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E.O. 12866 NESHAP for Major Sources: Industrial, Commercial, and Institutional Boilers and 

Process Heaters 2060-AR13 Final Rule 20121219

6560-50-P

ENVIRONMENTAL PROTECTION AGENCY

40 CFR Part 63

[EPA-HQ-OAR-2002-0058; FRL-9676-8]

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: Final rule; notice of final action on reconsideration. 

SUMMARY: In this action the EPA is taking final action on its 

reconsideration of certain issues in the 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, which were 

issued under section 112 of the Clean Air Act. As part of this 

action, the EPA is making technical corrections to the final 

rule to clarify definitions, references, applicability and 

compliance issues raised by petitioners and other stakeholders 

affected by this rule. On March 21, 2011, the EPA promulgated

national emission standards for this source category. On that 

same day, the EPA also published a notice announcing its intent 
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to reconsider certain provisions of the final rule. Following 

these actions, the Administrator received several petitions for 

reconsideration. After consideration of the petitions received, 

on December 23, 2011, the EPA proposed revisions to certain 

provisions of the March 21, 2011, final rule, and requested 

public comment on several provisions of the final rule. The EPA 

is now taking final action on the proposed reconsideration. 

DATES: The delay of effectiveness for 40 CFR part 63, subpart 

DDDDD is lifted and the incorporation by reference of certain 

publications listed in that rule are approved by the Director of 

the Federal Register as of [INSERT THE DATE OF PUBLICATION IN 

THE FEDERAL REGISTER]. The amendments in this rule to 40 CFR 

part 63, subpart DDDDD are effective as of [INSERT THE DATE 60 

DAYS AFTER THE DATE OF PUBLICATION IN THE FEDERAL REGISTER].

ADDRESSES: The EPA established a single docket under Docket ID 

No. EPA-HQ-OAR-2002-0058 for this action. All documents in the 

docket are listed on the http://www.regulations.gov web site. 

Although listed in the index, some information is not publicly 

available, e.g., confidential business information or other 

information whose disclosure is restricted by statute. Certain 

other material, such as copyrighted material, is not placed on 

the Internet and will be publicly available only in hard copy 

form. Publicly available docket materials are available either

electronically through http://www.regulations.gov or in hard 
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copy at the EPA’s Docket Center, Public Reading Room, EPA West 

Building, Room 3334, 1301 Constitution Avenue, NW, Washington, 

DC 20004. This Docket Facility is open from 8:30 a.m. to 4:30

p.m., Monday through Friday, excluding legal holidays. The 

telephone number for the Public Reading Room is (202) 566–1744, 

and the telephone number for the Air Docket is (202) 566–1742.

FOR FURTHER INFORMATION CONTACT: Mr. Jim Eddinger, 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) 541-5426; Fax number 

(919) 541-5450; Email address: eddinger.jim@epa.gov.

EXECUTIVE SUMMARY: 

Purpose of this Regulatory Action

The EPA is taking final action on its proposed 

reconsideration of certain provisions of its March 21, 2011,

final rule that established standards for new and existing 

industrial, commercial, and institutional boilers and process 

heaters at major sources of hazardous air pollutants. Section 

112(d) of the CAA requires the EPA to regulate HAP from major 

stationary sources based on the performance of MACT. Section 

112(h) of the CAA allows the EPA to establish work practice 

standards in lieu of numerical emission limits only in cases 

where the agency determines that it is not feasible to prescribe 
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or enforce an emission standard, including circumstances in 

which the agency determines that the application of measurement 

methodology is not practicable due to technological and economic 

limitations. The EPA is revising certain MACT standards

established in March 2011 for boilers and process heaters,

including standards for CO — as a surrogate for organic HAP; HCl 

— as a surrogate for acid gas HAP; Hg; TSM or filterable PM — as 

a surrogate for non-Hg metallic HAP; and dioxin/furan. 

This final rule amends certain provisions of the final rule 

issued by the EPA on March 21, 2011. The EPA delayed the 

effective date of the 2011 rule in a May 18, 2011, notice, but 

that delay notice was vacated by the U.S. District Court for the 

District of Columbia on January 9, 2012, and the March 2011 

final rule was, therefore, in effect until publication of this 

action. 

Summary of Major Reconsideration Provisions

In general, this final rule requires facilities classified 

as major sources of HAP with affected boilers or process heaters 

to reduce emissions of harmful toxic air emissions from these 

combustion sources. This will improve air quality and protect 

public health in communities where these facilities are located.

Recognizing the diversity of this source category and the 

multiple sectors of the economy this final rule effects, the EPA 

is revising certain subcategories for boilers and process 
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heaters in this action that were established in the March 2011 

final rule, based on the design of the combustion equipment. 

These revisions result in 19 subcategories for the boilers and 

process heaters source category. Numerical emission limits are 

established for most of the subcategories for five pollutants, 

CO, HCl, Hg, and PM or TSM. The review of existing data and 

consideration of new data have resulted in changes to some of 

the emission limits contained in the March 2011 final rule. 

Overall, for both new and existing affected units, about 30 

percent of the emission limits are more stringent, half are less 

stringent, and 20 percent unchanged as compared to the March 

2011 final rule. Also, based on its review and analysis of new 

data submissions, the EPA is establishing an alternative 

emission standard for CO, based on CEMS data for several 

subcategories with CO CEMS data available. This alternative 

standard is based on a 30-day rolling average for subcategories 

for which sufficient CEMS data were available for more than a 

30-day period, or a 10-day rolling average for subcategories for 

which CEMS data were available for less than a 30-day period,

and provides additional compliance flexibility to sources. All 

of the subcategories are subject to periodic tune-up work 

practices for dioxin/furan emissions.

The compliance dates for the rule are [INSERT THE DATE 3 

YEARS AFTER THE DATE OF PUBLICATION IN THE FEDERAL REGISTER] for 
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existing sources and [INSERT THE DATE OF PUBLICATION IN THE 

FEDERAL REGISTER] or upon startup, whichever is later, for new 

sources. New sources are defined as sources that began operation 

on or after June 4, 2010.

Costs and Benefits

The final rule affects 1,700 existing major source 

facilities with an estimated 14,136 boilers and process heaters 

and the EPA projects an additional 1,844 new boilers and process 

heaters to be subject to this final rule over the next 3 years.

This final rule affects multiple sectors of the economy 

including small entities. Table 1 summarizes the costs and 

benefits associated with this final rule. A more detailed 

discussion of the costs and benefits of this final rule is 

provided in section VI of this preamble.

TABLE 1. SUMMARY OF THE MONETIZED BENEFITS, SOCIAL COSTS AND NET 

BENEFITS FOR THE FINAL BOILER MACT RECONSIDERATION IN 2015 

(MILLIONS OF 2008$)1

3 percent Discount 

Rate

7 percent Discount 

Rate

Total Monetized 

Benefits2 $27,000 To $67,000 $25,000 to $61,000

Total Social Costs3 $1,400 to $1,600 $1,400 to $1,600

Net Benefits $26,000 to $65,000 $23,000 to $59,000

Non-monetized 

Benefits

Health effects from exposure to HAP 

(39,000 tons of HCl, 500 tons of HF, 

3,100 to 5,300 tons of Hg and 2,500 tons 

of other metals)

Health effects from exposure to other 

criteria pollutants (180,000 tons of CO 
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and 570,000 tons of SO2) 

Ecosystem effects 

Visibility impairment 

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

rounded to two significant figures. 

2 The total monetized co-benefits reflect the human health 

benefits associated with reducing exposure to PM2.5 through 

reductions of PM2.5 precursors such as directly emitted 

particles, SO2, and NOx and reducing exposure to ozone through 

reductions of VOC. It is important to note that the monetized 

benefits include many but not all health effects associated 

with PM2.5 exposure. Monetized benefits are shown as a range 

from Pope et al. (2002) to Laden et al. (2006). These models 

assume that all fine particles, regardless of their chemical 

composition, are equally potent in causing premature mortality 

because the scientific evidence is not yet sufficient to 

support the development of differential effects estimates by 

particle type. These estimates include the energy disbenefits 

valued at $24 million (using the 3 percent discount rate), 

which do not change the rounded totals. CO2-related disbenefits 

were calculated using the “social cost of carbon,” which is 

discussed further in the RIA.

3 The methodology used to estimate social costs for one year in 

the multimarket model using surplus changes results in the same 

social costs for both discount rates.

SUPPLEMENTARY INFORMATION:

Acronyms and Abbreviations. The following acronyms and 

abbreviations are used in this document.

ACC American Chemistry Council

ACCCI American Coke and Coal Chemicals Institute

AF&PA American Forest and Paper Association

AHFA American Home Furnishings Alliance

AISI American Iron and Steel Institute

AMP American Municipal Power Inc. 

AIE Alliance for Industrial Efficiency

APCD air pollution control devices

API American Petroleum Institute 

AIF Auto Industry Forum

BFG Blast furnace gas

BLDS Bag leak detection system 
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BCSE The Business Council for Sustainable Energy

CIBO Council of Industrial Boiler Owners

CO Carbon monoxide

CO2 Carbon dioxide

CEMS Continuous emissions monitoring system

CEG Citizens Energy Group

CAA Clean Air Act

CFR Code of Federal Regulations 

CPMS Continuous parameter monitoring system

CMI CraftMaster Manufacturing Inc.

ERT Electronic Reporting Tool

ESP Electrostatic precipitator

EPA Environmental Protection Agency

FBC Fluidized bed combustion

FR Federal Register

FSI Florida Sugar Industry 

GPSP Great Plains Synfuels Plant

HAP Hazardous air pollutants

HBES Health-based emissions standard

HF Hydrogen fluoride

Hg Mercury

HCl Hydrogen chloride

kWh Kilowatt hours

ISO International Standards Organization

lb Pounds

LFG Landfill gas

MACT Maximum achievable control technology

MATS Mercury Air Toxics Standards

MSU Michigan State University 

MMBtu Million British thermal units

NESHAP National Emission Standards for Hazardous Air 

Pollutants 

NPRA National Petrochemical and Refiners Association 

NTTAA National Technology Transfer and Advancement Act

NAICS North American Industry Classification System

NOx Nitrogen oxide

NSR New Source Review

OMB Office of Management and Budget

PM Particulate matter

PSU Penn State University

PS Performance Specification

ppm Parts per million

QA Quality assurance

QC Quality control

RFA Regulatory Flexibility Act

RIA Regulatory Impact Analysis

RPU Rochester Public Utilities
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RTC Response to comment

SCR Selective catalytic reduction

SNCR Selective non-catalytic reduction

SO2 Sulfur dioxide

TBtu/yr Trillion British thermal units per year

THC Total hydrocarbon

TSM Total selected metals

TTN Technology Transfer Network

tpy Tons per year

UMRA Unfunded Mandates Reform Act of 1995

U.S. United States

USCHPA US Clean Heat Power Association

US Sugar United States Sugar Corporation

UPL Upper prediction limit

UARG Utility Air Regulatory Group

VCS Voluntary Consensus Standards

VOC Volatile organic compounds

WM Waste Management Inc.

WEPCO Wisconsin Electric Power Company

WWW Worldwide Web 

Organization of this Document. The information presented in 

this preamble is organized as follows:

I. General Information

A. Does this action apply to me?

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

C. Judicial Review

II. Background Information

A. Chronological History of Related Actions

III. Summary of This Final Rule

A. What is an affected source?

B. What are the subcategories of boilers and process heaters?

C. What emission limits and work practice standards are being 

finalized?

D. What are the requirements during periods of startup and

shutdown?

E. What are the testing and initial compliance requirements?

F. What are the continuous compliance requirements?

G. What are the compliance dates?

IV. Summary of Significant Changes Since Proposal

A. Applicability
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B. Subcategories

C. Performance Test Requirements

D. Emission Limits

E. Work Practice Requirement

F. Averaging Times Definitions

G. Energy Assessment

H. Startup and Shutdown Definitions

I. Fuel Sampling Frequency

J. Affirmative Defense

V. Other Actions We Are Taking

VI. Impacts of This Final Rule

A. What are the incremental air impacts?

B. What are the incremental water and solid waste impacts?

C. What are the incremental energy impacts?

D. What are the incremental cost impacts?

E. What are the economic impacts?

F. What are the benefits of this final rule?

G. What are the incremental secondary air impacts?

VII. 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

K. Congressional Review Act

I. General Information

A. Does this action apply to me?

The regulated categories and entities potentially affected 

by this action include:
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TABLE 2. Potential Regulated Categories and Entities Affected

Category

NAICS 

code1

Examples of potentially 

regulated entities

Any industry using 

a 

boiler or

process heater as 

defined in the 

final rule

211 Extractors of crude petroleum and 

natural gas

321 Manufacturers of lumber and wood 

products

322 Pulp and paper mills

325 Chemical manufacturers

324 Petroleum refineries, and 

manufacturers of coal products

316, 

326,

339 

Manufacturers of rubber and 

miscellaneous plastic products

331 Steel works, blast furnaces

332 Electroplating, plating, polishing, 

anodizing, and coloring

336 Manufacturers of motor vehicle parts 

and accessories

221 Electric, gas, and sanitary services

622 Health services

611 Educational services

1 North American Industry Classification System.

This table is not intended to be exhaustive, but rather 

provides a guide for readers regarding entities likely to be 

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 
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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 this final 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).

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

In addition to being available in the docket, an electronic 

copy of this action will also be available on the WWW through 

the TTN. Following signature, a copy of the action will be

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

or promulgated rules at the following address: 

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

technology exchange in various areas of air pollution control.

C. Judicial Review

Under the CAA section 307(b)(1), judicial review of this

final rule is available only by filing a petition for review in 

the U.S. Court of Appeals for the District of Columbia Circuit 

by [INSERT DATE 60 DAYS FROM DATE OF PUBLICATION IN THE FEDERAL 

REGISTER]. Under CAA section 307(d)(7)(B), only an objection to 

this final rule that was raised with reasonable specificity 

during the period for public comment can be raised during

judicial review. Note, under CAA section 307(b)(2), the 
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requirements established by this final rule may not be 

challenged separately in any civil or criminal proceedings 

brought by the EPA to enforce these requirements.

II. Background Information

A. Chronological History of Related Actions

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 CAA. On the same day as the final rule was issued, the 

EPA 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 of the

March 2011 final rule where additional public comment was 

appropriate. This notice also identified several issues of 

central relevance to the rulemaking where reconsideration was 

appropriate under CAA section 307(d). 

On May 18, 2011, the EPA issued a notice to postpone the 

effective date of the March 21, 2011 final rule. Following 

promulgation of the final rule, the EPA received petitions for 

reconsideration from the following organizations 

(“Petitioners”): AIE, USCHPA, Alyeska Pipeline, ACC, AHFA, AISI, 

ACCCI, AMP, API, NPRA, AIF, Citizens Energy Group (CEG), CIBO, 

CMI, District Energy St. Paul, FSI, GPSP, Hovensa L.L.C., Tesoro 

Hawaii Corp., Industry Coalition (AF&PA et. al.), JELD-WEN Inc., 
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MSU, PSU, Purdue University, Renovar Energy Corp., RPU, Sierra 

Club, Southeastern Lumber Manufacturers Association, State of 

Washington Department of Ecology, BCSE, UARG, US Sugar, WM and 

WEPCO. Copies of these petitions are provided in the docket (see 

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

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

numerous provisions in the rule. On December 23, 2011, the EPA 

granted the petitions for reconsideration on certain issues, and 

proposed certain revisions to the final rule in response to the 

reconsideration petitions and to address the issues that the EPA 

previously identified as warranting reconsideration. That 

proposal solicited comment on several specific aspects of the 

rule, including:

 Revising the proposed subcategories.

 Solicitation of new data or corrections to existing data to 

revise emission standards calculations.

 Establishing an alternative TSM limit. 

 Appropriateness of an alternative TSM limit for the liquid 

subcategories.

 Establishing work practice standards for dioxin/furan 

emissions.

 Revising the efficiency assumptions for the alternative 

output-based emission standards.
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 Accommodating emissions averaging provisions in the 

alternative output-based emission standards.

 Establishing a mercury 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.

 Revisions to the monitoring requirements for oxygen in the 

March 2011 final rule.

 Establishing a full-load stack test requirement for carbon 

monoxide coupled with continuous oxygen (oxygen trim) 

monitoring.

 Revising PM monitoring requirements from CEMS to CPMS and 

exempting biomass units from PM CPMS requirements.

 Revising mercury monitoring requirements to allow for an 

alternative mercury CEMS.

 Considering use of SO2 CEMS to demonstrate compliance with

HCl limits.

 Minimum data availability provisions.

 Averaging times for monitored parameters and pollutants.

 Revised methods for computing minimum detection levels.
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 Providing an alternative CO emission limit based on CO CEMS 

data.

 Soliciting additional data to set MACT floor emission 

limits for non-continental liquid units.

 Selecting a 99 percent confidence interval for setting the 

CO emission limit.

 Tune-up frequencies, timing of initial tune-ups and 

adjusted tune-up requirements for shutdown units.

 Scope and duration of the energy assessment and deadline 

for completing the assessment.

 Revising work practices during startup and shutdown.

 Revisions to certain exemptions, including units serving as 

control devices, waste heat process heaters, units firing 

comparable fuels and residential units. 

 Revisions to reduced testing frequency for emission limits 

that are established at minimum detection levels.

 Removing fuel analysis requirements for gas 1 fuels at cofired units.

 Revisions to automating techniques for coal sampling.

 Revisions to emissions averaging across subcategories when 

units opt to switch to natural gas.

 Consideration of a new subcategory for units installed and

used in place of flares.
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In this action, the EPA is finalizing multiple changes to 

the March 2011 final rule after considering public comments on 

the items under reconsideration.

III. Summary of This Final Rule

As stated above, the December 23, 2011 proposed rule 

addressed specific issues and provisions the EPA identified for 

reconsideration. This summary of the final rule reflects the 

changes to 40 CFR part 63, subpart DDDDD (March 21, 2011 final 

rule) in regards to those provisions identified for 

reconsideration and on other discrete matters identified in 

response to comments or data received during the comment period. 

Information on other provisions and issues not proposed for 

reconsideration is contained in the notice and record for the 

2011 final rule. [See 76 FR 15608]

This section summarizes the requirements of this action. 

Section IV below provides a summary of the significant changes 

to the March 21, 2011 final rule.

A. What is an affected source?

This final rule revises the list of exemptions in §63.7491 

to include residential boilers that may be located at an

industrial, commercial or institutional major source. The 

exemption for boilers or process heaters used specifically for 

research and development has been revised to include boilers 

used for certain testing purposes.
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B. What are the subcategories of boilers and process heaters?

In this final rule, we are finalizing separate 

subcategories for heavy liquid-fired, light liquid-fired and 

liquid-fired units in non-continental locations for PM and CO, 

pollutants that are dependent on combustor design. In addition, 

a new subcategory for coal-fired fluidized bed boilers with 

integrated fluidized bed heat exchangers has been included in 

the final rule for CO which is dependent on boiler design.

Finally, we are finalizing the subcategory for PM at coal/fossil 

solid units across all coal combustor designs.

C. What emission limits and work practice standards are being 

finalized?

You must meet the emission limits presented in Table 3 of 

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

This final rule includes 19 subcategories, which are based on 

unit design. New and existing units in three of the 

subcategories are subject to work practices standards in lieu of 

emission limits for all pollutants. Numeric emission limits are 

finalized for new and existing sources in each of the other 16

subcategories.

The changes associated with the emission limits are due to 

new data, corrections to old data, and inventory changes. In 

summary, for existing subcategories, for the HCl emission 

limits, 10 are more stringent, 3 are less stringent and 1
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remained the same from the March 21, 2011 final rule; for the 

mercury emission limits, 3 are more stringent and 11 are less 

stringent from the March 21, 2011 final rule; for the PM 

emission limits, 2 are more stringent, 7 are less stringent and 

5 are unchanged from the March 21, 2011 final rule; and for the 

CO emission limits, 4 are more stringent and 10 are less 

stringent from the March 21, 2011 final rule. For new 

subcategories, for the HCl emission limits, 13 are less 

stringent and 1 is unchanged from the March 21, 2011 final rule; 

for the mercury emission limits, 11 are more stringent, 2 are

less stringent and 1 is unchanged from the March 21, 2011 final 

rule; for the PM emission limits, 9 are less stringent and 5 are

unchanged from the March 21, 2011 final rule; and for the CO 

emission limits, 3 are more stringent and 11 are less stringent 

from the March 21, 2011 final rule.

