for the measurement of mercury.

(v) If you request to use an alternative analytical method 

other than those required by Table 6 to this subpart, you must 

also include a detailed description of the methods and 

procedures that you are proposing to use. Methods in Table 6 to 

this subpart shall be used until the requested alternative is 

approved.

(vi) If you will be using fuel analysis from a fuel 

supplier in lieu of site-specific sampling and analysis, the 

fuel supplier must use the analytical methods required by Table 

6 to this subpart.

(h) You must obtain a single fuel sample for each fuel type 

according to the sampling procedures listed in Table 6 for fuel 

specification of gaseous fuels. 

(i) You must determine the concentration in the fuel of 

mercury, in units of microgram per cubic meter, dry basis, of 

each sample for each gas 1 fuel type according to the procedures 

in Table 6 to this subpart.

§63.7522 Can I use emissions averaging to comply with this 

subpart?
Page 187 of 360

(a) As an alternative to meeting the requirements of 

§63.7500 for particulate matter, hydrogen chloride, or mercury 

on a boiler or process heater-specific basis, if you have more 

than one existing boiler or process heater in any subcategory 

located at your facility, you may demonstrate compliance by 

emissions averaging, if your averaged emissions are not more 

than 90 percent of the applicable emission limit, according to 

the procedures in this section. You may not include new boilers 

or process heaters in an emissions average. 

(b) For a group of two or more existing boilers or process 

heaters in the same subcategory that each vent to a separate 

stack, you may average particulate matter, hydrogen chloride, or 

mercury emissions among existing units to demonstrate compliance 

with the limits in Table 2 to this subpart as specified in 

paragraph (b)(1) through (3) of this section, if you satisfy the 

requirements in paragraphs (c), (d), (e), (f), and (g) of this 

section.

(1) You may not include in an average units using a CEMS or 

PM CPMS for demonstrating compliance, even if the use of a CEMS 

or PM CPMS is optional.

(2) For Hg and HCl, averaging is allowed as follows:

(i) You may average among units in any of the solid fuel 

subcategories.
Page 188 of 360

(ii) You may average among units in any of the liquid fuel 

subcategories.

(iii) You may average among units in a subcategory of units 

designed to burn gas 2 (other) fuels.

(iv) You may not average across the liquid, solid fuel, and 

gas 2 (other) subcategories.

(3) For particulate matter, averaging is only allowed 

between units within each of the following combustor level 

subcategories and you may not average across subcategories:

(i) Pulverized coal/solid fossil fuel units.

(ii) Stokers designed to burn coal/solid fossil fuel. 

(iii) Fluidized bed units designed to burn coal/solid 

fossil fuel. 

(iv) Stokers/sloped grate/other units designed to burn kiln 

dried biomass/bio-based solids. 

(v) Stokers/sloped grate/other units designed to burn wet 

biomass/bio-based solids. 

(vi) Fluidized bed units designed to burn biomass/bio-based 

solid. 

(vii) Suspension burners designed to burn biomass/bio-based 

solid. 

(viii) Dutch ovens/pile burners designed to burn 

biomass/bio-based solid.

(ix) Fuel Cells designed to burn biomass/bio-based solid. 
Page 189 of 360

(x) Hybrid suspension/grate burners designed to burn wet 

biomass/bio-based solid.

(xi) Units designed to burn heavy liquid fuel.

(xii) Units designed to burn light liquid fuel.

(xiii) Units designed to burn liquid fuel in noncontinental states or territories.

(xiv) Units designed to burn gas 2 (other) gases.

(c) For each existing boiler or process heater in the 

averaging group, the emission rate achieved during the initial 

compliance test for the HAP being averaged must not exceed the 

emission level that was being achieved on [INSERT THE DATE 60 

DAYS AFTER PUBLICATION OF THE FINAL RULE IN THE FEDERAL 

REGISTER] or the control technology employed during the initial 

compliance test must not be less effective for the HAP being 

averaged than the control technology employed on [INSERT THE 

DATE 60 DAYS AFTER PUBLICATION OF THE FINAL RULE IN THE FEDERAL 

REGISTER].

(d) The averaged emissions rate from the existing boilers 

and process heaters participating in the emissions averaging 

option must be in compliance with the limits in Table 2 to this 

subpart at all times following the compliance date specified in 

§63.7495.

(e) You must demonstrate initial compliance according to 

paragraph (e)(1) or (2) of this section using the maximum rated 
Page 190 of 360

heat input capacity or maximum steam generation capacity of each 

unit and the results of the initial performance tests or fuel 

analysis.

(1) You must use Equation 1a or 1b of this section to 

demonstrate that the particulate matter, hydrogen chloride, or 

mercury emissions from all existing units participating in the 

emissions averaging option for that pollutant do not exceed the 

emission limits in Table 2 to this subpart. Use Equation 1a if 

you are complying with the emission limits on a heat input basis 

and use Equation 1b if you are complying with the emission 

limits on a steam generation (output) basis.

    

   

n

i

n

i

AveWeightedEmissions Er Hm Hm

1 1

1.1 (Eq.1a)

Where:

AveWeightedEmissions = Average weighted emissions for 

particulate matter, hydrogen chloride, or mercury, 

in units of pounds per million Btu of heat input.

Er = Emission rate (as determined during the initial 

compliance demonstration) of particulate matter, 

hydrogen chloride, or mercury from unit, i, in units 

of pounds per million Btu of heat input. Determine 

the emission rate for particulate matter, hydrogen 

chloride, or mercury by performance testing according 

to Table 5 to this subpart, or by fuel analysis for 

hydrogen chloride or mercury using the applicable 

equation in §63.7530(c).

Hm = Maximum rated heat input capacity of unit, i, in 

units of million Btu per hour.

n = Number of units participating in the emissions 

averaging option.

1.1 = Required discount factor.
Page 191 of 360

    

   

n

i

n

i

AveWeightedEmissions Er So So

1 1

1.1 (Eq.1b)

Where:

AveWeightedEmissions = Average weighted emissions for 

particulate matter, hydrogen chloride, or mercury, 

in units of pounds per million Btu of steam output.

Er = Emission rate (as determined during the initial 

compliance demonstration) of particulate matter, 

hydrogen chloride, or mercury from unit, i, in units 

of pounds per million Btu of steam output. Determine 

the emission rate for particulate matter, hydrogen 

chloride, or mercury by performance testing according 

to Table 5 to this subpart, or by fuel analysis for 

hydrogen chloride or mercury using the applicable 

equation in §63.7530(c). If you are taking credit for 

energy conservation measures from a unit according to 

§63.7533, use the adjusted emission level for that 

unit, Eadj, determined according to §63.7533 for that 

unit.

So = Maximum steam output capacity of unit, i, in units of 

million Btu per hour, as defined in §63.7575.

n = Number of units participating in the emissions 

averaging option.

1.1 = Required discount factor.

(2) If you are not capable of determining the maximum rated 

heat input capacity of one or more boilers that generate steam, 

you may use Equation 2 of this section as an alternative to 

using Equation 1a of this section to demonstrate that the 

particulate matter, hydrogen chloride, or mercury emissions from 

all existing units participating in the emissions averaging 

option do not exceed the emission limits for that pollutant in 

Table 2 to this subpart that are in pounds per million Btu of 

heat input.
Page 192 of 360

   

 

     

n

i

n

i

AveWeightedEmissions Er Sm Cfi Sm Cfi

1 1

1.1 (Eq. 2)

Where:

AveWeightedEmissions = Average weighted emission level for PM, 

hydrogen chloride, or mercury, in units of pounds 

per million Btu of heat input.

Er = Emission rate (as determined during the most recent 

compliance demonstration) of particulate matter, 

hydrogen chloride, or mercury from unit, i, in units 

of pounds per million Btu of heat input. Determine 

the emission rate for particulate matter, hydrogen 

chloride, or mercury by performance testing according 

to Table 5 to this subpart, or by fuel analysis for 

hydrogen chloride or mercury using the applicable 

equation in §63.7530(c).

Sm = Maximum steam generation capacity by unit, i, in 

units of pounds per hour.

Cfi = Conversion factor, calculated from the most recent 

compliance test, in units of million Btu of heat 

input per pounds of steam generated for unit, i.

1.1 = Required discount factor.

(f) After the initial compliance demonstration described in 

paragraph (e) of this section, you must demonstrate compliance 

on a monthly basis determined at the end of every month (12 

times per year) according to paragraphs (f)(1) through (3) of 

this section. The first monthly period begins on the compliance 

date specified in §63.7495.

(1) For each calendar month, you must use Equation 3a or 3b

of this section to calculate the average weighted emission rate 

for that month. Use Equation 3a and the actual heat input for 

the month for each existing unit participating in the emissions 
Page 193 of 360

averaging option if you are complying with emission limits on a 

heat input basis. Use Equation 3b and the actual steam 

generation for the month if you are complying with the emission 

limits on a steam generation (output) basis.

    

   

n

i

n

i

AveWeightedEmissions Er Hb Hb

1 1

1.1 (Eq. 3a)

Where:

AveWeightedEmissions = Average weighted emission level for 

particulate matter, hydrogen chloride, or mercury, 

in units of pounds per million Btu of heat input, 

for that calendar month.

Er = Emission rate (as determined during the most recent 

compliance demonstration) of particulate matter, 

hydrogen chloride, or mercury from unit, i, in units 

of pounds per million Btu of heat input. Determine 

the emission rate for particulate matter, hydrogen 

chloride, or mercury by performance testing according 

to Table 5 to this subpart, or by fuel analysis for 

hydrogen chloride or mercury using the applicable 

equation in §63.7530(c).

Hb = The heat input for that calendar month to unit, i, in 

units of million Btu.

n = Number of units participating in the emissions 

averaging option.

1.1 = Required discount factor.

    

   

n

i

n

i

AveWeightedEmissions Er So So

1 1

1.1 (Eq. 3b)

Where:

AveWeightedEmissions = Average weighted emission level for 

particulate matter, hydrogen chloride, or mercury, 

in units of pounds per million Btu of steam output, 

for that calendar month.
Page 194 of 360

Er = Emission rate (as determined during the most recent 

compliance demonstration) of particulate matter, 

hydrogen chloride, or mercury from unit, i, in units 

of pounds per million Btu of steam output. Determine 

the emission rate for particulate matter, hydrogen 

chloride, or mercury by performance testing according 

to Table 5 to this subpart, or by fuel analysis for 

hydrogen chloride or mercury using the applicable 

equation in §63.7530(c). If you are taking credit for 

energy conservation measures from a unit according to 

§63.7533, use the adjusted emission level for that 

unit, Eadj, determined according to §63.7533 for that 

unit.

So = The steam output for that calendar month from unit, 

i, in units of million Btu, as defined in §63.7575.

n = Number of units participating in the emissions 

averaging option.

1.1 = Required discount factor.

(2) If you are not capable of monitoring heat input, you 

may use Equation 4 of this section as an alternative to using 

Equation 3a of this section to calculate the average weighted 

emission rate using the actual steam generation from the boilers 

participating in the emissions averaging option.

   

 

     

n

i

n

i

AveWeightedEmissions Er Sa Cfi Sa Cfi

1 1

1.1 (Eq. 4)

Where:

AveWeightedEmissions = average weighted emission level for PM, 

hydrogen chloride, or mercury, in units of pounds 

per million Btu of heat input for that calendar 

month.

Er = Emission rate (as determined during the most recent 

compliance demonstration of particulate matter, 

hydrogen chloride, or mercury from unit, i, in units 

of pounds per million Btu of heat input. Determine 

the emission rate for particulate matter, hydrogen 
Page 195 of 360

chloride, or mercury by performance testing according 

to Table 5 to this subpart, or by fuel analysis for 

hydrogen chloride or mercury using the applicable 

equation in §63.7530(c).

Sa = Actual steam generation for that calendar month by 

boiler, i, in units of pounds.

Cfi = Conversion factor, as calculated during the most 

recent compliance test, in units of million Btu of 

heat input per pounds of steam generated for boiler, 

i.

1.1 = Required discount factor.

(3) Until 12 monthly weighted average emission rates have 

been accumulated, calculate and report only the average weighted 

emission rate determined under paragraph (f)(1) or (2) of this 

section for each calendar month. After 12 monthly weighted 

average emission rates have been accumulated, for each 

subsequent calendar month, use Equation 5 of this section to 

calculate the 12-month rolling average of the monthly weighted 

average emission rates for the current calendar month and the 

previous 11 calendar months.

12

1

  



n

i

Eavg ERi (Eq. 5)

Where:

Eavg = 12-month rolling average emission rate, (pounds per 

million Btu heat input)

ERi = Monthly weighted average, for calendar month “i” 

(pounds per million Btu heat input), as calculated by 

paragraph (f)(1) or (2) of this section.
Page 196 of 360

(g) You must develop, and submit to the applicable 

delegated authority for review and approval, an implementation 

plan for emission averaging according to the following 

procedures and requirements in paragraphs (g)(1) through (4) of 

this section.

(1) You must submit the implementation plan no later than 

180 days before the date that the facility intends to 

demonstrate compliance using the emission averaging option.

(2) You must include the information contained in 

paragraphs (g)(2)(i) through (vii) of this section in your 

implementation plan for all emission sources included in an 

emissions average:

(i) The identification of all existing boilers and process 

heaters in the averaging group, including for each either the 

applicable HAP emission level or the control technology 

installed as of [INSERT THE DATE 60 DAYS AFTER PUBLICATION OF 

THE FINAL RULE IN THE FEDERAL REGISTER] and the date on which 

you are requesting emission averaging to commence;

(ii) The process parameter (heat input or steam generated) 

that will be monitored for each averaging group;

(iii) The specific control technology or pollution 

prevention measure to be used for each emission boiler or 

process heater in the averaging group and the date of its 

installation or application. If the pollution prevention measure 
Page 197 of 360

reduces or eliminates emissions from multiple boilers or process 

heaters, the owner or operator must identify each boiler or 

process heater;

(iv) The test plan for the measurement of particulate 

matter, hydrogen chloride, or mercury emissions in accordance 

with the requirements in §63.7520;

(v) The operating parameters to be monitored for each 

control system or device consistent with §63.7500 and Table 4, 

and a description of how the operating limits will be 

determined;

(vi) If you request to monitor an alternative operating 

parameter pursuant to §63.7525, you must also include:

(A) A description of the parameter(s) to be monitored and 

an explanation of the criteria used to select the parameter(s); 

and

(B) A description of the methods and procedures that will 

be used to demonstrate that the parameter indicates proper 

operation of the control device; the frequency and content of 

monitoring, reporting, and recordkeeping requirements; and a 

demonstration, to the satisfaction of the applicable delegated 

authority, that the proposed monitoring frequency is sufficient 

to represent control device operating conditions; and

(vii) A demonstration that compliance with each of the

applicable emission limit(s) will be achieved under 
Page 198 of 360

representative operating load conditions. Following each 

compliance demonstration and until the next compliance 

demonstration, you must comply with the operating limit for 

operating load conditions specified in Table 4 to this subpart.

(3) The delegated authority shall review and approve or 

disapprove the plan according to the following criteria:

(i) Whether the content of the plan includes all of the 

information specified in paragraph (g)(2) of this section; and

(ii) Whether the plan presents sufficient information to 

determine that compliance will be achieved and maintained.

(4) The applicable delegated authority shall not approve an 

emission averaging implementation plan containing any of the 

following provisions:

(i) Any averaging between emissions of differing pollutants 

or between differing sources; or

(ii) The inclusion of any emission source other than an 

existing unit in the same subcategory.

(h) For a group of two or more existing affected units, 

each of which vents through a single common stack, you may 

average particulate matter, hydrogen chloride, or mercury 

emissions to demonstrate compliance with the limits for that 

pollutant in Table 2 to this subpart if you satisfy the 

requirements in paragraph (i) or (j) of this section.
Page 199 of 360

(i) For a group of two or more existing units in the same 

subcategory, each of which vents through a common emissions 

control system to a common stack, that does not receive 

emissions from units in other subcategories or categories, you 

may treat such averaging group as a single existing unit for 

purposes of this subpart and comply with the requirements of 

this subpart as if the group were a single unit.

(j) For all other groups of units subject to the common 

stack requirements of paragraph (h) of this section, including 

situations where the exhaust of affected units are each 

individually controlled and then sent to a common stack, the 

owner or operator may elect to:

(1) Conduct performance tests according to procedures 

specified in §63.7520 in the common stack if affected units from 

other subcategories vent to the common stack. The emission 

limits that the group must comply with are determined by the use 

of Equation 6 of this section.

    

  

n

i

n

i

En ELi Hi Hi

1 1

(Eq. 6)

Where:

En = HAP emission limit, pounds per million British 

thermal units (lb/MMBtu), parts per million (ppm), 

or nanograms per dry standard cubic meter (ng/dscm).

ELi = Appropriate emission limit from Table 2 to this 

subpart for unit i, in units of lb/MMBtu, ppm or 

ng/dscm.
Page 200 of 360

Hi = Heat input from unit i, MMBtu.

(2) Conduct performance tests according to procedures 

specified in §63.7520 in the common stack. If affected units and 

non-affected units vent to the common stack, the non-affected 

units must be shut down or vented to a different stack during 

the performance test unless the facility determines to 

demonstrate compliance with the non-affected units venting to 

the stack; and

(3) Meet the applicable operating limit specified in 

§63.7540 and Table 8 to this subpart for each emissions control 

system (except that, if each unit venting to the common stack 

has an applicable opacity operating limit, then a single 

continuous opacity monitoring system may be located in the 

common stack instead of in each duct to the common stack).

(k) The common stack of a group of two or more existing 

boilers or process heaters in the same subcategory subject to 

paragraph (h) of this section may be treated as a separate stack 

for purposes of paragraph (b) of this section and included in an 

emissions averaging group subject to paragraph (b) of this 

section.

§63.7525 What are my monitoring, installation, operation, and 

maintenance requirements?

(a) If your boiler or process heater is subject to a carbon 

monoxide emission limit in Table 1 or 2 to this subpart, you 
Page 201 of 360

must install, operate, and maintain an oxygen analyzer system as 

defined in §63.7575, or a carbon monoxide continuous emission 

monitoring system (CO CEMS) according to the procedures in 

paragraphs (a)(1) through (10) of this section. 

(1) The oxygen analyzer system or the CO CEMS must be 

installed by the compliance date specified in §63.7495. If a CO 

CEMS is used, the carbon monoxide level shall be monitored at 

the outlet of the boiler or process heater.

(2) You must operate the oxygen trim system with the oxygen 

level set at the minimum percent oxygen by volume that is 

established as the operating limit for oxygen according to Table 

4 to this subpart.

(3) Each CO CEMS must be installed, operated, and 

maintained according to the applicable procedures under 

Performance Specification 4, 4A, or 4B at 40 CFR part 60, 

appendix B, and according to the site-specific monitoring plan 

developed according to §63.7505(d).

(4) For a new unit, the initial performance evaluation 

shall be completed no later than [INSERT THE DATE 240 DAYS AFTER 

PUBLICATION OF THE FINAL RULE IN THE FEDERAL REGISTER] or 180

days after the date of initial startup, whichever is later. For 

an existing unit, the initial performance evaluation shall be 

completed no later than [INSERT THE DATE 3 YEARS AND 180 DAYS 

AFTER PUBLICATION OF THE FINAL RULE IN THE FEDERAL REGISTER].
Page 202 of 360

(5) You must conduct a performance evaluation of each CO

CEMS according to the requirements in §63.8(e) and according to 

Performance Specification 4, 4A, or 4B at 40 CFR part 60, 

appendix B. During each relative accuracy test run of the CO 

CEMS, emission data for carbon monoxide must be collected 

concurrently (or within a 30- to 60-minute period) by both the 

CO CEMS and by Method 10, 10A, or 10B at 40 CFR part 60, 

appendix A-4. The relative accuracy testing must be at 

representative operating conditions.

(6) For each CO CEMS, you must follow the quality assurance 

procedures (e.g., quarterly accuracy determinations and daily 

calibration drift tests) of Procedure 1 of appendix F to part 

60. The span value of the CO CEMS must be two times the 

applicable CO emission limit, expressed as a concentration.

(7) Each CO CEMS must complete a minimum of one cycle of 

operation (sampling, analyzing, and data recording) for each 

successive 15-minute period. Collect at least four CO CEMS data 

values representing the four 15-minute periods in an hour, or at 

least two 15-minute data values during an hour when CEMS 

calibration, quality assurance, or maintenance activities are 

being performed.

(8) The CO CEMS data must be reduced as specified in 

§63.8(g)(2).
Page 203 of 360

(9) You must calculate one-hour arithmetic averages, 

corrected to 3 percent oxygen from each hour of CO CEMS data in 

parts per million carbon monoxide concentration. For all 

subcategories except for units designed to burn liquid fuels in 

non-continental states and territories, the one-hour arithmetic 

averages required shall be used to calculate the boiler 

operating day daily arithmetic average emissions. Calculate a 

10-day rolling average from the daily averages. For units 

designed to burn liquid fuels in non-continental states and 

territories, the one-hour arithmetic averages required shall be 

used to calculate the 3-hour arithmetic average emissions. Use

Equation 19-19 in section 12.4.1 of Method 19 of 40 CFR part 60, 

appendix A-7 for calculating the average carbon monoxide 

concentration from the hourly values.

(10) For purposes of collecting CO data, you must operate 

the CO CEMS as specified in §63.7535(b). You must use all the 

data collected during all periods in calculating data averages 

and assessing compliance, except that you must exclude certain 

data as specified in §63.7535(c). Periods when CO data are 

unavailable may constitute monitoring deviations as specified in 

§63.7535(d).

(b) If your boiler or process heater has an average annual

heat input rate greater than 250 MMBtu per hour from solid 

fossil fuel and/or residual oil, and you demonstrate compliance 
Page 204 of 360

with the PM limit instead of the alternative total selected 

metals limit, you must install, certify, maintain, and operate a 

PM CPMS monitoring emissions discharged to the atmosphere and 

record the output of the system as specified in paragraphs 

(b)(1) through (4) of this section. For other boilers or process 

heaters, you may elect to use a PM CPMS operated in accordance 

with this section in lieu of using other CMS for monitoring PM 

compliance (e.g., bag leak detectors, ESP secondary power, PM 

scrubber pressure).

(1) Install, certify, operate, and maintain your PM CPMS 

according to the procedures in your approved site-specific 

monitoring plan developed in accordance with §63.7505(d), the 

requirements in §63.7540(a)(9), and (b)(1)(i) through (iii) of 

this section.

(i) The operating principle of the PM CPMS must be based on 

in-stack or extractive light scatter, light scintillation, beta 

attenuation, or mass accumulation detection of PM in the exhaust 

gas or representative exhaust gas sample. The reportable 

measurement output from the PM CPMS may be expressed as 

milliamps, stack concentration, or other raw data signal.

(ii) The PM CPMS must have a cycle time (i.e., period 

required to complete sampling, measurement, and reporting for 

each measurement) no longer than 60 minutes.
Page 205 of 360

(iii) The PM CPMS must be capable of detecting and 

responding to particulate matter concentrations of no greater 

than 0.5 milligram per actual cubic meter.

(2) For a new unit, complete the initial performance 

evaluation no later than [INSERT THE DATE 240 DAYS AFTER 

PUBLICATION OF THE FINAL RULE IN THE FEDERAL REGISTER] or 180

days after the date of initial startup, whichever is later. For 

an existing unit, complete the initial performance evaluation no 

later than [INSERT THE DATE 3 YEARS AND 180 DAYS AFTER 

PUBLICATION OF THE FINAL RULE IN THE FEDERAL REGISTER].

(3) Collect PM CPMS hourly average output data for all 

boiler operating hours except as indicated in §63.7535(a) 

through (d). Express the PM CPMS output as millamps, PM 

concentration, or other raw data signal value.

(4) Calculate the arithmetic 30-day rolling average of all 

of the hourly average PM CPMS output data collected during all 

boiler operating hours (e.g., milliamps, PM concentration, raw 

data signal).

(c) If you have an applicable opacity operating limit in 

this rule, and are not otherwise required or elect to install 

and operate a PM CPMS or a bag leak detection system, you must 

install, operate, certify and maintain each COMS according to 

the procedures in paragraphs (c)(1) through (7) of this section 

by the compliance date specified in §63.7495.
Page 206 of 360

(1) Each COMS must be installed, operated, and maintained 

according to Performance Specification 1 at appendix B to part 

60 of this chapter.

(2) You must conduct a performance evaluation of each COMS 

according to the requirements in §63.8(e) and according to 

Performance Specification 1 at appendix B to part 60 of this 

chapter.

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

a minimum of one cycle of sampling and analyzing for each 

successive 10-second period and one cycle of data recording for 

each successive 6-minute period.

(4) The COMS data must be reduced as specified in 

§63.8(g)(2).

(5) You must include in your site-specific monitoring plan 

procedures and acceptance criteria for operating and maintaining 

each COMS according to the requirements in §63.8(d). At a 

minimum, the monitoring plan must include a daily calibration 

drift assessment, a quarterly performance audit, and an annual 

zero alignment audit of each COMS.

(6) You must operate and maintain each COMS according to 

the requirements in the monitoring plan and the requirements of 

§63.8(e). You must identify periods the COMS is out of control 

including any periods that the COMS fails to pass a daily 

calibration drift assessment, a quarterly performance audit, or 
Page 207 of 360

an annual zero alignment audit. Any 6-minute period for which 

the monitoring system is out of control and data are not 

available for a required calculation constitutes a deviation 

from the monitoring requirements.

(7) You must determine and record all the 6-minute averages 

(and daily block averages as applicable) collected for periods 

during which the COMS is not out of control.

(d) If you have an operating limit that requires the use of 

a CMS other than a PM CPMS or COMS, you must install, operate, 

and maintain each CMS according to the procedures in paragraphs 

(d)(1) through (5) of this section by the compliance date 

specified in §63.7495.

(1) The continuous parameter monitoring system must 

complete a minimum of one cycle of operation for each successive 

15-minute period. You must have a minimum of four successive 

cycles of operation to have a valid hour of data.

(2) You must operate the monitoring system as specified in 

§63.7535(b), and comply with the data calculation requirements 

specified in §63.7535(c).

(3) Any 15-minute period for which the monitoring system is 

out-of-control and data are not available for a required 

calculation constitutes a deviation from the monitoring 

requirements. Other situations that constitute a monitoring 

deviation are specified in §63.7535(d).
Page 208 of 360

(4) You must determine the 30-day rolling average of all 

recorded readings, except as provided in paragraph (d)(3) of 

this section.

(5) You must record the results of each inspection, 

calibration, and validation check.

(e) If you have an operating limit that requires the use of 

a flow monitoring system, you must meet the requirements in 

paragraphs (d) and (e)(1) through (4) of this section.

(1) You must install the flow sensor and other necessary 

equipment in a position that provides a representative flow.

(2) You must use a flow sensor with a measurement 

sensitivity of no greater than 2 percent of the expected flow 

rate.

(3) You must minimize the effects of swirling flow or 

abnormal velocity distributions due to upstream and downstream 

disturbances.