TABLE 3. 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 

PM (or 

total 

selected 

metals) 

(lb per 

MMBtu of 

heat 

input)a

HCl (lb 

per 

MMBtu of 

heat 

input)a

Mercury

(lb 

per 

MMBtu 

of heat 

input)a

CO

(ppm @3% 

oxygen)a

Alternate 

CO CEMS 

limit,

(ppm @3% 

oxygen)b

Existing –

Coal Stoker 

0.040

(5.3E-05)

0.022 5.7E-06 160 340
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Subcategory

Filterable 

PM (or 

total 

selected 

metals) 

(lb per 

MMBtu of 

heat 

input)a

HCl (lb 

per 

MMBtu of 

heat 

input)a

Mercury

(lb 

per 

MMBtu 

of heat 

input)a

CO

(ppm @3% 

oxygen)a

Alternate 

CO CEMS 

limit,

(ppm @3% 

oxygen)b

Existing -

Coal 

Fluidized Bed

0.040

(5.3E-05)

0.022 5.7E-06 130 230

Existing -

Coal 

Fluidized Bed 

with FB heat 

exchanger

0.040

(5.3E-05)

0.022 5.7E-06 140 150

Existing –

Coal-Burning 

Pulverized 

Coal

0.040

(5.3E-05)

0.022 5.7E-06 130 320

Existing –

Biomass Wet 

Stoker/Sloped 

Grate/Other 

0.037

(2.4E-04)

0.022 5.7E-06 1,500 720

Existing –

Biomass KilnDried 

Stoker/Sloped 

Grate/Other 

0.32

(4.0E-03)

0.022 5.7E-06 460 ND

Existing -

Biomass 

Fluidized Bed 

0.11

(1.2E-03)

0.022 5.7E-06 470 310

Existing –

Biomass 

Suspension 

Burner

0.051

(6.5E-03)

0.022 5.7E-06 2,400 2,000c

Existing –

Biomass Dutch 

Ovens/Pile 

Burners

0.28

(2.0E-03)

0.022 5.7E-06 770 520c
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Subcategory

Filterable 

PM (or 

total 

selected 

metals) 

(lb per 

MMBtu of 

heat 

input)a

HCl (lb 

per 

MMBtu of 

heat 

input)a

Mercury

(lb 

per 

MMBtu 

of heat 

input)a

CO

(ppm @3% 

oxygen)a

Alternate 

CO CEMS 

limit,

(ppm @3% 

oxygen)b

Existing –

Biomass Fuel 

Cells

0.020

(5.8E-03)

0.022 5.7E-06 1,100 ND

Existing –

Biomass 

Hybrid 

Suspension 

Grate

0.44(4.5E04)

0.022 5.7E-06 2,800 900

Existing –

Heavy Liquid

0.062

(2.0E-04)

0.0011 2.0E-06 130 ND

Existing –

Light Liquid

0.0079

(6.2E-05)

0.0011 2.0E-06 130 ND

Existing –

nonContinental 

Liquid

0.27

(8.6E-04)

0.0011 2.0E-06 130 ND

Existing –

Gas 2 (Other 

Process 

Gases)

0.0067

(2.1E-04)

0.0017 7.9E-06 130 ND

New –Coal 

Stoker 

0.0011

(2.3E-05)

0.022 8.0E-07 130 340

New - Coal 

Fluidized Bed

0.0011

(2.3E-05)

0.022 8.0E-07 130 230

New - Coal 

Fluidized Bed 

with FB Heat 

Exchanger

0.0011

(2.3E-05)

0.022 8.0E-07 140 150
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Subcategory

Filterable 

PM (or 

total 

selected 

metals) 

(lb per 

MMBtu of 

heat 

input)a

HCl (lb 

per 

MMBtu of 

heat 

input)a

Mercury

(lb 

per 

MMBtu 

of heat 

input)a

CO

(ppm @3% 

oxygen)a

Alternate 

CO CEMS 

limit,

(ppm @3% 

oxygen)b

New – CoalBurning 

Pulverized 

Coal

0.0011

(2.3E-05)

0.022 8.0E-07 130 320

New –Biomass 

Wet 

Stoker/Sloped 

Grate/Other 

0.030

(2.6E-05)

0.022 8.0E-07 620 390

New –Biomass 

Kiln-Dried 

Stoker/Sloped 

Grate/Other 

0.030

(4.0E-03)

0.022 8.0E-07 460 ND

New - Biomass 

Fluidized Bed 

0.0098

(8.3E-05)

0.022 8.0E-07 230 310

New – Biomass 

Suspension 

Burner

0.030

(6.5E-03)

0.022 8.0E-07 2,400 2,000c

New – Biomass 

Dutch 

Ovens/Pile 

Burners

0.0032

(3.9E-05)

0.022 8.0E-07 330 520c

New – Biomass 

Fuel Cells

0.020

(2.9E-05)

0.022 8.0E-07 910 ND

New – Biomass 

Hybrid 

Suspension 

Grate

0.026

(4.4E-04)

0.022 8.0E-07 1,100 900

New – Heavy 

Liquid

0.013

(7.5E-05)

4.4E-04 4.8E-07 130 ND
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Subcategory

Filterable 

PM (or 

total 

selected 

metals) 

(lb per 

MMBtu of 

heat 

input)a

HCl (lb 

per 

MMBtu of 

heat 

input)a

Mercury

(lb 

per 

MMBtu 

of heat 

input)a

CO

(ppm @3% 

oxygen)a

Alternate 

CO CEMS 

limit,

(ppm @3% 

oxygen)b

New – Light 

Liquid

0.0011

(2.9E-05)

4.4E-04 4.8E-07 130 ND

New – NonContinental 

Liquid

0.023

(8.6E-04)

4.4E-04 4.8E-07 130 ND

New – Gas 2 

(Other 

Process 

Gases)

0.0067

(2.1E-04)

0.0017 7.9E-06 130 ND

NA-Not applicable; ND-No data available

a 3-run average, unless otherwise noted.

b 30-day rolling average, unless otherwise noted.

c 10-day rolling average.

We also are finalizing a work practice standard for 

dioxin/furan emissions from all subcategories.

D. What are the requirements during periods of startup and

shutdown?

We are finalizing revised work practice standards for 

periods of startup and shutdown to better reflect the maximum 

achievable control technology during those periods. In addition, 

we are finalizing definitions of startup and shutdown. We are 

defining startup as the period between the state of first-firing 

of fuel in the unit after a shutdown to the period where the 
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unit first supplies steam. We are defining shutdown as the 

period that begins when no more steam is supplied or at the 

point of no fuel being fired in the unit. For periods of startup 

and shutdown, we are finalizing the following work practice 

standard: You must operate all continuous monitoring systems 

during startup and shutdown. For startup, you must use one or a 

combination of the listed clean fuels. Once you start firing 

coal/solid fossil fuel, biomass/bio-based solids, heavy liquid 

fuel, or gas 2 (other) gases, you must engage all of the 

applicable control devices except limestone injection in FBC 

boilers, dry scrubber, fabric filter, SNCR and SCR. You must 

start your limestone injection in FBC boilers, dry scrubber, 

fabric filter, SNCR and SCR systems as expeditiously as 

possible. During shutdown while firing coal/solid fossil fuel, 

biomass/bio-based solids, heavy liquid fuel, or gas 2 (other) 

gases during shutdown, you must operate all applicable control 

devices, except limestone injection in FBC boilers, dry 

scrubber, fabric filter, SNCR and SCR. You must comply with all 

applicable emissions and operating limits at all times the unit 

is in operation except for periods that meet the definitions of 

startup and shutdown in this subpart, during which times you 

must comply with these work practices. You must keep records 

during periods of startup or shutdown. You must keep records 

concerning the date, duration, and fuel usage during startup and 
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shutdown. 

E. 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. This

final rule adds the requirement to 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.

F. What are the continuous compliance requirements?

This final rule removes the requirement for units 

combusting biomass with heat input capacities of 250 MMBtu/hr or 

greater to install, certify, maintain and operate a CEMS 

measuring PM emissions. This final rule requires units 

combusting solid fossil fuel or heavy liquid with heat input 

capacities of 250 MMBtu/hr or greater to install, certify, 

maintain, and operate PM CPMS. Moreover, owners or operators of 

units combusting solid fossil fuel or heavy liquid with heat 

input capacities of 250 MMBtu/hr or greater are allowed to 

install, certify, maintain and operate PM CEMS as an alternative 

to the use of PM CPMS, consistent with regulations for

similarly-sized commercial and industrial solid waste 

incinerators units and EGUs subject to the MATS. Just as units 

using PM CPMS will not be required to conduct parameter 
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monitoring for PM, units using PM CEMS will not be required to 

conduct parameter monitoring for PM. 

This final rule also includes an alternative method 

of demonstrating continuous compliance with the HCl emission 

limit. This method allows using SO2 emissions as an alternate 

operating limit. This method of demonstrating continuous 

compliance will be allowed only on a unit that utilizes a SO2

CEMS and an acid-gas control technology including wet scrubber, 

dry scrubbers and duct sorbent injection. Boilers or process 

heaters subject to an HCl emission limit that demonstrate 

compliance with an SO2 CEMS would be required to maintain the 30-

day rolling average SO2 emission rate at or below the highest

hourly average SO2 concentration measured during the most recent 

HCl performance test.

G. What are the compliance dates?

For existing sources, the EPA is establishing a compliance 

date of [INSERT 3 YEARS FROM DATE OF PUBLICATION IN THE FEDERAL 

REGISTER]. New sources must comply by [INSERT DATE OF 

PUBLICATION IN THE FEDERAL REGISTER] or upon startup, whichever 

is later. New sources are defined as sources which commenced 

construction or reconstruction on or after June 4, 2010 pursuant 

to section 112(a)(4).

Commenters have argued that the 3-year compliance deadline 

the EPA is establishing for existing sources to meet the 
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Page 27 of 374

standards does not provide them with sufficient time to meet the 

standards in view of the large number of sources that will be 

competing for the needed resources and materials from 

engineering consultants, permitting authorities, equipment 

vendors, construction contractors, financial institutions, and 

other critical suppliers.

As an initial matter, we note that many sources subject to 

the emission standards in the final rule should be able to meet 

the standards within three years, even those that need to 

install pollution control technologies to do so. In addition, 

many sources subject to the rule are gas fired units or small 

boilers (less than 10 MMBtu/hr) and will not need to install 

controls in order to demonstrate compliance, as these sources 

are subject to work practice standards. For these sources, the 

3-year compliance deadline is highly unlikely to be problematic 

either in general, or with respect to the claims commenters have 

made about the possibility that the demand for resources related 

to control technology will exceed the supply.

At the same time, the CAA allows title V permitting 

authorities to grant sources, on a case-by-case basis, 

extensions to the compliance time of up to one year if such time 

is needed for the installation of controls. See CAA section 

112(i)(4)(i)(A). Permitting authorities are already familiar 

with, and in many cases have experience with, applying the 1-
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year extension authority under section 112(i)(4)(A) since the 

provision applies to all NESHAP. We believe that should the 

range of circumstances that commenters have cited as impeding 

sources’ ability to install controls within three years 

materialize, then it is reasonable for permitting authorities to

take those circumstances into consideration when evaluating a 

source’s request for a 1-year extension, and where such 

applications prove to be well-founded, it is also reasonable for 

permitting authorities to make the 1-year extension available to 

applicants.

In making a determination as to whether an extension is 

appropriate, we believe it is also reasonable for permitting 

authorities to consider the large number of pollution control 

retrofit projects being undertaken for purposes of complying 

either with the standards in this rule or with those of other 

rules such as MATS for the power sector that may be competing 

for similar resources.

Further, commenters have pointed out that in some cases 

operators of existing sources that are subject to these 

standards and that generate energy may opt to meet the standards 

by terminating operations at these sources and building new 

sources to replace the energy generation at the shut-down 

sources. While the ultimate discretion to provide a 1-year 

extension lies with the permitting authority, the EPA believes 
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that it is reasonable for permitting authorities to allow the 

fourth year extension for the installation of replacement 

sources of energy generation at the site of a facility applying 

for an extension for that purpose. Specifically, the EPA 

believes where an applicant demonstrates that it is building 

replacement sources of energy generation for purposes of meeting 

the requirements of these standards such a replacement project 

could be deemed to constitute the “installation of controls” 

under section 112(i)(3)(B).

In a case where pollution controls are being installed or 

onsite replacement energy generation is being constructed to 

allow for retirement of older, under-controlled energy 

generation units, a determination that an extra year is 

necessary for compliance should be relatively straightforward. 

In order to install controls, companies are likely to undertake 

a number of steps relatively soon after the effective date of 

the rule, including obtaining necessary building and 

environmental permits and hiring contractors to perform the 

construction of the emission controls or replacement energy 

generation units. This should provide sufficient information for 

a permitting authority to determine that emission controls are 

being installed or that replacement energy generation is being 

constructed. As a result, a permitting authority will be in a 

position to make a determination as to whether a source’s 
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compliance schedule will exceed 3 years and to quickly make a 

determination as to when an extension is appropriate.

In sum, the EPA believes that although most, if not all, 

units will be able to fully comply with the standards within 3 

years, the fourth year that permitting authorities are allowed 

to grant for installation of controls is an important 

flexibility that will address situations where an extra year is 

necessary. Of course in situations where EPA is the permitting 

authority, we would also consider the above circumstances when 

acting on a permit application.

IV. Summary of Significant Changes Since Proposal

The EPA has made numerous changes in this final rule from 

the proposal after consideration of the public comments 

received. Most are changes to clarify applicability and 

implementation issues raised by the commenters. The public 

comments received on the proposed changes and the responses to 

them can be viewed in the memorandum “Response to Comments for 

Industrial, Commercial, and Institutional Boilers and Process 

Heaters National Emission Standards for Hazardous Air 

Pollutants” located in the docket. 

A. Applicability

Since proposal, the EPA has made certain changes to the 

applicability of this final rule. We have clarified that the 

exemption for boilers and process heaters used for research and 
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development includes boilers used for testing the propulsion 

systems on military vessels. This is consistent with the intent 

of the exemption in that these test boilers do not provide steam 

for heating, to a process, or other non-propulsion related uses 

but are used exclusively to test the propulsion systems of 

nuclear-powered aircraft carriers that are undergoing repair, 

overhaul, or installation. 

B. Subcategories

As described in the preamble to the proposed 

reconsideration rule, within the basic unit types of boilers and 

process heaters there are different designs and combustion 

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

emissions, have a much larger effect on pollutants whose 

emissions depend on the combustion conditions in a boiler or

process heater. In the case of boilers and process heaters, the 

combustion-related pollutants are the organic HAP. In the

proposed rule, we identified the following 17 subcategories for 

organic HAP: (1) Pulverized coal units; (2) stokers designed to 

burn coal; (3) fluidized bed units designed to burn coal; (4) 

stokers designed to burn wet biomass; (5) stokers designed to 

burn kiln-dried biomass; (6)fluidized bed units designed to burn 

biomass; (7) suspension burners designed to burn biomass; (8) 

dutch ovens/pile burners designed to burn biomass; (9) fuel 

cells designed to burn biomass; (10) hybrid suspension grate 
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units designed to burn biomass; (11)units designed to burn heavy

liquid fuel; (12) units designed to burn light liquid fuel; (13)

non-continental liquid units; (14) units designed to burn 

natural gas/refinery gas; (15) units designed to burn other

gases; (16) metal process furnaces; and (17) limited-use units.

In this final rule, we are also adding a separate 

subcategory for fluidized bed units with a fluidized bed heat 

exchanger designed to burn coal and adjusted the definition of 

the limited use subcategory.

Fluidized bed boilers are designed to combust fuel with 

relatively low heating value and high ash compared to other 

combustor designs. Two fuel properties of coal are heating 

values and ash content. As the heating value of the coal 

decreases, ash content increases. Fluidized bed boilers are 

designed to have large tube surface areas to transfer heat from 

the fuel through the process of conduction and convection, but 

in some cases the amount of tube surface area in the furnace for 

heat transfer is insufficient. In order to overcome insufficient 

heat exchange, certain fluidized bed boilers adopt a fluidized 

bed heat exchanger design to achieve heat transfer. The 

fluidized bed heat exchanger is located at the exit of the 

cyclone section of the unit. This design allows the boiler to 

combust coal with a lower heating value than a coal-fired 

fluidized bed boiler without a fluidized bed heat exchanger. 
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Therefore, because this boiler design does have different 

combustion-related HAP emission characteristics, a new 

subcategory of coal fluidized bed with integrated heat exchanger 

was added to the final rule.

The EPA is also revising the definition of the limited use 

subcategory. Many affected units operate on standby mode or low 

loads for periods longer than the proposed definition for 

limited use units, which limited operation to 876 hours per 

year. By converting to a capacity-factor approach, we are 

allowing more flexibility on unit operations without increasing 

emissions or harm to human health and the environment. For 

example, units operating at 10 percent load for 8,760 hours per 

year would emit the same amount of emissions as units operating 

at full load for 876 hours per year. Further, it is technically 

infeasible to schedule stack testing for these limited use units 

since these units serve as back up energy sources and their 

operating schedules can be intermittent and unpredictable. The 

limited use subcategory was adjusted to be based on units with a 

federally enforceable operating limit of less than or equal to 

10 percent of an average annual capacity factor.

C. Performance Test Requirements

Table 5 of this final rule has been revised to add 

performance test procedures for conducting performance stack 

tests for demonstrating compliance with the alternate TSM 
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emission limits. In the reconsideration proposal, we proposed 

emissions limits for TSM (i.e., arsenic, beryllium, cadmium, 

chromium, lead, manganese, nickel and selenium) as an 

alternative to the proposed PM emission limits for many of the 

subcategories. In the preamble to the proposed rule, we added 

procedures in Table 6 of the rule for conducting fuel analysis 

for total selected metals but we inadvertently failed to add 

performance test requirements for stack sampling of TSM

emissions in Table 5 of the rule. 

D. Emission Limits

One significant change since proposal is related to the PM 

emission limits for the coal subcategories. Several petitioners

disagreed with EPA’s position to set different PM limits for 

subcategories of boilers and process heaters based on the fuel 

used, and instead offered information to support the position 

that PM should be considered a combustion-based pollutant. The 

differences in PM particle size, fouling characteristics and 

feasibility of certain control technologies on certain unit 

designs suggested that PM is more appropriately classified as a 

combustion-based pollutant, but only for the coal subcategories. 

After assessing the points raised by the petitioners, the EPA 

agreed that PM emissions are influenced by unit design, and fuel 

type, and proposed to create combustion-based pollutant

subcategories for coal and solid fuels and create fuel-based 
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subcategories for liquid and biomass fuel units. The EPA is 

finalizing a single PM limit for all coal/solid fossil fuel 

subcategories, and is also finalizing emissions limits based on 

PM as a combustion-based pollutant for the biomass and liquid 

fuel subcategories.

Another change from proposal is that the alternative TSM 

emission limits are now applicable to the three liquid fuel 

subcategories. Several commenters provided data and comments 

supporting these alternative emission standards for non-mercury

metallic HAP. After assessing the revised data and the points 

made by the commenters, the EPA agrees that the limited data 

available for liquid fuel units are not unique to this 

subcategory. Based on the EPA agreeing with the commenters, the 

EPA re-calculated the TSM emission limits for the liquid fuel 

subcategories and included them in the final rule. 

The CO emission limit for several subcategories, both new 

and existing, have been revised to reflect a CO level that is 

consistent with MACT for organic HAP reduction. Several 

commenters recommended that the EPA evaluate a minimum CO 

standard (i.e., 100 ppm corrected to 7 percent oxygen) to serve 

as a lower bound surrogate for organic HAP. Commenters also 

provided data and information to support such a standard, and 

noted that the EPA has taken a similar approach in other 

emission standards under section 112. 
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The EPA evaluated whether there is a minimum CO level for 

boilers and process heaters below which there is no further 

benefit in organic HAP reduction/destruction. Specifically, we 

evaluated the relationship between CO and formaldehyde using the 

available data obtained during the rulemaking. Formaldehyde was

selected as the basis of the organic HAP comparison because it 

is the most prevalent organic HAP in the emission database and a 

large number of paired tests existed for boilers and process 

heaters for CO and formaldehyde. The paired data show decreasing 

formaldehyde emissions with decreasing CO emissions down to CO 

levels around 300 ppm, supporting the selection of CO as a 

surrogate for organic HAP emissions. A slight increase in 

formaldehyde emissions is observed at CO levels below around 200 

ppm, suggesting a breakdown in the CO-formaldehyde relationship 

at low CO levels. At levels lower than 150 ppm, the mean levels 

of formaldehyde appear to increase, as does the overall maximum 

value of and variability in formaldehyde emissions. However, we 

are aware of no reason why CO concentrations would continue to 

decrease and formaldehyde concentrations would increase as 

combustion conditions improve. It is possible that imprecise 

formaldehyde measurements at low concentrations (i.e., 1 – 2 

ppm) may account for this slight increase in formaldehyde 

emissions observed at CO levels below 100 ppm corrected to 7 

percent oxygen. Based on this, we do not believe that such 
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measurements are sufficiently reliable to use as a basis for 

establishing an emissions limit. 

Therefore, based on the above analysis, we are promulgating 

a minimum MACT floor level for CO of 130 ppm corrected to 3 

percent oxygen (which is equivalent to 100 ppm corrected to 7 

percent oxygen). We note this is the same approach used to 

establish the CO emission limit of 100 ppm corrected to 7 

percent oxygen for the Burning of Hazardous Waste in Boilers and 

Industrial Furnaces rule. Additional discussion of the rationale 

for this approach can be found in the memorandum "Revised MACT 

Floor Analysis (August 2012) for Industrial, Commercial, 

Institutional Boilers and Process Heaters National Emission 

Standards for Hazardous Air Pollutants – Major Source.”

Subcategories where the initial MACT floor 99 percent UPL 

calculations for CO were less than 100 ppm corrected to 7 

percent oxygen (or equivalently 130 ppm corrected to 3 percent 

oxygen) are as follows:

 New and Existing Subcategories: Coal-FB, Coal-PC, Heavy 

Liquid, Light Liquid, Non-Continental Liquid, Process Gas

 New Subcategories: Coal-Stoker

We believe a CO level of 130 ppm corrected to 3 percent oxygen

is an appropriate minimum MACT floor level. Although some 

measurements show CO levels below 130 ppm corrected to 3 percent 
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oxygen, it is not appropriate to establish a lower floor level 

because CO is a conservative surrogate for organic HAP. In other 

words, organic HAP emissions are extremely low when sources 

operate under the good combustion conditions required to achieve 

CO levels in the range of zero to 100 ppm. As such, lowering the 

CO floor below 100 ppm will not provide reductions in organic 

HAP emissions. There are myriad factors that affect combustion 

efficiency and, as a function of combustion efficiency , CO 

emissions. As combustion conditions improve and hydrocarbon 

levels decrease, the larger and easier to combust compounds are 

oxidized to form smaller compounds that are, in turn, oxidized 

to form CO and water. As combustion continues, CO is then 

oxidized to form carbon dioxide and water. Because CO is a 

difficult to destroy refractory compound (i.e., oxidation of CO 

to carbon dioxide is the slowest and last step in the oxidation 

of hydrocarbons), it is a conservative surrogate for destruction 

of hydrocarbons, including organic HAP. 

The conservative nature of CO as an indicator of good

combustion practices is supported by our data. At CO levels less 

than 100 ppm corrected to 7 percent oxygen, our data indicate 

that there is no apparent relationship between CO and organic 

HAP (i.e., formaldehyde). For example, a source with a CO level 

of 20 ppm may have the same measured formaldehyde as a source 

achieving a CO emission level of 100 ppm corrected to 7 percent 
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oxygen. Sources are required to establish operating requirements 

based on operating levels that were demonstrated during the 

test. Sources must comply with these operating requirements on a 

continuous basis. Compliance with these requirements adequately 

assures sources will be controlling organic HAP emissions to 

MACT levels.

As detailed in the docketed memorandum “Beyond the Floor 

Technology Analysis for Major Source Boilers and Process Heaters 

(Revised August 2012),” we reviewed the emission limits that are 

becoming less stringent since the March 2011 final rule in order 

to assess whether a beyond the floor option was technically 

achievable and cost effective. As a result of this review, the 

PM emission limits for several new biomass subcategories have 

been changed to reflect a beyond the floor limit of 0.03 

lb/MMBtu, based on the limit for new biomass boilers in 40 CFR 

part 60 subparts Db and Dc. Due to the low mercury emission 

limits for new solid fuel boilers, these new biomass units are 

expected to install a fabric filter level of control in order to 

meet the new source mercury limits for the solid fuel 

subcategory. This mercury control has the co-benefit of reducing 

PM emissions down to levels of 0.03 lb/MMBtu so there is no 

incremental cost to achieve these additional reductions in PM 

for the biomass units that have a design heat input capacity 

between 10 and 30 MMBtu/hr. For units with a design heat input 
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capacity of 30 MMBtu/hr or greater, these units are already 

subject to a PM limit of 0.03 lb/MMBtu and adjusting these new 

source limits to this level of control makes the limits 

consistent between both rules, without adding additional costs. 

We did not identify any beyond the floor options for existing 

source PM limits or new and existing limits for other pollutants 

as technically feasible or cost effective. 

The other changes associated with the other emission limits 

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

changes. In summary, compared to the December 23, 2011 proposed 

limits for existing units, the final HCl emission limits 

remained the same; for the final mercury emission limits, 3 are 

more stringent, 10 are less stringent and 1 is unchanged; for 

the final PM emission limits, 3 are more stringent, 5 are less 

stringent and 6 are unchanged; and for the final CO emission 

limits, 3 are more stringent and 11 are less stringent. For new 

units, compared to the proposed emission limits, 3 of the final

HCl emission limits are more stringent and 11 remained the same; 

for the final mercury emission limits, 10 are more stringent and 

4 are unchanged; for the final PM emission limits, 5 are more 

stringent, 2 are less stringent and 7 are unchanged; and for the 

final CO emission limits, 2 are more stringent, 11 are less 

stringent and 1 is unchanged.

E. Work Practice Requirement
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In this final rule several changes have been made to the 

work practice requirement to conduct a tune-up. First, the 

requirement to inspect the burner has been revised to allow 

units that sell electricity to schedule the burner inspection, 

as well as the air-to-fuel system inspection, at the time of the 

first outage but not to exceed 36 months from the previous 

inspection. This change is being made to this final rule because 

commenters stated that large boilers that serve electricity for 

sale may not require annual outages and would, therefore, need 

to be taken off-line for the sole purpose of an annual tune-up. 

This frequency is consistent with the requirements of the NESHAP 

for electric utility boilers (40 CFR part 63, subpart UUUUU). 

Also, for units where entry into a piece of process 

equipment or into a storage vessel is required to complete the 

tune-up inspections, inspections are required only during 

planned entries into the storage vessel or into process 

equipment. Commenters indicated that some process heaters are 

installed inside tanks and entry into the tank to access the 

heater may not occur within a 5 year period.

The requirement to optimize total emissions of CO has been 

revised to require that this optimization not only be consistent 

with the manufacturer’s specifications but also with any NOx

emission requirement to which the unit is subject. Some 

commenters indicated that many boilers need different tune-up 
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criteria due to their requirement to also comply with low NOx

emission limits. We are also aware that several states have 

boiler tune-up requirements to minimize NOx emissions first and 

then optimize CO emissions. 

We have added boilers or process heaters that have a 

continuous oxygen trim system to the types of boilers or process 

heaters that must conduct a tune-up every 5 years. These units 

do not need to be tuned as frequently because the trim system is 

designed to continuously measure and maintain an optimum air to 

fuel ratio which is the purpose of a tune-up. 

F. Averaging Times Definitions

We revised the definitions of “30-day rolling average” and 

“daily block average” to exclude periods of startup and shutdown 

or downtime from the arithmetic mean. Commenters requested that 

the EPA specify how a 30-day rolling average is calculated and 

whether it includes the previous 720 hours of valid operating 

data and that the valid data exclude hours during startup and 

shutdown as well as unit down time. We agree with the commenters 

that the definitions need clarification and that these periods 

should not be included in calculating the 30-day rolling 

average. Therefore, we have revised the definitions accordingly. 

We have also included in the final rule a definition of 

“10-day rolling average” that is consistent with the revised 

definition of “30-day rolling average.”
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G. Energy Assessment

In this final rule, we have revised the definition of 

energy assessment per the requirements of Table 3 of this final 

rule by providing duration for performing the energy assessment

for large fuel use facilities. In numbered paragraph (3) in the 

definition of "Energy assessment" in §63.7575, which is for 

facilities with units having a combined heat input capacity

greater than 1 TBtu/yr, we added time duration/size ratio and 

included a cap to the maximum number of on-site technical hours 

that should be used in the energy assessment. This addition of a 

duration for large fuel use facilities is being made to be 

consistent with durations specified for small [paragraph (1) in 

the definition of "Energy assessment"] and medium [paragraph (2) 

in the definition of "Energy assessment"] fuel use facilities. 

The energy assessment for facilities with affected boilers and 

process heaters having a combined heat input capacity greater 

than 1.0 TBtu/yr will be up to 24 on-site technical labor hours 

for the first TBtu/yr plus 8 technical labor hours for every 

additional 1.0 TBtu/yr not to exceed 160 technical hours, but 

may be longer at the discretion of the owner or operator.

The revised definition of energy assessment also clarifies 

our intentions that the scope of assessment is based on energy 

use by discrete segments of a facility and not by a total 

aggregation of all individual energy using elements of a 
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facility. The applicable discrete segments of a facility could 

vary significantly depending on the site and its complexity. We 

have added the following paragraph (4), to the energy assessment 

definition to help resolve current problems in identifying the 

scope of the various energy use systems in a large industrial 

complex and allow for more streamlined assessments:

"(4) The on-site energy use systems serving as the basis 

for the percent of affected boiler(s) and process heater(s) 

energy output in (1), (2) and (3) above may be segmented by 

production area or energy use area as most logical and 

applicable to the specific facility being assessed 

(e.g., product X manufacturing area; product Y drying area; 

Building Z)."

We have also revised paragraph 4 of Table 3 of the final 

rule to allow a source that is operating under an energy 

management program established through energy management systems 

compatible with ISO 50001, which includes the affected units, to 

satisfy the energy assessment requirement. We consider these 

energy management programs to be equivalent to the one-time 

energy assessment because facilities having these programs 

operate under a set of practices and procedures designed to 

manage energy use on an ongoing basis. These programs contain 

energy performance measurements and tracking plans with periodic 

reviews.
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The definition of “Energy use system” has also been revised 

in this final rule to clarify that energy use systems are only 

those systems using energy clearly produced by affected boilers 

and process heaters.

H. Startup and Shutdown Definitions

A number of commenters indicated that the proposed load 

specifications (i.e., 25 percent load) within the definitions of 

“startup” and “shutdown” were inconsistent with either safe or 

normal (proper) operation of the various types of boilers and 

process heaters encountered within the source category. As the 

basis for defining periods of startup and shutdown, a number of 

commenters suggested alternative load specifications based on 

the specific considerations of their boilers; other commenters

suggested the achievement of various steady-state conditions.

We have reviewed these comments and believe adjustments are 

appropriate in the definition of “startup” and “shutdown.” These 

adjustments are tailored for industrial boilers and are 

consistent with the definitions of “startup” and “shutdown” 

contained in the 40 CFR part 63, subpart A General Provisions. 

We believe these revised definitions address the comments and 

are rational based on the fact that industrial boilers function 

to provide steam or, in the case of cogeneration units, 

electricity; therefore, industrial boilers should be considered 

to be operating normally at all times steam of the proper 
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pressure, temperature, and flow rate is being supplied to a 

common header system or energy user(s) for use as either process 

steam or for the cogeneration of electricity. The definitions of 

“startup” and “shutdown” have been revised in the final rule as 

follows:

“Startup means either the first-ever firing of fuel in a 

boiler or process heater for the purpose of supplying steam or 

heat for heating and/or producing electricity, or for any other 

purpose, or the firing of fuel in a boiler or process heater 

after a shutdown event for any purpose. Startup ends when any of 

the steam or heat from the boiler or process heater is supplied 

for heating and/or producing electricity, or for any other 

purpose.”

“Shutdown means the cessation of operation of a boiler or 

process heater for any purpose. Shutdown begins either when none 

of the steam and heat from the boiler or process heater is 

supplied for heating and/or producing electricity, or for any 

other purpose, or at the point of no fuel being fired in the 

boiler or process heater, whichever is earlier. Shutdown ends 

when there is both no steam or heat being supplied and no fuel 

being fired in the boiler or process heater.”

The EPA is requiring sources to vent emissions to the main 

stack(s) and operate all control devices necessary to meet the 

normal operating standards under this final rule (with the 
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exception of limestone injection in FBC boilers, dry scrubber, 

fabric filter, SNCR and SCR) when firing coal/solid fossil fuel, 

biomass/bio-based solids, heavy liquid fuel or gas 2 (other) 

gases in the boiler or process heater during startup or 

shutdown. It is the responsibility of the operators of affected 

boilers and process heaters to start their limestone injection 

in FBC boilers, dry scrubber, fabric filter, SNCR and SCR

systems appropriately to comply with relevant standards 

applicable during normal operation. Startup ends and normal 

operating standards apply when heat or steam is supplied for any 

purpose.

The EPA carefully considered fuels and potential 

operational constraints of APCD when designing its work 

practices for periods of startup and shutdown. The EPA notes 

that there is no technical barrier to burning clean fuels (e.g., 

natural gas, distillate oil) for longer portions of startup or 

shutdown periods at a boiler and the HAP emission reduction 

benefits warrant additional utilization of such fuels until the

temperature and stack emissions pressure is sufficient to engage 

the APCD. The EPA is aware that SNCR and SCR systems with 

ammonia injection need to be operated within a prescribed and 

relatively narrow temperature window to provide NOx reductions. 

Further, the EPA is aware that dry scrubbers also need to be 

operated close to flue gas saturation temperature, and that 
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fabric filters need to be operated at temperatures above the 

acid dew point. Because these devices have specific temperature 

requirements for proper operation, the EPA notes in its work 

practices that it is the responsibility of the operators of 

affected boilers and process heaters to start their SNCR, SCR, 

fabric filter and dry scrubber systems appropriately to comply 

with relevant standards applicable during normal operation.

I. Fuel Sampling Frequency

The sampling frequency for gaseous fuel-fired units that 

elected to demonstrate that the unit meets the specification for 

mercury for the unit designed to burn gas 1 subcategory has been 

revised in this final rule. If the initial mercury constituents 

in the gaseous fuels are measured to be equal to or less than 

half of the mercury specification, no further sampling is 

required. If the initial mercury constituents are greater than 

half but equal to or less than 75 percent of the mercury 

specification, only semi-annual sampling need to be conducted. 

If the initial mercury constituents are greater than 75 percent

of the mercury specification, monthly sampling is required.

J. Affirmative Defense

In the proposal, we used terms such as “exceedance” or 

“excess emissions” in §63.7501, which created unnecessary 

confusion as to when the affirmative defense could be used. In 

the final amended rule, we have eliminated those terms and used 
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the word “violation” to make clear that the affirmative defense 

to civil penalties is available only where an event that causes 

a violation of the emissions standard meets the definition of

malfunction under §63.2.

We have also eliminated the 2-day notification requirement

that was included in 40 CFR 63.7501(b) at proposal because we 

expect to receive sufficient notification of malfunction events 

that result in violations in other required compliance reports, 

such as the malfunction report required under 40 CFR 63.7550(c).

In addition, we have revised the 45-day affirmative defense 

reporting requirement that was included in 40 CFR 63.7501(b) at 

proposal to require sources to include the report in the first 

compliance, deviation or excess emission report due after the 

initial occurrence of the violation, unless the compliance, 

deviation or excess emission report is due less than 45 days 

after the violation. In that case, the affirmative defense 

report may be included in the second compliance, deviation or 

excess emission report due after the initial occurrence of the 

violation. Because the affirmative defense report is now 

included in a subsequent compliance, deviation or excess 

emission report, there is no longer a need for the proposed 30-

day extension for submitting a stand-alone affirmative defense 

report. Consequently, we are not including this provision in the 

final amended rule. We have also re-evaluated the language 
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concerning the use of off-shift and overtime labor to the extent 

practicable and believe that the language is not necessary. 

Thus, we have deleted that phrase from section 63.7501(a)(2).

V. Other Actions We Are Taking

Section 307(d)(7)(B) of the CAA states that “[o]nly an 

objection to a rule or procedure which was raised with 

reasonable specificity during the period for public comment 

(including any public hearing) may be raised during judicial 

review. If the person raising an objection can demonstrate to 

the Administrator that it was impracticable to raise such 

objection within such time or if the grounds for such objection 

arose after the period for public comment (but within the time 

specified for judicial review) and if such objection is of 

central relevance to the outcome of the rule, the Administrator 

shall convene a proceeding for reconsideration of the rule and 

provide the same procedural rights as would have been afforded 

had the information been available at the time the rule was 

proposed. If the Administrator refuses to convene such a 

proceeding, such person may seek review of such refusal in the 

United States court of appeals for the appropriate circuit (as 

provided in subsection (b)).”

As to the first procedural criterion for reconsideration, a 

petitioner must show why the issue could not have been presented 

during the comment period, either because it was impracticable 
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to raise the issue during that time or because the grounds for 

the issue arose after the period for public comment (but within 

60 days of publication of the final action). The EPA is denying 

the petitions for reconsideration on a number of issues because 

this criterion has not been met. In many cases, the petitions 

reiterate comments made on the proposed June 2011 rule during 

the public comment period for that rule. On those issues, the 

EPA responded to those comments in the final rule and made 

appropriate revisions to the proposed rule after consideration 

of public comments received. It is well-established that an 

agency may refine its proposed approach without providing an 

additional opportunity for public comment. See Community 

Nutrition Institute v. Block, 749 F.2d at 58 and International 

Fabricare Institute v. EPA, 972 F.2d 384, 399 (D.C. Cir. 1992) 

(notice and comment is not intended to result in “interminable 

back-and-forth[,]” nor is agency required to provide additional 

opportunity to comment on its response to comments) and Small 

Refiner Lead Phase-Down Task Force v. EPA, 705 F.2d 506, 547 

(D.C. Cir. 1983) (“notice requirement should not force an agency 

endlessly to repropose a rule because of minor changes”)

In the EPA’s view, an objection is of central relevance to 

the outcome of the rule only if it provides substantial support 

for the argument that the promulgated regulation should be 

revised. See Union Oil v. EPA, 821 F.2d 768, 683 (D.C. Cir. 
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1987) (court declined to remand rule because petitioners failed 

to show substantial likelihood that final rule would have been 

changed based on information in petition). See also the EPA’s 

Denial of the Petitions to Reconsider the Endangerment and Cause 

or Contribute Findings for Greenhouse Gases under Section 202 of 

the Clean Air Act, 75 FR at 49556, 49561 (August 13, 2010). See 

also, 75 FR at 49556, 49560 - 49563 (August 13, 2010) and 76 FR 

at 4780, 4786 - 4788 (January 26, 2011) for additional 

discussion of the standard for reconsideration under CAA section 

307(d)(7)(B).

We are denying reconsideration on the following 57 issues 

contained in the petitions for reconsideration because they 

failed to meet the standard described above for reconsideration 

under CAA section 307(d)(7)(B). Specifically, on these issues, 

the petitioner has failed to show the following: that it was 

impracticable to raise their objections during the comment 

period or that the grounds for their objections arose after the 

close of the comment period; and/or that their concern is of 

central relevance to the outcome of the rule. Therefore, the EPA 

is denying the petitions for reconsideration on the issues for 

the reasons described below.

Issue: Delist gas units.

The petitioners (API, NPRA) requested that the EPA remove 

gas-fired units from the section 112(c) list of source 
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categories for which the EPA is required to establish emissions 

standards under section 112(d). The EPA is denying the petition 

for reconsideration for the following reasons. First, the issue 

is outside the scope of this rulemaking, which establishes 

emissions standards for new and existing units within the major 

source boilers and process heaters source category. The EPA did 

not solicit comment in the proposed rule regarding the scope of 

the subcategory. Further, petitioners provide no information to 

support delisting gas units under section 112(c)(9), which 

requires the EPA to make certain findings before delisting any 

sources. In addition, the petition does not address the D.C. 

Circuit’s decision in NRDC v. EPA, 489 F.3d 1364 (2007), 

regarding the EPA’s ability to delist subcategories of a source 

category pursuant to section 112(c)(9). For these reasons, the 

petitions do not provide support for the argument that the 

regulation should be changed. For this reason, the petition does 

not demonstrate that the issue is of central relevance to the 

outcome of the final rule and the EPA is denying the request for 

reconsideration.

Issue: Exempt natural gas hot water heaters with tanks greater 

than 120 gallons.

The petitioner (AIF) requested that the EPA exempt natural 

gas hot water heaters with tanks greater than 120 gallons. While 

the EPA disagrees with the petitioner regarding whether such 
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units should be subject to the emissions standards in this rule, 

the petitioner has not demonstrated that it lacked the 

opportunity to comment on whether such units should be required 

to meet emissions standards. The EPA proposed work practice 

standards for such units in its June 2010 proposal, and the 

petitioner had the opportunity to comment on whether such 

standards should be applied to such units at all. Therefore, the 

EPA is denying the request for reconsideration.

Issue: Exempt natural gas and distillate oil-fired circulating 

hot water systems with a design capacity of 10 MMBtu/hr or less.

The petitioner (CIBO) requested that the EPA exempt natural 

gas and distillate oil-fired circulation hot water systems that 

are not greater than 10 MMBtu/hr. While the EPA disagrees with 

the petitioner regarding whether such units should be subject to 

the emissions standards in this rule, the petitioner has not 

demonstrated that it lacked the opportunity to comment on 

whether such units should be required to meet emissions 

standards. The EPA proposed emissions standards for such units, 

and the petitioner had the opportunity to comment on whether 

such standards should be applied to such units at all. In 

addition, the petition does not provide any information to 

demonstrate that these units should be delisted pursuant to 

section 112(c)(9). Therefore, the EPA is denying the request for 

reconsideration.
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Issue: Confirm in definitions that open flame heaters (e.g., 

asphalt tank heaters) are not process heaters.

The petitioners (API, NPRA) requested that the EPA clarify 

in the definition of “process heater” that open flame heaters do 

not meet the definition. While the EPA disagrees with the 

petitioners whether clarification is needed in regards to open 

flame heaters, the petitioners have not demonstrated that it 

lacked the opportunity to comment on the proposed definition. 

The definition that the EPA proposed clearly states that process 

heaters are enclosed devices in which the combustion gases do 

not come into contact with process materials, and as such, does 

not include open flame heaters. Therefore, the EPA is denying 

reconsideration.

Issue: For blast furnace fuel-fired boiler exemption, compute 

the 90 percent BFG by volume threshold to exclude periods of BFG 

curtailment.

The petitioners (AISI, ACCCI) requested that the EPA revise 

the exemption for BFG fuel-fired boilers to exclude periods of 

BFG curtailment. While the EPA disagrees with the petitioners

regarding revising the exemption, the petitioners have not 

demonstrated that it lacked the opportunity to comment on the 

proposed exemption for BFG fuel-fired boilers. The EPA proposed 

the exemption for these boilers, and petitioners therefore had 

the opportunity to comment on whether the exemption should apply 
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to periods of BFG curtailment. Therefore, the EPA is denying the 

request for reconsideration.