(4) You must conduct a flow monitoring system performance 

evaluation in accordance with your monitoring plan at the time 

of each performance test but no less frequently than annually.

(f) If you have an operating limit that requires the use of 

a pressure monitoring system, you must meet the requirements in 

paragraphs (d) and (f)(1) through (6) of this section.
Page 209 of 360

(1) Install the pressure sensor(s) in a position that 

provides a representative measurement of the pressure (e.g., PM 

scrubber pressure drop).

(2) Minimize or eliminate pulsating pressure, vibration, 

and internal and external corrosion.

(3) Use a pressure sensor with a minimum tolerance of 1.27 

centimeters of water or a minimum tolerance of 1 percent of the 

pressure monitoring system operating range, whichever is less.

(4) Perform checks at least once each process operating day 

to ensure pressure measurements are not obstructed (e.g., check 

for pressure tap pluggage daily).

(5) Conduct a performance evaluation of the pressure 

monitoring system in accordance with your monitoring plan at the 

time of each performance test but no less frequently than 

annually.

(6) If at any time the measured pressure exceeds the 

manufacturer’s specified maximum operating pressure range, 

conduct a performance evaluation of the pressure monitoring 

system in accordance with your monitoring plan and confirm that 

the pressure monitoring system continues to meet the performance 

requirements in you monitoring plan. Alternatively, install and 

verify the operation of a new pressure sensor.
Page 210 of 360

(g) If you have an operating limit that requires a pH 

monitoring system, you must meet the requirements in paragraphs 

(d) and (g)(1) through (4) of this section.

(1) Install the pH sensor in a position that provides a 

representative measurement of scrubber effluent pH.

(2) Ensure the sample is properly mixed and representative 

of the fluid to be measured.

(3) Conduct a performance evaluation of the pH monitoring 

system in accordance with your monitoring plan at least once 

each process operating day.

(4) Conduct a performance evaluation (including a two-point 

calibration with one of the two buffer solutions having a pH 

within 1 of the pH of the operating limit) of the pH monitoring

system in accordance with your monitoring plan at the time of 

each performance test but no less frequently than quarterly.

(h) If you have an operating limit that requires a 

secondary electric power monitoring system for an electrostatic 

precipitator (ESP) operated with a wet scrubber, you must meet 

the requirements in paragraphs (h)(1) and (2) of this section.

(1) Install sensors to measure (secondary) voltage and 

current to the precipitator collection plates.

(2) Conduct a performance evaluation of the electric power 

monitoring system in accordance with your monitoring plan at the 
Page 211 of 360

time of each performance test but no less frequently than 

annually.

(i) If you have an operating limit that requires the use of 

a monitoring system to measure sorbent injection rate (e.g., 

weigh belt, weigh hopper, or hopper flow measurement device), 

you must meet the requirements in paragraphs (d) and (i)(1) 

through (2) of this section.

(1) Install the system in a position(s) that provides a 

representative measurement of the total sorbent injection rate.

(2) Conduct a performance evaluation of the sorbent 

injection rate monitoring system in accordance with your 

monitoring plan at the time of each performance test but no less 

frequently than annually.

(j) If you are not required to use a PM CPMS and elect to 

use a fabric filter bag leak detection system to comply with the 

requirements of this subpart, you must install, calibrate, 

maintain, and continuously operate the bag leak detection system 

as specified in paragraphs (j)(1) through (6) of this section.

(1) You must install a bag leak detection sensor(s) in a 

position(s) that will be representative of the relative or 

absolute particulate matter loadings for each exhaust stack, 

roof vent, or compartment (e.g., for a positive pressure fabric 

filter) of the fabric filter.
Page 212 of 360

(2) Conduct a performance evaluation of the bag leak 

detection system in accordance with your monitoring plan and 

consistent with the guidance provided in EPA-454/R-98-015 

(incorporated by reference, see §63.14).

(3) Use a bag leak detection system certified by the 

manufacturer to be capable of detecting particulate matter 

emissions at concentrations of 10 milligrams per actual cubic 

meter or less.

(4) Use a bag leak detection system equipped with a device 

to record continuously the output signal from the sensor.

(5) Use a bag leak detection system equipped with a system 

that will alert when an increase in relative particulate matter 

emissions over a preset level is detected. The alarm must be 

located where it can be easily heard or seen by plant operating 

personnel.

(6) Where multiple bag leak detectors are required, the 

system's instrumentation and alarm may be shared among 

detectors.

(k) For each unit that meets the definition of limited-use 

boiler or process heater, you must monitor and record the 

operating hours per year for that unit.

(l) For each unit for which you decide to demonstrate 

compliance with the mercury or hydrogen chloride emissions 

limits in Tables 1 or 2 of this subpart by use of a CEMS for 
Page 213 of 360

mercury or hydrogen chloride, you must install, certify,

maintain, and operate a CEMS measuring emissions discharged to 

the atmosphere and record the output of the system as specified 

in paragraphs (l)(1) through (8) of this section. For hydrogen 

chloride, this option for an affected unit takes effect on the 

date a final performance specification for a hydrogen chloride 

CEMS is published in the Federal Register or the date of 

approval of a site-specific monitoring plan.

(1) Notify the Administrator one month before starting use 

of the CEMS, and notify the Administrator one month before 

stopping use of the CEMS.

(2) Each CEMS shall be installed, certified, operated, and 

maintained according to the requirements in §63.7540(a)(14) for 

a mercury CEMS and §63.7540(a)(15) for a hydrogen chloride CEMS.

(3) For a new unit, you must complete the initial 

performance evaluation of the CEMS by the latest of the dates 

specified in paragraph (l)(3)(i) through (iii) of this section.

(i) No later than [INSERT THE DATE 240 DAYS AFTER 

PUBLICATION OF THE FINAL RULE IN THE FEDERAL REGISTER].

(ii) No later 180 days after the date of initial startup.

(iii) No later 180 days after notifying the Administrator 

before starting to use the CEMS in place of performance testing 

or fuel analysis to demonstrate compliance. 
Page 214 of 360

(4) For an existing unit, you must complete the initial 

performance evaluation by the latter of the two dates specified 

in paragraph (l)(4)(i) and (ii) of this section.

(i) No later than [INSERT THE DATE 3 YEARS AND 180 DAYS 

AFTER PUBLICATION OF THE FINAL RULE IN THE FEDERAL REGISTER].

(ii) No later 180 days after notifying the Administrator 

before starting to use the CEMS in place of performance testing 

or fuel analysis to demonstrate compliance. 

(5) Compliance with the applicable emissions limit shall be 

determined based on the 30-day rolling average of the hourly 

arithmetic average emissions rates using the continuous 

monitoring system outlet data. The 30-day rolling arithmetic 

average emission rate (lb/MMBtu) shall be calculated using the 

equations in EPA Reference Method 19 at 40 CFR part 60, appendix 

A-7, but substituting the mercury or hydrogen chloride 

concentration for the pollutant concentrations normally used in 

Method 19. 

(6) Collect CEMS hourly averages for all operating hours on 

a 30-day rolling average basis. Collect at least four CMS data 

values representing the four 15-minute periods in an hour, or at 

least two 15-minute data values during an hour when CMS 

calibration, quality assurance, or maintenance activities are 

being performed.
Page 215 of 360

(7) The one-hour arithmetic averages required shall be 

expressed in lb/MMBtu and shall be used to calculate the boiler 

operating day daily arithmetic average emissions.

(8) If you are using an add-on control to comply with the 

mercury or hydrogen chloride emission limit, you are allowed to 

substitute the use of the mercury or hydrogen chloride CEMS for 

the applicable fuel analysis, annual performance test, and 

operating limits specified in Table 4 to this subpart to 

demonstrate compliance with the mercury or hydrogen chloride 

emissions limit.

§63.7530 How do I demonstrate initial compliance with the 

emission limitations, fuel specifications and work practice 

standards?

(a) You must demonstrate initial compliance with each 

emission limit that applies to you by conducting initial 

performance tests and fuel analyses and establishing operating 

limits, as applicable, according to §63.7520, paragraphs (b) and 

(c) of this section, and Tables 5 and 7 to this subpart. If 

applicable, you must also install, operate, and maintain all 

applicable CMS (including CEMS, COMS, and continuous parameter 

monitoring systems) according to §63.7525.

(b) If you demonstrate compliance through performance

testing, you must establish each site-specific operating limit 

in Table 4 to this subpart that applies to you according to the 
Page 216 of 360

requirements in §63.7520, Table 7 to this subpart, and paragraph 

(b)(4) of this section, as applicable. You must also conduct 

fuel analyses according to §63.7521 and establish maximum fuel 

pollutant input levels according to paragraphs (b)(1) through

(3) of this section, as applicable, and as specified in 

§63.7510(a)(2). (Note that §63.7510(a)(2) exempts certain fuels 

from the fuel analysis requirements.) However, if you switch 

fuel(s) and cannot show that the new fuel(s) does (do) not 

increase the chlorine, mercury, or total selected metals input 

into the unit through the results of fuel analysis, then you 

must repeat the performance test to demonstrate compliance while 

burning the new fuel(s).

(1) You must establish the maximum chlorine fuel input 

(Clinput) during the initial fuel analysis according to the 

procedures in paragraphs (b)(1)(i) through (iii) of this 

section.

(i) You must determine the fuel type or fuel mixture that 

you could burn in your boiler or process heater that has the 

highest content of chlorine.

(ii) During the fuel analysis for hydrogen chloride, you 

must determine the fraction of the total heat input for each 

fuel type burned (Qi) based on the fuel mixture that has the 

highest content of chlorine, and the average chlorine 

concentration of each fuel type burned (Ci).
Page 217 of 360

(iii) You must establish a maximum chlorine input level 

using Equation 7 of this section.

 



 

n

i

Clinput Ci Qi

1

(Eq. 7)

Where:

Clinput = Maximum amount of chlorine entering the boiler or 

process heater through fuels burned in units of 

pounds per million Btu.

Ci = Arithmetic average concentration of chlorine in fuel 

type, i, analyzed according to §63.7521, in units of 

pounds per million Btu.

Qi = Fraction of total heat input from fuel type, i, 

based on the fuel mixture that has the highest 

content of chlorine. If you do not burn multiple 

fuel types during the performance testing, it is not 

necessary to determine the value of this term. 

Insert a value of “1” for Qi.

n = Number of different fuel types burned in your boiler 

or process heater for the mixture that has the 

highest content of chlorine.

(2) You must establish the maximum mercury fuel input level 

(Mercuryinput) during the initial fuel analysis using the 

procedures in paragraphs (b)(2)(i) through (iii) of this 

section.

(i) You must determine the fuel type or fuel mixture that 

you could burn in your boiler or process heater that has the 

highest content of mercury. 

(ii) During the compliance demonstration for mercury, you 

must determine the fraction of total heat input for each fuel 

burned (Qi) based on the fuel mixture that has the highest 
Page 218 of 360

content of mercury, and the average mercury concentration of 

each fuel type burned (HGi).

(iii) You must establish a maximum mercury input level 

using Equation 8 of this section.

 



 

n

i

Mercuryinput HGi Qi

1

(Eq. 8)

Where:

Mercuryinput = Maximum amount of mercury entering the boiler 

or process heater through fuels burned in units of 

pounds per million Btu.

HGi = Arithmetic average concentration of mercury in fuel 

type, i, analyzed according to §63.7521, in units of 

pounds per million Btu.

Qi = Fraction of total heat input from fuel type, i, based 

on the fuel mixture that has the highest mercury 

content. If you do not burn multiple fuel types 

during the performance test, it is not necessary to 

determine the value of this term. Insert a value of 

“1” for Qi.

n = Number of different fuel types burned in your boiler 

or process heater for the mixture that has the 

highest content of mercury.

(3) If you opt to comply with the alternative total 

selected metals limit, you must establish the maximum total 

selected metals fuel input (TSMinput) for solid fuels during the 

initial fuel analysis according to the procedures in paragraphs 

(b)(3)(i) through (iii) of this section.

(i) You must determine the fuel type or fuel mixture that 

you could burn in your boiler or process heater that has the 

highest content of total selected metals.
Page 219 of 360

(ii) During the fuel analysis for total selected metals, 

you must determine the fraction of the total heat input for each 

fuel type burned (Qi) based on the fuel mixture that has the 

highest content of total selected metals, and the average total 

selected metals concentration of each fuel type burned (TSMi).

(iii) You must establish a maximum total selected metals

input level using Equation 9 of this section.

 



 

n

i

TSMinput TSMi Qi

1

(Eq. 9)

Where:

TSMinput = Maximum amount of total selected metals entering the 

boiler or process heater through fuels burned in 

units of pounds per million Btu.

TSMi = Arithmetic average concentration of total selected 

metals in fuel type, i, analyzed according to 

§63.7521, in units of pounds per million Btu.

Qi = Fraction of total heat input from fuel type, i, 

based on the fuel mixture that has the highest 

content of total selected metals. If you do not burn 

multiple fuel types during the performance testing, 

it is not necessary to determine the value of this 

term. Insert a value of “1” for Qi.

n = Number of different fuel types burned in your boiler 

or process heater for the mixture that has the 

highest content of total selected metals.

(4) You must establish parameter operating limits according 

to paragraphs (b)(4)(i) through (vii) of this section. As 

indicated in Table 4 to this subpart, you are not required to 

establish and comply with the operating parameter limits when
Page 220 of 360

you are using a CEMS to monitor and demonstrate compliance with 

the applicable emission limit for that control device parameter.

(i) For a wet acid gas scrubber, you must establish the 

minimum scrubber effluent pH and liquid flow rate as defined in 

§63.7575, as your operating limits during the three-run 

performance test during which you demonstrate compliance with 

your applicable limit. If you use a wet scrubber and you conduct 

separate performance tests for hydrogen chloride and mercury 

emissions, you must establish one set of minimum scrubber 

effluent pH, liquid flow rate, and pressure drop operating 

limits. The minimum scrubber effluent pH operating limit must be 

established during the hydrogen chloride performance test. If 

you conduct multiple performance tests, you must set the minimum 

liquid flow rate operating limit at the higher of the minimum 

values established during the performance tests.

(ii) For any particulate control device (e.g., ESP, 

particulate wet scrubber, fabric filter) for which you use a PM 

CPMS, you must establish your operating limit during the threerun performance during which you demonstrate compliance with 

your applicable limit. The PM CPMS operating limit is the 1-hour 

average PM CPMS output value recorded during the performance 

test. If you conduct separate performance tests for PM and total 

selected metals, you must set the maximum PM CPMS operating 
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limits at the lower of maximum PM CPMS values established during 

the performance tests.

(iii) For a particulate wet scrubber, you must establish 

the minimum pressure drop and liquid flow rate as defined in 

§63.7575, as your operating limits during the three-run 

performance test during which you demonstrate compliance with 

your applicable limit. If you use a wet scrubber and you conduct 

separate performance tests for particulate matter and total 

selected metals emissions, you must establish one set of minimum 

scrubber liquid flow rate and pressure drop operating limits. 

The minimum scrubber effluent pH operating limit must be 

established during the hydrogen chloride performance test. If 

you conduct multiple performance tests, you must set the minimum 

liquid flow rate and pressure drop operating limits at the 

higher of the minimum values established during the performance 

tests. 

(iv) For an electrostatic precipitator operated with a wet 

scrubber, you must establish the minimum voltage and secondary 

amperage (or total power input), as defined in §63.7575, as your 

operating limits during the three-run performance test during 

which you demonstrate compliance with your applicable limit. 

(These operating limits do not apply to electrostatic 

precipitators that are operated as dry controls without a wet 

scrubber.)
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(v) For a dry scrubber, you must establish the minimum 

sorbent injection rate for each sorbent, as defined in §63.7575, 

as your operating limit during the three-run performance test

during which you demonstrate compliance with your applicable 

limit.

(vi) For activated carbon injection, you must establish the 

minimum activated carbon injection rate, as defined in §63.7575, 

as your operating limit during the three-run performance test

during which you demonstrate compliance with your applicable 

limit.

(vii) The operating limit for boilers or process heaters 

with fabric filters that demonstrate continuous compliance 

through bag leak detection systems is that a bag leak detection 

system be installed according to the requirements in §63.7525,

and that each fabric filter must be operated such that the bag 

leak detection system alarm does not sound more than 5 percent 

of the operating time during a 6-month period.

(c) If you elect to demonstrate compliance with an 

applicable emission limit through fuel analysis, you must 

conduct fuel analyses according to §63.7521 and follow the 

procedures in paragraphs (c)(1) through (5) of this section.

(1) If you burn more than one fuel type, you must determine 

the fuel mixture you could burn in your boiler or process heater 

that would result in the maximum emission rates of the 
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pollutants that you elect to demonstrate compliance through fuel 

analysis.

(2) You must determine the 90th percentile confidence level 

fuel pollutant concentration of the composite samples analyzed 

for each fuel type using the one-sided z-statistic test 

described in Equation 10 of this section.

P90  mean  SD  t (Eq. 10)

Where:

P90 = 90th percentile confidence level pollutant 

concentration, in pounds per million Btu.

Mean = Arithmetic average of the fuel pollutant 

concentration in the fuel samples analyzed according 

to §63.7521, in units of pounds per million Btu.

SD = Standard deviation of the pollutant concentration in 

the fuel samples analyzed according to §63.7521, in 

units of pounds per million Btu.

T = t distribution critical value for 90th percentile 

(0.1) probability for the appropriate degrees of 

freedom (number of samples minus one) as obtained 

from a Distribution Critical Value Table.

(3) To demonstrate compliance with the applicable emission 

limit for hydrogen chloride, the hydrogen chloride emission rate 

that you calculate for your boiler or process heater using 

Equation 11 of this section must not exceed the applicable 

emission limit for hydrogen chloride.

 



  

n

i

HCl Ci Qi

1

90 1.028 (Eq. 11)

Where:
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HCl = Hydrogen chloride emission rate from the boiler or 

process heater in units of pounds per million Btu.

Ci90 = 90th percentile confidence level concentration of 

chlorine in fuel type, i, in units of pounds per 

million Btu as calculated according to Equation 10 of 

this section.

Qi = Fraction of total heat input from fuel type, i, based 

on the fuel mixture that has the highest content of 

chlorine. If you do not burn multiple fuel types, it 

is not necessary to determine the value of this term. 

Insert a value of “1” for Qi.

n = Number of different fuel types burned in your boiler 

or process heater for the mixture that has the 

highest content of chlorine.

1.028 = Molecular weight ratio of hydrogen chloride to 

chlorine.

(4) To demonstrate compliance with the applicable emission 

limit for mercury, the mercury emission rate that you calculate 

for your boiler or process heater using Equation 12 of this 

section must not exceed the applicable emission limit for 

mercury.

 



 

n

i

Mercury Hgi Qi

1

90 (Eq. 12)

Where:

Mercury = Mercury emission rate from the boiler or process 

heater in units of pounds per million Btu.

Hgi90 = 90th percentile confidence level concentration of 

mercury in fuel, i, in units of pounds per million 

Btu as calculated according to Equation 10 of this 

section.

Qi = Fraction of total heat input from fuel type, i, 

based on the fuel mixture that has the highest 

mercury content. If you do not burn multiple fuel 
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types, it is not necessary to determine the value of 

this term. Insert a value of “1” for Qi.

n = Number of different fuel types burned in your boiler 

or process heater for the mixture that has the 

highest mercury content.

(5) To demonstrate compliance with the applicable emission 

limit for total selected metals for solid fuels, the total 

selected metals emission rate that you calculate for your boiler 

or process heater from solid fuels using Equation 13 of this 

section must not exceed the applicable emission limit for total 

selected metals.

 



 

n

i

Metals TSM i Qi

1

90 (Eq. 13)

Where:

Metals = Total selected metals emission rate from the boiler 

or process heater in units of pounds per million 

Btu.

TSMi90 = 90th percentile confidence level concentration of 

total selected metals in fuel, i, in units of pounds 

per million Btu as calculated according to Equation 

10 of this section.

Qi = Fraction of total heat input from fuel type, i, 

based on the fuel mixture that has the highest total 

selected metals content. If you do not burn multiple 

fuel types, it is not necessary to determine the 

value of this term. Insert a value of “1” for Qi.

n = Number of different fuel types burned in your boiler 

or process heater for the mixture that has the 

highest total selected metals content.

(d) If you own or operate an existing unit with a heat 

input capacity of less than 10 million Btu per hour, you must 

submit a signed statement in the Notification of Compliance 
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Status report that indicates that you conducted a tune-up of the 

unit.

(e) You must include with the Notification of Compliance 

Status a signed certification that the energy assessment was 

completed according to Table 3 to this subpart and is an 

accurate depiction of your facility.

(f) You must submit the Notification of Compliance Status 

containing the results of the initial compliance demonstration 

according to the requirements in §63.7545(e).

(g) If you elect to demonstrate that a gaseous fuel meets 

the specifications of an other gas 1 fuel as defined in 

§63.7575, you must conduct an initial fuel specification 

analyses according to §63.7521(f) through (i). If the mercury 

constituents in the gaseous fuels will never exceed the 

specification included in the definition, you will include a 

signed certification with the Notification of Compliance Status 

that the initial fuel specification test meets the gas 

specification outlined in the definition of other gas 1 fuels. 

If your gas constituents could vary above the specification, you 

will conduct monthly testing according to the procedures in 

§63.7521(f) through (i) and §63.7540(c) and maintain records of 

the results of the testing as outlined in §63.7555(g).

(h) If you own or operate a unit subject to emission limits 

in Tables 1 or 2 to this subpart, you must meet the work 
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practice standard according to Table 3 of this subpart. You must 

submit a signed statement in the Notification of Compliance 

Status report that indicates that you employed good combustion 

practices and you maintained oxygen concentrations as specified 

by the boiler manufacturer for each startup and shutdown event. 

§63.7533 Can I use emission credits earned from implementation 

of energy conservation measures to comply with this subpart?

(a) If you elect to comply with the alternative equivalent 

steam output-based emission limits, instead of the heat inputbased limits listed in Table 2 to this subpart, and you want to 

take credit for implementing energy conservation measures 

identified in an energy assessment, you may demonstrate 

compliance using emission reduction credits according to the 

procedures in this section. You may use this compliance approach 

for an existing affected boiler for demonstrating initial 

compliance according to §63.7522(e) and for demonstrating 

monthly compliance according to §63.7522(f). Owners or operators 

using this compliance approach must establish an emissions 

benchmark, calculate and document the emission credits, develop 

an Implementation Plan, comply with the general reporting 

requirements, and apply the emission credit according to the 

procedures in paragraphs (b) through (f) of this section. You 

cannot use this compliance approach for a new or reconstructed 

affected boiler.
Page 228 of 360

(b) For each existing affected boiler for which you intend 

to apply emissions credits, establish a benchmark from which 

emission reduction credits may be generated by determining the 

actual annual fuel heat input to the affected boiler before 

initiation of an energy conservation activity to reduce energy 

demand (i.e., fuel usage) according to paragraphs (b)(1) through 

(4) of this section. The benchmark shall be expressed in 

trillion Btu per year heat input.

(1) The benchmark from which emission credits may be 

generated shall be determined by using the most representative, 

accurate, and reliable process available for the source. The 

benchmark shall be established for a one-year period before the 

date that an energy demand reduction occurs, unless it can be 

demonstrated that a different time period is more representative 

of historical operations.

(2) Determine the starting point from which to measure 

progress. Inventory all fuel purchased and generated on-site 

(off-gases, residues) in physical units (MMBtu, million cubic 

feet, etc.).

(3) Document all uses of energy from the affected boiler. 

Use the most recent data available.

(4) Collect non-energy related facility and operational 

data to normalize, if necessary, the benchmark to current 

operations, such as building size, operating hours, etc. If
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possible, use actual data that are current and timely rather 

than estimated data.

(c) Emissions credits can be generated if the energy 

conservation measures were implemented after January 1, 2008 and 

if sufficient information is available to determine the 

appropriate value of credits.

(1) The following emission points cannot be used to 

generate emissions averaging credits:

(i) Energy conservation measures implemented on or before 

January 1, 2008, unless the level of energy demand reduction is 

increased after January 1, 2008, in which case credit will be 

allowed only for change in demand reduction achieved after 

January 1, 2008.

(ii) Emission credits on shut-down boilers. Boilers that 

are shut down cannot be used to generate credits.

(2) For all points included in calculating emissions 

credits, the owner or operator shall:

(i) Calculate annual credits for all energy demand points. 

Use Equation 14 to calculate credits. Energy conservation 

measures that meet the criteria of paragraph (c)(1) of this 

section shall not be included, except as specified in paragraph 

(c)(1)(i) of this section.

(3) Credits are generated by the difference between the 

benchmark that is established for each affected boiler, and the 
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actual energy demand reductions from energy conservation 

measures implemented after January 1, 2008. Credits shall be 

calculated using Equation 14 of this section as follows:

(i) The overall equation for calculating credits is:

baseline

n

i

ECredits EISiactual  EI 















 1

(Eq. 14)

where:

ECredits = Energy Input Savings for all energy conservation 

measures implemented for an affected boiler, 

expressed as a decimal fraction of the baseline 

energy input.

EISiactual = Energy Input Savings for each energy 

conservation measure, i, implemented for an 

affected boiler, million Btu per year.

EIbaseline = Energy Input baseline for the affected boiler, 

million Btu per year.

n = Number of energy conservation measures included 

in the emissions credit for the affected boiler.

(d) The owner or operator shall develop and submit for 

approval an Implementation Plan containing all of the 

information required in this paragraph for all boilers to be 

included in an emissions credit approach. The Implementation 

Plan shall identify all existing affected boilers to be included 

in applying the emissions credits. The Implementation Plan shall 

include a description of the energy conservation measures 

implemented and the energy savings generated from each measure 

and an explanation of the criteria used for determining that 
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savings. You must submit the implementation plan for emission 

credits to the applicable delegated authority for review and 

approval no later than 180 days before the date on which the 

facility intends to demonstrate compliance using the emission 

credit approach.

(e) The emissions rate as calculated using Equation 15 of 

this section from each existing boiler participating in the 

emissions credit option must be in compliance with the limits in 

Table 2 to this subpart at all times following the compliance 

date specified in §63.7495.

(f) You must use Equation 15 of this section to demonstrate 

initial compliance by demonstrating that the emissions from the 

affected boiler participating in the emissions credit compliance 

approach do not exceed the emission limits in Table 2 to this 

subpart.

E E  ECredits  adj  m  1  (Eq. 15)

where:

Eadj = Emission level adjusted by applying the emission 

credits earned, lb per million Btu steam output for 

the affected boiler.

Em = Emissions measured during the performance test, lb 

per million Btu steam output for the affected boiler.

ECredits = Emission credits from Equation 14 for the affected 

boiler.

Continuous Compliance Requirements
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§63.7535 Is there a minimum amount of monitoring data I must 

obtain?

(a) You must monitor and collect data according to this 

section and the site-specific monitoring plan required by 

§63.7505(d).