Issue: Exempt boilers whose flue gases are used in direct-fired 

process heaters subject to other NESHAP.

The petitioner (CMI) requested that the EPA exempt from the 

rule boilers whose flue gases are used in direct-fired process 

heaters that are subject to other NESHAP. The final rule does 

not apply to such units if they are subject to another NESHAP. 

The EPA does not see a need for further clarification. Since the 

final rule does in fact exempt these units, the EPA is denying 

the request for reconsideration.

Issue: Work practice standards do not meet EPA obligations under 

112(c)(6).

The petitioner (Sierra Club) requested that the EPA 

establish numeric emissions limits for Gas 1 units rather than 

work practice standards. Specifically, the petitioner alleges 

that the work practice standards do not meet the EPA’s 

obligations under section 112(c)(6) of the CAA, and that it was 

not the case that data were below the detection level for all 

HAP emitted from these units. The EPA is denying the request for 

reconsideration on this issue. While the EPA disagrees with the 

petitioner’s arguments regarding the legal authority to 

establish work practice standards for Gas 1 units and the basis 

for such standards, the petitioner has not demonstrated that it 
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lacked the opportunity to comment on this issue. The EPA 

proposed work practice standards for Gas 1 units and explained 

in the proposal its rationale for such standards, including the 

fact that a significant portion of the emissions data were below 

the detection level. 75 FR at 32024-25. Therefore, the 

petitioner had the opportunity to comment on this issue, and did 

in fact submit comments regarding the EPA’s legal authority to 

establish work practice standards for Gas 1 units. Therefore, 

the EPA is denying reconsideration on this issue.

Issue: Work practices for small units are not justified by 

112(h) since small units were not given their own subcategory.

The petitioner (Sierra Club) requested that the EPA require 

small units, those having a heat input capacity of less than 10 

MMBtu/hr, to meet numeric emissions limits rather than work 

practice standards. The EPA is denying the request for 

reconsideration on this issue because the petitioner has not 

demonstrated that it lacked the opportunity to comment on this 

issue. The EPA proposed work practice standards for these units 

and explained in the proposal its rationale for such standards. 

75 FR at 32024-25. The EPA did in fact receive comments 

regarding the proposed standards, to which it responded in the 

final rule. 76 FR at 15640. Moreover, the EPA notes that nothing 

in section 112(h) limits the EPA’s discretion to establish work 

practice standards to the establishment of such standards for an 
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entire category or subcategory. Therefore, the EPA is denying 

the request for reconsideration.

Issue: PM is not an adequate surrogate for non-mercury metallic 

HAP.

The petitioner (Sierra Club) requested that the EPA remove 

the PM standard as a surrogate for non-mercury metallic HAP and 

instead adopt a numeric limit for non-mercury metallic HAP 

because PM is not an appropriate surrogate. The EPA is denying 

the request for reconsideration on this issue. While the EPA 

disagrees with the petitioner’s argument regarding the 

suitability of PM as a surrogate for non-mercury metallic HAP, 

the petitioner has not demonstrated that it lacked the 

opportunity to comment on this issue. The EPA proposed PM 

standards as a surrogate for non-mercury metallic HAP and 

explained in the proposal the agency’s basis for concluding that 

PM was an appropriate surrogate. 75 FR at 32018. Therefore, the 

EPA is denying the request for reconsideration.

Issue: Establish direct limits on organics or select a surrogate 

besides CO.

The petitioner (Sierra Club) requested that the EPA remove 

the CO standard as a surrogate for organic HAP and instead adopt 

a numeric limit for these HAP, because CO is not an appropriate 

surrogate. The EPA is denying the request for reconsideration on 

this issue. While the EPA disagrees with the petitioner’s 
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argument regarding the suitability of CO as a surrogate for 

organic HAP, the petitioner has not demonstrated that it lacked 

the opportunity to comment on this issue. The EPA proposed CO 

standards as a surrogate for organic HAP and explained in the 

proposal the agency’s basis for concluding that CO was an 

appropriate surrogate. 75 FR at 32018. The EPA received comments 

on this issue, including comments stating that CO is not an 

appropriate surrogate for organic HAP. Therefore, the EPA is 

denying the request for reconsideration.

Issue: Adopt an alternative THC emission standard.

The petitioner (CIBO) requested that the EPA adopt a THC 

emissions standard as an alternative to the CO standard. The EPA 

is denying the request for reconsideration on this issue. While 

the EPA disagrees with the petitioner’s argument regarding 

whether a THC alternative standard is appropriate as a surrogate 

for non-dioxin organic HAP, the petitioner has not demonstrated 

that it lacked the opportunity to comment on this issue. The EPA 

raised in the proposal the possibility of THC as a surrogate for 

non-dioxin organic HAP, and explained why the use of CO as a 

surrogate was preferable. 75 FR at 32018. In addition, the EPA 

did not receive any comments or data during the public comment 

period on the proposed rule that would have enabled the agency 

to establish a THC alternative standard, including THC emissions 

data, nor did the petitioner provide any such data. Therefore, 
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the petition does not provide substantial support for its 

argument that the final rule should be changed. For these 

reasons, the EPA is denying the petition for reconsideration on 

this issue. 

Issue: Regulation of Total dioxin/furans exceeds statutory 

authority as only 2 compounds are in 112(b)(1).

The petitioners (AISI, ACCCI, AF&PA) alleged that the EPA 

lacks statutory authority to regulate total dioxin/furans under 

CAA section 112, and that the EPA’s response in the final rule 

explaining why it is issuing a total dioxin/furan standard was 

not a logical outgrowth of the proposed rule. The EPA is denying 

the request for reconsideration on this issue. First, the EPA 

disagrees that the final rule is not a logical outgrowth of the 

proposal. The EPA proposed emissions standards for total dioxin/ 

furans and adopted a final emissions standard for the same 

pollutant. Therefore, the commenter had the opportunity to 

provide its views during the public comment period regarding the 

EPA’s proposed emissions standard, including its views regarding 

the EPA’s authority to regulate the pollutant at issue. The fact 

that the EPA responded to those comments does not mean that the 

petitioner lacked the opportunity to comment – in fact, the 

petitioner did provide such comments. 76 FR at 15640. For this 

reason, the EPA is denying the petition for reconsideration.

Issue: HCl is an inadequate surrogate for all acid gases.
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The petitioner (Sierra Club) requested that the EPA remove 

the HCl standard as a surrogate for acid gases and instead adopt 

a numeric limit for these HAP, because HCl is not an appropriate 

surrogate. The EPA is denying the request for reconsideration on 

this issue. While the EPA disagrees with the petitioner’s 

argument regarding the suitability of HCl as a surrogate for 

acid gases, the petitioner has not demonstrated that it lacked 

the opportunity to comment on this issue. The EPA proposed HCl 

standards as a surrogate for acid gases and explained in the 

proposal the agency’s basis for concluding that HCl was an 

appropriate surrogate. 75 FR at 32018. While the EPA had 

emission data for HCl from hundreds of affected units upon which 

to establish standards, the EPA did not have sufficient data on 

the other acid gases to do so (hydrogen fluoride, hydrogen 

cyanide and chlorine). The petitioner did not refer to any such 

data and, therefore, the issue is not of central relevance to 

the outcome of the final rule. Therefore, the EPA is denying the 

request for reconsideration.

Issue: Establish work practice for other organic HAP instead of 

using CO as a surrogate.

The petitioners (AMP, JELD-WEN) requested that the EPA 

adopt a work practice standard for organic HAP rather than a 

numeric emissions limit based on CO as a surrogate for organic

HAP. The EPA is denying the request for reconsideration on this 
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issue. While the EPA disagrees that a work practice standard is 

appropriate for such HAP for the subcategories for which the EPA 

adopted a numeric CO limit in the final rule, the petitioners

have not demonstrated that they lacked the opportunity to 

comment on this issue. The EPA proposed numeric CO limits rather 

than a work practice, and the petitioners had the opportunity to 

provide their views during the public comment period on the 

proposed rule regarding why it believed a work practice standard 

should instead be finalized. Therefore, the EPA is denying the 

petition for reconsideration.

Issue: Allow health based compliance alternatives for HCl, other 

acid gases and manganese.

The petitioners (AMP, AF&PA, AHFA, AISI, ACCCI, RPU, CIBO)

requested that the EPA adopt a HBES for HCl and other acid gases 

as well as for manganese, pursuant to section 112(d)(4). The 

petitioners also requested that the EPA grant reconsideration on 

this issue to better address the comments and data submitted 

during the public comment period for the proposed rule. The EPA 

is denying the request for reconsideration of this issue. The

EPA did not propose a HBES for any pollutants, but did solicit 

public comment on such standards, explaining its concerns 

regarding health-based standards, including the lack of 

available data on which to base such standards. 75 FR at 32030. 

The EPA received comments addressing those concerns and 
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responded to them in the final rule. 76 FR at 15642. Therefore, 

the petitioners have not demonstrated that it lacked the 

opportunity to comment on this issue. Further, the EPA received 

no data during the public comment period for the proposed rule 

on which it could base a HBES for HCl, other acid gases or 

manganese. Therefore, the petitions do not provide substantial 

support to demonstrate that the final rule should be changed. 

For these reasons, the EPA is denying the petition for 

reconsideration.

Issue: Provide additional compliance alternatives according to 

Executive Order 13563 (additional subcategories and HBES).

The petitioner (AHFA) requested that the EPA provide 

additional compliance alternatives in the final rule pursuant to 

Executive Order 13563 (Improving Regulation and Regulatory 

Review), including HBES. The EPA is denying the request for 

reconsideration on this issue because it is not of central 

relevance. First, nothing in Executive Order 13563 affects the 

EPA’s discretion to establish HBES under the CAA. Additionally, 

the petition does not provide any information to address our 

concerns regarding HBES or data to establish such standards.

Issue: Remove energy assessment requirements.

The petitioners (AHFA, AISI, ACCCI, API, NPRA, AIF, CIBO, 

AF&PA, U.S. Sugar) requested that the EPA remove from the final 

rule the requirement that existing sources conduct an energy 
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assessment. The EPA is denying the request for reconsideration 

on this issue. The EPA proposed an energy assessment requirement 

as a beyond-the-floor standard, and petitioners commented on 

that proposal. The EPA addressed those comments in the final 

rule, and petitioners have not demonstrated that they lacked the 

opportunity to comment on whether the EPA should require an 

energy assessment, including the EPA’s legal authority to do so. 

76 FR at 15631. Therefore, the EPA is denying the petition for 

reconsideration. The EPA continues to believe that an energy 

assessment is not only authorized by the CAA but required as a 

cost-effective beyond-the-floor standard in accordance with 

section 112(d)(2).

Issue: Require energy assessment to be conducted every 5 years.

The petitioner (Washington Dept. of Ecology) requested that 

the EPA require more frequent energy assessments. The EPA 

proposed a one-time assessment (75 FR at p. 32036) and the 

petitioner has not demonstrated it lacked the opportunity to 

comment on the frequency of the assessment requirement.

Therefore, the EPA is denying the petition.

Issue: Modify cost analysis to include potential fuel savings 

from implementing assessment findings.

The petitioners (AIE, USCHPA) requested that the EPA modify

its cost impacts analysis to include potential fuel savings from 

implementing energy assessment findings. The EPA is denying the 
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petition. The impacts analysis, including specific mention of 

how cost savings for energy assessments were handled 

quantitatively, was explained in the proposal (see 75 FR 32026), 

and the petitioner therefore had the opportunity to comment on 

this issue. For this reason, the EPA is denying the petition for 

reconsideration on this issue.

Issue: Reconsider definition of “cost effective.”

The petitioners (AIE, USCHPA) requested that the EPA 

reconsider the definition of “cost-effective” in the final rule. 

The EPA is denying the request for reconsideration on this 

issue. The EPA proposed to define cost-effective energy 

conservation measures as any measure with return of investment 

period of two years or less. 75 FR at 32036. The petitioners

have not demonstrated it lacked the opportunity to comment on 

the proposed definition. Therefore, the EPA is denying the 

petition for reconsideration.

Issue: Establish work practice for other organic HAP instead of 

using CO surrogate.

The petitioners (AMP, JELD-WEN) requested that the EPA 

establish work practice standards for controlling organic HAP 

instead of using CO as a surrogate for organic HAP and 

establishing CO emission limits. The EPA is denying the request 

for reconsideration on this issue. Use of CO as a surrogate for 

organic HAP was subject to notice and comment. (75 FR 32018, 75 
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FR 32041). Responses to comment on this topic were provided in 

RTC document, Volume 2, EPA-HQ-OAR-2002-0058-3289, see section 

“Choice of Regulated Pollutants: THC vs. CO vs. Other Organic 

HAP”.

Issue: Provide alternative format for units of measure for CO 

emission limits to allow sources to use their existing 

monitoring equipment.

The petitioners (UARG, CIBO) requested that the EPA provide 

an alternative format (ppm at X percent CO2) for units of 

measure for CO emissions in addition to ppm at 3 percent oxygen. 

The EPA is denying the petition because the petitioners do not 

demonstrate that it was impracticable to comment on this issue. 

The format for units of measure for the limits was provided in 

the proposed rule, and petitioners could have commented on 

whether the proposed units were appropriate.

Issue: New source emission limits are unachievable and the EPA 

should collect additional fuel variability data from top 

performing units to adjust the limits.

The petitioner (AF&PA) requested that the EPA adjust the 

emissions limits for new sources by collecting additional data 

from the best performing units that they believed would result 

in increased variability. The petitioners have not demonstrated 

that they lacked the opportunity to comment. We proposed 

standards based on the data we had, including data collected 
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during the ICR process in which petitioners participated, and 

that data were available for public review. Therefore, 

petitioners could have commented on this issue. Second, the CAA

requires that we base the standards on the sources for which we 

have emissions information. Petitioners are always free to 

provide more information to us and the EPA specifically 

requested new data at each stage of the rulemaking to support 

the development of emission limits for each subcategory. (75 FR 

32041, 76 FR 28663, 76 FR 80612). The EPA has incorporated 

revised data corrections or new data submittals in its analysis

for the final rule. The EPA is denying the request for 

reconsideration.

Issue: Adjust the methodology for computing MACT floors to 

address statistical errors and variability concerns.

The petitioners (AISI, ACCCI, AF&PA) requested that the EPA 

adjust the methodology for computing MACT floors to address 

statistical errors and variability concerns, including: 1) 

dataset reflects the “best of the best” units; 2) misapplication 

of statistical formulae to address distribution, confidence 

limits, and variability; and 3) failure to address variability 

in emissions from one unit over time. The methods used to 

compute the MACT floors were subject to notice and comment. 

Where new data or data corrections have been submitted that 

might alter data distributions, identifying best performers or 
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application of fuel variability factors, these changes have been 

made in the final rule, but the general methodology remains the 

same. See Solite Corp. v. EPA, 952 F.2d 473, 485 (D.C. Cir. 

1991) (public had sufficient notice of final rule threshold 

calculations where methodology did not change significantly from 

proposed rule). The EPA explained the MACT floor methodology in 

the proposed rule, and addressed comments received on the 

proposed methodology in the final rule (75 FR 32019-26, 32027-

29, 76 15621-30, 76 FR 80614). Therefore, the EPA is denying the 

request for reconsideration.

Issue: Modify the basis for ranking the top performing units.

The petitioner (WEPCO) requested that the EPA modify the 

basis for ranking the top performing units, especially for new 

units, according to the average performance of the unit. The EPA 

is denying the petition. The methods used to rank units to 

establish the MACT floors were subject to notice and comment. 

The EPA explained its methodology in the proposed rule and 

addressed comments received on the ranking of data for computing 

the MACT floor in the final rule (75 FR 32019-26, 32027-29, 76 

FR 15627).

Issue: Do not use a pollutant-by-pollutant approach to establish 

MACT floors.

The petitioners (AISI, ACCCI, AF&PA) requested that the EPA 

not use a pollutant-by-pollutant approach to establish MACT 
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floors. The petitioners stated that this method is not a 

reasonable interpretation of Section 112(d)(3) of the CAA and 

that MACT floors should reflect levels achieved in practice, not 

aspirational controls. The EPA is denying the petition for 

reconsideration on this issue because it does not demonstrate 

that it was impracticable to comment on the issue. The EPA 

proposed MACT floors based on the pollutant-by-pollutant 

methodology, and therefore petitioners could, and in fact did, 

provide comments opposing this approach. See 75 FR 32021, 32029. 

The EPA addressed comments received on this approach in the 

final rule (76 FR 15621-23). Therefore, the EPA is denying the 

petition.

Issue: Revise approach to establish MACT floors where there is 

non-detect data.

The petitioner (Sierra Club) requested that the EPA not use 

the approach it used in the final rule based on the 

representative detection level (RDL) to establish MACT floors 

because it does not reflect actual emissions of any source 

within the subcategory. Further, the petitioner questioned the 

basis of the selected detection level, and whether or not other 

variability adjustments (e.g., UPL analysis) sufficiently

account for measurement imprecision. The EPA is denying the 

petition. The three times representative detection level 

approach was subject to notice and comment. The EPA explained 
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its rationale for this approach in the proposed rule (75 FR 

32021) and responded to comments received in the final rule (76 

FR 15623, 76 FR 80611).

Issue: The approach used to set MACT floor limits for 

dioxin/furan emissions is flawed and the EPA should establish an 

isomer-specific approach.

The petitioner (WEPCO) requested that the EPA establish an 

isomer-specific approach for dioxin/furan emissions because the 

three times detection level approach for dioxin/furan emissions 

is flawed. The EPA is denying the petition. This approach was 

subject to notice and comment. Rationale and responses to 

comments on this approach were provided at (75 FR 32021, 32041, 

76 FR 15623). Further, the methods for establishing a 

representative detection level for dioxin/furan have been 

revised to account for the sensitivity of individual isomers, 

see rationale provided at (76 FR 80606).

Issue: Incorporate a fuel variability factor for PM based on the 

ash content of the fuel used by best performing units.

The petitioners (WEPCO, CIBO) requested that the EPA 

incorporate a fuel variability factor for PM based on the ash 

content of the fuel used by best performing units. The MACT 

floor methodology was explained in the June 4, 2010 proposal

which included fuel variability factors that did not reflect the 

ash content of the fuel. Therefore, the petitioner could have 
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commented recommending that the EPA do so, and, in fact, 

comments were provided on this issue. The EPA is denying the 

petition for reconsideration on this issue because it does not 

demonstrate that it was impracticable to comment on the issue.

Responses to comment on this topic were provided in RTC 

document, Volume 1, EPA-HQ-OAR-2002-0058-3289, see section “MACT 

Floor Methodology: Fuel Analysis Variability”.

Issue: Allow energy assessors to determine the time needed to 

conduct assessment.

The petitioner (Washington Dept. of Ecology) requested that 

the EPA allow the energy assessor to determine the time needed 

to conduct the energy assessment. The EPA is denying the 

petition. The duration of energy assessments was subject to 

notice and comment and the duration remains up to the affected 

source. Specific concerns with maximum duration requirements 

included in the March 21, 2011 final rule were clarified in the 

December 23, 2011 proposed notice of reconsideration. (76 FR 

80615)

Issue: The unit designed to burn gas 1 subcategory should allow 

for limited use of liquid fuels.

The petitioners (ACC, CEG, API, NPRA) requested that the 

EPA allow units in the Gas 1 subcategory for limited use of 

liquid fuels; for example, units with a federally enforceable 

permit on back up fuels or units burning 10 percent or less of 
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its heat input from liquid fuels should qualify as gas 1 units.

The EPA is denying the petition because it does not demonstrate 

that it was impracticable to comment on the issue. The EPA 

proposed definitions of the various subcategories, and 

petitioners had the opportunity to comment on those definitions, 

including the proposed definition of the Gas 1 subcategory which 

did allow for the limited use of liquid fuels. The EPA addressed 

comments received on this issue in the final rule (76 FR 15620).

Issue: The unit designed to burn gas 1 subcategory should 

automatically include other gaseous fuels such as petrochemical 

process gas and landfill gas.

The petitioners (ACC, AIF, WM) requested that the EPA 

redefine the unit designed to burn gas 1 subcategory to 

automatically include other gaseous fuels such as petrochemical 

process gas and LFG, especially when the LFG is routed to a 

treatment system prior to use or sale. The EPA proposed 

definitions of units designed to burn gas 1 and units designed 

to burn gas 2 (other), and therefore the petitioner had the 

opportunity to comment on these definitions and to recommend 

that other gases be included in the definition of the Gas 1 

subcategory (75 FR 32017, 32065). The EPA addressed comments 

received on this issue in the final rule (76 FR 15638). 

Therefore, the EPA is denying the petition.
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Issue: Reconsider the emission standards established for the 

unit designed to burn gas 2 subcategory.

Petitioners (AIF, CIBO, WM, CEG) requested that the EPA 

reconsider the emission standards for the unit designed to burn 

gas 2 subcategory in light of what they feel was a limited 

dataset and lack of data from a diverse set of fuel types. The 

EPA is denying the petition. The MACT floor methodology was open 

to notice and comment in the June 4, 2010 proposal. The EPA 

proposed emissions standards for this subcategory and the 

petitioners had an opportunity to comment on the proposed 

standards and the data on which the standards were based. The 

EPA further notes that the CAA requires that the MACT standards 

be based on the best performing sources for which the 

Administrator has emissions information. 

Issue: Adjust the “metal process furnaces” subcategory 

definition to include any gas-fired process furnace.

The petitioners (AISI, ACCCI) requested that the EPA adjust 

the “metal process furnaces” subcategory definition to include 

any gas-fired process furnace. The EPA is denying the petition. 

The definition of the subcategory for metal process furnaces was 

subject to notice and comment. (75 FR 32064, 76 FR 15620).

Issue: The designed to burn rationale for subcategorization is 

arbitrary.
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The petitioner (Sierra Club) alleged that the designed to 

burn rationale for subcategorization is arbitrary, especially 

considering the large number of co-fired units in the inventory.

The EPA proposed subcategories based on boiler design, and the 

petitioner has not demonstrated that it was impracticable to 

comment on the issue. In fact, the petitioner did submit 

comments on the proposed rule opposing the EPA’s proposed 

subcategorization approach. Therefore, the EPA is denying the 

petition. 

Issue: The EPA should consider exempting units from NSR.

The petitioners (MSU, PSU, Purdue, Citizens Thermal Energy) 

requested that the EPA consider exempting units from NSR who 

switch fuels, install pollution controls, or construct energy 

efficiency projects to meet the requirements of this rule

because complying with the rule requirements will trigger NSR. 

The EPA is denying the petition. The applicability of NSR is 

outside the scope of this rulemaking. Moreover, it was not 

impracticable to comment on this issue during the 2011 

rulemaking, in fact, comments were submitted on this issue, to 

which the EPA responded. See RTC document, Volume 2, EPA-HQ-OAR2002-0058-3289, DCN EPA-HQ-OAR-2002-0058-2729.1, excerpt 17.

Issue: Remove the 10 percent penalty for sources opting to use 

the emission averaging compliance alternative.
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The petitioners (AMP, MSU, PSU, Purdue, RPU, U.S. Sugar, 

Citizens Thermal Energy) requested that the EPA remove the 10 

percent penalty for sources opting to use the emission averaging 

compliance alternative. The EPA is denying the petition. The EPA 

proposed an emissions averaging approach that included the 10 

percent adjustment factor. (75 FR 32035) Therefore, the petition 

does not demonstrate that it was impracticable to comment on 

this issue. Responses to comment on this topic were provided in 

RTC document, Volume 2, EPA-HQ-OAR-2002-0058-3289, see section 

“Emissions Averaging.”

Issue: Allow emissions averaging across subcategories.

The petitioners (MSU, PSU, Purdue, RPU, Citizens Thermal 

Energy) requested that the EPA allow emissions averaging across 

subcategories. The EPA is denying the petition. The EPA proposed 

an emissions averaging approach that did not allow averaging 

across subcategories, and petitioners therefore had the 

opportunity to comment recommending that the EPA allow such 

averaging. Responses to comment on this topic were provided in 

RTC document, Volume 2, EPA-HQ-OAR-2002-0058-3289, DCN EPA-HQOAR-2002-0058-3213.1, excerpt 175.

Issue: Allow a source’s actual heat input instead of the maximum 

design heat input to be used in the emissions averaging 

provisions.
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The petitioner (CIBO) requested that the EPA allow a 

source’s actual heat input instead of the maximum design heat 

input to be used in the emissions averaging provisions of the 

final rule. The EPA proposed an emissions averaging approach 

that was based on the maximum rated heat input capacity, and 

petitioners therefore had the opportunity to comment 

recommending that the EPA base the averaging on actual heat 

input. Therefore, the EPA is denying the petition. 

Issue: Reduce stack testing frequency to once every five years

to reduce burden on facilities.

The petitioners (ACC, CIBO, JELD-WEN) requested that the 

EPA reduce stack testing frequency to once every 5 years and 

rely on the extensive set of continuous parameter monitoring in 

order to reduce burden on facilities. The EPA is denying the 

petition. The EPA proposed to require stack testing every year. 

The petition does not demonstrate that it was impracticable to 

comment on this issue, and the petitioners could have submitted 

comments requesting less frequent stack testing. 

Issue: Incorporate detailed fuel sampling procedures using 

incorporation by reference mechanisms instead of detailing 

sampling procedures in the regulatory language.

The petitioner (CIBO) requested that the EPA incorporate 

detailed fuel sampling procedures using incorporation by 

reference mechanisms and citing credible literature (e.g., 
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American Society for Testing and Materials) instead of detailing 

sampling procedures in the regulatory language since sampling 

procedures are subject to change over time. The EPA is denying

the petition because the petitioner has not demonstrated that it 

was impracticable to comment on this issue. The EPA proposed 

fuel sampling procedures in the regulatory text in the June 4, 

2010 proposal, and the petitioner therefore had the opportunity 

to comment recommending its preferred approach.

Issue: Remove the advanced submittal requirement for sitespecific fuel monitoring plans before each analysis. 

The petitioner (UARG) requested that the EPA remove the 

advanced submittal requirement for site-specific fuel monitoring 

plans before each analysis, especially if monthly frequency is 

maintained. If the fuel monitoring plan requirement remains, the 

petitioner requests that the EPA remove the requirement to 

report things that might change, such as unanticipated fuel use 

(based on unanticipated fuel changes). The EPA is denying the 

petition and disagrees with the commenter. First, the EPA 

proposed a fuel monitoring plan, and petitioners had the 

opportunity to comment on the plan requirement. The final rule 

requires submittal of a fuel monitoring plan 60 days before 

demonstrating initial compliance. The rule does not require resubmittal of this plan before each monthly analysis, see 40 CFR 

section 63.7521(b)(1).
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Issue: Allow EPA Method 5B to demonstrate compliance with PM 

emission limits.

The petitioner (UARG) requested that the EPA allow EPA 

Method 5B to demonstrate compliance with PM emission limits. The 

EPA is denying the petition because it does not demonstrate that 

it was impracticable to comment on this issue. The EPA proposed 

methods to demonstrate compliance in the June 4, 2010 proposal

and did not propose to allow Method 5B for PM compliance 

demonstrations. Therefore, the petitioner had the opportunity to 

submit comments recommending that the EPA allow the use of this 

method. For this reason, the EPA is denying the petition on this 

issue. 

Issue: Remove or make references to Methods 2, 2F, 2G and 4 

optional.

The petitioner (UARG) requested that the EPA remove or make 

references to EPA Methods 2, 2F, 2G and 4 optional. The EPA is

denying the petition because it does not demonstrate that it was 

impracticable to comment on this issue. The EPA proposed methods 

to demonstrate compliance in the June 4, 2010 proposal and did 

not propose to make EPA Methods 2, 2F, 2G and 4 optional.

Therefore, the petitioner had the opportunity to submit comments 

recommending that the EPA make the use of these methods 

optional. For this reason, the EPA is denying the petition on 

this issue. 
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Issue: Allow sources to petition for alternative PM monitoring 

requirements based on source-specific limitations.

The petitioner (CEG) requested that the EPA allow sources 

to petition for alternative PM monitoring requirements based on 

source-specific limitations (e.g., common stacks with more than 

one subcategory). The EPA is denying this petition because it is 

not of central relevance to this rulemaking. The General 

Provisions at 40 CFR 63.8 allow sources to petition the EPA for 

alternative monitoring plans. Therefore, no such provision is 

needed in this final rule.

Issue: Allow sources with overlapping CEMS regulations to comply 

with existing QA/QC plans or 40 CFR 75 Appendices A and B.

The petitioners (CIBO, CMI) requested that the EPA allow 

sources with overlapping CEMS regulations to comply with 

existing QA/QC plans or 40 CFR 75 Appendices A and B. The EPA is 

denying this petition because it is not of central relevance to 

this rulemaking.

Issue: No justification or discussion was provided on why the 

EPA selected 12 hours as the averaging time period and also why 

the EPA selected block averages instead of rolling averages.

The petitioner (Sierra Club) alleges that the EPA provided no 

justification or discussion explaining why the EPA selected 12 

hours as the averaging time period and why the EPA selected 

block averages instead of rolling averages for parameter 
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monitor. The petitioner requested that the EPA clarify that the 

averaging times for continuous parameter monitoring should be 

the same as the averaging times during the most recent 

performance test. Averaging times were open to notice and 

comment in the June 4, 2010 proposal. In the June 2010 proposal, 

we required that parameters be set based on 4-hour block

averages during the compliance test, and that continuous 

compliance be demonstrated by monitoring 12-hour block average 

values for most parameters. We selected this averaging period to 

reflect operating conditions during the performance test to 

ensure the control system is continuously operating at the same 

or better level as during a performance test demonstrating

compliance with the emission limits. Therefore, the EPA is 

denying the petition. 

Issue: The EPA position regarding treatment of “out-of-control” 

and “maintenance” periods as deviations is not supported or 

explained.

The petitioner (UARG) alleges that the EPA position 

regarding treatment of “out-of-control” and “maintenance” 

periods as deviations is not supported or explained. The 

petitioner requested that the EPA revise the definition of 

“deviation” to be consistent with how deviation is treated with 

respect to CO CEMS and CPMS. The EPA is denying the petition. 
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The definition of deviations was open to notice and comment in 

the June 4, 2010 proposal.

Issue: Require checks of pressure monitoring taps only if 

reading is abnormal.

The petitioner (CMI) requested that the EPA require checks 

of pressure monitoring taps only if reading is abnormal. The 

requirement to check pressure tap pluggage daily was open to 

notice and comment in the June 2010 proposal. In addition, the 

EPA is denying this petition because it is not of central 

relevance to this rulemaking.

Issue: The EPA has not sufficiently correlated emission limits 

to operating parameters and should not set enforceable limits on 

maximum and minimum control device operating parameters.

The petitioners (UARG, AMP, CIBO) alleges that the EPA has 

not sufficiently correlated emission limits to operating 

parameters and requested the EPA not to set enforceable limits 

on maximum and minimum control device operating parameters. One 

petitioner (CIBO) requested that the rule should allow sources 

to set their own ESP secondary voltage requirement based on load 

and coal quality since power consumption by an ESP is influenced 

by factors other than operating load, including ESP design, 

amount of PM collected, and resistivity of the PM. Other 

petitioners (UARG and AMP) also indicate that the limits set on 

control devices inhibit the flexibility to operate control 
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devices with a margin of safety. The EPA is denying the 

petition. Operating limits were open to notice and comment in 

the June 4, 2010 proposal.

Issue: The EPA should delay incorporating PS 17 in this rule 

until the revisions for PS 17 are completed.

The petitioner (UARG) requested that the EPA delay 

incorporating PS 17 in this rule, which outlines how to select 

and install CPMS, until the revisions for PS 17 are completed.

The EPA is denying this petition. The final rule did not 

incorporate PS 17, or any other PS, in the provision regarding 

selection and installation of CPMS and ongoing quality assurance 

of data from CPMS. Comments related to revising PS 17 are 

outside the scope of this rulemaking. (RTC document, Chapter 11, 

EPA-HQ-OAR-2002-0058-3289, DCN EPA-HQ-OAR-2002-0058-2960.1, 

excerpt 150).

Issue: The EPA should not set an enforceable operating limit on 

opacity.

The petitioner (UARG) alleged that there is insufficient 

correlation between opacity and PM emissions and requested that 

the EPA not set an enforceable operating limit on opacity. The 

EPA is denying the petition. The EPA proposed opacity limits in 

the June 4, 2010 proposal and the petitioner therefore had the 

opportunity to comment on the proposed limits, including 

comments requesting that no limit be established. 
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Issue: Update outdated BLDS Guidance.

The petitioner (UARG) requested that the EPA update the

outdated BLDS Guidance that is currently incorporated by 

reference. The EPA is denying this petition. The current 

guidance document is the most recent guidance available and 

comments related to revising the guidance document are outside 

the scope of this rulemaking. (RTC document, Chapter 11, EPA-HQOAR-2002-0058-3289, DCN EPA-HQ-OAR-2002-0058-2997.1, excerpt 

10).

Issue: The EPA should reconsider emission limits for HCl on 

coal-fired boilers using a hot-side ESP for particulate control.

The petitioners (MSU, PSU, Purdue, Citizens Thermal Energy) 

requested that the EPA reconsider emission limits for HCl on 

coal-fired boilers using a hot-side ESP for particulate control. 

The petitioners are unaware of any HCl control devices that are 

compatible with a hot-side ESP. The EPA is denying the petition. 

The basis for subcategorization was subject to notice and 

comment. The EPA did not propose a separate subcategory for such 

units, and the petitioner could have commented recommending that 

the agency do so. (75 FR 32012, 76 FR 15617-18, 76 FR 80607) 

Further, the EPA disagrees with the petitioner that the 

subcategories could be based on the level of controls installed 

on the unit.
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Issue: The EPA should change electronic reporting requirements 

to avoid WebFIRE and ERT shortcomings.

The petitioner (UARG) requested that the EPA change the

electronic reporting requirements to avoid WebFIRE and ERT 

shortcomings. The petitioner requested that to meet the EPA’s

obligations under the Paperwork Reduction Act the EPA specify 

each individual data item requested in the ERT. The petitioner 

also requests that the EPA explain how the ERT electronic 

signature mechanisms will meet the requirements of the CrossMedia Electronic Reporting Rule.

The EPA is denying the petition because it does not 

demonstrate that it was impracticable to comment on this issue. 

The EPA proposed to require the use of the ERT and WebFIRE, and 

the petitioner therefore had the opportunity to comment on any 

concerns with the proposed approach.

Issue: Eliminate gas curtailment notification requirements or 

adjust the frequency of these notifications to be consistent 

with the reporting requirements in the Title V program.

The petitioner (AIF) requested that the EPA eliminate the 

gas curtailment notification requirements or adjust the 

frequency of these notifications to be consistent with the semiannual reporting requirements in the Title V program. The EPA is

denying the petition. Reporting requirements were open to notice 

and comment in the June 4, 2010 proposal.
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Issue: Allow facilities to become area or synthetic minor 

sources instead of installing controls.

The petitioner (GPSP) requested that the EPA allow 

facilities to become area or synthetic minor sources instead of 

installing controls. The EPA is denying the petition. Whether or 

not sources elect to become area or synthetic minor sources is 

not of central relevance to this rulemaking, as nothing in this 

rule affects whether or how a source can become a synthetic 

minor source (RTC document, EPA-HQ-OAR-2002-0058-3289, Volume 1, 

DCN EPA-HQ-OAR-2002-0058-2176.2, excerpt 4).

VI. Impacts of This Final Rule

A. What are the incremental air impacts?

Table 4 of this preamble illustrates, for each basic fuel 

subcategory, the total emissions reductions achieved by the 

final amended rule (i.e., the difference in emissions between a 

boiler or process heater controlled to the amended floor level 

of control and boilers or process heaters at the current 

baseline) for new and existing sources. Nationwide emissions of 

selected HAP (i.e., HCl, HF, mercury, metals, and VOC) will be 

reduced by 44,300 tpy. This is an incremental increase of 4,000

tpy in HAP reductions compared to the estimates in the March 

2011 final rule. This increase is due mainly to changes in the 

inventory (336 units were added since the March 2011 inventory). 

Excluding the changes in the inventory, the amendments to the 
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regulatory provisions themselves resulted in a decrease of 1,100

tpy of estimated reductions, part of this incremental reduction 

in HAP is contributed to edits to the baseline emission data 

received since the March 2011 final rule, as well as changes to 

the subcategories and emission limits as a result of this 

amended rule. The amendments to the final rule are expected to 

result in an additional 4,600 tpy of reductions in HCl 

emissions. The amendments are also expected to have a modest 

effect on mercury, estimated to range from a slight decrease of 

0.12 tpy up to a slight increase of 0.96 tpy in emission 

reductions as a result of the changes to the regulatory 

requirements. Reductions in emissions of filterable PM will 

decrease by 18,500 tpy due to the final amended rule. Reductions 

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

beryllium, cadmium, chromium, cobalt, lead, manganese, nickel, 

and selenium) will decrease by 260 tpy. In addition, the 

amendments are estimated to result in an additional 50,100 tpy

of reductions in SO2 emissions. A discussion of the methodology 

used to estimate emissions, emissions reductions, and 

incremental emission reductions is presented in “Revised (August

2012) Methodology for Estimating Cost and Emission Impacts for 

Industrial, Commercial, and Institutional Boilers and Process 

Heaters NESHAP - Major Source” in the docket.
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TABLE 4. Summary of Total Emissions Reductions for the Final 

Amended Rule (tons/yr)

Source Subcategory HCl PM Non 

Mercury 

Metalsa

Mercury

b VOC

Existing 

Units

Limited Use 1 2 0.42 2.1E-04 0.48

Solid units 36,737 21,367 147 0.4 to 

1.5

1,619

Liquid units 2,143 9,434 2,315 0.9 to 

1

620

NonContinental 

Liquid units

35 3 1 0.01 to 

0.02

23

Gas 1

(NG/RG) 

units

20 117 0.3 0.01 88

Gas 1 

Metallurgica

l Furnaces

0.4 3 0.02 0.001 27

Gas 2 

(other)units

4 8 0.06 3.8E03 to 

4.6E-03

40

New 

Units

Solid units 0 351 5 0.02 0

Liquid units 0 0 0 0 0

Gas 1 units 0 0 0 0 0

Gas 1 

Metallurgica

l Furnaces

0 0 0 0 0

Gas 2 

(other) 

units

0 0 0 0 0

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

cobalt, lead, manganese, nickel, and selenium.

b Mercury reductions are presented as a range due to adjustments 

on reported fractions and limits of detection. See memorandum 

entitled "Revised (March 2012) Methodology for Estimating Cost 

and Emissions Impacts for Industrial, Commercial, Institutional 
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Boilers and Process Heaters National Emission Standards for 

Hazardous Air Pollutants – Major Source" for a description of 

the two methods for estimating mercury reductions.

B. What are the incremental water and solid waste impacts?

The EPA estimated the additional water usage that would 

result from installing wet scrubbers to meet the amended 

emission limits for HCl would be 556 million gallons per year 

for existing sources compared to the current baseline. In 

addition to the increased water usage, an additional 160 million 

gallons per year of wastewater would be produced for existing 

sources. Only half of these incremental changes are due to 

changes in the regulatory provisions. The other half is due to 

changes in the number of identified existing units and projected 

new units. The annual costs of treating the additional 

wastewater are $1.2 million. These additional costs are 

accounted for in the incremental control cost estimates.

The EPA estimated the additional solid waste that would 

result due to the amendments to be 138,000 tpy, with nearly all 

due to changes in the regulatory provisions. Solid waste is 

generated from flyash and dust captured in PM and mercury 

controls as well as from spent carbon that is injected into 

exhaust streams or used to filter gas streams. The costs of 

handling the additional solid waste generated are $5.8 million. 

These costs are also accounted for in the incremental control 

costs estimates.
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A discussion of the methodology used to estimate 

incremental impacts is presented in “Revised (August 2012) 

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 incremental energy impacts?

The EPA estimated that the March 2011 final rule would 

result in an increase of about 1.4 billion kWh/yr in national 

energy usage 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 

final rule. The amendments are expected to decrease energy usage 

by a net 143 million kWh/yr compared to the March 2011 rule.

These reductions are driven by the regulatory provisions of 

these amendments. Additionally, the EPA expects these amendments 

will result in a decrease of 4.4 million MMBtu/yr in fuel 

savings, compared with the estimates in the March 2011 final 

rule.

D. What are the incremental cost impacts?

For these final amendments, we estimated the incremental 

difference between the national costs impacts for the final 

amended rule and the March 2011 final rule. First, we determined 

the control measures, work practices, and monitoring and testing

requirements that would be required by boilers and process 
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heaters located at major source facilities to comply with the 

final amended rule. To estimate the national cost impacts of the 

final amended rule for existing sources, we used the identical 

methodology used to estimate the cost impacts for the March 2011 

final rule with one exception. In this revised analysis, it was 

assumed that several liquid fuel units that reported natural gas 

firing capability would switch to natural gas as a compliance 

option instead of installing add-on controls to demonstrate 

compliance with the emission limits. Thus, the only costs to 

these units would be the tune-up work practice costs. A 

discussion of the methodology used to estimate cost impacts is 

presented in “Revised (August 2012) Methodology for Estimating 

Cost and Emission Impacts for Industrial, Commercial, and 

Institutional Boilers and Process Heaters NESHAP - Major Source” 

in the docket.

The resulting total national cost impact of the final 

amended rule is $4.7 billion in capital expenditures and $1.5

billion per year in total annual costs, considering fuel 

savings. The total capital expenditures are slightly lower than 

estimated for the March 2011 final rule, but the total annual 

costs are slightly higher than estimated for the March 2011 

final rule. See 76 FR 15651. The total capital and annual costs 

include costs for control devices, work practices, testing and 

monitoring. 
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In order to determine the incremental cost impacts of the 

amended requirements and emission limits, we first estimated the 

cost impacts of the additional existing boilers and process 

heaters added to the Boiler MACT inventory database since 

promulgation of the March 2011 final rule and the revised number 

of new boilers and process heaters that could be potentially 

constructed. Since the March 2011 final rule, we became aware of 

72 major source facilities that were not previously in the 

Boiler MACT inventory database. Adding the boilers and process 

heaters located at these newly identified major source 

facilities resulted in 73 additional coal-fired units, 32 

additional biomass-fired units, 82 additional oil-fired units, 

and 149 additional gas-fired units. Our revised number of new 

boilers and process heaters included 82 additional biomass 

units, 1,728 additional gas 1 units and 13 fewer liquid units.