(b) You must operate the monitoring system and collect data 

at all required intervals at all times that the affected source 

is operating and compliance is required, except for periods of 

monitoring system malfunctions or out of control periods (see 

§63.8(c)(7) of this part), and required monitoring system 

quality assurance or control activities, including, as 

applicable, calibration checks, required zero and span 

adjustments, and scheduled CMS maintenance as defined in your 

site-specific monitoring plan. A monitoring system malfunction 

is any sudden, infrequent, not reasonably preventable failure of 

the monitoring system to provide valid data. Monitoring system 

failures that are caused in part by poor maintenance or careless 

operation are not malfunctions. You are required to complete

monitoring system repairs in response to monitoring system 

malfunctions or out-of-control periods and to return the 

monitoring system to operation as expeditiously as practicable.

(c) You may not use data recorded during monitoring system 

malfunctions or out-of-control periods, repairs associated with 

monitoring system malfunctions or out-of-control periods, or 
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required monitoring system quality assurance or control 

activities in data averages and calculations used to report 

emissions or operating levels. You must record and make 

available upon request results of CMS performance audits and

dates and duration of periods when the CMS is out of control to 

completion of the corrective actions necessary to return the CMS 

to operation consistent with your site-specific monitoring plan. 

You must use all the data collected during all other periods in 

assessing compliance and the operation of the control device and 

associated control system.

(d) Except for periods of monitoring system malfunctions, 

repairs associated with monitoring system malfunctions, and 

required monitoring system quality assurance or quality control 

activities (including, as applicable, system accuracy audits, 

calibration checks, and required zero and span adjustments), 

failure to collect required data is a deviation of the 

monitoring requirements.

§63.7540 How do I demonstrate continuous compliance with the 

emission limitations, fuel specifications and work practice 

standards?

(a) You must demonstrate continuous compliance with each 

emission limit in Tables 1 and 2 to this subpart, the work 

practice standards in Table 3 to this subpart, and the operating 

limits in Table 4 to this subpart that applies to you according 
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to the methods specified in Table 8 to this subpart and 

paragraphs (a)(1) through (17) of this section. 

(1) Following the date on which the initial compliance 

demonstration is completed or is required to be completed under 

§§63.7 and 63.7510, whichever date comes first, operation above 

the established maximum or below the established minimum 

operating limits shall constitute a deviation of established 

operating limits listed in Table 4 of this subpart except during 

performance tests conducted to determine compliance with the 

emission limits or to establish new operating limits. Operating 

limits must be confirmed or reestablished during performance

tests.

(2) As specified in §63.7550(c), you must keep records of 

the type and amount of all fuels burned in each boiler or 

process heater during the reporting period to demonstrate that 

all fuel types and mixtures of fuels burned would result in 

either of the following:

(i) Lower emissions of hydrogen chloride, mercury, and 

total selected metals than the applicable emission limit for 

each pollutant, if you demonstrate compliance through fuel 

analysis.

(ii) Lower fuel input of chlorine, mercury, and total 

selected metals than the maximum values calculated during the 
Page 235 of 360

last performance test, if you demonstrate compliance through 

performance testing.

(3) If you demonstrate compliance with an applicable 

hydrogen chloride emission limit through fuel analysis for a 

solid or liquid fuel and you plan to burn a new type of solid or 

liquid fuel, you must recalculate the hydrogen chloride emission 

rate using Equation 11 of §63.7530 according to paragraphs 

(a)(3)(i) through (iii) of this section. You are not required to 

complete fuel analyses for the fuels described in 

§63.7510(a)(2)(i) through (iii). You may exclude the fuels 

described in §63.7510(a)(2)(i) through (iii) when recalculating 

the hydrogen chloride emission rate.

(i) You must determine the chlorine concentration for any 

new fuel type in units of pounds per million Btu, based on 

supplier data or your own fuel analysis, according to the 

provisions in your site-specific fuel analysis plan developed 

according to §63.7521(b).

(ii) You must determine the new mixture of fuels that will 

have the highest content of chlorine.

(iii) Recalculate the hydrogen chloride emission rate from 

your boiler or process heater under these new conditions using 

Equation 11 of §63.7530. The recalculated hydrogen chloride

emission rate must be less than the applicable emission limit.
Page 236 of 360

(4) If you demonstrate compliance with an applicable 

hydrogen chloride emission limit through performance testing and 

you plan to burn a new type of fuel or a new mixture of fuels, 

you must recalculate the maximum chlorine input using Equation 7 

of §63.7530. If the results of recalculating the maximum 

chlorine input using Equation 7 of §63.7530 are greater than the 

maximum chlorine input level established during the previous 

performance test, then you must conduct a new performance test 

within 60 days of burning the new fuel type or fuel mixture 

according to the procedures in §63.7520 to demonstrate that the 

hydrogen chloride emissions do not exceed the emission limit. 

You must also establish new operating limits based on this 

performance test according to the procedures in §63.7530(b). In 

recalculating the maximum chlorine input and establishing the 

new operating limits, you are not required to complete fuel 

analyses for and include the fuels described in 

§63.7510(a)(2)(i) through (iii). 

(5) If you demonstrate compliance with an applicable 

mercury emission limit through fuel analysis, and you plan to 

burn a new type of fuel, you must recalculate the mercury 

emission rate using Equation 12 of §63.7530 according to the 

procedures specified in paragraphs (a)(5)(i) through (iii) of 

this section. You are not required to complete fuel analyses for 

the fuels described in §63.7510(a)(2)(i) through (iii). You may 
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exclude the fuels described in §63.7510(a)(2)(i) through (iii) 

when recalculating the mercury emission rate.

(i) You must determine the mercury concentration for any 

new fuel type in units of pounds per million Btu, based on 

supplier data or your own fuel analysis, according to the 

provisions in your site-specific fuel analysis plan developed 

according to §63.7521(b).

(ii) You must determine the new mixture of fuels that will 

have the highest content of mercury.

(iii) Recalculate the mercury emission rate from your 

boiler or process heater under these new conditions using 

Equation 12 of §63.7530. The recalculated mercury emission rate

must be less than the applicable emission limit.

(6) If you demonstrate compliance with an applicable 

mercury emission limit through performance testing, and you plan 

to burn a new type of fuel or a new mixture of fuels, you must 

recalculate the maximum mercury input using Equation 8 of 

§63.7530. If the results of recalculating the maximum mercury 

input using Equation 8 of §63.7530 are higher than the maximum 

mercury input level established during the previous performance

test, then you must conduct a new performance test within 60 

days of burning the new fuel type or fuel mixture according to 

the procedures in §63.7520 to demonstrate that the mercury 

emissions do not exceed the emission limit. You must also 
Page 238 of 360

establish new operating limits based on this performance test 

according to the procedures in §63.7530(b). You are not required 

to complete fuel analyses for the fuels described in 

§63.7510(a)(2)(i) through (iii). You may exclude the fuels 

described in §63.7510(a)(2)(i) through (iii) when recalculating 

the mercury emission rate.

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

you demonstrate continuous compliance using a bag leak detection 

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

bag leak detection system alarm and complete corrective actions 

as soon as practical, and operate and maintain the fabric filter 

system such that the alarm does not sound more than 5 percent of 

the operating time during a 6-month period. You must also keep 

records of the date, time, and duration of each alarm, the time 

corrective action was initiated and completed, and a brief 

description of the cause of the alarm and the corrective action 

taken. You must also record the percent of the operating time 

during each 6-month period that the alarm sounds. In calculating 

this operating time percentage, if inspection of the fabric 

filter demonstrates that no corrective action is required, no 

alarm time is counted. If corrective action is required, each 

alarm shall be counted as a minimum of 1 hour. If you take 

longer than 1 hour to initiate corrective action, the alarm time 
Page 239 of 360

shall be counted as the actual amount of time taken to initiate 

corrective action.

(8) If you install a CO CEMS according to §63.7525(a), then 

you must meet the requirements in paragraphs (a)(8)(i) through 

(iii) of this section.

(i) Continuously monitor CO according to §§63.7525(a) and 

63.7535.

(ii) Maintain a CO emission level below or at your 

applicable alternative CO CEMS-based standard in Tables 1 or 2 

to this subpart at all times.

(iii) Keep records of CO levels according to §63.7555(b).

(9) The owner or operator of an affected source using a PM 

CPMS to meet requirements of this subpart shall install, 

certify, operate, and maintain the PM CPMS in accordance with 

your site-specific monitoring plan as required in §63.7505(d).

(10) If your boiler or process heater is in either the 

natural gas, refinery gas, other gas 1, or Metal Process Furnace 

subcategories and has a heat input capacity of 10 million Btu 

per hour or greater, you must conduct a tune-up of the boiler or 

process heater annually to demonstrate continuous compliance as 

specified in paragraphs (a)(10)(i) through (a)(10)(vi) of this 

section. This requirement does not apply to limited-use boilers 

and process heaters, as defined in §63.7575.
Page 240 of 360

(i) As applicable, inspect the burner, and clean or replace 

any components of the burner as necessary (you may delay the 

burner inspection until the next scheduled or unscheduled unit 

shutdown);

(ii) Inspect the flame pattern, as applicable, and adjust 

the burner as necessary to optimize the flame pattern. The 

adjustment should be consistent with the manufacturer’s 

specifications, if available;

(iii) Inspect the system controlling the air-to-fuel ratio, 

as applicable, and ensure that it is correctly calibrated and 

functioning properly;

(iv) Optimize total emissions of carbon monoxide. This 

optimization should be consistent with the manufacturer’s 

specifications, if available;

(v) Measure the concentrations in the effluent stream of 

carbon monoxide in parts per million, by volume, and oxygen in 

volume percent, before and after the adjustments are made 

(measurements may be either on a dry or wet basis, as long as it 

is the same basis before and after the adjustments are made); 

and

(vi) Maintain on-site and submit, if requested by the 

Administrator, an annual report containing the information in 

paragraphs (a)(10)(vi)(A) through (C) of this section,
Page 241 of 360

(A) The concentrations of carbon monoxide in the effluent 

stream in parts per million by volume, and oxygen in volume 

percent, measured before and after the adjustments of the 

boiler;

(B) A description of any corrective actions taken as a part 

of the combustion adjustment; and

(C) The type and amount of fuel used over the 12 months 

prior to the annual adjustment, but only if the unit was 

physically and legally capable of using more than one type of 

fuel during that period. Units sharing a fuel meter may estimate 

the fuel used by each unit.

(11) If your boiler or process heater has a heat input 

capacity of less than 10 million Btu per hour (except as 

specified in paragraph (a)(12) of this section), or meets the 

definition of limited-use boiler or process heater in §63.7575, 

you must conduct a biennial tune-up of the boiler or process 

heater as specified in paragraphs (a)(10)(i) through (a)(10)(vi) 

of this section to demonstrate continuous compliance.

(12) If your boiler or process heater has a heat input 

capacity of less than 5 million Btu per hour, and the unit is in 

the units designed to burn natural gas, refinery gas or other 

gas 1 fuels, units designed to burn gas 2 (other), or units 

designed to burn light liquid subcategories, you must conduct a 

tune-up of the boiler or process heater every 5 years as 
Page 242 of 360

specified in paragraphs (a)(10)(i) through (a)(10)(vi) of this 

section to demonstrate continuous compliance. You may delay the 

burner inspection specified in paragraph (a)(10)(i) of this 

section until the next scheduled or unscheduled unit shutdown, 

but you must inspect each burner at least once every 72 months.

(13) If the unit is not operating on the required date for 

a tune-up, the tune-up must be conducted within one week of 

startup.

(14) If you are using a CEMS measuring mercury emissions to 

meet requirements of this subpart you must install, certify, 

operate, and maintain the mercury CEMS as specified in 

paragraphs (a)(14)(i) and (ii) of this section.

(i) Operate the mercury CEMS in accordance with performance 

specification 12A of 40 CFR part 60, appendix B or operate a 

sorbent trap based integrated monitor in accordance with 

performance specification 12B of 40 CFR part 60, appendix B. The 

duration of the performance test must be a calendar month. For 

each calendar month in which the unit operates, you must obtain 

hourly mercury concentration data, and stack gas volumetric flow 

rate data.

(ii) If you are using a mercury CEMS, you must install, 

operate, calibrate, and maintain an instrument for continuously 

measuring and recording the mercury mass emissions rate to the 

atmosphere according to the requirements of performance
Page 243 of 360

specifications 6 and 12A of 40 CFR part 60, appendix B, and 

quality assurance procedure 6 of 40 CFR part 60, appendix F.

(15) If you are using a CEMS to measure hydrogen chloride 

emissions to meet requirements of this subpart, you must 

install, certify, operate, and maintain the hydrogen chloride 

CEMS as specified in paragraphs (a)(15)(i) and (ii) of this 

section. This option for an affected unit takes effect on the 

date a final performance specification for a hydrogen chloride 

CEMS is published in the Federal Register or the date of 

approval of a site-specific monitoring plan.

(i) Operate the continuous emissions monitoring system in 

accordance with the applicable performance specification in 40

CFR part 60, appendix B. The duration of the performance test 

must be a calendar month. For each calendar month in which the 

unit operates, you must obtain hourly hydrogen chloride 

concentration data, and stack gas volumetric flow rate data.

(ii) If you are using a hydrogen chloride continuous 

emissions monitoring system, you must install, operate,

calibrate, and maintain an instrument for continuously measuring 

and recording the hydrogen chloride mass emissions rate to the 

atmosphere according to the requirements of the applicable 

performance specification of 40 CFR part 60, appendix B, and the 

quality assurance procedures of 40 CFR part 60, appendix F.
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(16) If you demonstrate compliance with an applicable total 

selected metals emission limit through performance testing, and 

you plan to burn a new type of fuel or a new mixture of fuels, 

you must recalculate the maximum total selected metals input 

using Equation 9 of §63.7530. If the results of recalculating 

the maximum total selected metals input using Equation 9 of 

§63.7530 are higher than the maximum total selected input level 

established during the previous performance test, then you must 

conduct a new performance test within 60 days of burning the new 

fuel type or fuel mixture according to the procedures in 

§63.7520 to demonstrate that the total selected metals emissions 

do not exceed the emission limit. You must also establish new 

operating limits based on this performance test according to the 

procedures in §63.7530(b). You are not required to complete fuel 

analyses for the fuels described in §63.7510(a)(2)(i) through 

(iii). You may exclude the fuels described in §63.7510(a)(2)(i) 

through (iii) when recalculating the total selected metals 

emission rate.

(17) If you demonstrate compliance with an applicable total 

selected metals emission limit through fuel analysis for solid 

fuels, and you plan to burn a new type of fuel, you must 

recalculate the total selected metals emission rate using 

Equation 13 of §63.7530 according to the procedures specified in 

paragraphs (a)(5)(i) through (iii) of this section. You are not 
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required to complete fuel analyses for the fuels described in 

§63.7510(a)(2)(i) through (iii). You may exclude the fuels 

described in §63.7510(a)(2)(i) through (iii) when recalculating 

the total selected metals emission rate.

(i) You must determine the total selected metals

concentration for any new fuel type in units of pounds per 

million Btu, based on supplier data or your own fuel analysis, 

according to the provisions in your site-specific fuel analysis 

plan developed according to §63.7521(b).

(ii) You must determine the new mixture of fuels that will 

have the highest content of total selected metals.

(iii) Recalculate the total selected metals emission rate 

from your boiler or process heater under these new conditions 

using Equation 13 of §63.7530. The recalculated total selected 

metals emission rate must be less than the applicable emission 

limit. 

(b) You must report each instance in which you did not meet 

each emission limit and operating limit in Tables 1 through 4 to 

this subpart that apply to you. These instances are deviations 

from the emission limits or operating limits, respectively, in 

this subpart. These deviations must be reported according to the 

requirements in §63.7550.

(c) If you elected to demonstrate that the unit meets the

specification for mercury for the other gas 1 subcategory and 
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you cannot submit a signed certification under §63.7545(g) 

because the constituents could exceed the specification, you 

must conduct monthly fuel specification testing of the gaseous 

fuels, according to the procedures in §63.7521(f) through (i).

(d) For periods of startup and shutdown, you must meet the 

work practice standards according to Table 3 of this subpart.

§63.7541 How do I demonstrate continuous compliance under the 

emissions averaging provision?

(a) Following the compliance date, the owner or operator 

must demonstrate compliance with this subpart on a continuous 

basis by meeting the requirements of paragraphs (a)(1) through 

(5) of this section.

(1) For each calendar month, demonstrate compliance with 

the average weighted emissions limit for the existing units 

participating in the emissions averaging option as determined in 

§63.7522(f) and (g).

(2) You must maintain the applicable opacity limit 

according to paragraphs (a)(2)(i) and (ii) of this section.

(i) For each existing unit participating in the emissions 

averaging option that is equipped with a dry control system and 

not vented to a common stack, maintain opacity at or below the 

applicable limit.

(ii) For each group of units participating in the emissions 

averaging option where each unit in the group is equipped with a 
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dry control system and vented to a common stack that does not 

receive emissions from non-affected units, maintain opacity at 

or below the applicable limit at the common stack.

(3) For each existing unit participating in the emissions 

averaging option that is equipped with a wet scrubber, maintain 

the 30-day rolling average parameter values at or below the 

operating limits established during the most recent performance

test.

(4) For each existing unit participating in the emissions 

averaging option that has an approved alternative operating 

plan, maintain the 30-day rolling average parameter values at or 

below the operating limits established in the most recent 

performance test.

(5) For each existing unit participating in the emissions 

averaging option venting to a common stack configuration 

containing affected units from other subcategories, maintain the 

appropriate operating limit for each unit as specified in Table 

4 to this subpart that applies.

(b) Any instance where the owner or operator fails to 

comply with the continuous monitoring requirements in paragraphs 

(a)(1) through (5) of this section is a deviation.

Notification, Reports, and Records

§63.7545 What notifications must I submit and when?
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(a) You must submit to the delegated authority all of the 

notifications in §63.7(b) and (c), §63.8(e), (f)(4) and (6), and 

§63.9(b) through (h) that apply to you by the dates specified.

(b) As specified in §63.9(b)(2), if you startup your 

affected source before [INSERT THE DATE 60 DAYS AFTER THE DATE 

OF PUBLICATION OF THE FINAL RULE IN THE FEDERAL REGISTER], you 

must submit an Initial Notification not later than 120 days 

after [INSERT THE DATE 60 DAYS AFTER THE DATE OF PUBLICATION OF 

THE FINAL RULE IN THE FEDERAL REGISTER].

(c) As specified in §63.9(b)(4) and (b)(5), if you startup 

your new or reconstructed affected source on or after [INSERT 

THE DATE 60 DAYS AFTER PUBLICATION OF THE FINAL RULE IN THE 

FEDERAL REGISTER], you must submit an Initial Notification not 

later than 15 days after the actual date of startup of the 

affected source.

(d) If you are required to conduct a performance test you 

must submit a Notification of Intent to conduct a performance 

test at least 60 days before the performance test is scheduled 

to begin.

(e) If you are required to conduct an initial compliance 

demonstration as specified in §63.7530(a), you must submit a 

Notification of Compliance Status according to §63.9(h)(2)(ii). 

For the initial compliance demonstration for each affected 

source, you must submit the Notification of Compliance Status, 
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including all performance test results and fuel analyses, before 

the close of business on the 60th day following the completion 

of all performance test and/or other initial compliance 

demonstrations for the affected source according to 

§63.10(d)(2). The Notification of Compliance Status report must 

contain all the information specified in paragraphs (e)(1) 

through (8), as applicable.

(1) A description of the affected unit(s) including 

identification of which subcategory the unit is in, the design 

heat input capacity of the unit, a description of the add-on 

controls used on the unit, description of the fuel(s) burned, 

including whether the fuel(s) were determined by you or EPA 

through a petition process to be a non-waste under §241.3, 

whether the fuel(s) were processed from discarded non-hazardous 

secondary materials within the meaning of §241.3, and 

justification for the selection of fuel(s) burned during the 

compliance demonstration.

(2) Summary of the results of all performance tests and

fuel analyses, and calculations conducted to demonstrate initial 

compliance including all established operating limits.

(3) A summary of the maximum carbon monoxide emission 

levels recorded during the performance test to show that you 

have met any applicable emission standard in Table 1 or 2 to 
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this subpart, if you are not using a CO CEMS to demonstrate 

compliance.

(4) Identification of whether you plan to demonstrate 

compliance with each applicable emission limit through 

performance testing, a CEMS, or fuel analysis.

(5) Identification of whether you plan to demonstrate 

compliance by emissions averaging and identification of whether 

you plan to demonstrate compliance by using emission credits 

through energy conservation:

(i) If you plan to demonstrate compliance by emission 

averaging, report the emission level that was being achieved or 

the control technology employed on [INSERT THE DATE 60 DAYS 

AFTER PUBLICATION OF THE FINAL RULE IN THE FEDERAL REGISTER].

(6) A signed certification that you have met all applicable 

emission limits and work practice standards.

(7) If you had a deviation from any emission limit, work 

practice standard, or operating limit, you must also submit a 

description of the deviation, the duration of the deviation, and 

the corrective action taken in the Notification of Compliance 

Status report.

(8) In addition to the information required in §63.9(h)(2),

your notification of compliance status must include the 

following certification(s) of compliance, as applicable, and 

signed by a responsible official:
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(i) “This facility complies with the requirements in 

§63.7540(a)(10), (a)(11), or (a)(12) to conduct an annual,

biennial, or 5-year tune-up, as applicable, of each unit.”

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

according to §63.7530(e).”

(iii) Except for units that qualify for a statutory 

exemption as provided in section 129(g)(1) of the Clean Air Act, 

include the following: “No secondary materials that are solid 

waste were combusted in any affected unit.”

(f) If you operate a unit designed to burn natural gas, 

refinery gas, or other gas 1 fuels that is subject to this 

subpart, and you intend to use a fuel other than natural gas, 

refinery gas, gaseous fuel subject to another subpart of this 

part, or other gas 1 fuel to fire the affected unit during a 

period of natural gas curtailment or supply interruption, as 

defined in §63.7575, you must submit a notification of 

alternative fuel use within 48 hours of the declaration of each

period of natural gas curtailment or supply interruption, as 

defined in §63.7575. The notification must include the 

information specified in paragraphs (f)(1) through (5) of this 

section.

(1) Company name and address.

(2) Identification of the affected unit.
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(3) Reason you are unable to use natural gas or equivalent 

fuel, including the date when the natural gas curtailment was 

declared or the natural gas supply interruption began.

(4) Type of alternative fuel that you intend to use.

(5) Dates when the alternative fuel use is expected to 

begin and end.

(g) If you intend to commence or recommence combustion of 

solid waste, you must provide 30 days prior notice of the date 

upon which you will commence or recommence combustion of solid 

waste. The notification must identify:

(1) The name of the owner or operator of the affected 

source, the location of the source, the boiler(s) or process 

heater(s) that will commence burning solid waste, and the date 

of the notice.

(2) The currently applicable subcategory under this 

subpart.

(3) The date on which you became subject to the currently 

applicable emission limits.

(4) The date upon which you will commence combusting solid 

waste.

(h) If you intend to switch fuels, and this fuel switch may 

result in the applicability of a different subcategory, you must 

provide 30 days prior notice of the date upon which you will 

switch fuels. The notification must identify:
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(1) The name of the owner or operator of the affected 

source, the location of the source, the boiler(s) that will 

switch fuels, and the date of the notice.

(2) The currently applicable subcategory under this 

subpart.

(3) The date on which you became subject to the currently 

applicable standards.

(4) The date upon which you will commence the fuel switch.

§63.7550 What reports must I submit and when?

(a) You must submit each report in Table 9 to this subpart 

that applies to you.

(b) Unless the EPA Administrator has approved a different 

schedule for submission of reports under §63.10(a), you must 

submit each report by the date in Table 9 to this subpart and 

according to the requirements in paragraphs (b)(1) through (5) 

of this section. For units that are subject only to a 

requirement to conduct an annual, biennial, or 5-year tune-up 

according to §63.7540(a)(10), (a)(11), or (a)(12), respectively, 

and not subject to emission limits or operating limits, you may 

submit only an annual, biennial, or 5-year compliance report, as 

applicable, as specified in paragraphs (b)(1) through (5) of 

this section, instead of a semi-annual compliance report. 

(1) The first compliance report must cover the period 

beginning on the compliance date that is specified for your 
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affected source in §63.7495 and ending on June 30 or December 

31, whichever date is the first date that occurs at least 180 

days (or 1, 2, or 5 years, as applicable, if submitting an 

annual, biennial, or 5-year compliance report) after the 

compliance date that is specified for your source in §63.7495.

(2) The first compliance report must be postmarked or 

delivered no later than July 31 or January 31, whichever date is 

the first date following the end of the first calendar half 

after the compliance date that is specified for your source in 

§63.7495. The first annual, biennial, or 5-year compliance 

report must be postmarked no later than January 31.

(3) Each subsequent compliance report must cover the 

semiannual reporting period from January 1 through June 30 or 

the semiannual reporting period from July 1 through December 31. 

Annual, biennial, and 5-year compliance reports must cover the 

applicable 1-, 2-, or 5-year periods from January 1 to December 

31.

(4) Each subsequent compliance report must be postmarked or 

delivered no later than July 31 or January 31, whichever date is 

the first date following the end of the semiannual reporting 

period. Annual, biennial, and 5-year compliance reports must be 

postmarked no later than January 31.

(5) For each affected source that is subject to permitting 

regulations pursuant to part 70 or part 71 of this chapter, and 
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if the delegated authority has established dates for submitting 

semiannual reports pursuant to §70.6(a)(3)(iii)(A) or 

§71.6(a)(3)(iii)(A), you may submit the first and subsequent 

compliance reports according to the dates the delegated

authority has established instead of according to the dates in 

paragraphs (b)(1) through (4) of this section.

(c) The compliance report must contain the information 

required in paragraphs (c)(1) through (13) of this section.

(1) Company name and address.

(2) Statement by a responsible official with that 

official's name, title, and signature, certifying the truth, 

accuracy, and completeness of the content of the report.

(3) Date of report and beginning and ending dates of the

reporting period.

(4) The total fuel use by each affected source subject to 

an emission limit, for each calendar month within the semiannual 

(or annual, biennial, or 5-year) reporting period, including, 

but not limited to, a description of the fuel, whether the fuel 

has received a non-waste determination by EPA or your basis for 

concluding that the fuel is not a waste, and the total fuel 

usage amount with units of measure.

(5) A summary of the results of the annual performance 

tests for affected sources subject to an emission limit, a 

summary of any fuel analyses associated with performance tests,
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and documentation of any operating limits that were 

reestablished during this test, if applicable. If you are 

conducting performance tests once every 3 years consistent with 

§63.7515(b) or (c), the date of the last 2 performance tests, a 

comparison of the emission level you achieved in the last 2 

performance tests to the 75 percent emission limit threshold 

required in §63.7515(b) or (c), and a statement as to whether 

there have been any operational changes since the last 

performance test that could increase emissions.

(6) A signed statement indicating that you burned no new 

types of fuel in an affected source subject to an emission 

limit. Or, if you did burn a new type of fuel and are subject to 

a hydrogen chloride emission limit, you must submit the 

calculation of chlorine input, using Equation 5 of §63.7530, 

that demonstrates that your source is still within its maximum 

chlorine input level established during the previous performance 

testing (for sources that demonstrate compliance through 

performance testing) or you must submit the calculation of 

hydrogen chloride emission rate using Equation 11 of §63.7530 

that demonstrates that your source is still meeting the emission 

limit for hydrogen chloride emissions (for boilers or process 

heaters that demonstrate compliance through fuel analysis). If 

you burned a new type of fuel and are subject to a mercury 

emission limit, you must submit the calculation of mercury 
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input, using Equation 8 of §63.7530, that demonstrates that your 

source is still within its maximum mercury input level 

established during the previous performance testing (for sources 

that demonstrate compliance through performance testing), or you 

must submit the calculation of mercury emission rate using 

Equation 12 of §63.7530 that demonstrates that your source is 

still meeting the emission limit for mercury emissions (for 

boilers or process heaters that demonstrate compliance through 

fuel analysis). If you burned a new type of fuel and are subject 

to a total selected metals emission limit, you must submit the 

calculation of total selected metals input, using Equation 9 of 

§63.7530, that demonstrates that your source is still within its 

maximum total selected metals input level established during the 

previous performance testing (for sources that demonstrate 

compliance through performance testing), or you must submit the 

calculation of total selected metals emission rate, using 

Equation 13 of §63.7530, that demonstrates that your source is 

still meeting the emission limit for total selected metals

emissions (for boilers or process heaters that demonstrate 

compliance through fuel analysis).

(7) If you wish to burn a new type of fuel in an affected 

source subject to an emission limit and you cannot demonstrate 

compliance with the maximum chlorine input operating limit using 

Equation 7 of §63.7530 or the maximum mercury input operating 
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limit using Equation 8 of §63.7530, or the maximum total 

selected metals input operating limit using Equation 9 of 

§63.7530 you must include in the compliance report a statement 

indicating the intent to conduct a new performance test within 

60 days of starting to burn the new fuel.

(8) A summary of any monthly fuel analyses conducted to 

demonstrate compliance according to §§63.7521 and 63.7530 for 

affected sources subject to emission limits, and any fuel 

specification analyses conducted according to §63.7521(f) and 

§63.7530(g).

(9) If there are no deviations from any emission limits or 

operating limits in this subpart that apply to you, a statement 

that there were no deviations from the emission limits or 

operating limits during the reporting period.

(10) If there were no deviations from the monitoring 

requirements including no periods during which the CMSs, 

including CEMS, COMS, and continuous parameter monitoring 

systems, were out of control as specified in §63.8(c)(7), a 

statement that there were no deviations and no periods during 

which the CMS were out of control during the reporting period.

(11) If a malfunction occurred during the reporting period, 

the report must include the number, duration, and a brief 

description for each type of malfunction which occurred during 

the reporting period and which caused or may have caused any 
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applicable emission limitation to be exceeded. The report must 

also include a description of actions taken by you during a 

malfunction of a boiler, process heater, or associated air 

pollution control device or CMS to minimize emissions in 

accordance with §63.7500(a)(3), including actions taken to 

correct the malfunction.

(12) Include the date of the most recent tune-up for each 

unit subject to only the requirement to conduct an annual, 

biennial, or 5-year tune-up according to §63.7540(a)(10), 

(a)(11), or (a)(12) respectively. Include the date of the most 

recent burner inspection if it was not done annually, 

biennially, or on a 5-year period and was delayed until the next 

scheduled or unscheduled unit shutdown.

(13) If you plan to demonstrate compliance by emission 

averaging, certify the emission level achieved or the control 

technology employed is no less stringent than the level or 

control technology contained in the notification of compliance 

status in §63.7545(e)(5)(i).

(14) For units subject to emission limits in Tables 1 or 2 

of this subpart, for each startup or shutdown event during the 

reporting period, report the percentage concentration of oxygen 

in the firebox on an hourly basis throughout the event, the 

calendar date and length of each event, and the reason for each 

event.
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(d) For each deviation from an emission limit or operating 

limit in this subpart that occurs at an affected source where 

you are not using a CMS to comply with that emission limit or 

operating limit, the compliance report must additionally contain 

the information required in paragraphs (d)(1) through (4) of 

this section.

(1) The total operating time of each affected source during 

the reporting period.

(2) A description of the deviation and which emission limit

or operating limit from which you deviated.

(3) Information on the number, duration, and cause of 

deviations (including unknown cause), as applicable, and the 

corrective action taken.

(4) A copy of the test report if the annual performance 

test showed a deviation from the emission limits.

(e) For each deviation from an emission limit, operating 

limit, and monitoring requirement in this subpart occurring at 

an affected source where you are using a CMS to comply with that 

emission limit or operating limit, you must include the 

information required in paragraphs (e)(1) through (12) of this 

section. This includes any deviations from your site-specific 

monitoring plan as required in §63.7505(d).
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(1) The date and time that each deviation started and 

stopped and description of the nature of the deviation (i.e., 

what you deviated from).

(2) The date and time that each CMS was inoperative, except 

for zero (low-level) and high-level checks.

(3) The date, time, and duration that each CMS was out of 

control, including the information in §63.8(c)(8).

(4) The date and time that each deviation started and 

stopped.

(5) A summary of the total duration of the deviation during 

the reporting period and the total duration as a percent of the 

total source operating time during that reporting period.

(6) An analysis of the total duration of the deviations 

during the reporting period into those that are due to control 

equipment problems, process problems, other known causes, and 

other unknown causes.

(7) A summary of the total duration of CMS's downtime 

during the reporting period and the total duration of CMS 

downtime as a percent of the total source operating time during 

that reporting period.

(8) An identification of each parameter that was monitored 

at the affected source for which there was a deviation.

(9) A brief description of the source for which there was a 

deviation.
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(10) A brief description of each CMS for which there was a 

deviation.

(11) The date of the latest CMS certification or audit for 

the system for which there was a deviation.

(12) A description of any changes in CMSs, processes, or 

controls since the last reporting period for the source for 

which there was a deviation.

(f) Each affected source that has obtained a Title V 

operating permit pursuant to part 70 or part 71 of this chapter 

must report all deviations as defined in this subpart in the 

semiannual monitoring report required by §70.6(a)(3)(iii)(A) or 

§71.6(a)(3)(iii)(A). If an affected source submits a compliance 

report pursuant to Table 9 to this subpart along with, or as 

part of, the semiannual monitoring report required by 

§70.6(a)(3)(iii)(A) or §71.6(a)(3)(iii)(A), and the compliance 

report includes all required information concerning deviations 

from any emission limit, operating limit, or work practice 

requirement in this subpart, submission of the compliance report 

satisfies any obligation to report the same deviations in the 

semiannual monitoring report. However, submission of a 

compliance report does not otherwise affect any obligation the 

affected source may have to report deviations from permit 

requirements to the delegated authority.

(g) (Reserved)
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(h) Within 60 days after the date of completing each 

performance test, you must transmit the results of the 

performance tests required by this subpart to EPA’s WebFIRE 

database by using the Compliance and Emissions Data Reporting 

Interface (CEDRI) that is accessed through EPA’s Central Data 

Exchange (CDX) (www.epa.gov/cdx). Performance test data must be 

submitted in the file format generated through use of EPA’s 

Electronic Reporting Tool (ERT) (see 

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

collected using test methods on the ERT website are subject to 

this requirement for submitting reports electronically to 

WebFIRE. Owners or operators who claim that some of the 

information being submitted for performance tests is 

confidential business information (CBI) must submit a complete 

ERT file including information claimed to be CBI on a compact 

disk or other commonly used electronic storage media (including, 

but not limited to, flash drives) to the EPA. The electronic 

media must be clearly marked as CBI and mailed to U.S. 

EPA/OAPQS/CORE CBI Office, Attention: WebFIRE Administrator, MD 

C404-02, 4930 Old Page Rd., Durham, NC 27703. The same ERT file 

with the CBI omitted must be submitted to EPA via CDX as 

described earlier in this paragraph. At the discretion of the 

delegated authority, you must also submit these reports, 

including the confidential business information, to the 
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delegated authority in the format specified by the delegated 

authority.

(i) Within 60 days after the date of completing each CEMS 

(CO and Hg) performance evaluation test, as defined in §63.2 and 

required by this subpart, you must submit the relative accuracy 

test audit data electronically into EPA’s Central Data Exchange 

by using the Electronic Reporting Tool as described in paragraph 

(h) of this section. Only data collected using test methods 

compatible with ERT are subject to this requirement to be 

submitted electronically to EPA’s CDX.

(j) Within 60 days after the reporting periods ending on 

March 31, June 30, September 30, and December 31, you must 

transmit quarterly reports to EPA’s WebFIRE database by using 

the Compliance and Emissions Data Reporting Interface (CEDRI) 

that is accessed through EPA’s Central Data Exchange (CDX)

(www.epa.gov/cdx). For each reporting period, the quarterly 

reports must include all of the calculated 30 day rolling 

average values based on the daily CEMS (CO and Hg) and CPMS (PM 

CPMS output, scrubber pH, scrubber liquid flow rate, scrubber 

pressure drop) data. 

§63.7555 What records must I keep?

(a) You must keep records according to paragraphs (a)(1) 

and (2) of this section.
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(1) A copy of each notification and report that you 

submitted to comply with this subpart, including all

documentation supporting any Initial Notification or 

Notification of Compliance Status or semiannual compliance 

report that you submitted, according to the requirements in 

§63.10(b)(2)(xiv).

(2) Records of performance tests, fuel analyses, or other 

compliance demonstrations and performance evaluations as 

required in §63.10(b)(2)(viii).

(b) For each CEMS, COMS, and continuous monitoring system 

you must keep records according to paragraphs (b)(1) through (5) 

of this section.

(1) Records described in §63.10(b)(2)(vii) through (xi).

(2) Monitoring data for continuous opacity monitoring 

system during a performance evaluation as required in 

§63.6(h)(7)(i) and (ii).

(3) Previous (i.e., superseded) versions of the performance 

evaluation plan as required in §63.8(d)(3).

(4) Request for alternatives to relative accuracy test for 

CEMS as required in §63.8(f)(6)(i).

(5) Records of the date and time that each deviation 

started and stopped.

(c) You must keep the records required in Table 8 to this 

subpart including records of all monitoring data and calculated 
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averages for applicable operating limits, such as opacity, 

pressure drop, pH, and operating load, to show continuous 

compliance with each emission limit and operating limit that 

applies to you.

(d) For each boiler or process heater subject to an 

emission limit in Table 1 or 2 to this subpart, you must also 

keep the applicable records in paragraphs (d)(1) through (9) of 

this section.

(1) You must keep records of monthly fuel use by each 

boiler or process heater, including the type(s) of fuel and 

amount(s) used.

(2) If you combust non-hazardous secondary materials that 

have been determined not to be solid waste pursuant to 

§241.3(b)(1) and (2), you must keep a record that documents how 

the secondary material meets each of the legitimacy criteria. If 

you combust a fuel that has been processed from a discarded nonhazardous secondary material pursuant to §241.3(b)(4), you must 

keep records as to how the operations that produced the fuel 

satisfy the definition of processing in §241.2. If the fuel 

received a non-waste determination pursuant to the petition 

process submitted under §241.3(c), you must keep a record that 

documents how the fuel satisfies the requirements of the 

petition process. Units exempt from the incinerator standards 

under section 129(g)(1) of the Clean Air Act because they are 
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qualifying facilities burning a homogeneous waste stream do not 

need to maintain the records described in this paragraph (d)(2).

(3) You must keep records of monthly hours of operation by 

each boiler or process heater that meets the definition of 

limited-use boiler or process heater.

(4) A copy of all calculations and supporting documentation 

of maximum chlorine fuel input, using Equation 7 of §63.7530, 

that were done to demonstrate continuous compliance with the 

hydrogen chloride emission limit, for sources that demonstrate 

compliance through performance testing. For sources that 

demonstrate compliance through fuel analysis, a copy of all 

calculations and supporting documentation of hydrogen chloride

emission rates, using Equation 11 of §63.7530, that were done to 

demonstrate compliance with the hydrogen chloride emission 

limit. Supporting documentation should include results of any 

fuel analyses and basis for the estimates of maximum chlorine 

fuel input or hydrogen chloride emission rates. You can use the 

results from one fuel analysis for multiple boilers and process 

heaters provided they are all burning the same fuel type. 

However, you must calculate chlorine fuel input, or hydrogen 

chloride emission rate, for each boiler and process heater.

(5) A copy of all calculations and supporting documentation 

of maximum mercury fuel input, using Equation 8 of §63.7530, 

that were done to demonstrate continuous compliance with the 
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mercury emission limit for sources that demonstrate compliance 

through performance testing. For sources that demonstrate 

compliance through fuel analysis, a copy of all calculations and 

supporting documentation of mercury emission rates, using 

Equation 12 of §63.7530, that were done to demonstrate 

compliance with the mercury emission limit. Supporting 

documentation should include results of any fuel analyses and 

basis for the estimates of maximum mercury fuel input or mercury 

emission rates. You can use the results from one fuel analysis 

for multiple boilers and process heaters provided they are all 

burning the same fuel type. However, you must calculate mercury 

fuel input, or mercury emission rates, for each boiler and 

process heater.

(6) If, consistent with §63.7515(b) and (c), you choose to 

stack test less frequently than annually, you must keep annual 

records that document that your emissions in the previous stack 

test(s) were less than 75 percent of the applicable emission 

limit (or, in specific instances noted in Tables 1 and 2 to this 

subpart, less than the applicable emission limit), and document 

that there was no change in source operations including fuel 

composition and operation of air pollution control equipment

that would cause emissions of the relevant pollutant to increase 

within the past year.
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(7) Records of the occurrence and duration of each 

malfunction of the boiler or process heater, or of the 

associated air pollution control and monitoring equipment.

(8) Records of actions taken during periods of malfunction 

to minimize emissions in accordance with the general duty to 

minimize emissions in §63.7500(a)(3), including corrective 

actions to restore the malfunctioning boiler or process heater, 

air pollution control, or monitoring equipment to its normal or 

usual manner of operation.

(9) A copy of all calculations and supporting documentation 

of maximum total selected metals fuel input, using Equation 9 of 

§63.7530, that were done to demonstrate continuous compliance 

with the total selected metals emission limit for sources that 

demonstrate compliance through performance testing. For sources 

that demonstrate compliance through fuel analysis, a copy of all 

calculations and supporting documentation of total selected 

metals emission rates, using Equation 13 of §63.7530, that were 

done to demonstrate compliance with the total selected metals

emission limit. Supporting documentation should include results 

of any fuel analyses and basis for the estimates of maximum 

total selected metals fuel input or total selected metals

emission rates. You can use the results from one fuel analysis 

for multiple boilers and process heaters provided they are all 

burning the same fuel type. However, you must calculate total 
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selected metals fuel input, or total selected metals emission 

rates, for each boiler and process heater.

(e) If you elect to average emissions consistent with 

§63.7522, you must additionally keep a copy of the emission 

averaging implementation plan required in §63.7522(g), all 

calculations required under §63.7522, including monthly records 

of heat input or steam generation, as applicable, and monitoring 

records consistent with §63.7541. 

(f) If you elect to use emission credits from energy 

conservation measures to demonstrate compliance according to 

§63.7533, you must keep a copy of the Implementation Plan 

required in §63.7533(d) and copies of all data and calculations 

used to establish credits according to §63.7533(b), (c), and 

(f).

(g) If you elected to demonstrate that the unit meets the 

specification for mercury for the other gas 1 subcategory and 

you cannot submit a signed certification under §63.7545(g) 

because the constituents could exceed the specification, you 

must maintain monthly records of the calculations and results of 

the fuel specification for mercury in Table 6. 

(h) If you operate a unit designed to burn natural gas, 

refinery gas, or other gas 1 fuel that is subject to this 

subpart, and you use an alternative fuel other than natural gas, 

refinery gas, gaseous fuel subject to another subpart under this 
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part, or other gas 1 fuel, you must keep records of the total 

hours per calendar year that alternative fuel is burned.

(i) For each startup or shutdown event, you must maintain 

records that boiler operators have completed training for 

startup and shutdown procedures.

§63.7560 In what form and how long must I keep my records?

(a) Your records must be in a form suitable and readily 

available for expeditious review, according to §63.10(b)(1).

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

for 5 years following the date of each occurrence, measurement, 

maintenance, corrective action, report, or record.

(c) You must keep each record on site, or they must be 

accessible from on site (for example, through a computer 

network), for at least 2 years after the date of each 

occurrence, measurement, maintenance, corrective action, report, 

or record, according to §63.10(b)(1). You can keep the records 

off site for the remaining 3 years.

Other Requirements and Information

§63.7565 What parts of the General Provisions apply to me?

Table 10 to this subpart shows which parts of the General 

Provisions in §§63.1 through 63.15 apply to you.

§63.7570 Who implements and enforces this subpart?

(a) This subpart can be implemented and enforced by EPA, or 

a delegated authority such as your state, local, or tribal 
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agency. If the EPA Administrator has delegated authority to your 

state, local, or tribal agency, then that agency (as well as 

EPA) has the authority to implement and enforce this subpart. 

You should contact your EPA Regional Office to find out if this 

subpart is delegated to your state, local, or tribal agency.

(b) In delegating implementation and enforcement authority 

of this subpart to a state, local, or tribal agency under 40 CFR 

part 63, subpart E, the authorities listed in paragraphs (b)(1) 

through (5) of this section are retained by the EPA 

Administrator and are not transferred to the state, local, or 

tribal agency, however, EPA retains oversight of this subpart 

and can take enforcement actions, as appropriate.

(1) Approval of alternatives to the non-opacity emission 

limits and work practice standards in §63.7500(a) and (b) under 

§63.6(g).

(2) Approval of alternative opacity emission limits in 

§63.7500(a) under §63.6(h)(9).

(3) Approval of major change to test methods in Table 5 to 

this subpart under §63.7(e)(2)(ii) and (f) and as defined in 

§63.90, and alternative analytical methods requested under 

§63.7521(b)(2).

(4) Approval of major change to monitoring under §63.8(f) 

and as defined in §63.90, and approval of alternative operating 

parameters under §63.7500(a)(2) and §63.7522(g)(2).
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(5) Approval of major change to recordkeeping and reporting 

under §63.10(e) and as defined in §63.90.

§63.7575 What definitions apply to this subpart?

Terms used in this subpart are defined in the Clean Air 

Act, in §63.2 (the General Provisions), and in this section as 

follows:

30-day rolling average means the arithmetic mean of all 

valid data from 30 successive operating days that is calculated 

for each operating day using the data from that operating day 

and the previous 29 operating days.

Affirmative defense means, in the context of an enforcement 

proceeding, a response or defense put forward by a defendant, 

regarding which the defendant has the burden of proof, and the 

merits of which are independently and objectively evaluated in a 

judicial or administrative proceeding.

Annual heat input means the heat input for the 12 months 

preceding the compliance demonstration.

Average annual heat input rate means annual heat input 

divided by the hours of operation for the 12 months preceding 

the compliance demonstration.

Bag leak detection system means a group of instruments that 

are capable of monitoring particulate matter loadings in the 

exhaust of a fabric filter (i.e., baghouse) in order to detect 

bag failures. A bag leak detection system includes, but is not 
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limited to, an instrument that operates on electrodynamic, 

triboelectric, light scattering, light transmittance, or other 

principle to monitor relative particulate matter loadings.

Benchmarking means a process of comparison against standard 

or average.

Biodiesel means a mono-akyl ester derived from biomass and 

conforming to ASTM D6751–08, Standard Specification for 

Biodiesel Fuel Blend Stock (B100) for Middle Distillate Fuels

(incorporated by reference, see §63.14).

Biomass or bio-based solid fuel means any biomass-based 

solid fuel that is not a solid waste. This includes, but is not 

limited to, wood residue; wood products (e.g., trees, tree 

stumps, tree limbs, bark, lumber, sawdust, sander dust, chips, 

scraps, slabs, millings, and shavings); animal manure, including 

litter and other bedding materials; vegetative agricultural and 

silvicultural materials, such as logging residues (slash), nut 

and grain hulls and chaff (e.g., almond, walnut, peanut, rice, 

and wheat), bagasse, orchard prunings, corn stalks, coffee bean 

hulls and grounds. This definition of biomass is not intended to 

suggest that these materials are or are not solid waste.

Blast furnace gas fuel-fired boiler or process heater means 

an industrial/commercial/institutional boiler or process heater 

that receives 90 percent or more of its total annual gas volume

from blast furnace gas.
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Boiler means an enclosed device using controlled flame 

combustion and having the primary purpose of recovering thermal 

energy in the form of steam or hot water. Controlled flame 

combustion refers to a steady-state, or near steady-state, 

process wherein fuel and/or oxidizer feed rates are controlled. 

A device combusting solid waste, as defined in §241.3, is not a 

boiler unless the device is exempt from the definition of a 

solid waste incineration unit as provided in section 129(g)(1) 

of the Clean Air Act. Waste heat boilers that use only natural 

gas, refinery gas, or other gas 1 fuels for supplemental fuel 

are excluded from this definition.

Boiler system means the boiler and associated components, 

such as, the feed water system, the combustion air system, the 

fuel system (including burners), blowdown system, combustion 

control system, and energy consuming systems. 

Calendar year means the period between January 1 and 

December 31, inclusive, for a given year.

Coal means all solid fuels classifiable as anthracite, 

bituminous, sub-bituminous, or lignite by ASTM D388

(incorporated by reference, see §63.14), coal refuse, and 

petroleum coke. For the purposes of this subpart, this 

definition of “coal” includes synthetic fuels derived from coal 

for creating useful heat, including but not limited to, solvent-
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refined coal, coal-oil mixtures, and coal-water mixtures. Coal 

derived gases are excluded from this definition.

Coal refuse means any by-product of coal mining or coal 

cleaning operations with an ash content greater than 50 percent 

(by weight) and a heating value less than 13,900 kilojoules per 

kilogram (6,000 Btu per pound) on a dry basis.

Commercial/institutional boiler means a boiler used in 

commercial establishments or institutional establishments such 

as medical centers, research centers, institutions of higher 

education, hotels, and laundries to provide steam and/or hot 

water.

Common stack means the exhaust of emissions from two or 

more affected units through a single flue. Affected units with a 

common stack may each have separate air pollution control 

systems located before the common stack, or may have a single 

air pollution control system located after the exhausts come 

together in a single flue.

Cost-effective energy conservation measure means a measure 

that is implemented to improve the energy efficiency of the 

boiler or facility that has a payback (return of investment) 

period of 2 years or less. 

Daily block average means the arithmetic mean of all valid 

emission concentrations or parameter levels recorded when a unit 
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is operating measured over the 24-hour period from 12 am 

(midnight) to 12 am (midnight). 

Deviation.

(1) Deviation means any instance in which an affected 

source subject to this subpart, or an owner or operator of such 

a source:

(i) Fails to meet any requirement or obligation established 

by this subpart including, but not limited to, any emission 

limit, operating limit, or work practice standard; or

(ii) Fails to meet any term or condition that is adopted to 

implement an applicable requirement in this subpart and that is 

included in the operating permit for any affected source

required to obtain such a permit.

(2) A deviation is not always a violation. The 

determination of whether a deviation constitutes a violation of 

the standard is up to the discretion of the entity responsible 

for enforcement of the standards.

Dioxins/furans means tetra- through octa-chlorinated 

dibenzo-p-dioxins and dibenzofurans.

Distillate oil means fuel oils, including recycled oils, 

that comply with the specifications for fuel oil numbers 1 and 

2, as defined by ASTM D396 (incorporated by reference, see 

§63.14).
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Dry scrubber means an add-on air pollution control system 

that injects dry alkaline sorbent (dry injection) or sprays an 

alkaline sorbent (spray dryer) to react with and neutralize acid 

gas in the exhaust stream forming a dry powder material. Sorbent 

injection systems in fluidized bed boilers and process heaters 

are included in this definition. A dry scrubber is a dry control 

system.

Dutch oven means a unit having a refractory-walled cell 

connected to a conventional boiler setting. Fuel materials are 

introduced through an opening in the roof of the dutch oven and 

burn in a pile on its floor. Fluidized bed boilers are not part 

of the dutch oven design category.

Electric utility steam generating unit means a fossil fuelfired combustion unit of more than 25 megawatts that serves a 

generator that produces electricity for sale. A fossil fuelfired unit that cogenerates steam and electricity and supplies 

more than one-third of its potential electric output capacity 

and more than 25 megawatts electrical output to any utility 

power distribution system for sale is considered an electric 

utility steam generating unit. To be “capable of combusting” 

fossil fuels, an EGU would need to have these fuels allowed in 

their operating permits and have the appropriate fuel handling 

facilities on-site or otherwise available (e.g., coal handling 

equipment, including coal storage area, belts and conveyers, 
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pulverizers, etc.; oil storage facilities). In addition, fossil 

fuel-fired EGU means any EGU that fired fossil fuel for more 

than 10.0 percent of the average annual heat input in any 3 

consecutive calendar years or for more than 15.0 percent of the 

annual heat input during any one calendar year after [COMPLIANCE 

DATE OF THE FINAL EGU RULE].

Electrostatic precipitator (ESP) means an add-on air 

pollution control device used to capture particulate matter by 

charging the particles using an electrostatic field, collecting 

the particles using a grounded collecting surface, and 

transporting the particles into a hopper. An electrostatic 

precipitator is usually a dry control system.

Emission credit means emission reductions above those 

required by this subpart. Emission credits generated may be used 

to comply with the emissions limits. Credits may come from 

pollution prevention projects that result in reduced fuel use by 

affected units. Shutdowns cannot be used to generate credits.

Energy assessment means the following only as this term is 

used in Table 3 to this subpart. 

(1) Energy assessment for facilities with affected boilers 

and process heaters using less than 0.3 trillion Btu per year 

heat input will be 8 technical labor hours in length maximum, 

but may be longer at the discretion of the owner or operator of 

the affected source. The boiler system and energy use system 
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accounting for at least 50 percent of the energy output will be 

evaluated to identify energy savings opportunities, within the 

limit of performing an 8-hour energy assessment.

(2) The Energy assessment for facilities with affected 

boilers and process heaters using 0.3 to 1.0 trillion Btu per 

year will be 24 technical labor hours in length maximum, but may 

be longer at the discretion of the owner or operator. The boiler 

system and any energy use system accounting for at least 33 

percent of the energy output will be evaluated to identify 

energy savings opportunities, within the limit of performing a 

24-hour energy assessment.

(3) In the Energy assessment for facilities with affected 

boilers and process heaters using greater than 1.0 trillion Btu

per year, the boiler system and any energy use system accounting 

for at least 20 percent of the energy output will be evaluated 

to identify energy savings opportunities.

Energy management practices means the set of practices and 

procedures designed to manage energy use that are demonstrated 

by the facility’s energy policies, a facility energy manager and 

other staffing responsibilities, energy performance measurement 

and tracking methods, an energy saving goal, action plans, 

operating procedures, internal reporting requirements, and 

periodic review intervals used at the facility.
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Energy use system includes, but is not limited to, process 

heating; compressed air systems; machine drive (motors, pumps, 

fans); process cooling; facility heating, ventilation, and airconditioning systems; hot water systems; building envelop; and 

lighting.