The resulting cost impact for these additional existing and 

new boilers and process heaters is $1.0 billion in capital 

expenditures and $0.31 billion per year in total annual costs, 

considering fuel savings. 

Therefore, discounting the added costs for the additional 

boilers and process heaters included in the costs analysis, the 

estimated incremental cost impacts for these amended 

requirements on existing and new boilers and process heaters are 

$1.0 billion in capital expenditures and $0.13 billion per year 
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in total annual costs less than the costs estimated in the March 

2011 rule.

Table 5 of this preamble shows the total capital and annual 

cost impacts of the final amended rule for each subcategory. 

Costs include testing and monitoring costs, but not 

recordkeeping and reporting costs.

TABLE 5. Summary of Total Capital and Annual Costs for New and 

Existing Sources for the Final Amended Rule

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 621 2,554 46 904

Biomass 

units

502 405 29 109

Heavy 

Liquid 

units

319 761 5.4 221

Light 

Liquid 

units

615 712 4.2 166

NonContinental 

Liquid 

units

21 62 0.8 17

Gas 1 

(NG/RG) 

units

11,929 77 0.9 (295) 

Gas 2 

(other) 

units

129 138 2.3 58
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Energy 

Assessmen

t

ALL 1,700

(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.

Potential control device cost savings and increased 

recordkeeping and reporting costs associated with the emissions 

averaging provisions in the final rule are not accounted for in 

either the capital or annualized cost estimates.

A discussion of the methodology used to estimate cost 

impacts is presented in “Revised (August 2012) 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 final amended 

rule using the methodology that was discussed in the March 2011 

final rule RIA and in the preamble to the March 2011 final rule. 
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See FR 76 15651. The market impact results are very similar to 

the results presented in the March 2011 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 results for sales tests for small businesses were somewhat 

reduced than those calculated for the March 2011 final rule. 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 3 percent for this final amended rule and 

the median was 0.2 percent for the RIA and also 0.2 percent for 

this final amended rule. The number of parent companies with 

sales tests exceeding 3 percent dropped from 8 in the RIA to 5

for this final amended 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 final amended rule

is minimal. In the RIA for the March 2011 final rule, we

estimated employment changes ranging between -3,100 to +6,500 

employees, with a central estimate of +1,700. For this final 

amended rule we estimate employment changes ranging between -
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2,600 to +5,400 employees, with a central estimate of +1,400. 

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).

F. What are the benefits of this final rule? 

We calculated health benefits using the methodology 

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

We incorporated the revised emission reductions estimated for 

this reconsideration final rule into the analysis. We were 

unable to estimate the benefits from reducing exposure to HAP 

and ozone, ecosystem impairment and visibility impairment, 

including reducing 180,000 tons of carbon monoxide, 39,000 tons 

of HCl, 500 tons of HF, 2,500 tons of other metals and 3,100 to 

5,300 pounds of mercury. Please refer to the full description of 

the unquantified benefits as well as technical details of the 

analysis and its limitations and uncertainties in the final 

Boiler RIA (March 2011). These monetized benefits are 

approximately 23 percent higher than the March 2011 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 final regulatory action to be $27 billion to $67 billion 

at a 3 percent discount rate and $25 to $61 billion at a 7 

percent discount rate. All estimates are for the implementation
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year (2015) in 2008$. A summary of the monetized benefits 

estimates at discount rates of 3 percent and 7 percent is 

provided in Table 7 of this preamble. A summary of the avoided 

health incidences is provided in Table 8 of this preamble.

Table 7. Summary of the Monetized Benefits Estimates for the 

Final Boiler MACT (millions of 2008$)a, b

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 14,139 $1,200 to $2,900 $1,100 to $ $2,700

SO2 563,358 $26,000 to $64,000 $24,000 to $61,000

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

aAll 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 because the scientific evidence is not yet sufficient to 

allow differentiation of effect estimates by particle type. 

Benefits from reducing hazardous air pollutants (HAP) are not 

included. These estimates do not include energy disbenefits 

valued at $24 million (using a 3 percent discount rate). These 

benefits reflect existing boilers and new boilers anticipated to 

come online by 2015.

b There are some slight differences in the emission reductions 

used in the RIA and those used in the air impacts section of 

this preamble due to some late changes in the data that were 

received after the RIA was completed. Refer to the memoranda 

“Revised (August 2012) Methodology for Estimating Cost and 

Emission Impacts for Industrial, Commercial, and Institutional 

Boilers and Process Heaters NESHAP - Major Source” for a 

discussion of the differences. 

Table 8. Summary of the Avoided Health Incidences for the Final 

Boiler MACTa

Avoided Health 

Incidences

Premature Mortality 3,000-7,900

Morbidity
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Avoided Health 

Incidences

Chronic Bronchitis 2,000

Acute Myocardial Infarction 5,000

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

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

rounded to two significant figures. All fine particles are 

assumed to have equivalent health effects because the scientific 

evidence is not yet sufficient to allow differentiation of 

effect estimates by particle type. Benefits from reducing HAP 

are not included. These benefits reflect existing boilers and 

new boilers anticipated to come online by 2015.

G. What are the incremental secondary air impacts?

For units adding controls to meet the amended emission 

limits, we anticipate very minor secondary air impacts. The 

combustion of fuel needed to generate additional electricity 

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

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

covered by capped emissions trading programs and methodological 

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

we do not estimate an increase in secondary air impacts for this 

final rule from additional electricity demand. We do estimate 

greenhouse gas impacts, which result from increased electricity 
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consumption, to be 859,200 tpy from existing units and 79,700 

tpy from new units. This is 19,200 tpy less than the estimated 

greenhouse gas impacts associated with the March 2011 final 

rule.

VII. 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 OMB for review under Executive Orders 12866 and 13563 (76 FR 

3821, January 21, 2011) and any changes made in response to the 

OMB recommendations have been documented in the docket for this 

action.

The EPA did prepare a new RIA for this action. The EPA 

prepared an assessment of the changes in the costs and benefits 

of this final rule compared to the costs and benefits associated 

with the March 21, 2011, final rule. Overall, the costs and 
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impacts are estimated to be similar to the costs and impacts 

associated with the previous final rule, although the 

distribution is somewhat different and the number of affected 

units in the inventory has increased by about 302 units. When 

comparing the costs using only those sources that were part of 

the final rule inventory, the costs have decreased. The EPA reran the multimarket model to assess changes in economic impacts, 

and this analysis confirmed that the overall economic impacts 

are similar to the previous final rule. The benefits are 

projected to increase by about 20 percent because of the 

increase in the estimated SO2 reductions. A summary of the costs 

and benefits of the previous final rule is provided in the 

preamble to the previous final rule (see 76 FR 15658) and the 

detailed analysis for the previous final rule is provided in the 

RIA for the previous final rule. In addition, memoranda are 

provided in the docket to document the changes in costs, 

economic impacts, and benefits associated with this final rule, 

shown in Table 9. 

TABLE 9. SUMMARY OF THE MONETIZED BENEFITS, SOCIAL COSTS AND NET 

BENEFITS FOR THE FINAL BOILER MACT RECONSIDERATION IN 2015 

(MILLIONS OF 2008$)1

3 percent Discount 

Rate

7 percent Discount 

Rate

Total Monetized 

Benefits2 $27,000 to $67,000 $24,000 to $61,000

Total Social Costs3 $1,400 to $1,600 $1,400 to $1,600
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3 percent Discount 

Rate

7 percent Discount 

Rate

Net Benefits $26,000 To $65,000 $23,200 To $59,000

Non-monetized 

Benefits

Health effects from exposure to HAP 

(39,000 tons of HCl, 500 tons of HF, 3,100 

to 5,300 tons of mercury, and 2,500 tons 

of other metals)

Health effects from exposure to other 

criteria pollutants (180,000 tons of CO 

and 570,000 tons of SO2) 

Ecosystem effects 

Visibility impairment 

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

rounded to two significant figures. 

2 The total monetized co-benefits reflect the human health 

benefits associated with reducing exposure to PM2.5 through 

reductions of PM2.5 precursors such as directly emitted 

particles, SO2, and NOx and reducing exposure to ozone through 

reductions of VOC. It is important to note that the monetized 

benefits include many but not all health effects associated 

with PM2.5 exposure. Monetized benefits are shown as a range 

from Pope et al. (2002) to Laden et al. (2006). These models 

assume that all fine particles, regardless of their chemical 

composition, are equally potent in causing premature mortality 

because the scientific evidence is not yet sufficient to 

support the development of differential effects estimates by 

particle type. These estimates include the energy disbenefits 

valued at $24 million (using the 3 percent discount rate), 

which do not change the rounded totals. CO2-related disbenefits 

were calculated using the “social cost of carbon”, which is 

discussed further in the RIA.

3 The methodology used to estimate social costs for one year in 

the multimarket model using surplus changes results in the same 

social costs for both discount rates.

B. Paperwork Reduction Act

The OMB has approved the information collection 

requirements contained in the March 21, 2011 final rule under 

the provisions of the Paperwork Reduction Act, 44 U.S.C. 3501 et
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seq. and has assigned OMB control number 2060-0551. The EPA has 

updated the supporting statement to reflect the final inventory 

and burden estimates associated with this action since some of 

the monitoring, recordkeeping and reporting requirements have 

changed since the March 21, 2011 final rule. These revised 

estimates have been sent to OMB for review and approval.

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 final rule will require maintenance inspections of the 

control devices but will 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 
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gas supply emergencies. The recordkeeping requirements require 

only the specific information needed to determine compliance.

The revised 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 

$95.3 million which is about the same as estimated for the March 

2011 final rule. This includes 323,130 labor hours per year at a 

total labor cost of $30.6 million per year, and total non-labor 

capital costs of $64.7 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 VI.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 100,608 hours per year at a total labor cost of $5.3 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 
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displays a currently valid OMB control number. The OMB control 

numbers for the EPA's regulations in 40 CFR are listed in 40 CFR 

part 9. In addition, the EPA is amending the table in 40 CFR 

part 9 of currently approved OMB control numbers for various 

regulations to list the regulatory citations for the information 

requirements contained in this final rule.

C. Regulatory Flexibility Act

The RFA generally requires an agency to prepare a 

regulatory flexibility analysis of any rule subject to notice 

and comment rulemaking requirements under the Administrative 

Procedure Act or any other statute unless the agency certifies 

that the rule will not have a significant economic impact on a 

substantial number of small entities.1 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. 

 

1

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 not-for-profit enterprise which is independently 

owned and operated and is not dominant in its field.
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§605(c). This final rule is closely related to the final major 

source rule, which the EPA signed on February 21, 2011. The EPA 

prepared a final regulatory flexibility analyses in connection 

with the major source rule. Therefore, pursuant to §605(c), the 

EPA is not required to complete a final 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.

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 final 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 final action would 

decrease capital and annualized costs on small entities by about 

3 percent and 10 percent, respectively, relative to the closely 

related final rule. 

D. Unfunded Mandates Reform Act
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Title II of the UMRA of 1995, 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. Federal agencies must 

also develop a plan to provide notice to small governments that 

might be significantly or uniquely affected by any regulatory 

requirements. The plan must enable officials of affected small 

governments to have meaningful and timely input in the 

development of the EPA regulatory proposals with significant 

Federal intergovernmental mandates and must inform, educate, and 

advise small governments on compliance with the regulatory 

requirements.

Both this rule and the March 21, 2011 final rule contain a 

federal mandate that may result in expenditures of $100 million 

or more for state, local and tribal governments, in the 

aggregate, or the private sector in any one year. Accordingly, 

the EPA prepared under section 202 of the UMRA a written 

statement for the final rule. This final rule also contains a 

federal mandate that may result in expenditures of $100 million 

or more for state, local, and tribal governments, in the 

aggregate, or the private sector in any one year. The discussion 

below has been updated to reflect the changes.

1. Statutory Authority
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As discussed in section I of this preamble, the statutory 

authority for this final 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 boilers and process heaters located at major sources of 

HAP emissions.

2. Social Costs and Benefits

The regulatory impact analysis prepared for the March 21, 

2011 final rule, which we have revised for this final 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)” and in the 

“Regulatory Impact Results for the Reconsideration Final Rule 

for National Emission Standards for Hazardous Air Pollutants for 

Industrial, Commercial, and Institutional Boilers and Process 

Heaters at Major Sources” in the docket. Based on estimated 

compliance costs associated with this final rule and the 

predicted change in prices and production in the affected 
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industries, the estimated social costs of this rule are $1.4 to 

1.6 billion (2008 dollars).

It is estimated that 3 years after implementation of this 

final rule, HAP would be reduced by 45,000 tpy, including 

reductions in HCl, hydrogen fluoride, metallic HAP including 

mercury, and several other organic HAP from boilers and process 

heaters. Studies have determined a relationship between exposure 

to these HAP and the onset of cancer, however, the agency is 

unable to provide a monetized estimate of the HAP benefits at 

this time. In addition, there are significant annual reductions 

in fine particulate matter (PM2.5) and in SO2 that would occur, 

including 25 thousand tons of PM2.5 and 558 thousand tons of SO2.

These reductions occur within 3 years after the implementation 

of the final 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)

are 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 worklost days (i.e., days when employees are unable to work). While 

we are unable to monetize the benefits associated with the HAP 

emissions reductions, we are able to monetize the benefits 

associated with the PM2.5 and SO2 emissions reductions. For SO2
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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 final regulatory 

action 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 final rule and any disproportionate budgetary 

effects. Our estimates of the future compliance costs of the 

rule are discussed previously in this preamble.

We do not believe that there will be any disproportionate 

budgetary effects of this final rule on any particular areas of 
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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 final

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 final rule is 

presented in the “Regulatory Impact Analysis for the Final

Industrial Boilers and Process Heaters MACT (2011)” and a

memoranda that are included in the docket, entitled 

“Regulatory Impact Results for the Reconsideration Final Rule

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 

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 
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output, and little impact on communities that may be affected by 

this final 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 final rule. We consulted 

with state and local air pollution control officials during the 

development of the final rule. We have also held meetings on 

this final rule with many of the stakeholders from numerous 

individual companies, institutions, environmental groups, 

consultants and vendors, labor unions and other interested 

parties. We have added materials to the docket to document these 

meetings.

Consistent with section 205, 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.
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The regulatory alternative upon which the emission limits 

in this final 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 

final rule, the impacts are not expected to be significant.

Therefore, this final 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 

13132. This final 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.

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
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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.

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 to those regulatory actions that 

concern health or safety risks, such that the analysis required 

under section 5-501 of the Order has the potential to influence 

the regulation. This action is not subject to EO 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, 
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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 

recreate the RIA for this final 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 

conducted for the previous final rule. Therefore, we conclude 

that this final 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 NTTAA, Public Law No. 104-113, 12(d) 

(15 U.S.C. 272 note) directs the EPA to use VCS in its 

regulatory activities unless to do so would be inconsistent with 

applicable law or otherwise impractical. VCS are technical 

standards (e.g., materials specifications, test methods, 

sampling procedures, and business practices) that are developed 

or adopted by VCS bodies. NTTAA directs the EPA to provide 

Congress, through the OMB, explanations when the agency decides 

not to use available and applicable VCS. 

This action does not involve any new technical standards

from those contained in the March 21, 2011 final rule. 
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Therefore, the EPA did not consider the use of any VCS. See 76 

FR 15660-15662 for the NTTAA discussion in the March 21, 2011 

final rule.

J. Executive Order 12898: Federal Actions to Address 

Environmental Justice in Minority Populations and Low-Income 

Populations

Executive Order 12898 (59 FR 7629, February 16, 1994) 

establishes federal executive policy on environmental justice. 

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 the 

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 previous final rule, 

while the amendments are somewhat less stringent for some 
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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 previous final rule are still valid. Therefore, the EPA 

has determined this final rule will not have disproportionately 

high and adverse human or environmental effects on minority or 

low-income populations.

K. Congressional Review Act

The Congressional Review Act, 5 U.S.C. 801 et seq., as

added by the Small Business Regulatory Enforcement Fairness Act 

of 1996, generally provides that before a rule may take effect, 

the agency promulgating the rule must submit a rule report, 

which includes a copy of the rule, to each House of the Congress 

and to the Comptroller General of the United States. EPA will 

submit a report containing this final rule and other required 

information to the U.S. Senate, the U.S. House of

Representatives, and the Comptroller General of the United 

States prior to publication of the rule in the Federal Register. 

A major rule cannot take effect until 60 days after it is

published in the Federal Register. This action is a “major rule”

as defined by 5 U.S.C. 804(2). This rule will be effective 

[INSERT DATE 60 DAYS AFTER PUBLICATION IN THE FEDERAL REGISTER].

List of Subjects in 40 CFR Part 63
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Environmental protection, Administrative practice and 

procedure, Air pollution control, Hazardous substances, 

Incorporation by reference, Intergovernmental relations, 

Reporting and Recordkeeping requirements.

Dated:

Lisa P. Jackson,

Administrator.
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For the reasons cited in the preamble, title 40, chapter I, 

part 63 of the Code of Federal Regulations is amended as 

follows:

PART 63--[AMENDED]

1. The authority for part 63 continues to read as 

follows:

Authority: 42 U.S.C. 7401, et seq.

2. Remove subpart DDDDD, as published at 69 FR 55253 on 

September 13, 2004, from the code of federal regulations 

pursuant to the vacatur of that rule issued at NRDC v. EPA, 489 

F.3d at 1257–58 (DC Cir. 2007). 

3. The delay published at 76 FR 28662, on May 18, 2011, is 

lifted.

Subpart A—[Amended]

4. Section 63.14 is amended by:

a. Revising paragraphs (b)(19), (b)(23), (b)(35), (b)(40), 

(b)(69), and (b)(70).

b. Removing and reserving paragraphs (b)(53).

c. Adding paragraphs (b)(46), (b)(55), and (b)(76) through 

(83).

d. Adding paragraphs (p)(12) through (20).

e. Adding paragraph (r). 

f. Removing Editorial Note 2 and the corresponding text at 

the end of Section 63.14.
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The revisions read as follows: 

§63.14 Incorporations by reference.

* * * * *

(b) * * *

(19) ASTM D95–05 (Reapproved 2010), Standard Test Method 

for Water in Petroleum Products and Bituminous Materials by 

Distillation, approved May 1, 2010, IBR approved for 

§63.10005(i) and table 6 to subpart DDDDD.

* * * * *

(23) ASTM D4006–11, Standard Test Method for Water in Crude 

Oil by Distillation, including Annex A1 and Appendix X1, 

approved June 1, 2011, IBR approved for §63.10005(i) and table 6 

to subpart DDDDD.

* * * * *

(35) ASTM D6784-02 (Reapproved 2008) Standard Test Method 

for Elemental, Oxidized, Particle-Bound and Total Mercury in 

Flue Gas Generated from Coal-Fired Stationary Sources (Ontario 

Hydro Method), approved April 1, 2008, IBR approved for table 1 

to subpart DDDDD of this part, table 2 to subpart DDDDD of this 

part, table 5 to subpart DDDDD, table 11 to subpart DDDDD of 

this part, table 12 to subpart DDDDD of this part, table 13 to 

subpart DDDDD of this part, and table 4 to subpart JJJJJJ of 

this part.
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* * * * *

(40) ASTM D396–10 Standard Specification for Fuel Oils, 

approved October 1, 2010, IBR approved for §63.7575 and 

§63.11237.

* * * * *

(46) ASTM D4606–03(2007), Standard Test Method for 

Determination of Arsenic and Selenium in Coal by the Hydride 

Generation/Atomic Absorption Method, approved October 1, 2007, 

IBR approved for table 6 to subpart DDDDD.

(55) ASTM D6357–11, Test Methods for Determination of Trace 

Elements in Coal, Coke, and Combustion Residues from Coal 

Utilization Processes by Inductively Coupled Plasma Atomic 

Emission Spectrometry, approved April 1, 2011, IBR approved for 

table 6 to subpart DDDDD.

* * * * *

(69) ASTM D4057–06 (Reapproved 2011), Standard Practice for 

Manual Sampling of Petroleum and Petroleum Products, including 

Annex A1, approved June 1, 2011, IBR approved for §63.10005(i) 

and table 6 to subpart DDDDD.

(70) ASTM D4177–95 (Reapproved 2010), Standard Practice 

for Automatic Sampling of Petroleum and Petroleum Products, 

including Annexes A1 through A6 and Appendices X1 and X2, 

approved May 1, 2010, IBR approved for §63.10005(i) and table 6 

to subpart DDDDD.
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* * * * *

(76) ASTM D6751–11b, Standard Specification for Biodiesel 

Fuel Blend Stock (B100) for Middle Distillate Fuels, approved 

July 15, 2011, IBR approved for §63.7575 and §63.11237.

(77) ASTM D975-11b, Standard Specification for Diesel Fuel 

Oils, approved December 1, 2011, IBR approved for §63.7575.

(78) ASTM D5864-11 Standard Test Method for Determining 

Aerobic Aquatic Biodegradation of Lubricants or Their 

Components, approved March 1, 2011, IBR approved for table 6 to 

subpart DDDDD.