Equivalent means the following only as this term is used in 

Table 6 to this subpart:

(1) An equivalent sample collection procedure means a 

published voluntary consensus standard or practice (VCS) or EPA 

method that includes collection of a minimum of three composite 

fuel samples, with each composite consisting of a minimum of 

three increments collected at approximately equal intervals over 

the test period.

(2) An equivalent sample compositing procedure means a 

published VCS or EPA method to systematically mix and obtain a 

representative subsample (part) of the composite sample.

(3) An equivalent sample preparation procedure means a 

published VCS or EPA method that: Clearly states that the 

standard, practice or method is appropriate for the pollutant 

and the fuel matrix; or is cited as an appropriate sample 

preparation standard, practice or method for the pollutant in 

the chosen VCS or EPA determinative or analytical method.
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(4) An equivalent procedure for determining heat content 

means a published VCS or EPA method to obtain gross calorific 

(or higher heating) value.

(5) An equivalent procedure for determining fuel moisture 

content means a published VCS or EPA method to obtain moisture 

content. If the sample analysis plan calls for determining 

metals (especially the mercury, selenium, or arsenic) using an 

aliquot of the dried sample, then the drying temperature must be 

modified to prevent vaporizing these metals. On the other hand, 

if metals analysis is done on an “as received” basis, a separate 

aliquot can be dried to determine moisture content and the 

metals concentration mathematically adjusted to a dry basis.

(6) An equivalent pollutant (mercury, hydrogen chloride) 

determinative or analytical procedure means a published VCS or 

EPA method that clearly states that the standard, practice, or 

method is appropriate for the pollutant and the fuel matrix and 

has a published detection limit equal or lower than the methods 

listed in Table 6 to this subpart for the same purpose.

Fabric filter means an add-on air pollution control device 

used to capture particulate matter by filtering gas streams 

through filter media, also known as a baghouse. A fabric filter 

is a dry control system.

Federally enforceable means all limitations and conditions 

that are enforceable by the EPA Administrator, including the 
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requirements of 40 CFR parts 60 and 61, requirements within any 

applicable state implementation plan, and any permit 

requirements established under 40 CFR 52.21 or under 40 CFR 

51.18 and 40 CFR 51.24.

Fluidized bed boiler means a boiler utilizing a fluidized 

bed combustion process that is not a pulverized coal boiler. 

Fluidized bed combustion means a process where a fuel is 

burned in a bed of granulated particles, which are maintained in 

a mobile suspension by the forward flow of air and combustion 

products.

Fuel cell means a boiler type in which the fuel is dropped 

onto suspended fixed grates and is fired in a pile. The 

refractory-lined fuel cell uses combustion air preheating and 

positioning of secondary and tertiary air injection ports to 

improve boiler efficiency. Fluidized bed, dutch oven, pile 

burner, hybrid suspension grate, and suspension burners are not 

part of the fuel cell subcategory.

Fuel type means each category of fuels that share a common 

name or classification. Examples include, but are not limited 

to, bituminous coal, sub-bituminous coal, lignite, anthracite, 

biomass, residual oil. Individual fuel types received from 

different suppliers are not considered new fuel types. 
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Gaseous fuel includes, but is not limited to, natural gas, 

process gas, landfill gas, coal derived gas, refinery gas, and 

biogas. Blast furnace gas is exempted from this definition.

Heat input means heat derived from combustion of fuel in a 

boiler or process heater and does not include the heat input 

from preheated combustion air, recirculated flue gases, or 

exhaust gases from other sources such as gas turbines, internal 

combustion engines, kilns, etc.

Heavy Liquid includes residual oil and any other liquid 

fuel not classified as a light liquid.

Hourly average means the arithmetic average of at least 

four CMS data values representing the four 15-minute periods in 

an hour, or at least two 15-minute data values during an hour 

when CMS calibration, quality assurance, or maintenance 

activities are being performed.

Hot water heater means a closed vessel with a capacity of 

no more than 120 U.S. gallons in which water is heated by 

combustion of gaseous or liquid fuel and is withdrawn for use 

external to the vessel at pressures not exceeding 160 psig, 

including the apparatus by which the heat is generated and all 

controls and devices necessary to prevent water temperatures 

from exceeding 210 degrees Fahrenheit (99 degrees Celsius). Hot 

water boilers (i.e., not generating steam) combusting gaseous or

liquid fuel with a heat input capacity of less than 1.6 million 
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Btu per hour are included in this definition. Hot water heater

also means a tankless unit that provides on demand hot water. 

Hybrid suspension grate boiler means a boiler designed with 

air distributors to spread the fuel material over the entire 

width and depth of the boiler combustion zone. The fuel 

combusted in these units exceed a moisture content of 40 percent 

on an as-fired basis. The drying and much of the combustion of 

the fuel takes place in suspension, and the combustion is 

completed on the grate or floor of the boiler. Fluidized bed, 

dutch oven, and pile burner designs are not part of the hybrid 

suspension grate boiler design category.

Industrial boiler means a boiler used in manufacturing, 

processing, mining, and refining or any other industry to 

provide steam and/or hot water.

Light liquid includes distillate oil, biodiesel or 

vegetable oil.

Limited-use boiler or process heater means any boiler or 

process heater that burns any amount of solid, liquid, or 

gaseous fuels, has a rated capacity of greater than 10 MMBtu per 

hour heat input, and has a federally enforceable limit of no 

more than 876 hours per year of operation.

Liquid fuel includes, but is not limited to, distillate 

oil, residual oil, on-spec used oil, biodiesel and vegetable 

oil.
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Load fraction means the actual heat input of the boiler or 

process heater divided by the average operating load determined 

according to Table 7 to this subpart.

Metal process furnaces include natural gas-fired annealing 

furnaces, preheat furnaces, reheat furnaces, aging furnaces, 

heat treat furnaces, and homogenizing furnaces.

Million Btu (MMBtu) means one million British thermal 

units. 

Minimum activated carbon injection rate means load fraction

(percent) multiplied by the lowest hourly average activated 

carbon injection rate measured according to Table 7 to this 

subpart during the most recent performance test demonstrating 

compliance with the applicable emission limits.

Minimum pressure drop means the lowest hourly average 

pressure drop measured according to Table 7 to this subpart 

during the most recent performance test demonstrating compliance 

with the applicable emission limit.

Minimum scrubber effluent pH means the lowest hourly

average sorbent liquid pH measured at the inlet to the wet 

scrubber according to Table 7 to this subpart during the most 

recent performance test demonstrating compliance with the 

applicable hydrogen chloride emission limit.

Minimum scrubber liquid flow rate means the lowest hourly 

average liquid flow rate (e.g., to the PM scrubber or to the 
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acid gas scrubber) measured according to Table 7 to this subpart 

during the most recent performance test demonstrating compliance 

with the applicable emission limit.

Minimum scrubber pressure drop means the lowest hourly 

average scrubber pressure drop measured according to Table 7 to 

this subpart during the most recent performance test

demonstrating compliance with the applicable emission limit.

Minimum sorbent injection rate means load fraction 

(percent) multiplied by the lowest hourly average sorbent 

injection rate for each sorbent measured according to Table 7 to 

this subpart during the most recent performance test

demonstrating compliance with the applicable emission limits.

Minimum total secondary electric power means the lowest 

hourly average total secondary electric power determined from 

the values of secondary voltage and secondary current to the 

electrostatic precipitator measured according to Table 7 to this 

subpart during the most recent performance test demonstrating 

compliance with the applicable emission limits.

Natural gas means:

(1) A naturally occurring mixture of hydrocarbon and 

nonhydrocarbon gases found in geologic formations beneath the 

earth's surface, of which the principal constituent is methane; 

or
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(2) Liquid petroleum gas, as defined in ASTM D1835

(incorporated by reference, see §63.14); or

(3) A mixture of hydrocarbons that maintains a gaseous 

state at ISO conditions. Additionally, natural gas must either 

be composed of at least 70 percent methane by volume or have a 

gross calorific value between 34 and 43 mega joules (MJ) per dry 

standard cubic meter (910 and 1,150 Btu per dry standard cubic 

foot); or

(4) Propane or propane derived synthetic natural gas. 

Propane means a colorless gas derived from petroleum and natural 

gas, with the molecular structure C3H8.

Opacity means the degree to which emissions reduce the 

transmission of light and obscure the view of an object in the 

background.

Operating day means a 24-hour period between 12 midnight 

and the following midnight during which any fuel is combusted at 

any time in the boiler or process heater unit. It is not 

necessary for fuel to be combusted for the entire 24-hour 

period.

Other combustor means a unit designed to burn solid fuel 

that is not classified as a dutch oven, fluidized bed, fuel 

cell, hybrid suspension grate boiler, pulverized coal boiler, 

stoker, sloped grate, or suspension boiler as defined in this 

subpart.
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Other gas 1 fuel means a gaseous fuel that is not natural 

gas or refinery gas and does not exceed the maximum 

concentration of 40 micrograms/cubic meters of mercury. 

Oxygen analyzer system means all equipment required to 

determine the oxygen content of a gas stream and used to monitor 

oxygen in the boiler flue gas or firebox. This definition 

includes oxygen trim systems. The source owner or operator must

install, calibrate, maintain, and operate the oxygen analyzer 

system in accordance with the manufacturer’s recommendations. 

Oxygen trim system means a system of monitors that is used 

to maintain excess air at the desired level in a combustion 

device. A typical system consists of a flue gas oxygen and/or 

carbon monoxide monitor that automatically provides a feedback 

signal to the combustion air controller. 

Particulate matter (PM) means any finely divided solid or 

liquid material, other than uncombined water, as measured by the 

test methods specified under this subpart, or an approved 

alternative method.

Period of gas curtailment or supply interruption means a 

period of time during which the supply of gaseous fuel to an 

affected facility is halted for reasons beyond the control of 

the facility. The act of entering into a contractual agreement 

with a supplier of natural gas established for curtailment 

purposes does not constitute a reason that is under the control 
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of a facility for the purposes of this definition. An increase 

in the cost or unit price of natural gas due to normal market 

fluctuations not during periods of supplier delivery restriction 

does not constitute a period of natural gas curtailment or 

supply interruption. On-site gaseous fuel system emergencies or 

equipment failures qualify as periods of supply interruption

when the emergency or failure is beyond the control of the 

facility.

Pile burner means a boiler design incorporating a design 

where the anticipated biomass fuel has a high relative moisture 

content. Grates serve to support the fuel, and underfire air 

flowing up through the grates provides oxygen for combustion, 

cools the grates, promotes turbulence in the fuel bed, and fires 

the fuel. The most common form of pile burning is the dutch 

oven. 

Process heater means an enclosed device using controlled 

flame, and the unit's primary purpose is to transfer heat 

indirectly to a process material (liquid, gas, or solid) or to a 

heat transfer material for use in a process unit, instead of 

generating steam. Process heaters include units heating hot 

water as a process heat transfer medium. Process heaters are 

devices in which the combustion gases do not come into direct 

contact with process materials. A device combusting solid waste, 

as defined in §241.3, is not a process heater unless the device 
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is exempt from the definition of a solid waste incineration unit 

as provided in section 129(g)(1) of the Clean Air Act. Process 

heaters do not include units used for comfort heat or space 

heat, food preparation for on-site consumption, or autoclaves. 

Waste heat process heaters that use only natural gas, refinery 

gas, or other gas 1 fuels for supplemental fuel are excluded 

from this definition.

Pulverized coal boiler means a boiler in which pulverized 

coal or other solid fossil fuel is introduced into an air stream 

that carries the coal to the combustion chamber of the boiler 

where it is fired in suspension.

Qualified energy assessor means:

(1) Someone who has demonstrated capabilities to evaluate 

energy savings opportunities for steam generation and major 

energy using systems, including, but not limited to:

(i) Boiler combustion management.

(ii) Boiler thermal energy recovery, including

(A) Conventional feed water economizer,

(B) Conventional combustion air preheater, and

(C) Condensing economizer.

(iii) Boiler blowdown thermal energy recovery.

(iv) Primary energy resource selection, including

(A) Fuel (primary energy source) switching, and
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(B) Applied steam energy versus direct-fired energy versus 

electricity.

(v) Insulation issues.

(vi) Steam trap and steam leak management.

(vi) Condensate recovery.

(viii) Steam end-use management.

(2) Capabilities and knowledge includes, but is not limited 

to:

(i) Background, experience, and recognized abilities to 

perform the assessment activities, data analysis, and report 

preparation.

(ii) Familiarity with operating and maintenance practices 

for steam or process heating systems.

(iii) Additional potential steam system improvement 

opportunities including improving steam turbine operations and 

reducing steam demand.

(iv) Additional process heating system opportunities 

including effective utilization of waste heat and use of proper 

process heating methods.

(v) Boiler-steam turbine cogeneration systems.

(vi) Industry specific steam end-use systems.

Refinery gas means any gas that is generated at a petroleum 

refinery and is combusted. Refinery gas includes natural gas 

when the natural gas is combined and combusted in any proportion 
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with a gas generated at a refinery. Refinery gas includes gases 

generated from other facilities when that gas is combined and 

combusted in any proportion with gas generated at a refinery.

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., 

university campus, military base, church grounds) or 

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

Residual oil means crude oil, and all fuel oil numbers 4, 5 

and 6, as defined in ASTM D396–10 (incorporated by reference, 

see §63.14(b)).

Responsible official means responsible official as defined 

in §70.2.

Shutdown means the period that begins when a unit last 

operates at 25 percent load and ending with a state of no fuel 

combustion in the unit.

Sloped grate means a unit where the solid fuel is fed to 

the top of the grate from where it slides downwards; while 

sliding the fuel first dries and then ignites and burns. The ash 

is deposited at the bottom of the grate. Fluidized bed, dutch 

oven, pile burner, hybrid suspension grate, suspension burners, 

and fuel cells are not considered to be a sloped grate design. 
Page 294 of 360

Solid fossil fuel includes, but is not limited to, coal, 

coke, petroleum coke, and tire derived fuel. 

Solid fuel means any solid fossil fuel or biomass or biobased solid fuel.

Startup means the period between the state of no combustion 

in the unit to the period where the unit first achieves 25 

percent load (i.e., a cold start).

Steam output means (1) For a boiler that produces steam for 

process or heating only (no power generation), the energy 

content in terms of MMBtu of the boiler steam output, (2) for a 

boiler that cogenerates process steam and electricity (also 

known as combined heat and power), the total energy output, 

which is the sum of the energy content of the steam exiting the 

turbine and sent to process in MMBtu and the energy of the 

electricity generated converted to MMBtu at a rate of 10,000 Btu 

per kilowatt-hour generated (10 MMBtu per megawatt-hour), and 

(3) for a boiler that generates only electricity, the alternate 

output-based emission limits would be calculated using Equations 

16 through 20 of this section, as appropriate:

(a) For emission limits for boilers in the solid fuel 

subcategory use Equation 16 of this section:

ELOBE = ELT x 12.7 MMBtu/Mwh (Eq. 16)

Where:

ELOBE = Emission limit in units of pounds per megawatt-hour.
Page 295 of 360

ELT = Appropriate emission limit from Table 1 or 2 of this 

subpart in units of pounds per million Btu heat input.

(b) For PM and CO emission limits for boilers in one of the 

subcategories of units designed to burn coal use Equation 17 of 

this section:

ELOBE = ELT x 12.2 MMBtu/Mwh (Eq. 17)

Where:

ELOBE = Emission limit in units of pounds per megawatt-hour.

ELT = Appropriate emission limit from Table 1 or 2 of this 

subpart in units of pounds per million Btu heat input.

(c) For PM and CO emission limits for boilers in one of the 

subcategories of units designed to burn biomass use Equation 18 

of this section:

ELOBE = ELT x 13.9 MMBtu/Mwh (Eq. 18)

Where:

ELOBE = Emission limit in units of pounds per megawatt-hour.

ELT = Appropriate emission limit from Table 1 or 2 of this 

subpart in units of pounds per million Btu heat input.

(d) For emission limits for boilers in the one of the 

subcategories of units designed to burn liquid fuels use 

Equation 19 of this section:

ELOBE = ELT x 13.8 MMBtu/Mwh (Eq. 19)

Where:

ELOBE = Emission limit in units of pounds per megawatt-hour.
Page 296 of 360

ELT = Appropriate emission limit from Table 1 or 2 of this 

subpart in units of pounds per million Btu heat input.

(e) For emission limits for boilers in the Gas 2 

subcategory use Equation 20 of this section:

ELOBE = ELT x 10.4 MMBtu/Mwh (Eq. 20)

Where:

ELOBE = Emission limit in units of pounds per megawatt-hour.

ELT = Appropriate emission limit from Table 1 or 2 of this 

subpart in units of pounds per million Btu heat input.

Stoker means a unit consisting of a mechanically operated 

fuel feeding mechanism, a stationary or moving grate to support 

the burning of fuel and admit under-grate air to the fuel, an 

overfire air system to complete combustion, and an ash discharge 

system. This definition of stoker includes air swept stokers. 

There are two general types of stokers: underfeed and overfeed. 

Overfeed stokers include mass feed and spreader stokers.

Fluidized bed, dutch oven, pile burner, hybrid suspension grate, 

suspension burners, and fuel cells are not considered to be a 

stoker design. 

Stoker/sloped grate/other unit designed to burn kiln dried 

biomass means the unit is in the units designed to burn 

biomass/bio-based solid subcategory that is either a stoker, 

sloped grate, or other combustor design and is not in the 
Page 297 of 360

stoker/sloped grate/other units designed to burn wet biomass 

subcategory. 

Stoker/sloped grate/other unit designed to burn wet biomass

means the unit is in the units designed to burn biomass/biobased solid subcategory that is either a stoker, sloped grate, 

or other combustor design and any of the biomass/bio-based solid 

fuel combusted in the unit exceeds 20 percent moisture. 

Suspension burner means a unit designed to feed the fuel by 

means of fuel distributors. The distributors inject air at the 

point where the fuel is introduced into the boiler in order to 

spread the fuel material over the boiler width. The drying (and 

much of the combustion) occurs while the material is suspended 

in air. The combustion of the fuel material is completed on a 

grate or floor below. Suspension boilers almost universally are 

designed to have high heat release rates to dry quickly the wet 

fuel as it is blown into the boilers. Fluidized bed, dutch oven, 

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

the suspension burner subcategory.

Temporary boiler means any gaseous or liquid fuel boiler 

that is designed to, and is capable of, being carried or moved 

from one location to another by means of, for example, wheels, 

skids, carrying handles, dollies, trailers, or platforms. A 

boiler is not a temporary boiler if any one of the following 

conditions exists:
Page 298 of 360

(1) The equipment is attached to a foundation.

(2) The boiler or a replacement remains at a location for 

more than 12 consecutive months. Any temporary boiler that 

replaces a temporary boiler at a location and performs the same 

or similar function will be included in calculating the 

consecutive time period. 

(3) The equipment is located at a seasonal facility and 

operates during the full annual operating period of the seasonal 

facility, remains at the facility for at least 2 years, and 

operates at that facility for at least 3 months each year.

(4) The equipment is moved from one location to another in 

an attempt to circumvent the residence time requirements of this 

definition.

Total selected metals means the combination of the 

following metallic hazardous air pollutants: arsenic, beryllium, 

cadmium, chromium, lead, manganese, nickel and selenium.

Tune-up means adjustments made to a boiler in accordance 

with procedures supplied by the manufacturer (or an approved 

specialist) to optimize the combustion efficiency.

Unit designed to burn biomass/bio-based solid subcategory

includes any boiler or process heater that burns at least 10 

percent biomass or bio-based solids on an annual heat input 

basis in combination with solid fossil fuels, liquid fuels, or 

gaseous fuels.
Page 299 of 360

Unit designed to burn coal/solid fossil fuel subcategory

includes any boiler or process heater that burns any coal or 

other solid fossil fuel alone or at least 10 percent coal or 

other solid fossil fuel on an annual heat input basis in 

combination with liquid fuels, gaseous fuels, or less than 10 

percent biomass and bio-based solids on an annual heat input 

basis.

Unit designed to burn gas 1 subcategory includes any boiler 

or process heater that burns only natural gas, refinery gas, 

and/or other gas 1 fuels; with the exception of liquid fuels 

burned for periodic testing not to exceed a combined total of 48 

hours during any calendar year, or during periods of gas 

curtailment and gas supply emergencies.

Unit designed to burn gas 2 (other) subcategory includes 

any boiler or process heater that is not in the unit designed to 

burn gas 1 subcategory and burns any gaseous fuels either alone 

or in combination with less than 10 percent coal/solid fossil 

fuel, less than 10 percent biomass/bio-based solid fuel, and 

less than 10 percent liquid fuels on an annual heat input basis. 

Unit designed to burn heavy liquid subcategory means a unit 

in the unit designed to burn liquid subcategory where at least 

10 percent of the heat input from liquid fuels on an annual heat 

input basis comes from heavy liquids.
Page 300 of 360

Unit designed to burn light liquid subcategory means a unit 

in the unit designed to burn liquid subcategory that is not part 

of the unit designed to burn heavy liquid subcategory.

Unit designed to burn liquid subcategory includes any 

boiler or process heater that burns any liquid fuel, but less 

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

biomass/bio-based solid fuel on an annual heat input basis, 

either alone or in combination with gaseous fuels. Gaseous fuel 

boilers and process heaters that burn liquid fuel for periodic 

testing of liquid fuel, maintenance, or operator training, not 

to exceed a combined total of 48 hours during any calendar year 

or during periods of maintenance, operator training, or testing 

of liquid fuel, not to exceed a combined total of 48 hours 

during any calendar year are not included in this definition. 

Gaseous fuel boilers and process heaters that burn liquid fuel 

during periods of gas curtailment or gas supply emergencies of 

any duration are also not included in this definition.

Unit designed to burn liquid fuel that is a non-continental 

unit means an industrial, commercial, or institutional boiler or 

process heater designed to burn liquid fuel located in the State 

of Hawaii, the Virgin Islands, Guam, American Samoa, the 

Commonwealth of Puerto Rico, or the Northern Mariana Islands.

Unit designed to burn solid fuel subcategory means any 

boiler or process heater that burns only solid fuels or at least 
Page 301 of 360

10 percent solid fuel on an annual heat input basis in 

combination with liquid fuels or gaseous fuels.

Vegetable oil means oils extracted from vegetation.

Voluntary Consensus Standards or VCS mean technical 

standards (e.g., materials specifications, test methods, 

sampling procedures, business practices) developed or adopted by 

one or more voluntary consensus bodies. EPA/Office of Air 

Quality Planning and Standards, by precedent, has only used VCS 

that are written in English. Examples of VCS bodies are: 

American Society of Testing and Materials (ASTM 100 Barr Harbor 

Drive, P.O. Box CB700, West Conshohocken, Pennsylvania 19428–

B2959, (800) 262–1373, http://www.astm.org), American Society of 

Mechanical Engineers (ASME ASME, Three Park Avenue, New York, NY 

10016–5990, (800) 843–2763, http://www.asme.org), International 

Standards Organization (ISO 1, ch. de la Voie-Creuse, Case 

postale 56, CH-1211 Geneva 20, Switzerland, +41 22 749 01 11, 

http://www.iso.org/iso/home.htm), Standards Australia (AS Level 

10, The Exchange Centre, 20 Bridge Street, Sydney, GPO Box 476, 

Sydney NSW 2001, + 61 2 9237 6171 http://www.stadards.org.au), 

British Standards Institution (BSI, 389 Chiswick High Road, 

London, W4 4AL, United Kingdom, +44 (0)20 8996 9001, 

http://www.bsigroup.com), Canadian Standards Association (CSA

5060 Spectrum Way, Suite 100, Mississauga, Ontario L4W 5N6, 

Canada, 800-463-6727, http://www.csa.ca), European Committee for 
Page 302 of 360

Standardization (CEN CENELEC Management Centre Avenue Marnix 17 

B-1000 Brussels, Belgium +32 2 550 08 11, 

http://www.cen.eu/cen), and German Engineering Standards (VDI

VDI Guidelines Department, P.O. Box 10 11 39 40002, Duesseldorf, 

Germany, +49 211 6214-230, http://www.vdi.eu). The types of

standards that are not considered VCS are standards developed 

by: the United States, e.g. , California (CARB) and Texas 

(TCEQ); industry groups, such as American Petroleum Institute 

(API), Gas Processors Association (GPA), and Gas Research 

Institute (GRI); and other branches of the U.S. government, 

e.g., Department of Defense (DOD) and Department of 

Transportation (DOT). This does not preclude EPA from using 

standards developed by groups that are not VCS bodies within 

their rule. When this occurs, EPA has done searches and reviews 

for VCS equivalent to these non-EPA methods.

Waste heat boiler means a device that recovers normally 

unused energy and converts it to usable heat. Waste heat boilers 

are also referred to as heat recovery steam generators. This 

definition includes both fired and unfired waste heat boilers.

Waste heat process heater means an enclosed device that 

recovers normally unused energy and converts it to usable heat. 

Waste heat process heaters are also referred to as recuperative 

process heaters. This definition includes both fired and unfired 

waste heat process heaters.
Page 303 of 360

Wet scrubber means any add-on air pollution control device 

that mixes an aqueous stream or slurry with the exhaust gases 

from a boiler or process heater to control emissions of 

particulate matter or to absorb and neutralize acid gases, such 

as hydrogen chloride. A wet scrubber creates an aqueous stream 

or slurry as a byproduct of the emissions control process. 

Work practice standard means any design, equipment, work 

practice, or operational standard, or combination thereof, that 

is promulgated pursuant to section 112(h) of the Clean Air Act.

Tables to Subpart DDDDD of Part 63

Table 1 to Subpart DDDDD of Part 63—Emission Limits for New or 

Reconstructed Boilers and Process Heaters (Units with heat input 

capacity of 10 million Btu per hour or greater) 

As stated in §63.7500, you must comply with the following 

applicable emission limits:

If your boiler 

or process 

heater is in 

this 

subcategory 

...

For the 

following 

pollutants 

... 

The 

emissions 

must not 

exceed the 

following 

emission 

limits, 

except 

during 

periods of 

startup and 

shutdown...

Or the 

emissions 

must not 

exceed the 

following 

alternative 

outputbased 

limits...

Using this 

specified 

sampling 

volume or 

test run 

duration...

1. Units in 

all 

subcategories 

designed to 

burn solid 

fuel

a. Hydrogen 

Chloride

0.022 lb per 

MMBtu of 

heat input.

0.025 lb 

per MMBtu 

of steam 

output or 

0.28 lb per 

MWh

For M26A, 

collect a 

minimum of 

1 dscm per 

run; for 

M26 collect 

a minimum 
Page 304 of 360

If your boiler 

or process 

heater is in 

this 

subcategory 

...

For the 

following 

pollutants 

... 

The 

emissions 

must not 

exceed the 

following 

emission 

limits, 

except 

during 

periods of 

startup and 

shutdown...

Or the 

emissions 

must not 

exceed the 

following 

alternative 

outputbased 

limits...

Using this 

specified 

sampling 

volume or 

test run 

duration...

of 120 

liters per 

run

 b. Mercury 8.60E-07 lb 

per MMBtu of 

heat input.

9.4E-07 lb 

per MMBtu 

of steam 

output or 

1.1 E-05 lb 

per MWh

For M29, 

collect a 

minimum of 

4 dscm per 

run; for 

M30A or 

M30B, 

collect a 

minimum 

sample as 

specified 

in the 

method; for 

ASTM D6784b

collect a 

minimum of 

4 dscm.

2. Pulverized 

coal boilers 

designed to 

burn 

coal/solid 

fossil fuel

a. Carbon 

monoxide 

(CO) (or 

CEMS)

9 ppm by 

volume on a 

dry basis 

corrected to 

3 percent 

oxygen, 3-

run average; 

or (28 ppm 

by volume on 

a dry basis 

corrected to 

3 percent 

oxygen, 10-

day rolling 

average).

0.0074 lb 

per MMBtu 

of steam 

output or 

0.092 lb 

per MWh; 3-

run 

average.

1 hr 

minimum 

sampling 

time, use a 

span value 

of 20 ppmv

for Method 

10.
Page 305 of 360

If your boiler 

or process 

heater is in 

this 

subcategory 

...

For the 

following 

pollutants 

... 

The 

emissions 

must not 

exceed the 

following 

emission 

limits, 

except 

during 

periods of 

startup and 

shutdown...

Or the 

emissions 

must not 

exceed the 

following 

alternative 

outputbased 

limits...

Using this 

specified 

sampling 

volume or 

test run 

duration...

b.

Filterable

Particulate 

Matter (or 

Total 

Selected 

Metals)

0.0013 lb 

per MMBtu of 

heat input; 

or (2.8E-05a

lb per MMBtu 

of heat 

input). 

0.0013 lb 

per MMBtu 

of steam 

output or 

0.016 lb 

per MWh; or 

(2.8E-05a

lb per 

MMBtu of 

steam 

output or 

3.5E-04a lb 

per MWh).

Collect a 

minimum of 

3 dscm per 

run

3. Stokers 

designed to 

burn 

coal/solid 

fossil fuel

a. CO (or 

CEMS)

19 ppm by 

volume on a 

dry basis 

corrected to 

3 percent 

oxygen, 3-

run average; 

or (34 ppm 

by volume on 

a dry basis 

corrected to 

3 percent 

oxygen, 10-

day rolling 

average).

0.017 lb 

per MMBtu 

of steam 

output or 

0.20 lb per 

MWh; 3-run 

average.

1 hr 

minimum 

sampling 

time, use a 

span value 

of 30 ppmv 

for Method 

10.

b.

Filterable

Particulate 

Matter (or 

Total 

Selected 

Metals)

0.028 lb per 

MMBtu of 

heat input; 

or (2.2E-05a

lb per MMBtu 

of heat 

input).

0.028 lb 

per MMBtu 

of steam 

output or 

0.35 lb per 

MWh; or 

(3.0E-05a

Collect a 

minimum of 

2 dscm per 

run
Page 306 of 360

If your boiler 

or process 

heater is in 

this 

subcategory 

...

For the 

following 

pollutants 

... 

The 

emissions 

must not 

exceed the 

following 

emission 

limits, 

except 

during 

periods of 

startup and 

shutdown...

Or the 

emissions 

must not 

exceed the 

following 

alternative 

outputbased 

limits...

Using this 

specified 

sampling 

volume or 

test run 

duration...

lb per 

MMBtu of 

steam 

output or 

2.7E-04a lb 

per MWh). 

4. Fluidized 

bed units 

designed to 

burn 

coal/solid 

fossil fuel

a. CO (or 

CEMS)

17 ppm by 

volume on a 

dry basis 

corrected to 

3 percent 

oxygen, 3-

run average; 

or (59 ppm 

by volume on 

a dry basis 

corrected to 

3 percent 

oxygen, 10-

day rolling 

average).

0.015 lb 

per MMBtu 

of steam 

output or 

0.18 lb per 

MWh; 3-run 

average.

1 hr 

minimum 

sampling 

time, use a 

span value 

of 40 ppmv 

for Method 

10.

b.

Filterable

Particulate 

Matter (or 

Total 

Selected 

Metals)

0.0011 lb 

per MMBtu of 

heat input; 

or (1.7E-05a

lb per MMBtu 

of heat 

input).

0.0012 lb 

per MMBtu 

of steam 

output or 

0.014 lb 

per MWh; or 

(1.8E-05a

lb per 

MMBtu of 

steam 

output or 

2.1E-04a lb 

per MWh) .

Collect a 

minimum of 

4 dscm per 

run
Page 307 of 360

If your boiler 

or process 

heater is in 

this 

subcategory 

...

For the 

following 

pollutants 

... 

The 

emissions 

must not 

exceed the 

following 

emission 

limits, 

except 

during 

periods of 

startup and 

shutdown...

Or the 

emissions 

must not 

exceed the 

following 

alternative 

outputbased 

limits...

Using this 

specified 

sampling 

volume or 

test run 

duration...

5. 

Stokers/sloped 

grate/others 

designed to 

burn wet 

biomass fuel

a. CO (or 

CEMS)

590 ppm by 

volume on a 

dry basis 

corrected to 

3 percent 

oxygen, 3-

run average; 

or (410 ppm 

by volume on 

a dry basis 

corrected to 

3 percent 

oxygen, 10-

day rolling 

average).

0.56 lb per 

MMBtu of 

steam 

output or 

6.5 lb per 

MWh; 3-run 

average.

1 hr 

minimum 

sampling 

time, use a 

span value 

of 600 ppmv 

for Method 

10.

b.

Filterable

Particulate 

Matter (or 

Total 

Selected 

Metals)

0.029 lb per 

MMBtu of 

heat input; 

or (2.6E-05 

lb per MMBtu 

of heat 

input).

0.034 lb 

per MMBtu 

of steam 

output or 

0.41 lb per 

MWh; or 

(2.7E-05 lb 

per MMBtu 

of steam 

output or 

3.7E-04 lb 

per MWh) .

Collect a 

minimum of 

2 dscm per 

run

6. 

Stokers/sloped 

grate/others 

designed to 

burn kilndried biomass 

fuel

a. CO 250 ppm by 

volume on a 

dry basis 

corrected to 

3 percent 

oxygen.

0.23 lb per 

MMBtu of 

steam 

output or 

2.8 lb per 

MWh.

1 hr 

minimum 

sampling 

time, use a 

span value 

of 400 ppmv 

for Method 

10.
Page 308 of 360

If your boiler 

or process 

heater is in 

this 

subcategory 

...

For the 

following 

pollutants 

... 

The 

emissions 

must not 

exceed the 

following 

emission 

limits, 

except 

during 

periods of 

startup and 

shutdown...

Or the 

emissions 

must not 

exceed the 

following 

alternative 

outputbased 

limits...

Using this 

specified 

sampling 

volume or 

test run 

duration...

b.

Filterable

Particulate 

Matter (or 

Total 

Selected 

Metals)

0.32 lb per 

MMBtu of 

heat input; 

or (4.0E-03 

lb per MMBtu 

of heat 

input).

0.37 lb per 

MMBtu of 

steam 

output or 

4.5 lb per 

MWh; or 

(4.2E-03 lb 

per MMBtu 

of steam 

output or 

0.056 lb 

per MWh) .

Collect a 

minimum of 

2 dscm per 

run

7. Fluidized 

bed units 

designed to 

burn 

biomass/biobased solids

a. CO (or 

CEMS)

230 ppm by 

volume on a 

dry basis 

corrected to 

3 percent 

oxygen, 3-

run average; 

or (180 ppm 

by volume on 

a dry basis 

corrected to 

3 percent 

oxygen, 10-

day rolling 

average).

0.22 lb per 

MMBtu of 

steam 

output or 

2.6 lb per 

MWh; 3-run 

average.

1 hr 

minimum 

sampling 

time, use a 

span value 

of 400 ppmv 

for Method 

10.

b.

Filterable

Particulate 

Matter (or 

Total 

Selected 

Metals)

0.0098 lb 

per MMBtu of 

heat input; 

or (4.2E-05a

lb per MMBtu 

of heat 

input).

0.012 lb 

per MMBtu 

of steam 

output or 

0.14 lb per 

MWh; or 

(5.4E-05a

lb per 

Collect a 

minimum of 

3 dscm per 

run
Page 309 of 360

If your boiler 

or process 

heater is in 

this 

subcategory 

...

For the 

following 

pollutants 

... 

The 

emissions 

must not 

exceed the 

following 

emission 

limits, 

except 

during 

periods of 

startup and 

shutdown...

Or the 

emissions 

must not 

exceed the 

following 

alternative 

outputbased 

limits...

Using this 

specified 

sampling 

volume or 

test run 

duration...

MMBtu of 

steam 

output or 

5.9E-04a lb 

per MWh) .

8. Suspension 

burners 

designed to 

burn 

biomass/biobased solids

a. CO (or 

CEMS)

58 ppm by 

volume on a 

dry basis 

corrected to 

3 percent 

oxygen, 3-

run average; 

or (1,400

ppm by 

volume on a 

dry basis 

corrected to 

3 percent 

oxygen, 10-

day rolling 

average).

0.046 lb 

per MMBtu 

of steam 

output or 

0.64 lb per 

MWh; 3-run 

average;

1 hr 

minimum 

sampling 

time, use a 

span value 

of 100 ppmv 

for Method 

10.

b.

Filterable

Particulate 

Matter (or 

Total 

Selected 

Metals)

0.051 lb per 

MMBtu of 

heat input; 

or (1.1E-03 

lb per MMBtu 

of heat 

input).

0.052 lb 

per MMBtu 

of steam 

output or 

0.71 lb per 

MWh; or 

(0.0012 lb 

per MMBtu 

of steam 

output or 

0.016 lb 

per MWh) .

Collect a 

minimum of 

1 dscm per 

run

9. Dutch 

Ovens/Pile 

a. CO (or 

CEMS)

810 ppm by 

volume on a 

0.89 lb per 

MMBtu of 

1 hr 

minimum 
Page 310 of 360

If your boiler 

or process 

heater is in 

this 

subcategory 

...

For the 

following 

pollutants 

... 

The 

emissions 

must not 

exceed the 

following 

emission 

limits, 

except 

during 

periods of 

startup and 

shutdown...

Or the 

emissions 

must not 

exceed the 

following 

alternative 

outputbased 

limits...

Using this 

specified 

sampling 

volume or 

test run 

duration...

burners 

designed to 

burn 

biomass/biobased solids

dry basis 

corrected to 

3 percent 

oxygen, 3-

run average; 

or (440 ppm 

by volume on 

a dry basis 

corrected to 

3 percent 

oxygen, 10-

day rolling 

average).

steam 

output or 

8.9 lb per 

MWh; 3-run 

average.

sampling 

time, use a 

span value 

of 1000 

ppmv for 

Method 10.

b.

Filterable

Particulate 

Matter (or 

Total 

Selected 

Metals)

0.036 lb per 

MMBtu of 

heat input; 

or (4.1E-05 

lb per MMBtu 

of heat 

input).

0.050 lb 

per MMBtu 

of steam 

output or 

0.51 lb per 

MWh; or 

(5.5E-05 lb 

per MMBtu 

of steam 

output or 

5.8E-04 lb 

per MWh).

Collect a 

minimum of 

1 dscm per 

run

10. Fuel cell 

units designed 

to burn 

biomass/biobased solids

a. CO 210 ppm by 

volume on a 

dry basis 

corrected to 

3 percent 

oxygen.

0.29 lb per 

MMBtu of 

steam 

output or 

2.3 lb per 

MWh.

1 hr 

minimum 

sampling 

time, use a 

span value 

of 500 ppmv 

for Method 

10.
Page 311 of 360

If your boiler 

or process 

heater is in 

this 

subcategory 

...

For the 

following 

pollutants 

... 

The 

emissions 

must not 

exceed the 

following 

emission 

limits, 

except 

during 

periods of 

startup and 

shutdown...

Or the 

emissions 

must not 

exceed the 

following 

alternative 

outputbased 

limits...

Using this 

specified 

sampling 

volume or 

test run 

duration...

b.

Filterable

Particulate 

Matter (or 

Total 

Selected 

Metals)

0.011 lb per 

MMBtu of 

heat input; 

or (4.9E-05a

lb per MMBtu 

of heat 

input).

0.030 lb 

per MMBtu 

of steam 

output or 

0.16 lb per 

MWh; or 

(8.6E-05a

lb per 

MMBtu of 

steam 

output or 

6.9E-04a lb 

per MWh) .

Collect a 

minimum of 

1 dscm per 

run

11. Hybrid 

suspension 

grate boiler 

designed to 

burn 

biomass/biobased solids

a. CO (or 

CEMS)

1,500 ppm by 

volume on a 

dry basis 

corrected to 

3 percent 

oxygen, 3-

run average; 

or (730 ppm 

by volume on 

a dry basis 

corrected to 

3 percent 

oxygen, 10-

day rolling 

average).

1.80 lb per 

MMBtu of 

steam 

output or 

17 lb per 

MWh; 3-run

average.

1 hr 

minimum 

sampling 

time, use a 

span value 

of 3000 

ppmv for 

Method 10.
Page 312 of 360

If your boiler 

or process 

heater is in 

this 

subcategory 

...

For the 

following 

pollutants 

... 

The 

emissions 

must not 

exceed the 

following 

emission 

limits, 

except 

during 

periods of 

startup and 

shutdown...

Or the 

emissions 

must not 

exceed the 

following 

alternative 

outputbased 

limits...

Using this 

specified 

sampling 

volume or 

test run 

duration...

b.

Filterable

Particulate 

Matter (or 

Total 

Selected 

Metals)

0.026 lb per 

MMBtu of 

heat input; 

or (4.9E-04a

lb per MMBtu 

of heat 

input).

0.033 lb 

per MMBtu 

of steam 

output or 

0.37 lb per 

MWh; or 

(6.2E-04a

lb per 

MMBtu of 

steam 

output or 

6.9E-03a lb 

per MWh) . 

Collect a 

minimum of 

3 dscm per 

run

12. Units 

designed to 

burn liquid 

fuel

a. Hydrogen 

Chloride

0.0012 lb 

per MMBtu of 

heat input.

0.0013 lb 

per MMBtu 

of steam 

output or 

0.017 lb 

per MWh

For M26A: 

Collect a 

minimum of 

1 dscm per 

run; for 

M26, 

collect a 

minimum of 

120 liters 

per run

b. Mercury 4.9E-07a lb 

per MMBtu of 

heat input.

5.4E-07a lb 

per MMBtu 

of steam 

output or 

6.8E-06a lb 

per MWh

For M29, 

collect a 

minimum of 

4 dscm per 

run; for 

M30A or 

M30B, 

collect a 

minimum 

sample as 

specified 

in the 
Page 313 of 360

If your boiler 

or process 

heater is in 

this 

subcategory 

...

For the 

following 

pollutants 

... 

The 

emissions 

must not 

exceed the 

following 

emission 

limits, 

except 

during 

periods of 

startup and 

shutdown...

Or the 

emissions 

must not 

exceed the 

following 

alternative 

outputbased 

limits...

Using this 

specified 

sampling 

volume or 

test run 

duration...

method; for 

ASTM D6784b

collect a 

minimum of 

4 dscm.

13. Units 

designed to 

burn heavy 

liquid fuel

a. CO (or 

CEMS)

10 ppm by 

volume on a 

dry basis 

corrected to 

3 percent 

oxygen, 3-

run average; 

or (18 ppm 

by volume on 

a dry basis 

corrected to 

3 percent 

oxygen, 10-

day rolling 

average).

0.0091 lb 

per MMBtu 

of steam 

output or 

0.11 lb per 

MWh; 3-run 

average.

1 hr 

minimum 

sampling 

time, use a 

span value 

of 30 ppmv 

for Method 

10.

b. 

Filterable 

Particulate 

Matter 

0.013 lb per 

MMBtu of 

heat input. 

0.015 lb 

per MMBtu 

of steam 

output or 

0.18 lb per 

MWh.

Collect a 

minimum of 

2 dscm per 

run.

14. Units 

designed to 

burn light 

liquid fuel

a. CO (or 

CEMS)

3 ppm by 

volume on a 

dry basis 

corrected to 

3 percent 

oxygen; or 

(60 ppm by 

volume on a 

dry basis 

0.0031 lb 

per MMBtu 

of steam 

output or 

0.033 lb 

per MWh.

1 hr 

minimum 

sampling 

time, use a 

span value 

of 10 ppmv 

for Method 

10.
Page 314 of 360

If your boiler 

or process 

heater is in 

this 

subcategory 

...

For the 

following 

pollutants 

... 

The 

emissions 

must not 

exceed the 

following 

emission 

limits, 

except 

during 

periods of 

startup and 

shutdown...

Or the 

emissions 

must not 

exceed the 

following 

alternative 

outputbased 

limits...

Using this 

specified 

sampling 

volume or 

test run 

duration...

corrected to 

3 percent 

oxygen, 1-

day block

average).

b. 

Filterable 

Particulate 

Matter 

0.0011a lb 

per MMBtu of 

heat input 

for light 

liquid.

0.0015

a lb 

per MMBtu 

of steam 

output or 

0.016 lb 

per MWh.

Collect a 

minimum of 

3 dscm per 

run

15. Units 

designed to 

burn liquid 

fuel located 

in noncontinental 

states and 

territories

a. CO 18 ppm by 

volume on a 

dry basis 

corrected to 

3 percent 

oxygen, 3-

run average 

based on 

stack test 

(91 ppm by 

volume on a 

dry basis 

corrected to 

3 percent 

oxygen, 3-

hour rolling 

average 

based on 

CEM).

0.017 lb 

per MMBtu 

of steam 

output or 

0.20 lb per 

MWh; 3-run 

average.

1 hr 

minimum 

sampling 

time, use a 

span value 

of 40 ppmv 

for Method 

10.
Page 315 of 360

If your boiler 

or process 

heater is in 

this 

subcategory 

...

For the 

following 

pollutants 

... 

The 

emissions 

must not 

exceed the 

following 

emission 

limits, 

except 

during 

periods of 

startup and 

shutdown...

Or the 

emissions 

must not 

exceed the 

following 

alternative 

outputbased 

limits...

Using this 

specified 

sampling 

volume or 

test run 

duration...

b. 

Filterable 

Particulate 

Matter 

0.0080 lb 

per MMBtu of 

heat input.

0.0087 lb 

per MMBtu 

of steam 

output or 

0.11 lb per 

MWh.

Collect a 

minimum of 

4 dscm per 

run

16. Units 

designed to 

burn gas 2 

(other) gases

a. CO 4 ppm by 

volume on a 

dry basis 

corrected to 

3 percent 

oxygen.

0.005 lb 

per MMBtu 

of steam 

output or 

0.031 lb 

per MWh.

1 hr 

minimum 

sampling 

time, use a 

span value 

of 10 ppmv 

for Method 

10.

b. Hydrogen 

Chloride

0.0017 lb 

per MMBtu of 

heat input.

0.0029 lb 

per MMBtu 

of steam 

output or 

0.018 lb 

per MWh

For M26A, 

Collect a 

minimum of 

1 dscm per 

run; for 

M26, 

collect a 

minimum of 

120 liters 

per run 

c. Mercury 7.9E-06 lb 

per MMBtu of 

heat input.

1.4E-05 lb 

per MMBtu 

of steam 

output or 

8.3E-05 lb 

per MWh

For M29, 

collect a 

minimum of 

3 dscm per 

run; for 

M30A or 

M30B, 

collect a 

minimum 

sample as 

specified 
Page 316 of 360

If your boiler 

or process 

heater is in 

this 

subcategory 

...

For the 

following 

pollutants 

... 

The 

emissions 

must not 

exceed the 

following 

emission 

limits, 

except 

during 

periods of 

startup and 

shutdown...

Or the 

emissions 

must not 

exceed the 

following 

alternative 

outputbased 

limits...

Using this 

specified 

sampling 

volume or 

test run 

duration...

in the 

method; for 

ASTM D6784b

collect a 

minimum of 

3 dscm.

d.

Filterable

Particulate 

Matter (or 

Total 

Selected 

Metals)

0.0067 lb 

per MMBtu of 

heat input; 

or (2.4E-04 

lb per MMBtu 

of heat 

input).

0.012 lb 

per MMBtu 

of steam 

output or 

0.070 lb 

per MWh; or 

(4.0E-04 lb 

per MMBtu 

of steam 

output or 

0.0025 lb 

per MWh).

Collect a 

minimum of 

1 dscm per 

run

a If you are conducting stack tests to demonstrate compliance 

and your performance tests for this pollutant for at least 2 

consecutive years show that your emissions are at or below this 

limit, you can skip testing according to §63.7515 if all of the 

other provision of §63.7515 are met. For all other pollutants 

that do not contain a footnote “a”, your performance tests for 

this pollutant for at least 2 consecutive years must show that 

your emissions are at or 75 percent of this limit in order to 

qualify for skip testing. 

b Incorporated by reference, see §63.14.
Page 317 of 360

Table 2 to Subpart DDDDD of Part 63—Emission Limits for Existing 

Boilers and Process Heaters (Units with heat input capacity of 

10 million Btu per hour or greater) 

As stated in §63.7500, you must comply with the following 

applicable emission limits:

If your boiler 

or process 

heater is in 

this 

subcategory 

...

For the 

following 

pollutants 

...

The 

emissions 

must not 

exceed the 

following 

emission 

limits,

except 

during 

periods of 

startup and 

shutdown...

The emissions 

must not 

exceed the 

following 

alternative 

output-based 

limits...

Using this 

specified 

sampling 

volume or 

test run 

duration...

1. Units in 

all 

subcategories 

designed to 

burn solid 

fuel

a. Hydrogen 

Chloride

0.022 lb per 

MMBtu of 

heat input.

0.025 lb per 

MMBtu of 

steam output 

or 0.28 lb 

per MWh

For M26A, 

Collect a 

minimum of 1 

dscm per 

run; for 

M26, collect 

a minimum of 

120 liters 

per run.

 b. Mercury 3.1E-06 lb 

per MMBtu of 

heat input.

3.5E-06 lb 

per MMBtu of 

steam output 

or 4.0E-05 lb 

per MWh

For M29, 

collect a 

minimum of 3 

dscm per 

run; for 

M30A or 

M30B, 

collect a 

minimum 

sample as 

specified in 

the method; 

for ASTM 

D6784b

collect a 

minimum of 3 

dscm.

2. Pulverized a. CO (or 41 ppm by 0.035 lb per 1 hr minimum 
Page 318 of 360

If your boiler 

or process 

heater is in 

this 

subcategory 

...

For the 

following 

pollutants 

...

The 

emissions 

must not 

exceed the 

following 

emission 

limits,

except 

during 

periods of 

startup and 

shutdown...

The emissions 

must not 

exceed the 

following 

alternative 

output-based 

limits...

Using this 

specified 

sampling 

volume or 

test run 

duration...

coal boilers 

designed to 

burn 

coal/solid 

fossil fuel

CEMS) volume on a 

dry basis 

corrected to 

3 percent 

oxygen, 3-

run average; 

or (28 ppm 

by volume on 

a dry basis 

corrected to 

3 percent 

oxygen, 10-

day rolling 

average).

MMBtu of 

steam output 

or 0.42 lb 

per MWh; 3-

run average.

sampling 

time, use a 

span value 

of 100 ppmv 

for Method 

10.

b.

Filterable

Particulate 

Matter (or 

Total 

Selected 

Metals)

0.044 lb per 

MMBtu of 

heat input; 

or (5.9E-05 

lb per MMBtu 

of heat 

input).

0.045 lb per 

MMBtu of 

steam output 

or 0.54 lb 

per MWh; or 

(6.0E-05 lb 

per MMBtu of 

steam output 

or 7.3E-04 lb 

per MWh).

Collect a 

minimum of 1 

dscm per 

run.

3. Stokers 

designed to 

burn 

coal/solid 

fossil fuel

a. CO (or 

CEMS)

220 ppm by

volume on a 

dry basis 

corrected to 

3 percent 

oxygen, 3-

run average; 

or (34 ppm 

by volume on 

a dry basis 

corrected to 

0.20 lb per 

MMBtu of 

steam output 

or 2.3 lb per 

MWh; 3-run 

average

1 hr minimum 

sampling 

time, use a 

span value 

of 400 ppmv 

for Method 

10.
Page 319 of 360

If your boiler 

or process 

heater is in 

this 

subcategory 

...

For the 

following 

pollutants 

...

The 

emissions 

must not 

exceed the 

following 

emission 

limits,

except 

during 

periods of 

startup and 

shutdown...

The emissions 

must not 

exceed the 

following 

alternative 

output-based 

limits...

Using this 

specified 

sampling 

volume or 

test run 

duration...

3 percent 

oxygen, 10-

day rolling 

average).

b.

Filterable

Particulate 

Matter (or 

Total 

Selected 

Metals)

0.028 lb per 

MMBtu of 

heat input; 

or (8.3E-05 

lb per MMBtu 

of heat 

input).

0.030 lb per 

MMBtu of 

steam output 

or 0.35 lb 

per MWh; or 

(8.8E-05 lb 

per MMBtu of 

steam output 

or 0.0011 lb 

per MWh).

Collect a 

minimum of 2 

dscm per 

run.

4. Fluidized 

bed units 

designed to 

burn coal/ 

solid fossil 

fuel

a. CO (or 

CEMS)

56 ppm by 

volume on a 

dry basis 

corrected to 

3 percent 

oxygen, 3-

run average; 

or (59 ppm

by volume on 

a dry basis 

corrected to 

3 percent 

oxygen, 10-

day rolling 

average).

0.049 lb per 

MMBtu of 

steam output 

or 0.57 lb 

per MWh; 3-

run average

1 hr minimum 

sampling 

time, use a 

span value 

of 100 ppmv 

for Method 

10.

b.

Filterable

Particulate 

Matter (or 

Total 

Selected 

0.088 lb per 

MMBtu of 

heat input; 

or (1.7E-05 

lb per MMBtu 

of heat 

0.092 lb per 

MMBtu of 

steam output 

or 1.1 lb per 

MWh; or 

(1.8E-05 lb 

Collect a 

minimum of 1 

dscm per 

run.
Page 320 of 360

If your boiler 

or process 

heater is in 

this 

subcategory 

...

For the 

following 

pollutants 

...

The 

emissions 

must not 

exceed the 

following 

emission 

limits,

except 

during 

periods of 

startup and 

shutdown...

The emissions 

must not 

exceed the 

following 

alternative 

output-based 

limits...

Using this 

specified 

sampling 

volume or 

test run 

duration...

Metals) input). per MMBtu of 

steam output 

or 2.1E-04 lb 

per MWh).

5. 

Stokers/sloped 

grate/others 

designed to 

burn wet 

biomass fuel

a. CO (or 

CEMS)

790 ppm by 

volume on a 

dry basis 

corrected to 

3 percent 

oxygen, 3-

run average; 

or (410 ppm 

by volume on 

a dry basis 

corrected to 

3 percent 

oxygen, 10-

day rolling

average).