(79) ASTM D240-09 Standard Test Method for Heat of 

Combustion of Liquid Hydrocarbon Fuels by Bomb Calorimeter, 

approved July 1, 2009, IBR approved for table 6 to subpart 

DDDDD.

(80) ASTM D4208-02(2007) Standard Test Method for Total 

Chlorine in Coal by the Oxygen Bomb Combustion/Ion Selective 

Electrode Method, approved May 1, 2007, IBR approved for table 6 

to subpart DDDDD.

(81) ASTM D5192-09 Standard Practice for Collection of Coal 

Samples from Core, approved June 1, 2009, IBR approved for table 

6 to subpart DDDDD.

(82) ASTM D7430-11ae1, Standard Practice for Mechanical 

Sampling of Coal, approved October 1, 2011, IBR approved for 

table 6 to subpart DDDDD.
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(83) ASTM D6883-04, Standard Practice for Manual Sampling 

of Stationary Coal from Railroad Cars, Barges, Trucks, or 

Stockpiles, approved June 1, 2004, IBR approved for table 6 to 

subpart DDDDD.

* * * * *

(p) * * *

(12) Method 5050 (SW-846-5050), Bomb Preparation Method for 

Solid Waste, Revision 0, September 1994, in EPA Publication No. 

SW-846, Test Methods for Evaluating Solid Waste, 

Physical/Chemical Methods, Third Edition IBR approved for table 

6 to subpart DDDDD.

(13) Method 9056 (SW-846-9056), Determination of Inorganic 

Anions by Ion Chromatography, Revision 1, February 2007, in EPA 

Publication No. SW-846, Test Methods for Evaluating Solid Waste, 

Physical/Chemical Methods, Third Edition, IBR approved for table 

6 to subpart DDDDD.

(14) Method 9076 (SW-846-9076), Test Method for Total 

Chlorine in New and Used Petroleum Products by Oxidative 

Combustion and Microcoulometry, Revision 0, September 1994, in 

EPA Publication No. SW-846, Test Methods for Evaluating Solid 

Waste, Physical/Chemical Methods, Third Edition, IBR approved 

for table 6 to subpart DDDDD.

(15) Method 1631 Revision E, Mercury in Water by Oxidation, 

Purge and Trap, and Cold Vapor Atomic Absorption Fluorescence 
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Spectrometry, Revision E, EPA-821-R-02-019, August 2002, IBR 

approved for table 6 to subpart DDDDD.

(16) Method 200.8, Determination of Trace Elements in 

Waters and Wastes by Inductively Coupled Plasma – Mass 

Spectrometry, Revision 5.4, 1994, IBR approved for table 6 to 

subpart DDDDD.

(17) Method 6020A (SW-846-6020A), Inductively Coupled

Plasma-Mass Spectrometry, Revision 1, February 2007, in EPA 

Publication No. SW-846, Test Methods for Evaluating Solid Waste, 

Physical/Chemical Methods, Third Edition, IBR approved for table 

6 to subpart DDDDD.

(18) Method 6010C (SW-846-6010C), Inductively Coupled 

Plasma-Atomic Emission Spectrometry, Revision 3, February 2007, 

in EPA Publication No. SW-846, Test Methods for Evaluating Solid 

Waste, Physical/Chemical Methods, Third Edition, IBR approved 

for table 6 to subpart DDDDD.

(19) Method 7060A (SW-846-7060A), Arsenic (Atomic 

Absorption, Furnace Technique), Revision 1, September 1994, in 

EPA Publication No. SW-846, Test Methods for Evaluating Solid 

Waste, Physical/Chemical Methods, Third Edition, IBR approved 

for table 6 to subpart DDDDD.

(20) Method 7740 (SW-846-7740), Selenium (Atomic 

Absorption, Furnace Technique), Revision 0, September 1986, in 

EPA Publication No. SW-846, Test Methods for Evaluating Solid 
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Waste, Physical/Chemical Methods, Third Edition, IBR approved 

for table 6 to subpart DDDDD.

* * * * *

(r) The following material is available for purchase from 

the Technical Association of the Pulp and Paper Industry 

(TAPPI), 15 Technology Parkway South, Norcross, GA 30092, (800) 

332–8686, http://www.tappi.org.

(1) TAPPI T 266, Determination of Sodium, Calcium, Copper, 

Iron, and Manganese in Pulp and Paper by Atomic Absorption 

Spectroscopy (Reaffirmation of T 266 om-02), Draft No. 2, July 

2006, IBR approved for table 6 to subpart DDDDD.

(2) [Reserved]

Subpart DDDDD—[Amended]

5. Section 63.7485 is revised to read as follows: 

§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 §63.7575.

6. Section 63.7490 is amended by adding paragraph (e) to 

read as follows:
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§63.7490 What is the affected source of this subpart?

* * * * *

(e) An existing electric utility steam generating unit 

(EGU) that meets the applicability requirements of this subpart 

after the effective date of this final rule due to a change 

(e.g., fuel switch) is considered to be an existing source under 

this subpart.

7. Section 63.7491 is amended by:

a. Revising the introductory paragraph.

b. Revising paragraph (a).

c. Revising paragraph (c).

d. Revising paragraph (h)

e. Revising paragraph (i).

f. Revising paragraph (m).

g. Adding paragraph (n).

The revisions read as follows:

§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 (EGU) covered 

by subpart UUUUU of this part.

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

for research and development, including test steam boilers used 

to provide steam for testing the propulsion systems on military 

vessels. This does not include units that provide heat or steam 

to a process at a research and development facility.

* * * * *

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

affected source subject to another subpart of this part, such as 

boilers and process heaters used as control devices to comply 

with subparts JJJ, OOO, PPP, and U of this part.

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

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

part 61, or part 65 of this chapter provided that at least 50 

percent of the average annual heat input during any 3 

consecutive calendar years to the boiler or process heater is 

provided by regulated gas streams that are subject to another 

standard.

* * * * *

(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.

8. Section 63.7495 is amended by:

a. Revising paragraph (a).
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b. Revising paragraph (b).

c. Revising paragraph (e).

d. Adding paragraphs (f) and (g). 

§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 OF 

PUBLICATION 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 THE DATE OF PUBLICATION IN THE FEDERAL REGISTER], 

except as provided in §63.6(i).

* * * * *

(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 and are no longer subject to part 60, subparts CCCC or 

DDDD beginning on the effective date of the switch as identified 

under the provisions of §§60.2145(a)(2) and (3) or 

§§60.2710(a)(2) and (3).
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(f) If you own or operate an existing EGU that becomes 

subject to this subpart after [INSERT THE DATE OF PUBLICATION IN 

THE FEDERAL REGISTER], you must be in compliance with the 

applicable existing source provisions of this subpart on the 

effective date such unit becomes subject to this subpart.

(g) If you own or operate an existing industrial, 

commercial, or institutional boiler or process heater and would 

be subject to this subpart except for a exemption in §63.7491(i) 

that becomes subject to this subpart after [INSERT THE DATE OF 

PUBLICATION IN THE FEDERAL REGISTER], you must be in compliance 

with the applicable existing source provisions of this subpart 

within 3 years after such unit becomes subject to this subpart.

9. Section 63.7499 is amended by: 

a. Revising paragraph (d).

b. Revising paragraphs (f) through (l).

b. Adding paragraphs (p) through (u). 

§63.7499 What are the subcategories of boilers and process 

heaters?

* * * * * 

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

dried biomass/bio-based solid.

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

solid.

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

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

biomass/bio-based solid.

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

biomass/bio-based solid.

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

(k) Units designed to burn liquid fuel that are noncontinental units.

(l) Units designed to burn gas 1 fuels.

* * * * * 

(p) Units designed to burn solid fuel.

(q) Units designed to burn liquid fuel.

(r) Units designed to burn coal/solid fossil fuel.

(s) Fluidized bed units with an integrated fluidized bed 

heat exchanger designed to burn coal/solid fossil fuel.

(t) Units designed to burn heavy liquid fuel.

(u) Units designed to burn light liquid fuel.

10. Section 63.7500 is amended by:

a. Revising paragraph (a).

b. Revising paragraph (c).

c. Adding paragraph (d).
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d. Adding paragraph (e).

e. Adding paragraph (f).

§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), through (e) of this section. You must meet these 

requirements at all times the affected unit is operating, except 

as provided in paragraph (f) of this section.

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

standard in Tables 1 through 3, and 11 through 13 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 output-based emission limits, 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 and 

process heaters that generate steam. The output-based emission 

limits, in units of pounds per megawatt-hour, in Tables 1 or 2 

to this subpart are an alternative applicable only to boilers 

that generate electricity. If you operate a new boiler or 

process heater, you can choose to comply with alternative limits 

as discussed in paragraphs (a)(1)(i) through (a)(1)(iii) of this 

section, but on or after [INSERT THE DATE 3 YEARS AFTER THE DATE 
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OF PUBLICATION IN THE FEDERAL REGISTER], you must comply with 

the emission limits in Table 1 to this subpart.

(i) If your boiler or process heater commenced construction 

or reconstruction after June 4, 2010 and before May 20, 2011, 

you may comply with the emission limits in Table 1 or 11 to this 

subpart until [INSERT THE DATE 3 YEARS AFTER THE DATE OF 

PUBLICATION IN THE FEDERAL REGISTER].

(ii) If your boiler or process heater commenced 

construction or reconstruction after May 20, 2011 and before 

December 23, 2011, you may comply with the emission limits in 

Table 1 or 12 to this subpart until [INSERT THE DATE 3 YEARS 

AFTER THE DATE OF PUBLICATION IN THE FEDERAL REGISTER].

(iii) If your boiler or process heater commenced 

construction or reconstruction after December 23, 2011 and 

before [INSERT THE DATE OF PUBLICATION IN THE FEDERAL REGISTER], 

you may comply with the emission limits in Table 1 or 13 to this 

subpart until [INSERT THE DATE 3 YEARS AFTER THE DATE OF 

PUBLICATION IN THE FEDERAL REGISTER].

(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 or an alternative 
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monitoring parameter, you must apply to the EPA Administrator 

for approval of alternative monitoring under §63.8(f).

(3) At all times, you must operate and maintain any 

affected source (as defined in §63.7490), 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.

* * * * *

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

tune-up every 5 years as specified in §63.7540. They are not 

subject to the emission limits in Tables 1 and 2 or 11 through 

13 to this subpart, the annual tune-up, or the energy assessment 

requirements in Table 3 to this subpart, or the operating limits 

in Table 4 to this subpart. 

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

of less than or equal to 5 million Btu per hour in the 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.
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(e) Boilers and process heaters in the units designed to 

burn gas 1 fuels subcategory with a heat input capacity of less 

than or equal to 5 million Btu per hour must complete a tune-up 

every 5 years as specified in §63.7540. Boilers and process 

heaters in the units designed to burn gas 1 fuels subcategory 

with a heat input capacity greater than 5 million Btu per hour 

and less than 10 million Btu per hour must complete a tune-up 

every 2 years as specified in §63.7540. Boilers and process 

heaters in the units designed to burn gas 1 fuels subcategory 

are not subject to the emission limits in Tables 1 and 2 or 11 

through 13 to this subpart, or the operating limits in Table 4 

to this subpart.

(f) These standards apply at all times the affected unit is 

operating, except during periods of startup and shutdown during 

which time you must comply only with Table 3 to this subpart.

11. Section 63.7501 is amended by revising the section 

heading and the section to read as follows:

§63.7501 Affirmative Defense for Violation of Emission Standards 

During Malfunction 

In response to an action to enforce the standards set forth 

in §63.7500 you may assert an affirmative defense to a claim for 

civil penalties for violations of such standards that are caused 

by malfunction, as defined at §63.2. Appropriate penalties may 

be assessed if you fail to meet your burden of proving all of 
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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 standard, you must timely meet the reporting 

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

a preponderance of evidence that:

(1) The violation: 

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

failure of air pollution control equipment, 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) Was not part of a recurring pattern indicative of 

inadequate design, operation, or maintenance; and

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

violation occurred; and

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

(including any bypass) were minimized to the maximum extent 

practicable; and

(4) If the violation resulted from a bypass of control 

equipment or a process, then the bypass was unavoidable to 
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prevent loss of life, personal injury, or severe property 

damage; and

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

the violation on ambient air quality, the environment, and human 

health; and

(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 violation were 

documented by properly signed, contemporaneous operating logs; 

and

(8) At all times, the affected source 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 violation resulting 

from the malfunction event at issue. The analysis shall also 

specify, using best monitoring methods and engineering judgment, 

the amount of any emissions that were the result of the 

malfunction. 

(b) Report. The owner or operator seeking to assert an 

affirmative defense shall submit a written report to the 

Administrator with all necessary supporting documentation, that 
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it has met the requirements set forth in §63.7500 of this 

section. This affirmative defense report shall be included in 

the first periodic compliance, deviation report or excess 

emission report otherwise required after the initial occurrence 

of the violation of the relevant standard (which may be the end 

of any applicable averaging period). If such compliance, 

deviation report or excess emission report is due less than 45 

days after the initial occurrence of the violation, the 

affirmative defense report may be included in the second 

compliance, deviation report or excess emission report due after 

the initial occurrence of the violation of the relevant 

standard.

12. Section 63.7505 is amended by:

a. Revising paragraph (a).

b. Revising paragraph (c).

c. Revising paragraphs (d) introductory text, (d)(1) 

introductory text, and (d)(1)(iii). 

§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 the affected unit is 

operating except for the periods noted in §63.7500(f).

* * * * *
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(c) You must demonstrate compliance with all applicable 

emission limits using performance stack 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 

CPMS), where applicable. You may demonstrate compliance with the 

applicable emission limit for hydrogen chloride (HCl), mercury, 

or total selected metals (TSM) 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 TSM alternative standard or 

the HCl standard.) Otherwise, you must demonstrate compliance 

for HCl, mercury, or TSM using performance testing, if subject 

to an applicable emission limit listed in Tables 1, 2, or 11

through 13 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 
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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 

Administrator for approval upon request, a site-specific 

monitoring plan that addresses design, data collection, and the 

quality 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 sitespecific 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 CEMS or 

COMS operated according to the performance specifications 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.

* * * * *

(iii) Performance evaluation procedures and acceptance 

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

drift).
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* * * * *

13. Section 63.7510 is revised to read as follows: 

§63.7510 What are my initial compliance requirements and by what 

date must I conduct them?

(a) For each boiler or process heater that is required or 

that you elect to demonstrate compliance with any of the 

applicable emission limits in Tables 1 or 2 or 11 through 13 of 

this subpart through performance 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 each boiler or process heater that burns 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 units 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.
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(ii) When natural gas, refinery gas, or 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 

part, part 60, part 61, or part 65, 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 conduct a fuel analysis 

for mercury on gaseous fuels unless the fuel is exempted in 

paragraphs (a)(2)(i) and (ii) 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 each boiler or process heater that you elect to 

demonstrate compliance with the applicable emission limits in 

Tables 1 or 2 or 11 through 13 to this subpart for HCl, mercury, 

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

described in paragraph (a)(2)(i) and (ii) of this section are 

exempt from these fuel analysis and operating limit 

requirements. The fuels described in paragraph (a)(2)(ii) of 

this section are exempt from the chloride fuel analysis and 

operating limit requirements. Boilers and process heaters that 

use a CEMS for mercury or HCl are exempt from the performance 

testing and operating limit requirements specified in paragraph 

(a) of this section for the HAP for which CEMS are used. 

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

monoxide (CO) limit, your initial compliance demonstration for 

CO is to conduct a performance test for CO according to Table 5 

to this subpart or conduct a performance evaluation of your 

continuous CO monitor, if applicable, according to §63.7525(a). 

Boilers and process heaters that use a CO CEMS to comply with 

the applicable alternative CO CEMS emission standard listed in 

Tables 12, or 11 through 13 to this subpart, as specified in 

§63.7525(a), are exempt from the initial CO performance testing 

and oxygen concentration operating limit requirements specified 

in paragraph (a) of this section.

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

limit, your initial compliance demonstration for PM is to 

conduct a performance test in accordance with §63.7520 and Table 

5 to this subpart. 
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(e) For existing affected sources (as defined in §63.7490), 

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, 

except as specified in paragraph (j) of this section. You must 

complete an initial tune-up by following the procedures 

described in §63.7540(a)(10)(i) through (vi) no later than the 

compliance date specified in §63.7495, except as specified in 

paragraph (j) of this section. You must complete the one-time 

energy assessment specified in Table 3 to this subpart no later 

than the compliance date specified in §63.7495, except as 

specified in paragraph (j) of this section.

(f) For new or reconstructed affected sources (as defined 

in §63.7490), you must complete the initial compliance 

demonstration with the emission limits no later than [INSERT THE 

DATE 180 DAYS AFTER THE DATE OF PUBLICATION IN THE FEDERAL 

REGISTER] or within 180 days after startup of the source, 

whichever is later. If you are demonstrating compliance with an 

emission limit in Tables 11 through 13 to this subpart that is 

less stringent (that is, higher) than the applicable emission 

limit in Table 1 to this subpart, you must demonstrate 

compliance with the applicable emission limit in Table 1 no 
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later than [INSERT THE DATE 3 YEARS AND 180 DAYS AFTER THE DATE 

OF PUBLICATION IN THE FEDERAL REGISTER].

(g) For new or reconstructed affected sources (as defined 

in §63.7490), you must demonstrate initial compliance with the 

applicable work practice standards in Table 3 to this subpart 

within the applicable annual, biennial, or 5-year schedule as 

specified in §63.7540(a) following the initial compliance date 

specified in §63.7495(a). 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 (as defined in §63.7490) that 

ceased burning solid waste consistent with §63.7495(e) and for 

which the 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 complete all compliance demonstrations for this 

subpart before you commence or recommence combustion of solid 

waste.

(i) For an existing EGU that becomes subject after [INSERT 

THE DATE OF PUBLICATION IN THE FEDERAL REGISTER], you must 

demonstrate compliance within 180 days after becoming an 

affected source.
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(j) For existing affected sources (as defined in §63.7490) 

that have not operated between the effective date of the rule 

and the compliance date that is specified for your source in 

§63.7495, you must complete the initial compliance 

demonstration, if subject to the emission limits in Table 2 to 

this subpart, as specified in paragraphs (a) through (d) of this 

section, no later than 180 days after the re-start of the 

affected source and according to the applicable provisions in 

§63.7(a)(2) as cited in Table 10 to this subpart. You must 

complete an initial tune-up by following the procedures 

described in §63.7540(a)(10)(i) through (vi) no later than 30 

days after the re-start of the affected source and, if 

applicable, complete the one-time energy assessment specified in 

Table 3 to this subpart, no later than the compliance date 

specified in §63.7495.

14. Section 63.7515 is revised to read as follows: 

§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), (g), and (h) 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), (g), and (h) of this section. 
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(b) If your performance tests for a given 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 or 11 through 13 to this subpart, 

at or below the emission limit) for the pollutant, and if there 

are no changes in the operation of the individual boiler or 

process heater or air pollution control equipment that could 

increase emissions, you may choose to conduct performance tests 

for the pollutant every third year. 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 HCl. 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 TSM input level is 

waived unless the stack test is conducted for TSM.

(c) If a performance test shows emissions exceeded the 

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

in Tables 1 and 2 or 11 through 13 to this subpart) 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 (at or below 75 percent of the 
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emission limit, as specified in Tables 1 and 2 or 11 through 13 

to this subpart).

(d) 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 

(as defined in §63.7490), 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.

(e) If you demonstrate compliance with the mercury, HCl, or 

TSM 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 Tables 1, 2, or 11 through 13

to this subpart. You may comply with this monthly requirement by 

completing the fuel analysis any time within the calendar month 

as long as the analysis is separated from the previous analysis 

by at least 14 calendar days. If you burn a new type of fuel, 
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you must conduct a fuel analysis before burning the new type of 

fuel in your boiler or process heater. You must still meet all 

applicable continuous compliance requirements in §63.7540. If 

each of 12 consecutive monthly fuel analyses demonstrates 75

percent or less of the compliance level, you may decrease the 

fuel analysis frequency to quarterly for that fuel. If any 

quarterly sample exceeds 75 percent of the compliance level or 

you begin burning a new type of fuel, you must return to monthly 

monitoring for that fuel, until 12 months of fuel analyses are 

again less than 75 percent of the compliance level.

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

the associated fuel analyses within 60 days after the completion 

of the performance tests. This report must also verify that the 

operating limits for each boiler or process heater 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.

(g) For affected sources (as defined in §63.7490) that have 

not operated since the previous compliance demonstration and 

more than one year has passed since the previous compliance 

demonstration, you must complete the subsequent compliance 

demonstration, if subject to the emission limits in Tables 1, 2, 

or 11 through 13 to this subpart, no later than 180 days after 
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the re-start of the affected source and according to the 

applicable provisions in §63.7(a)(2) as cited in Table 10 to 

this subpart. You must complete an subsequent tune-up by 

following the procedures described in §63.7540(a)(10)(i) through 

(vi) and the schedule described in §63.7540(a)(13) for units 

that are not operating at the time of their scheduled tune-up.

(h) If your affected boiler or process heater is in the 

unit designed to burn light liquid subcategory and you combust 

ultra low sulfur liquid fuel, you do not need to conduct further 

performance tests if the pollutants measured during the initial 

compliance performance tests meet the emission limits in Tables 

1 or 2 of this subpart providing you demonstrate ongoing 

compliance with the emissions limits by monitoring and recording 

the type of fuel combusted on a monthly basis. If you intend to 

use a fuel other than ultra low sulfur liquid fuel, natural gas, 

refinery gas, or other gas 1 fuel, you must conduct new 

performance tests within 60 days of burning the new fuel type.