0.72 lb per 

MMBtu of 

steam output 

or 8.7 lb per 

MWh; 3-run 

average.

1 hr minimum 

sampling 

time, use a 

span value 

of 1000 ppmv 

for Method 

10.

b.

Filterable

Particulate 

Matter (or 

Total 

Selected 

Metals)

0.029 lb per 

MMBtu of 

heat input; 

or (5.7E-05 

lb per MMBtu 

of heat 

input).

0.034 lb per 

MMBtu of 

steam output 

or 0.41 lb 

per MWh; or 

(6.6E-05 lb 

per MMBtu of 

steam output 

or 8.0E-04 lb 

per MWh).

Collect a 

minimum of 2 

dscm per 

run.
Page 321 of 360

If your boiler 

or process 

heater is in 

this 

subcategory 

...

For the 

following 

pollutants 

...

The 

emissions 

must not 

exceed the 

following 

emission 

limits,

except 

during 

periods of 

startup and 

shutdown...

The emissions 

must not 

exceed the 

following 

alternative 

output-based 

limits...

Using this 

specified 

sampling 

volume or 

test run 

duration...

6. 

Stokers/sloped 

grate/others 

designed to 

burn kilndried biomass 

fuel

a. CO 250 ppm by 

volume on a 

dry basis 

corrected to 

3 percent 

oxygen.

0.23 lb per 

MMBtu of 

steam output 

or 2.8 lb per 

MWh.

1 hr minimum 

sampling 

time, use a 

span value 

of 500 ppmv 

for Method 

10.

b.

Filterable

Particulate 

Matter (or 

Total 

Selected 

Metals)

0.32 lb per 

MMBtu of 

heat input; 

or (4.0E-03 

lb per MMBtu 

of heat 

input).

0.37 lb per 

MMBtu of 

steam output 

or 4.5 lb per 

MWh; or 

(0.0046 lb 

per MMBtu of 

steam output 

or 0.056 lb 

per MWh). 

Collect a 

minimum of 1 

dscm per 

run.

7. Fluidized 

bed units 

designed to 

burn 

biomass/biobased solid

a. CO (or 

CEMS)

370 ppm by 

volume on a 

dry basis 

corrected to 

3 percent 

oxygen, 3-

run average; 

or (180 ppm 

by volume on 

a dry basis 

corrected to 

3 percent 

oxygen, 10-

day rolling 

average).

0.36 lb per 

MMBtu of 

steam output 

or 4.1 lb per 

MWh; 3-run 

average.

1 hr minimum 

sampling 

time, use a 

span value 

of 500 ppmv 

for Method 

10.
Page 322 of 360

If your boiler 

or process 

heater is in 

this 

subcategory 

...

For the 

following 

pollutants 

...

The 

emissions 

must not 

exceed the 

following 

emission 

limits,

except 

during 

periods of 

startup and 

shutdown...

The emissions 

must not 

exceed the 

following 

alternative 

output-based 

limits...

Using this 

specified 

sampling 

volume or 

test run 

duration...

b.

Filterable

Particulate 

Matter (or 

Total 

Selected 

Metals)

0.11 lb per 

MMBtu of 

heat input; 

or (0.0012 

lb per MMBtu 

of heat 

input). 

0.14 lb per 

MMBtu of 

steam output 

or 1.6 lb per 

MWh; or 

(0.0015 lb 

per MMBtu of 

steam output 

or 0.017 lb 

per MWh).

Collect a 

minimum of 1 

dscm per 

run.

8. Suspension 

burners 

designed to 

burn 

biomass/biobased solid

a. CO (or 

CEMS)

58 ppm by 

volume on a

dry basis 

corrected to 

3 percent 

oxygen, 3-

run average; 

or (1,400

ppm by 

volume on a 

dry basis 

corrected to 

3 percent 

oxygen, 10-

day rolling 

average).

0.046 lb per 

MMBtu of 

steam output 

or 0.64 lb 

per MWh; 3-

run average;

1 hr minimum 

sampling 

time, use a 

span value 

of 100ppmv 

for Method 

10.

b.

Filterable

Particulate 

Matter (or 

Total 

Selected 

Metals)

0.051 lb per 

MMBtu of 

heat input; 

or (0.0011 

lb per MMBtu 

of heat 

input). 

0.052 lb per 

MMBtu of 

steam output 

or 0.71 lb 

per MWh; or 

(0.0012 lb 

per MMBtu of 

steam output 

or 0.016 lb 

Collect a 

minimum of 1 

dscm per 

run.
Page 323 of 360

If your boiler 

or process 

heater is in 

this 

subcategory 

...

For the 

following 

pollutants 

...

The 

emissions 

must not 

exceed the 

following 

emission 

limits,

except 

during 

periods of 

startup and 

shutdown...

The emissions 

must not 

exceed the 

following 

alternative 

output-based 

limits...

Using this 

specified 

sampling 

volume or 

test run 

duration...

per MWh).

9. Dutch 

Ovens/Pile 

burners 

designed to 

burn 

biomass/biobased solid

a. CO (or 

CEMS)

810 ppm by 

volume on a 

dry basis 

corrected to 

3 percent 

oxygen, 3-

run average; 

or (440 ppm 

by volume on 

a dry basis 

corrected to 

3 percent 

oxygen, 10-

day rolling 

average).

0.89 lb per 

MMBtu of 

steam output 

or 8.9 lb per 

MWh; 3-run 

average.

1 hr minimum 

sampling 

time, use a 

span value 

of 1000 ppmv 

for Method 

10.

b.

Filterable

Particulate 

Matter (or 

Total 

Selected 

Metals)

0.036 lb per 

MMBtu of 

heat input; 

or (2.4E-04 

lb per MMBtu 

of heat 

input).

0.050 lb per 

MMBtu of 

steam output 

or 0.51 lb 

per MWh; or 

(3.4E-04 lb 

per MMBtu of 

steam output 

or 0.0034 lb 

per MWh). 

Collect a 

minimum of 1 

dscm per 

run.

10. Fuel cell 

units designed 

to burn 

biomass/ biobased solid

a. CO 1,500 ppm by 

volume on a 

dry basis 

corrected to 

3 percent 

oxygen.

3.2 lb per 

MMBtu of 

steam output 

or 17 lb per 

MWh.

1 hr minimum 

sampling 

time, use a 

span value 

of 2000 ppmv 

for Method 

10.

b.

Filterable

0.033 lb per 

MMBtu of 

0.090 lb per 

MMBtu of 

Collect a 

minimum of 1 
Page 324 of 360

If your boiler 

or process 

heater is in 

this 

subcategory 

...

For the 

following 

pollutants 

...

The 

emissions 

must not 

exceed the 

following 

emission 

limits,

except 

during 

periods of 

startup and 

shutdown...

The emissions 

must not 

exceed the 

following 

alternative 

output-based 

limits...

Using this 

specified 

sampling 

volume or 

test run 

duration...

Particulate 

Matter (or 

Total 

Selected 

Metals)

heat input; 

or (4.9E-05 

lb per MMBtu 

of heat 

input). 

steam output 

or 0.46 lb 

per MWh; or 

(1.4E-04 lb 

per MMBtu of 

steam output 

or 6.9E-04 lb 

per MWh). 

dscm per 

run.

11. Hybrid 

suspension 

grate units 

designed to 

burn biomass/ 

bio-based 

solid

a. CO (or 

CEMS)

3,900 ppm by 

volume on a 

dry basis 

corrected to 

3 percent 

oxygen, 3-

run average; 

or (730 ppm 

by volume on 

a dry basis 

corrected to 

3 percent 

oxygen, 10-

day rolling 

average).

3.9 lb per 

MMBtu of 

steam output 

or 43 lb per 

MWh; 3-run 

average;

1 hr minimum 

sampling 

time, use a 

span value 

of 5000 ppmv 

for Method 

10.

b.

Filterable

Particulate 

Matter (or 

Total 

Selected 

Metals)

0.44 lb per 

MMBtu of 

heat input; 

or (4.9E-04a

lb per MMBtu 

of heat 

input). 

0.55 lb per 

MMBtu of 

steam output 

or 6.2 lb per 

MWh; or 

(6.2E-04a lb 

per MMBtu of 

steam output 

or 6.9E-03a

lb per MWh).

Collect a 

minimum of 1 

dscm per 

run.

12. Units 

designed to 

a. Hydrogen 

Chloride

0.0012 lb 

per MMBtu of 

0.0015 lb per 

MMBtu of 

For M26A, 

collect a 
Page 325 of 360

If your boiler 

or process 

heater is in 

this 

subcategory 

...

For the 

following 

pollutants 

...

The 

emissions 

must not 

exceed the 

following 

emission 

limits,

except 

during 

periods of 

startup and 

shutdown...

The emissions 

must not 

exceed the 

following 

alternative 

output-based 

limits...

Using this 

specified 

sampling 

volume or 

test run 

duration...

burn liquid 

fuel

heat input. steam output 

or 0.017 lb 

per MWh

minimum of 1 

dscm per 

run; for 

M26, collect 

a minimum of 

120 liters 

per run.

b. Mercury 2.6E-05 lb 

per MMBtu of 

heat input.

3.3E-05 lb 

per MMBtu of 

steam output 

or 3.6E-04 lb 

per MWh.

For M29, 

collect a 

minimum of 2 

dscm per 

run; for 

M30A or M30B 

collect a 

minimum 

sample as

specified in 

the method, 

for ASTM 

D6784b

collect a

minimum of 2 

dscm.

13. Units 

designed to 

burn heavy 

liquid fuel

a. CO (or 

CEMS)

10 ppm by 

volume on a 

dry basis 

corrected to 

3 percent 

oxygen, 3-

run average; 

or (18 ppm 

by volume on 

a dry basis 

corrected to 

3 percent 

0.0091 lb per 

MMBtu of 

steam output 

or 0.11 lb 

per MWh; 3-

run average.

1 hr minimum 

sampling 

time, use a 

span value 

of 20 ppmv 

for Method 

10.
Page 326 of 360

If your boiler 

or process 

heater is in 

this 

subcategory 

...

For the 

following 

pollutants 

...

The 

emissions 

must not 

exceed the 

following 

emission 

limits,

except 

during 

periods of 

startup and 

shutdown...

The emissions 

must not 

exceed the 

following 

alternative 

output-based 

limits...

Using this 

specified 

sampling 

volume or 

test run 

duration...

oxygen, 10-

day rolling 

average).

b. 

Filterable 

Particulate 

Matter 

0.062 lb per 

MMBtu of 

heat input. 

0.075 lb per 

MMBtu of 

steam output 

or 0.86 lb 

per MWh.

Collect a 

minimum of 1 

dscm per 

run.

14. Units 

designed to 

burn light 

liquid fuel

a. CO (or 

CEMS)

7 ppm by 

volume on a 

dry basis 

corrected to 

3 percent 

oxygen; or 

(60 ppm by 

volume on a 

dry basis 

corrected to 

3 percent 

oxygen, 1-

day block

average).

0.0071 lb per 

MMBtu of 

steam output 

or 0.076 lb 

per MWh.

1 hr minimum 

sampling 

time, use a 

span value 

of 10 ppmv 

for Method 

10.

b. 

Filterable 

Particulate 

Matter 

0.0034 lb 

per MMBtu of 

heat input.

0.0045 lb per 

MMBtu of 

steam output 

or 0.047 lb 

per MWh.

Collect a 

minimum of 3 

dscm per 

run.

15. Units 

designed to 

burn liquid 

fuel located 

in noncontinental 

states and 

territories

a. CO (or 

CEMS)

18 ppm by 

volume on a 

dry basis 

corrected to 

3 percent 

oxygen, 3-

run average 

based on 

0.017 lb per 

MMBtu of 

steam output 

or 0.20 lb 

per MWh; 3-

run average.

1 hr minimum 

sampling 

time, use a 

span value 

of 40 ppmv 

for Method 

10.
Page 327 of 360

If your boiler 

or process 

heater is in 

this 

subcategory 

...

For the 

following 

pollutants 

...

The 

emissions 

must not 

exceed the 

following 

emission 

limits,

except 

during 

periods of 

startup and 

shutdown...

The emissions 

must not 

exceed the 

following 

alternative 

output-based 

limits...

Using this 

specified 

sampling 

volume or 

test run 

duration...

stack test 

(91 ppm by 

volume on a 

dry basis 

corrected to 

3 percent 

oxygen, 3-

hour rolling

average 

based on 

CEM).

b. 

Filterable 

Particulate 

Matter 

0.0080 lb 

per MMBtu of 

heat input.

0.0097 lb per 

MMBtu of 

steam output 

or 0.11 lb 

per MWh. 

Collect a 

minimum of 2 

dscm per 

run.

16. Units 

designed to 

burn gas 2 

(other) gases

a. CO 4 ppm by 

volume on a 

dry basis 

corrected to 

3 percent 

oxygen.

0.0050 lb per 

MMBtu of 

steam output 

or 0.031 lb 

per MWh.

1 hr minimum 

sampling 

time, use a 

span value 

of 10 ppmv 

for Method 

10.

b. Hydrogen 

Chloride

0.0017 lb 

per MMBtu of 

heat input.

0.0029 lb per 

MMBtu of 

steam output 

or 0.018 lb 

per MWh.

For M26A, 

collect a 

minimum of 1 

dscm per 

run; for 

M26, collect 

a minimum of 

120 liters 

per run.

c. Mercury 7.9E-06 lb 

per MMBtu of 

heat input.

1.4E-05 lb 

per MMBtu of 

steam output 

For M29, 

collect a 

minimum of 2 
Page 328 of 360

If your boiler 

or process 

heater is in 

this 

subcategory 

...

For the 

following 

pollutants 

...

The 

emissions 

must not 

exceed the 

following 

emission 

limits,

except 

during 

periods of 

startup and 

shutdown...

The emissions 

must not 

exceed the 

following 

alternative 

output-based 

limits...

Using this 

specified 

sampling 

volume or 

test run 

duration...

or 8.3E-05 lb 

per MWh.

dscm per 

run; for 

M30A or 

M30B, 

collect a 

minimum 

sample as 

specified in 

the method; 

for ASTM 

D6784b

collect a 

minimum of 2 

dscm.

d.

Filterable

Particulate 

Matter (or 

Total 

Selected 

Metals).

0.0067 lb 

per MMBtu of 

heat input 

or (2.4E-04 

lb per MMBtu 

of heat 

input). 

0.012 lb per 

MMBtu of 

steam output 

or 0.070 lb 

per MWh; or 

(4.0E-04 lb 

per MMBtu of 

steam output 

or 0.0025 lb 

per MWh). 

Collect a 

minimum of 1 

dscm per 

run.

a If you are conducting stack tests to demonstrate compliance 

and your performance tests for this pollutant for at least 2 

consecutive years show that your emissions are at or below this 

limit, you can skip testing according to §63.7515 if all of the 

other provision of §63.7515 are met. For all other pollutants 

that do not contain a footnote a, your performance tests for 

this pollutant for at least 2 consecutive years must show that 

your emissions are at or 75 percent of this limit in order to 

qualify for skip testing. 
Page 329 of 360

b Incorporated by reference, see §63.14.

Table 3 to Subpart DDDDD of Part 63—Work Practice Standards

As stated in §63.7500, you must comply with the following 

applicable work practice standards:

If your unit is... You must meet the following...

1. A new or existing boiler or 

process heater with heat input 

capacity of less than 5 

million Btu per hour in any of 

the following subcategories: 

unit designed to burn natural 

gas, refinery gas or other gas 

1 fuels; unit designed to burn 

gas 2 (other); or unit 

designed to burn light liquid.

Conduct a tune-up of the boiler 

or process heater every 5 years 

as specified in §63.7540.

2. A limited use boiler or 

process heater; or a new or 

existing boiler or process 

heater with heat input 

capacity of less than 10 

million Btu per hour in the 

unit designed to burn heavy 

liquid or unit designed to 

burn solid fuel subcategories; 

or a new or existing boiler or 

process heater with heat input 

capacity of less than 10 

million Btu per hour, but 

equal to or greater than 5 

million Btu per hour, in any

of the following 

subcategories: unit designed 

to burn natural gas, refinery 

gas or other gas 1 fuels; unit 

designed to burn gas 2 

(other); or unit designed to 

burn light liquid.

Conduct a tune-up of the boiler 

or process heater biennially as 

specified in §63.7540.

3. A new or existing boiler or 

process heater with heat input 

capacity of 10 million Btu per 

hour or greater. 

Conduct a tune-up of the boiler 

or process heater annually as 

specified in §63.7540. Units in 

either the Gas 1 or Metal Process 

Furnace subcategories will 
Page 330 of 360

If your unit is... You must meet the following...

conduct this tune-up as a work 

practice for all regulated 

emissions under this subpart. 

Units in all other subcategories 

will conduct this tune-up as a 

work practice for dioxins/furans.

4. An existing boiler or 

process heater located at a 

major source facility. 

Must have a one-time energy 

assessment performed on the major 

source facility by qualified 

energy assessor. An energy 

assessment completed on or after 

January 1, 2008, that meets or is 

amended to meet the energy 

assessment requirements in this 

table, satisfies the energy 

assessment requirement. The 

energy assessment must include: 

a. A visual inspection of the 

boiler or process heater 

system.

b. An evaluation of operating 

characteristics of the 

facility, specifications of 

energy using systems, 

operating and maintenance 

procedures, and unusual 

operating constraints.

c. An inventory of major systems

consuming energy from affected 

boilers and process heaters 

and which are under the 

control of the boiler/process 

heater owner/operator.

d. A review of available 

architectural and engineering 

plans, facility operation and 

maintenance procedures and 

logs, and fuel usage.

e. A review of the facility's 

energy management practices 

and provide recommendations 

for improvements consistent 

with the definition of energy 

management practices. 

f. A list of major energy 

conservation measures.
Page 331 of 360

If your unit is... You must meet the following...

g. A list of the energy savings 

potential of the energy 

conservation measures 

identified.

h. A comprehensive report 

detailing the ways to improve 

efficiency, the cost of 

specific improvements, 

benefits, and the time frame 

for recouping those 

investments.

5. An existing or new unit 

subject to emission limits in 

Tables 1 or 2 to this subpart.

You must employ good combustion 

practices and demonstrate that 

good combustion practices are 

maintained by monitoring O2

concentrations and optimizing 

those concentrations as specified 

by the boiler manufacturer; you 

must ensure that boiler operators 

are trained in startup and 

shutdown procedures, including 

maintenance and cleaning, safety, 

control device startup, and 

procedures to minimize emissions; 

and you must maintain records 

during periods of startup and 

shutdown and include in your 

compliance reports the O2

conditions/data for each event, 

length of startup/shutdown and 

reason for the startup/shutdown 

(i.e., normal/routine, 

problem/malfunction, outage).

Table 4 to Subpart DDDDD of Part 63—Operating Limits for Boilers 

and Process Heaters

As stated in §63.7500, you must comply with the applicable 

operating limits: 

If you demonstrate 

compliance using . . . You must meet these operating limits . . .

1. Wet PM scrubber Maintain the 30-day rolling average 
Page 332 of 360

If you demonstrate 

compliance using . . . You must meet these operating limits . . .

control on a boiler 

not using a PM CPMS. 

pressure drop and the 30-day rolling 

average liquid flow rate at or above the 

lowest one-hour average pressure drop and 

the lowest one-hour average liquid flow 

rate, respectively, measured during the 

most recent performance test demonstrating 

compliance with the PM emission limitation 

according to §63.7530(b) and Table 7 to 

this subpart.

2. Wet acid gas (HCl) 

scrubber control on a 

boiler not using a 

hydrogen chloride 

CEMS.

Maintain the 30-day rolling average 

effluent pH at or above the lowest onehour average pH and the 30-day rolling 

average liquid flow rate at or above the 

lowest one-hour average liquid flow rate 

measured during the most recent 

performance test demonstrating compliance 

with the HCl emission limitation according 

to §63.7530(b) and Table 7 to this 

subpart.

3. Fabric filter 

control on units not 

using a PM CPMS.

a. Maintain opacity to less than or equal 

to 10 percent opacity (daily block 

average); or

b. Install and operate a bag leak 

detection system according to §63.7525 and 

operate the fabric filter such that the 

bag leak detection system alarm does not 

sound more than 5 percent of the operating 

time during each 6-month period.

4. Electrostatic 

precipitator control 

on units not using a 

PM CPMS.

a. This option is for boilers and process 

heaters that operate dry control systems 

(i.e., an ESP without a wet scrubber). 

Existing and new boilers and process 

heaters must maintain opacity to less than 

or equal to 10 percent opacity (daily 

block average); or 

b. This option is only for boilers and 

process heaters not subject to PM CPMS or 

continuous compliance with an opacity 

limit (i.e., COMS). Maintain the 30-day 

rolling average total secondary electric 

power input of the electrostatic 
Page 333 of 360

If you demonstrate 

compliance using . . . You must meet these operating limits . . .

precipitator at or above the operating 

limits established during the performance 

test according to §63.7530(b) and Table 7 

to this subpart.

5. Dry scrubber or 

carbon injection 

control on a boiler 

not using a mercury 

CEMS.

Maintain the minimum sorbent or carbon 

injection rate as defined in §63.7575 of 

this subpart.

6. Any other add-on 

air pollution control 

type on units not 

using a PM CPMS.

This option is for boilers and process 

heaters that operate dry control systems. 

Existing and new boilers and process 

heaters must maintain opacity to less than 

or equal to 10 percent opacity (daily 

block average).

7. Fuel analysis. Maintain the fuel type or fuel mixture 

such that the applicable emission rates 

calculated according to §63.7530(c)(1), 

(2) and/or (3) is less than the applicable 

emission limits.

8. Performance 

testing.

For boilers and process heaters that 

demonstrate compliance with a performance 

test, maintain the operating load of each 

unit such that it does not exceed 110 

percent of the average operating load 

recorded during the most recent 

performance test.

9. Oxygen Analyzer 

System

For boilers and process heaters subject to 

a carbon monoxide emission limit that 

demonstrate compliance with an O2 analyzer 

system as specified in §63.7525(a), 

maintain the oxygen level such that it is 

not below the lowest hourly average oxygen 

concentration measured during the most 

recent CO performance test.
Page 334 of 360

Table 5 to Subpart DDDDD of Part 63—Performance Testing 

Requirements

As stated in §63.7520, you must comply with the following 

requirements for performance testing for existing, new or 

reconstructed affected sources:

To conduct a 

performance 

test for the 

following 

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

1. Particulate 

Matter

a. Select sampling 

ports location and 

the number of 

traverse points.

Method 1 at 40 CFR part 60, 

appendix A-1 of this 

chapter.

 b. Determine 

velocity and 

volumetric flowrate of the stack 

gas.

Method 2, 2F, or 2G at 40 

CFR part 60, appendix A-1 

or A-2 to part 60 of this 

chapter.

 c. Determine oxygen 

or carbon dioxide 

concentration of 

the stack gas.

Method 3A or 3B at 40 CFR 

part 60, appendix A-2 to 

part 60 of this chapter, or 

ANSI/ASME PTC 19.10-1981.a

 d. Measure the 

moisture content of 

the stack gas.

Method 4 at 40 CFR part 60, 

appendix A-3 of this 

chapter.

 e. Measure the 

particulate matter 

emission 

concentration.

Method 5 or 17 (positive 

pressure fabric filters 

must use Method 5D) at 40 

CFR part 60, appendix A-3 

or A-6 of this chapter.

 f. Convert 

emissions 

concentration to lb 

per MMBtu emission 

rates.

Method 19 F-factor 

methodology at 40 CFR part 

60, appendix A-7 of this 

chapter.

2. Hydrogen 

chloride

a. Select sampling 

ports location and 

the number of 

traverse points.

Method 1 at 40 CFR part 60, 

appendix A-1 of this 

chapter.

 b. Determine 

velocity and 

volumetric flowMethod 2, 2F, or 2G at 40 

CFR part 60, appendix A-2 

of this chapter.
Page 335 of 360

To conduct a 

performance 

test for the 

following 

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

rate of the stack 

gas.

 c. Determine oxygen 

or carbon dioxide 

concentration of 

the stack gas.

Method 3A or 3B at 40 CFR 

part 60, appendix A-2 of 

this chapter, or ANSI/ASME 

PTC 19.10-1981.a

 d. Measure the 

moisture content of 

the stack gas.

Method 4 at 40 CFR part 60, 

appendix A-3 of this 

chapter.

 e. Measure the 

hydrogen chloride 

emission 

concentration.

Method 26 or 26A (M26 or 

M26A) at 40 CFR part 60, 

appendix A-8 of this 

chapter.

 f. Convert 

emissions 

concentration to lb 

per MMBtu emission 

rates.

Method 19 F-factor 

methodology at 40 CFR part 

60, appendix A-7 of this 

chapter.

3. Mercury a. Select sampling 

ports location and 

the number of 

traverse points.

Method 1 at 40 CFR part 60, 

appendix A-1 of this 

chapter.

 b. Determine 

velocity and 

volumetric flowrate of the stack 

gas.

Method 2, 2F, or 2G at 40 

CFR part 60, appendix A-1 

or A-2 of this chapter.

 c. Determine oxygen 

or carbon dioxide 

concentration of 

the stack gas.

Method 3A or 3B at 40 CFR 

part 60, appendix A-1 of 

this chapter, or ANSI/ASME 

PTC 19.10-1981.a

 d. Measure the 

moisture content of 

the stack gas.

Method 4 at 40 CFR part 60, 

appendix A-3 of this 

chapter.

 e. Measure the 

mercury emission 

concentration.

Method 29, 30A, or 30B 

(M29, M30A, or M30B) at 40 

CFR part 60, appendix A-8 

of this chapter or Method 

101A at 40 CFR part 60, 

appendix B of this chapter, 

or ASTM Method D6784.a
Page 336 of 360

To conduct a 

performance 

test for the 

following 

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

 f. Convert 

emissions 

concentration to lb 

per MMBtu emission 

rates.

Method 19 F-factor 

methodology at 40 CFR part 

60, appendix A-7 of this 

chapter.

4. CO a. Select the 

sampling ports 

location and the 

number of traverse 

points.

Method 1 at 40 CFR part 60, 

appendix A-1 of this 

chapter.

 b. Determine oxygen 

concentration of 

the stack gas.

Method 3A or 3B at 40 CFR 

part 60, appendix A-3 of 

this chapter, or ASTM 

D6522–00 (Reapproved 2005), 

or ANSI/ASME PTC 19.10-

1981.a

 c. Measure the 

moisture content of 

the stack gas.

Method 4 at 40 CFR part 60, 

appendix A-3 of this 

chapter.

 d. Measure the CO 

emission 

concentration.

Method 10 at 40 CFR part 

60, appendix A-4 of this 

chapter. Use a span value 

of 2 times the 

concentration of the 

applicable emission limit.

a Incorporated by reference, see §63.14.

Table 6 to Subpart DDDDD of Part 63—Fuel Analysis Requirements

As stated in §63.7521, you must comply with the following 

requirements for fuel analysis testing for existing, new or 

reconstructed affected sources. However, equivalent methods (as 

defined in §63.7575) may be used in lieu of the prescribed 

methods at the discretion of the source owner or operator:
Page 337 of 360

To conduct a 

fuel

analysis for 

the following

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

1. Mercury a. Collect fuel 

samples. 

Procedure in §63.7521(c) or 

ASTM D2234/D2234Ma(for coal) 

or EPA 1631 or EPA 1631E or 

ASTM D6323a (forsolid), or 

EPA 821-R-01-013 (for liquid 

or solid), or equivalent.

 b. Composite fuel 

samples.

Procedure in §63.7521(d) or 

equivalent.

 c. Prepare 

composited fuel 

samples.

EPA SW–846–3050Ba (for solid 

samples), EPA SW–846–3020Aa

(for liquid samples), ASTM 

D2013/D2013Ma (for coal), 

ASTM D5198a (for biomass), 

or ASTME829 or EPA 3050 (for 

solid fuel), or EPA 821-R01-013 (for liquid or 

solid), or equivalent.

 d. Determine heat 

content of the fuel 

type. 

ASTM D5865a (for coal) or 

ASTM E711a (for biomass), or 

ASTM D5864 for liquids and 

other solids, or ASTM D240 

or equivalent.

 e. Determine 

moisture content of 

the fuel type. 

ASTM D3173a,ASTM E871a, or 

ASTM D5864, or ASTM D240 or 

equivalent.

 f. Measure mercury 

concentration in 

fuel sample.

ASTM D6722a (for coal), EPA 

SW–846–7471Ba (for solid 

samples), or EPA SW–846–

7470Aa (for liquid samples), 

or equivalent.

 g. Convert 

concentration into 

units of pounds of 

mercury per MMBtu of 

heat content.

Equation 8 in §63.7530.
Page 338 of 360

To conduct a 

fuel

analysis for 

the following

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

h. Calculate the 

mercury emission 

rate from the boiler 

or process heater in 

units of pounds per 

million Btu.

Equations 10 and 12 in 

§63.7530.

2. Hydrogen 

Chloride

a. Collect fuel 

samples. 

Procedure in §63.7521(c) or 

ASTM D2234/D2234Ma (for 

coal) or ASTM D6323a (for 

coal or biomass), or 

equivalent.

 b. Composite fuel 

samples.

Procedure in §63.7521(d) or 

equivalent.

 c. Prepare 

composited fuel 

samples.

EPA SW–846–3050Ba (for solid 

samples), EPA SW–846–3020Aa

(for liquid samples), ASTM 

D2013/D2013Ma (for coal), or 

ASTM D5198a (for biomass),or 

ASTME829 (for solid fuel), 

or EPA 3050 or equivalent.

 d. Determine heat 

content of the fuel 

type. 

ASTM D5865a (for coal) or 

ASTM E711a (for biomass), 

ASTM D5864, ASTM D240 or 

equivalent.

 e. Determine 

moisture content of 

the fuel type. 

ASTM D3173a or ASTM E871a, 

or D5864, or ASTM D240 or 

equivalent.

 f. Measure chlorine 

concentration in 

fuel sample.

EPA SW–846–9250a, ASTM 

D6721a , ASTM D4208(for 

coal), or EPA SW-846-5050a or 

ASTM E776a (for solid fuel), 

or EPA SW-846-9056 or SW846-9076 (for solids or 

liquids) or equivalent.
Page 339 of 360

To conduct a 

fuel

analysis for 

the following

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

 g. Convert 

concentrations into 

units of pounds of 

hydrogen chloride 

per MMBtu of heat 

content.

Equation 7 in §63.7530.

h. Calculate the 

hydrogen chloride 

emission rate from 

the boiler or 

process heater in 

units of pounds per 

million Btu.

Equations 10 and 11 in 

§63.7530.

3. Mercury Fuel 

Specification 

for other gas 1 

fuels

a. Measure mercury 

concentration in the 

fuel sample and 

convert to units of 

micrograms per cubic 

meter.

ASTM D5954a,

ASTM D6350a, ISO 6978-

1:2003(E)a, or ISO 6978-

2:2003(E)a, or equivalent.

4. Total 

Selected Metals 

for solid fuels

a. Collect fuel 

samples. 

Procedure in §63.7521(c) or 

ASTM D2234/D2234Ma (for 

coal) or ASTM D6323a (for 

coal or biomass), or 

equivalent.

b. Composite fuel 

samples.

Procedure in §63.7521(d) or 

equivalent.

c. Prepare 

composited fuel 

samples.

EPA SW–846–3050Ba (for solid 

samples), EPA SW–846–3020Aa

(for liquid samples), ASTM 

D2013/D2013Ma (for coal), 

ASTM D5198a or TAPPI T266 

(for biomass), or ASTME829 

(for solid fuel), or EPA 

3050 or equivalent.

d. Determine heat ASTM D5865a (for coal) or 
Page 340 of 360

To conduct a 

fuel

analysis for 

the following

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

content of the fuel 

type. 

ASTM E711a (for biomass), or 

ASTM D5864 for liquids and 

other solids, or ASTM D240 

or equivalent.

e. Determine 

moisture content of 

the fuel type. 

ASTM D3173a or ASTM E871a, 

or D5864, or ASTM D240 or 

equivalent.

f. Measure total 

selected metals 

concentration in 

fuel sample.

ASTM D3683, or ASTM D4606, 

or ASTM D6357 or EPA 200.8 

or or EPA SW-846-6020, or 

EPA SW-846-6020A, or ASTM 

E885, or EPA SW-846-6010B, 

EPA 7060 or EPA 7060A (for 

arsenic only), or EPA SW846-7740 (for selenium 

only), 

g. Convert 

concentrations into 

units of pounds of 

total selected 

metals per MMBtu of 

heat content.

Equations 9 in §63.7530.

h. Calculate the 

total selected 

metals emission rate 

from the boiler or 

process heater in 

units of pounds per 

million Btu.

Equations 10 and 13 in 

§63.7530.

a Incorporated by reference, see §63.14.
Page 341 of 360

Table 7 to Subpart DDDDD of Part 63—Establishing Operating 

Limits

As stated in §63.7520, you must comply with the following 

requirements for establishing operating limits:

If you have 

an 

applicable 

emission 

limit for . 

. .

And your 

operating 

limits are 

based on . . 

.

You must. . 

. Using . . .

According to 

the following

requirements

1. 

Particulate 

matter, 

total 

selected 

metals, or 

mercury.

a. Wet 

scrubber 

operating 

parameters.

i. Establish 

a sitespecific 

minimum 

scrubber 

pressure 

drop and 

minimum flow 

rate 

operating 

limit 

according to 

§63.7530(b).

(1) Data 

from the 

scrubber 

pressure 

drop and 

liquid flow 

rate 

monitors and 

the 

particulate 

matter or 

mercury 

performance 

test.

(a) You must 

collect 

scrubber 

pressure drop 

and liquid 

flow rate 

data every 15 

minutes 

during the 

entire period 

of the 

performance 

tests.

 (b) Determine 

the lowest 

hourly 

average 

scrubber 

pressure drop 

and liquid 

flow rate by 

computing the 

hourly 

averages 

using all of 

the 15-minute 

readings 

taken during 

each 

performance 

test.
Page 342 of 360

If you have 

an 

applicable 

emission 

limit for . 

. .

And your 

operating 

limits are 

based on . . 

.

You must. . 

. Using . . .

According to 

the following

requirements

 b. 

Electrostatic 

precipitator 

operating 

parameters 

(option only 

for units 

that operate 

wet 

scrubbers).

i. Establish 

a sitespecific 

minimum 

total 

secondary 

electric 

power input 

according to 

§63.7530(b).

(1) Data 

from the 

voltage and 

secondary 

amperage 

monitors 

during the 

particulate 

matter or 

mercury 

performance 

test.

(a) You must 

collect 

secondary 

voltage and 

secondary 

amperage for 

each ESP cell 

and calculate 

total 

secondary 

electric 

power input 

data every 15 

minutes 

during the 

entire period 

of the 

performance 

tests.

 (b) Determine 

the average 

total 

secondary 

electric 

power input 

by computing 

the hourly 

averages 

using all of 

the 15-minute 

readings 

taken during 

each 

performance 

test.

2. Hydrogen 

Chloride

a. Wet 

scrubber 

operating 

parameters.

i. Establish 

sitespecific 

minimum 

pressure 

drop, 

(1) Data 

from the 

pressure 

drop, pH, 

and liquid 

flow-rate 

(a) You must 

collect pH 

and liquid 

flow-rate 

data every 15 

minutes 
Page 343 of 360

If you have 

an 

applicable 

emission 

limit for . 

. .

And your 

operating 

limits are 

based on . . 

.

You must. . 

. Using . . .

According to 

the following

requirements

effluent pH, 

and flow 

rate 

operating 

limits 

according to 

§63.7530(b).

monitors and 

the hydrogen 

chloride 

performance 

test.

during the 

entire period 

of the 

performance 

tests.

 (b) Determine 

the hourly 

average pH 

and liquid 

flow rate by 

computing the 

hourly 

averages 

using all of 

the 15-minute 

readings 

taken during 

each 

performance 

test.

 b. Dry 

scrubber 

operating 

parameters.

i. Establish 

a sitespecific 

minimum 

sorbent 

injection 

rate 

operating 

limit 

according to 

§63.7530(b). 

If different 

acid gas 

sorbents are 

used during 

the hydrogen 

chloride 

performance 

test, the 

(1) Data 

from the 

sorbent 

injection 

rate 

monitors and 

hydrogen 

chloride or 

mercury 

performance 

test.

(a) You must 

collect 

sorbent 

injection 

rate data 

every 15 

minutes 

during the 

entire period 

of the 

performance 

tests.
Page 344 of 360

If you have 

an 

applicable 

emission 

limit for . 

. .

And your 

operating 

limits are 

based on . . 

.

You must. . 

. Using . . .

According to 

the following

requirements

average 

value for 

each sorbent 

becomes the 

sitespecific 

operating 

limit for 

that 

sorbent.

 (b) Determine 

the hourly 

average

sorbent 

injection 

rate by 

computing the 

hourly 

averages 

using all of 

the 15-minute 

readings 

taken during 

each 

performance 

test.

(c) Determine 

the lowest 

hourly 

average of 

the three 

test run 

averages 

established 

during the 

performance 

test as your 

operating 

limit. When 

your unit 

operates at 
Page 345 of 360

If you have 

an 

applicable 

emission 

limit for . 

. .

And your 

operating 

limits are 

based on . . 

.

You must. . 

. Using . . .

According to 

the following

requirements

lower loads, 

multiply your 

sorbent 

injection 

rate by the 

load fraction 

(e.g., for 50 

percent load, 

multiply the 

injection 

rate 

operating 

limit by 0.5) 

to determine 

the required 

injection 

rate.

3. Mercury a. Activated 

carbon 

injection.

i. Establish 

a sitespecific 

minimum 

activated 

carbon 

injection 

rate 

operating 

limit 

according to 

§63.7530(b).

(1) Data 

from the 

activated 

carbon rate 

monitors and 

mercury 

performance 

test.

(a) You must 

collect 

activated 

carbon 

injection 

rate data 

every 15 

minutes 

during the 

entire period 

of the 

performance 

tests.

(b) Determine 

the hourly 

average 

activated 

carbon 

injection 

rate by 

computing the 

hourly 

averages 

using all of 
Page 346 of 360

If you have 

an 

applicable 

emission 

limit for . 

. .

And your 

operating 

limits are 

based on . . 

.

You must. . 

. Using . . .

According to 

the following

requirements

the 15-minute 

readings 

taken during 

each 

performance 

test.

(c) Determine 

the lowest 

hourly 

average 

established 

during the 

performance 

test as your 

operating 

limit. When 

your unit 

operates at 

lower loads, 

multiply your 

activated 

carbon 

injection 

rate by the 

load fraction 

(e.g., actual 

heat input 

divided by 

heat input 

during 

performance 

test, for 50 

percent load, 

multiply the 

injection 

rate 

operating 

limit by 0.5) 

to determine 

the required 

injection 
Page 347 of 360

If you have 

an 

applicable 

emission 

limit for . 

. .

And your 

operating 

limits are 

based on . . 

.

You must. . 

. Using . . .

According to 

the following

requirements

rate.

4. Carbon 

monoxide

a. Oxygen i. Establish 

a unitspecific 

limit for 

minimum 

oxygen level 

according to 

§63.7520.

(1) Data 

from the 

oxygen 

analyzer 

system 

specified in 

§63.7525(a).

(a) You must 

collect 

oxygen data 

every 15 

minutes 

during the 

entire period 

of the 

performance 

tests.

(b) Determine 

the hourly 

average 

oxygen 

concentration

by computing 

the hourly

averages 

using all of 

the 15-minute 

readings 

taken during 

each 

performance 

test.

(c) Determine 

the lowest 

hourly 

average 

established 

during the 

performance 

test as your 

minimum 

operating 

limit.

5. Any 

pollutant 

for which 

compliance 

a. Boiler or 

process 

heater 

operating 

i. Establish 

a unit 

specific 

limit for 

(1) Data 

from the 

operating 

load 

(a) You must 

collect 

operating 

load or steam 
Page 348 of 360

If you have 

an 

applicable 

emission 

limit for . 

. .

And your 

operating 

limits are 

based on . . 

.

You must. . 

. Using . . .

According to 

the following

requirements

is 

demonstrated 

by a 

performance 

test.

load. maximum 

operating 

load 

according to 

§63.7520(c).

monitors or 

from steam 

generation 

monitors.

generation 

data every 15 

minutes 

during the 

entire period 

of the 

performance 

test.

(b) Determine 

the average 

operating 

load by 

computing the 

hourly 

averages 

using all of 

the 15-minute 

readings 

taken during 

each 

performance 

test.

(c) Determine 

the average 

of the three 

test run 

averages 

during the 

performance 

test, and 

multiply this 

by 1.1 (110 

percent) as 

your 

operating 

limit.
Page 349 of 360

Table 8 to Subpart DDDDD of Part 63—Demonstrating Continuous 

Compliance

As stated in §63.7540, you must show continuous compliance 

with the emission limitations for affected sources according to 

the following:

If you must meet the 

following operating 

limits or work 

practice

standards . . .

You must demonstrate continuous compliance 

by . . .

1. Opacity a. Collecting the opacity monitoring system 

data according to §63.7525(c) and §63.7535; 

and

 b. Reducing the opacity monitoring data to 

6-minute averages; and

 c. Maintaining opacity to less than or equal 

to 10 percent (daily block average).

2. PM CPMS a. Collecting the PM CPMS output data 

according to §63.7525; 

b. Reducing the data to 30-day rolling 

averages; and

c. Maintaining the 30-day rolling average PM 

CPMS output data to less than the operating 

limit established during the performance 

test according to §63.7530.

3. Fabric Filter Bag 

Leak Detection 

Operation

Installing and operating a bag leak 

detection system according to §63.7525 and 

operating the fabric filter such that the 

requirements in §63.7540(a)(9) are met.

4. Wet Scrubber 

Pressure Drop and 

Liquid Flow-rate

a. Collecting the pressure drop and liquid 

flow rate monitoring system data according 

to §§63.7525 and 63.7535; and

 b. Reducing the data to 30-day rolling

averages; and

 c. Maintaining the 30-day rolling average 
Page 350 of 360

If you must meet the 

following operating 

limits or work 

practice

standards . . .

You must demonstrate continuous compliance 

by . . .

pressure drop and liquid flow-rate at or 

above the operating limits established 

during the performance test according to 

§63.7530(b).

5. Wet Scrubber pH a. Collecting the pH monitoring system data 

according to §§63.7525 and 63.7535; and

 b. Reducing the data to 30-day rolling

averages; and

 c. Maintaining the 30-day rolling average pH 

at or above the operating limit established 

during the performance test according to 

§63.7530(b).

6. Dry Scrubber 

Sorbent or Carbon 

Injection Rate

a. Collecting the sorbent or carbon 

injection rate monitoring system data for 

the dry scrubber according to §§63.7525 and 

63.7535; and

 b. Reducing the data to 30-day rolling

averages; and

 c. Maintaining the 30-day rolling average 

sorbent or carbon injection rate at or above 

the minimum sorbent or carbon injection rate 

as defined in §63.7575.

7. Electrostatic 

Precipitator Total 

Secondary Electric 

Power Input

a. Collecting the total secondary electric 

power input monitoring system data for the 

electrostatic precipitator according to 

§§63.7525 and 63.7535; and

 b. Reducing the data to 30-day rolling

averages; and

 c. Maintaining the 30-day rolling average 

total secondary electric power input at or 

above the operating limits established 

during the performance test according to 

§63.7530(b).

8. Fuel Pollutant 

Content

a. Only burning the fuel types and fuel 

mixtures used to demonstrate compliance with 
Page 351 of 360

If you must meet the 

following operating 

limits or work 

practice

standards . . .

You must demonstrate continuous compliance 

by . . .

the applicable emission limit according to 

§63.7530(b) or (c) as applicable; and

 b. Keeping monthly records of fuel use

according to §63.7540(a).

9. Oxygen content a. Continuously monitor the oxygen content 

using an oxygen trim system according to 

§63.7525(a).

b. Reducing the data to 30-day rolling

averages; and

c. Maintain the 30-day rolling average 

oxygen content at or above the lowest hourly 

average oxygen level measured during the 

most recent carbon monoxide performance 

test.

10. Carbon monoxide 

emissions

a. Continuously monitor the carbon monoxide 

concentration in the combustion exhaust 

according to §63.7525(a).

b. Correcting the data to 3 percent oxygen, 

and reducing the data to one-hour and daily 

block averages for all subcategories except 

units designed to burn liquid fuels located 

in non-continental states and territories;

c. Reducing the data from the daily averages 

to 10-day rolling averages for all 

subcategories except units designed to burn 

liquid fuels located in non-continental 

states and territories;

d. Reducing the data from the one-hour 

averages to three-hour averages for units 

designed to burn liquid fuels located in 

non-continental states and territories;

e. Maintaining the 10-day rolling average 

carbon monoxide concentration at or below 

the applicable emission limit in Tables 1 or 

2 of this subpart for all subcategories 

except units designed to burn liquid fuels 
Page 352 of 360

If you must meet the 

following operating 

limits or work 

practice

standards . . .

You must demonstrate continuous compliance 

by . . .

located in non-continental states and 

territories; and 

f. Maintaining the 3-hour rolling average 

carbon monoxide concentration at or below 

the applicable emission limit in Tables 1 or 

2 of this subpart for units designed to burn 

liquid fuels located in non-continental 

states and territories.

11. Boiler or 

process heater 

operating load

a. Collecting operating load data or steam 

generation data every 15 minutes.

b. Maintaining the operating load such that 

it does not exceed 110 percent of the 

average operating load recorded during the 

most recent performance test according to 

§63.7520(c).

Table 9 to Subpart DDDDD of Part 63—Reporting Requirements

As stated in §63.7550, you must comply with the following 

requirements for reports:

You must 

submit 

a(n) The report must contain . . .

You must submit 

the report . . .

1. 

Compliance 

report

a. Information required in 

§63.7550(c)(1) through (12); 

and

Semiannually, 

annually, 

biennially, or 

every 5 years 

according to the 

requirements in 

§63.7550(b).

 b. If there are no deviations 

from any emission limitation 

(emission limit and operating 

limit) that applies to you and 

there are no deviations from 
Page 353 of 360

You must 

submit 

a(n) The report must contain . . .

You must submit 

the report . . .

the requirements for work 

practice standards in Table 3 

to this subpart that apply to 

you, a statement that there 

were no deviations from the 

emission limitations and work 

practice standards during the 

reporting period. If there 

were no periods during which 

the CMSs, including continuous 

emissions monitoring system, 

continuous opacity monitoring 

system, and operating 

parameter monitoring systems, 

were out-of-control as 

specified in §63.8(c)(7), a 

statement that there were no 

periods during which the CMSs 

were out-of-control during the 

reporting period; and

 c. If you have a deviation 

from any emission limitation 

(emission limit and operating 

limit) where you are not using 

a CMS to comply with that 

emission limit or operating 

limit, or a deviation from a 

work practice standard during 

the reporting period, the 

report must contain the 

information in §63.7550(d); 

and 

 d. If there were periods 

during which the CMSs, 

including continuous emissions 

monitoring system, continuous 

opacity monitoring system, and 

operating parameter monitoring 

systems, were out-of-control 

as specified in §63.8(c)(7), 

or otherwise not operating, 

the report must contain the 

information in §63.7550(e).
Page 354 of 360

Table 10 to Subpart DDDDD of Part 63—Applicability of General 

Provisions to Subpart DDDDD

As stated in §63.7565, you must comply with the applicable 

General Provisions according to the following:

Citation Subject

Applies to subpart 

DDDDD

§63.1 Applicability Yes.

§63.2 Definitions Yes. Additional 

terms defined in 

§63.7575

§63.3 Units and 

Abbreviations

Yes.

§63.4 Prohibited 

Activities and 

Circumvention

Yes.

§63.5 Preconstruction 

Review and 

Notification 

Requirements

Yes.

§63.6(a), (b)(1)-(b)(5), 

(b)(7), (c)

Compliance with 

Standards and 

Maintenance 

Requirements

Yes.

§63.6(e)(1)(i) General duty to 

minimize 

emissions.

No. See 

§63.7500(a)(3) for 

the general duty 

requirement.

§63.6(e)(1)(ii) Requirement to 

correct 

malfunctions as 

soon as 

practicable.

No.

§63.6(e)(3) Startup, 

shutdown, and 

malfunction plan 

requirements.

No.
Page 355 of 360

Citation Subject

Applies to subpart 

DDDDD

§63.6(f)(1) Startup, 

shutdown, and 

malfunction 

exemptions for 

compliance with 

non-opacity 

emission 

standards.

No.

§63.6(f)(2) and (3) Compliance with 

non-opacity 

emission 

standards.

Yes.

§63.6(g) Use of 

alternative 

standards

Yes.

§63.6(h)(1) Startup, 

shutdown, and 

malfunction 

exemptions to 

opacity 

standards.

No. See 

§63.7500(a).

§63.6(h)(2) to (h)(9) Determining 

compliance with 

opacity emission 

standards

Yes.

§63.6(i) Extension of 

compliance.

Yes. Facilities may 

request extensions 

of compliance for 

the installation of 

combined heat and 

power or waste heat 

recovery as a means 

of complying with 

this subpart.

§63.6(j) Presidential 

exemption.

Yes.

§63.7(a), (b), (c), and 

(d)

Performance 

Testing 

Requirements

Yes.

 
Page 356 of 360

Citation Subject

Applies to subpart 

DDDDD

§63.7(e)(1) Conditions for 

conducting 

performance 

tests.

No. Subpart DDDDD 

specifies 

conditions for 

conducting 

performance tests 

at §63.7520(a) to 

(c).

§63.7(e)(2)-(e)(9), (f), 

(g), and (h)

Performance 

Testing 

Requirements

Yes.

 

§63.8(a) and (b) Applicability 

and Conduct of 

Monitoring

Yes.

§63.8(c)(1) Operation and 

maintenance of 

CMS

Yes.

§63.8(c)(1)(i) General duty to 

minimize 

emissions and 

CMS operation

No. See 

§63.7500(a)(3).

§63.8(c)(1)(ii) Operation and 

maintenance of 

CMS

Yes.

§63.8(c)(1)(iii) Startup, 

shutdown, and 

malfunction 

plans for CMS

No.

§63.8(c)(2) to (c)(9) Operation and 

maintenance of 

CMS

Yes.

§63.8(d)(1) and (2) Monitoring 

Requirements, 

Quality Control 

Program

Yes.
Page 357 of 360

Citation Subject

Applies to subpart 

DDDDD

§63.8(d)(3) Written 

procedures for 

CMS

Yes, except for the 

last sentence, 

which refers to a 

startup, shutdown, 

and malfunction 

plan. Startup, 

shutdown, and 

malfunction plans 

are not required.

§63.8(e) Performance 

evaluation of a 

CMS 

Yes.

§63.8(f) Use of an 

alternative 

monitoring 

method.

Yes.

§63.8(g) Reduction of 

monitoring data.

Yes.

§63.9 Notification 

Requirements

Yes. 

§63.10(a), (b)(1) Recordkeeping 

and Reporting 

Requirements

Yes.

§63.10(b)(2)(i) Recordkeeping of 

occurrence and 

duration of 

startups or 

shutdowns

Yes.

§63.10(b)(2)(ii) Recordkeeping of 

malfunctions

No. See 

§63.7555(d)(7) for 

recordkeeping of 

occurrence and 

duration and 

§63.7555(d)(8) for 

actions taken 

during 

malfunctions.

§63.10(b)(2)(iii) Maintenance 

records

Yes.
Page 358 of 360

Citation Subject

Applies to subpart 

DDDDD

§63.10(b)(2)(iv) and (v) Actions taken to 

minimize 

emissions during 

startup, 

shutdown, or 

malfunction

No.

§63.10(b)(2)(vi) Recordkeeping 

for CMS 

malfunctions

Yes.

§63.10(b)(2)(vii) to 

(xiv)

Other CMS 

requirements

Yes.

§63.10(b)(3) Recordkeeping 

requirements for 

applicability 

determinations

No.

§63.10(c)(1) to (9) Recordkeeping 

for sources with 

CMS

Yes.

§63.10(c)(10) and (11) Recording nature 

and cause of 

malfunctions, 

and corrective 

actions

No. See 

§63.7555(d)(7) for 

recordkeeping of 

occurrence and 

duration and 

§63.7555(d)(8) for 

actions taken 

during 

malfunctions.

§63.10(c)(12) and (13) Recordkeeping 

for sources with 

CMS

Yes.

§63.10(c)(15) Use of startup, 

shutdown, and 

malfunction plan

No.

§63.10(d)(1) and (2) General 

reporting 

requirements

Yes.
Page 359 of 360

Citation Subject

Applies to subpart 

DDDDD

§63.10(d)(3) Reporting 

opacity or 

visible emission 

observation 

results 

No.

§63.10(d)(4) Progress reports 

under an 

extension of 

compliance

Yes.

§63.10(d)(5) Startup, 

shutdown, and 

malfunction 

reports

No. See 

§63.7550(c)(11) for 

malfunction 

reporting 

requirements.

§63.10(e) Additional 

reporting 

requirements for 

sources with CMS

Yes.

§63.10(f) Waiver of 

recordkeeping or 

reporting 

requirements

Yes.

§63.11 Control Device 

Requirements

No.

§63.12 State Authority 

and Delegation

Yes.

§63.13-63.16 Addresses, 

Incorporation by 

Reference, 

Availability of 

Information, 

Performance 

Track Provisions

Yes.
Page 360 of 360

Citation Subject

Applies to subpart 

DDDDD

§63.1(a)(5),(a)(7)-

(a)(9), (b)(2), (c)(3)-

(4), (d), 63.6(b)(6), 

(c)(3), (c)(4), (d), 

(e)(2), (e)(3)(ii), 

(h)(3), (h)(5)(iv), 

63.8(a)(3), 63.9(b)(3), 

(h)(4), 63.10(c)(2)-(4), 

(c)(9).

Reserved No.