(i) If you operate a CO CEMS that meets the Performance 

Specifications outlined in §63.7525(a)(3) of this subpart to 

demonstrate compliance with the applicable alternative CO CEMS 

emission standard listed in Tables 1, 2, or 11 through 13 to 

this subpart, you are not required to conduct CO performance 

tests and are not subject to the oxygen concentration operating 

limit requirement specified in §63.7510(a).
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15. Section §63.7520 is amended by:

a. Revising paragraph (a).

b. Revising paragraph (c).

c. Revising paragraph (d).

d. Revising paragraph (e).

e. Adding paragraph (f).

§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 the 

representative performance of each boiler or process heater 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.

* * * * *

(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 

TSM if you are opting to comply with the TSM alternative 

standard and you must demonstrate initial compliance and 
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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 a minimum of 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 

or 11 through 13 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 (PM)

concentrations, the measured HCl concentrations, the measured 

mercury concentrations, and the measured TSM concentrations that 

result from the performance test to pounds per million Btu heat 

input emission rates.

(f) Except for a 30-day rolling average based on CEMS (or 

sorbent trap monitoring system) data, if measurement results for 

any pollutant are reported as below the method detection level 

(e.g., laboratory analytical results for one or more sample 

components are below the method defined analytical detection 
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level), you must use the method detection level as the measured 

emissions level for that pollutant in calculating compliance. 

The measured result for a multiple component analysis (e.g., 

analytical values for multiple Method 29 fractions both for 

individual HAP metals and for total HAP metals) may include a 

combination of method detection level data and analytical data 

reported above the method detection level.

16. Section 63.7521 is revised to read as follows: 

§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 and liquid fuels, you 

must also conduct fuel analyses for TSM if you are opting to 

comply with the TSM alternative standard. For gas 2 (other) 

fuels, you must conduct fuel analyses 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 TSM alternative 

standard or the HCl 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 
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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 transient flame stability purposes. You are 

required to conduct fuel analyses only for fuels and units that 

are subject to emission limits for mercury, HCl, or TSM in 

Tables 1 and 2 or 11 through 13 to this subpart. Gaseous and 

liquid fuels are exempt from the sampling requirements in 

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

subpart. 

(b) You must develop a site-specific fuel monitoring plan

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) If you intend to use an alternative analytical method 

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

submit the fuel analysis plan to the Administrator for review 

and approval 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.
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(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.

(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.
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(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 the methods listed 

in Table 6 to this subpart, or use an automated sampling 

mechanism that provides representative composite fuel 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.
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(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 

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

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

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

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

procedure.

(e) You must determine the concentration of pollutants in 

the fuel (mercury and/or chlorine and/or TSM) 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 (4) 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, 

part 60, part 61, or part 65.
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(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.

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

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

streams directly derived from natural gas at natural gas 

production sites or natural gas plants.

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

analysis plan for other gas 1 fuels to the EPA Administrator for 

review and approval according to the following procedures and 

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

(1) If you intend to use an alternative analytical method 

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

submit the fuel analysis plan to the Administrator for review 

and approval 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) 
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Page 157 of 374

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 

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.
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(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 other gas 1 fuel type according to the 

procedures in Table 6 to this subpart.

17. Section §63.7522 is revised by:

a. Revising paragraphs (a) through (d).

b. Revising paragraphs (e)(1) and (e)(2).

c. Revising paragraphs (f) introductory text, (f)(1), and 

(f)(2).

d. Revising paragraphs (g) introductory text, (g)(2)(i), 

(g)(2)(iv), (g)(2)(vi)(B), (g)(3) introductory text, (g)(4) 

introductory text, and (g)(4)(ii).

e. Revising paragraph (h).

f. Revising paragraph (i).

g. Revising paragraph (j)(1).

h. Revising paragraph (k).

The revisions read as follows:
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§63.7522 Can I use emissions averaging to comply with this 

subpart?

(a) As an alternative to meeting the requirements of 

§63.7500 for PM (or TSM), HCl, or mercury on a boiler or process 

heater-specific basis, if you have more than one existing boiler 

or process heater in any subcategories 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 PM (or TSM), HCl, 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 average units using a CEMS or PM CPMS for 

demonstrating compliance.

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

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

subcategories.
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(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 units designed to burn 

liquid, units designed to burn solid fuel, and units designed to 

burn gas 2 (other) subcategories.

(3) For PM (or TSM), averaging is only allowed between 

units within each of the following subcategories and you may not 

average across subcategories:

(i) Units designed to burn coal/solid fossil fuel.

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

dried biomass/bio-based solids. 

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

biomass/bio-based solids. 

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

solid. 

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

solid. 

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

(vii) Fuel Cells designed to burn biomass/bio-based solid. 

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

biomass/bio-based solid.
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(ix) Units designed to burn heavy liquid fuel.

(x) Units designed to burn light liquid fuel.

(xi) Units designed to burn liquid fuel that are noncontinental units.

(xii) 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 OF 

PUBLICATION 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 OF PUBLICATION IN THE FEDERAL 

REGISTER].

(d) The averaged emissions rate from the existing boilers 

and process heaters participating in the emissions averaging 

option must not exceed 90 percent of the limits in Table 2 to 

this subpart at all times the affected units are operating 

following the compliance date specified in §63.7495.

(e) * * *

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

demonstrate that the PM (or TSM), HCl, or mercury emissions from 

all existing units participating in the emissions averaging 

option for that pollutant do not exceed the emission limits in 
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Table 2 to this subpart. Use Equation 1a if you are complying 

with the emission limits on a heat input basis, use Equation 1b 

if you are complying with the emission limits on a steam 

generation (output) basis, and use Equation 1c if you are 

complying with the emission limits on a electric generation 

(output) basis.

    

   

n

i

n

i

AveWeightedEmissions Er Hm Hm

1 1

1.1

(Eq.1a)

Where:

AveWeightedEmissions = Average weighted emissions for PM

(or TSM), HCl, or mercury, in units of pounds per 

million Btu of heat input.

Er = Emission rate (as determined during the initial 

compliance demonstration) of PM (or TSM), HCl, or 

mercury from unit, i, in units of pounds per million 

Btu of heat input. Determine the emission rate for PM

(or TSM), HCl, or mercury by performance testing 

according to Table 5 to this subpart, or by fuel 

analysis for HCl or mercury or TSM 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. 

    

   

n

i

n

i

AveWeightedEmissions Er So So

1 1

1.1

(Eq.1b)

Where:
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Page 163 of 374

AveWeightedEmissions = Average weighted emissions for PM

(or TSM), HCl, or mercury, in units of pounds per 

million Btu of steam output.

Er = Emission rate (as determined during the initial 

compliance demonstration) of PM (or TSM), HCl, or 

mercury from unit, i, in units of pounds per million 

Btu of steam output. Determine the emission rate for 

PM (or TSM), HCl, or mercury by performance testing 

according to Table 5 to this subpart, or by fuel 

analysis for HCl or mercury or TSM 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.

    

   

n

i

n

i

AveWeightedEmissions Er Eo Eo

1 1

1.1

(Eq.1c)

Where:

AveWeightedEmissions = Average weighted emissions for PM

(or TSM), HCl, or mercury, in units of pounds per 

megawatt hour.

Er = Emission rate (as determined during the initial 

compliance demonstration) of PM (or TSM), HCl, or 

mercury from unit, i, in units of pounds per megawatt 

hour. Determine the emission rate for PM (or TSM), 

HCl, or mercury by performance testing according to 

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

or mercury or TSM 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.
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Eo = Maximum electric generating output capacity of unit, 

i, in units of megawatt 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 PM (or 

TSM), HCl, 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.

   

 

     

n

i

n

i

AveWeightedEmissions Er Sm Cfi Sm Cfi

1 1

1.1

(Eq. 2)

Where:

AveWeightedEmissions = Average weighted emission level for PM

(or TSM), HCl, or mercury, in units of pounds per 

million Btu of heat input.

Er = Emission rate (as determined during the most recent 

compliance demonstration) of PM (or TSM), HCl, or 

mercury from unit, i, in units of pounds per million 

Btu of heat input. Determine the emission rate for PM

(or TSM), HCl, or mercury by performance testing 

according to Table 5 to this subpart, or by fuel 

analysis for HCl or mercury or TSM using the 

applicable equation in §63.7530(c).

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

units of pounds per hour.
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Page 165 of 374

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. If the affected source elects to 

collect monthly data for up the 11 months preceding the first 

monthly period, these additional data points can be used to 

compute the 12-month rolling average in paragraph (f)(3) of this 

section.

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

or 3c 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 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. Use 

Equation 3c and the actual steam generation for the month if you 
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Page 166 of 374

are complying with the emission limits on a electrical 

generation (output) basis. 

    

   

n

i

n

i

AveWeightedEmissions Er Hb Hb

1 1

1.1

(Eq. 3a)

Where:

AveWeightedEmissions = Average weighted emission level for PM

(or TSM), HCl, 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 PM (or TSM), HCl, or 

mercury from unit, i, in units of pounds per million 

Btu of heat input. Determine the emission rate for PM

(or TSM), HCl, or mercury by performance testing 

according to Table 5 to this subpart, or by fuel 

analysis for HCl or mercury or TSM according to Table 

6 to this subpart.

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 PM

(or TSM), HCl, or mercury, in units of pounds per 

million Btu of steam output, for that calendar 

month.

Er = Emission rate (as determined during the most recent 

compliance demonstration) of PM (or TSM), HCl, or 

mercury from unit, i, in units of pounds per million 

Btu of steam output. Determine the emission rate for 
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Page 167 of 374

PM (or TSM), HCl, or mercury by performance testing 

according to Table 5 to this subpart, or by fuel 

analysis for HCl or mercury or TSM according to Table 

6 to this subpart. 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.

    

   

n

i

n

i

AveWeightedEmissions Er Eo Eo

1 1

1.1

(Eq. 3c)

Where:

AveWeightedEmissions = Average weighted emission level for PM

(or TSM), HCl, or mercury, in units of pounds per 

megawatt hour, for that calendar month.

Er = Emission rate (as determined during the most recent 

compliance demonstration) of PM (or TSM), HCl, or 

mercury from unit, i, in units of pounds per megawatt 

hour. Determine the emission rate for PM (or TSM), 

HCl, or mercury by performance testing according to 

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

or mercury or TSM according to Table 6 to this 

subpart. 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.

Eo = The electric generating output for that calendar 

month from unit, i, in units of megawatt hour, as 

defined in §63.7575.

n = Number of units participating in the emissions 

averaging option.

1.1 = Required discount factor.
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(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

(or TSM), HCl, 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 PM (or TSM), HCl, or 

mercury from unit, i, in units of pounds per million 

Btu of heat input. Determine the emission rate for PM

(or TSM), HCl, or mercury by performance testing 

according to Table 5 to this subpart, or by fuel 

analysis for HCl or mercury or TSM according to Table 

6 to this subpart.

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.

* * * * *

(g) You must develop, and submit upon request to the 

applicable Administrator for review and approval, an 

implementation plan for emission averaging according to the 
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Page 169 of 374

following procedures and requirements in paragraphs (g)(1) 

through (4) of this section.

(2) * * *

(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 OF PUBLICATION IN THE FEDERAL 

REGISTER] and the date on which you are requesting emission 

averaging to commence;

* * * * *

(iv) The test plan for the measurement of PM (or TSM), HCl, 

or mercury emissions in accordance with the requirements in 

§63.7520;

* * * * *

(vi) * * *

(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 Administrator, that 

the proposed monitoring frequency is sufficient to represent 

control device operating conditions; and

* * * * *
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(3) The Administrator shall review and approve or 

disapprove the plan according to the following criteria:

* * * * *

(4) The applicable Administrator shall not approve an 

emission averaging implementation plan containing any of the 

following provisions:

* * * * *

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

existing unit in the same subcategories.

* * * * *

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

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

average PM (or TSM), HCl, 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.

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

subcategories, 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) * * *
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(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.

Hi = Heat input from unit i, MMBtu.

* * * * *

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

boilers or process heaters in the same subcategories 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.

18. Section 63.7525 is amended by:

a. Revising paragraph (a)

b. Revising paragraph (b).

c. Adding paragraphs (b)(6) through (b)(8).
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d. Revising paragraph (c) introductory text.

e. Revising paragraphs (d) introductory text and paragraphs 

(d)(1) through (d)(4).

f. Revising paragraph (e)(2).

g. Revising paragraph (e)(3).

h. Revising paragraph (f)(2).

i. Revising paragraph (j).

j. Revising paragraph (k).

k. Adding paragraph (l).

l. Adding paragraph (m).

The revisions read as follows: 

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

maintenance requirements?

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

emission limit in Tables 1, 2, or 11 through 13 to this subpart, 

you must install, operate, and maintain an oxygen analyzer 

system, as defined in §63.7575, or install, certify, operate and 

maintain continuous emission monitoring systems for CO and 

oxygen according to the procedures in paragraphs (a)(1) through 

(7) of this section.

(1) Install the CO CEMS and oxygen analyzer by the 

compliance date specified in §63.7495. The CO and oxygen levels 

shall be monitored at the same location at the outlet of the 

boiler or process heater.
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(2) To demonstrate compliance with the applicable 

alternative CO CEMS emission standard listed in Tables 1, 2, or 

11 through 13 to this subpart, you must install, certify, 

operate, and maintain a CO CEMS and an oxygen analyzer according 

to the applicable procedures under Performance Specification 4, 

4A, or 4B at 40 CFR part 60, appendix B, the site-specific 

monitoring plan developed according to §63.7505(d), and the 

requirements in §63.7540(a)(8) and (a) of this section. Any 

boiler or process heater that has a CO CEMS that is compliant 

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

appendix B, a site-specific monitoring plan developed according 

to §63.7505(d), and the requirements in §63.7540(a)(8) and (a) 

of this section must use the CO CEMS to comply with the 

applicable alternative CO CEMS emission standard listed in 

Tables 1, 2, or 11 through 13 to this subpart.

(i) 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.

(ii) During each relative accuracy test run of the CO CEMS, 

you must be collect emission data for CO 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.
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(iii) 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 

measurement span value of the CO CEMS must be two times the 

applicable CO emission limit, expressed as a concentration.

(iv) Any CO CEMS that does not comply with §63.7525(a) 

cannot be used to meet any requirement in this subpart to 

demonstrate compliance with a CO emission limit listed in Tables 

1, 2, or 11 through 13 to this subpart.

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

evaluation no later than [INSERT THE DATE 180 DAYS AFTER THE 

DATE OF PUBLICATION 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 THE DATE OF 

PUBLICATION IN THE FEDERAL REGISTER].

(3) Complete a minimum of one cycle of CO and oxygen CEMS 

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

successive 15-minute period. Collect CO and oxygen data 

concurrently. Collect at least four CO and oxygen 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.
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(4) Reduce the CO CEMS data as specified in §63.8(g)(2).

(5) Calculate one-hour arithmetic averages, corrected to 3 

percent oxygen from each hour of CO CEMS data in parts per 

million CO concentration. The one-hour arithmetic averages 

required shall be used to calculate the 30-day or 10-day rolling 

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 CO concentration from the hourly values.

(6) For purposes of collecting CO data, 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).

(7) Operate an oxygen trim system with the oxygen level set 

no lower than the lowest hourly average oxygen concentration 

measured during the most recent CO performance test as the 

operating limit for oxygen according to Table 7 to this subpart.

(b) If your boiler or process heater is in the unit 

designed to burn coal/solid fossil fuel subcategory or the unit 

designed to burn heavy liquid subcategory and has an average 

annual heat input rate greater than 250 MMBtu per hour from 

solid fossil fuel and/or heavy liquid, and you demonstrate 
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compliance with the PM limit instead of the alternative TSM

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. As an alternative to use of 

a PM CPMS to demonstrate compliance with the PM limit, you may 

choose to use a PM CEMS. If you choose to use a PM CEMS to 

demonstrate compliance with the PM limit instead of the 

alternative TSM limit, you must install, certify, maintain, and 

operate a PM CEMS monitoring emissions discharged to the 

atmosphere and record the output of the system as specified in 

paragraph (b)(5) through (b)(8) of this section. For other 

boilers or process heaters, you may elect to use a PM CPMS or PM 

CEMS 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). Owners of 

boilers and process heaters who elect to comply with the 

alternative TSM limit are not required to install a PM CPMS.

(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.
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(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 must be expressed as 

milliamps.

(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.

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

responding to PM 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 180 DAYS AFTER THE 

DATE OF PUBLICATION 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 THE DATE OF 

PUBLICATION IN THE FEDERAL REGISTER].

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

boiler or process heater operating hours except as indicated in 

§63.7535(a) through (d). Express the PM CPMS output as 

milliamps.
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(4) Calculate the arithmetic 30-day rolling average of all 

of the hourly average PM CPMS output data collected during all 

boiler or process heater operating hours (milliamps).

(5) Install, certify, operate, and maintain your PM CEMS 

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)(5)(i) through (iv) of 

this section.

(i) You shall conduct a performance evaluation of the PM 

CEMS according to the applicable requirements of § 60.8(e), and 

Performance Specification 11 at 40 CFR part 60, appendix B of 

this chapter.

(ii) During each PM correlation testing run of the CEMS 

required by Performance Specification 11 at 40 CFR part 60, 

appendix B of this chapter, you shall collect PM and oxygen (or 

carbon dioxide) data concurrently (or within a 30-to 60-minute 

period) by both the CEMS and conducting performance tests using 

Method 5 at 40 CFR part 60, appendix A–3 or Method 17 at 40 CFR 

part 60, appendix A–6 of this chapter.

(iii) You shall perform quarterly accuracy determinations 

and daily calibration drift tests in accordance with Procedure 2 

at 40 CFR part 60, appendix F of this chapter. You must perform 

Relative Response Audits annually and perform Response 

Correlation Audits every 3 years.
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(iv) Within 60 days after the date of completing each CEMS 

relative accuracy test audit or performance test conducted to 

demonstrate compliance with this subpart, you must submit the 

relative accuracy test audit data and performance test data to 

the EPA by successfully submitting the data electronically into 

the EPA’s Central Data Exchange by using the Electronic 

Reporting Tool (see http://www.epa.gov/ttn/chief/ert/ert 

tool.html/).

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

evaluation no later than [INSERT THE DATE 180 DAYS AFTER THE 

DATE OF PUBLICATION 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 THE DATE OF 

PUBLICATION IN THE FEDERAL REGISTER].

(7) Collect PM CEMS hourly average output data for all 

boiler or process heater operating hours except as indicated in 

§63.7535(a) through (d).

(8) Calculate the arithmetic 30-day rolling average of all 

of the hourly average PM CEMS output data collected during all 

boiler or process heater operating hours.

(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, PM CEMS, or a bag leak detection system, 
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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.

* * * * *

(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 CPMS must complete a minimum of one cycle of 

operation every 15-minutes. You must have a minimum of four 

successive cycles of operation, one representing each of the 

four 15-minute periods in an hour, 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).

(4) You must determine the 30-day rolling average of all 

recorded readings, except as provided in §63.7535(c).

* * * * *
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(e) * * *

(2) You must use a flow sensor with a measurement 

sensitivity of no greater than 2 percent of the design flow 

rate.

(3) You must minimize, consistent with good engineering 

practices, the effects of swirling flow or abnormal velocity 

distributions due to upstream and downstream disturbances.

* * * * *

(f) * * *

(2) Minimize or eliminate pulsating pressure, vibration, 

and internal and external corrosion consistent with good 

engineering practices.

* * * * *

(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 PM loadings for each exhaust stack, roof vent, or 

compartment (e.g., for a positive pressure fabric filter) of the 

fabric filter.
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(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 PM 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 plant operating personnel when an increase in 

relative PM emissions over a preset level is detected. The alert 

must easily recognizable (e.g., heard or seen) by plant 

operating personnel.

(6) Where multiple bag leak detectors are required, the 

system's instrumentation and alert may be shared among 

detectors.

(k) For each unit that meets the definition of limited-use 

boiler or process heater, you must keep fuel use records for the 

days the boiler or process heater was operating.

(l) For each unit for which you decide to demonstrate 

compliance with the mercury or HCl emissions limits in Tables 1 

or 2 or 11 through 13 of this subpart by use of a CEMS for 

mercury or HCl, you must install, certify, maintain, and operate 
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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 HCl, this option for an 

affected unit takes effect on the date a final performance 

specification for a HCl 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 HCl 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 180 DAYS AFTER THE DATE 

OF PUBLICATION 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. 
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(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 THE DATE OF PUBLICATION 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 HCl 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.
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(7) The one-hour arithmetic averages required shall be 

expressed in lb/MMBtu and shall be used to calculate the boiler 

30-day and 10-day rolling average emissions.

(8) You are allowed to substitute the use of the PM, 

mercury or HCl CEMS for the applicable fuel analysis, annual 

performance test, and operating limits specified in Table 4 to 

this subpart to demonstrate compliance with the PM, mercury or 

HCl emissions limit, and if you are using an acid gas wet 

scrubber or dry sorbent injection control technology to comply 

with the HCl emission limit, you are allowed to substitute the 

use of a sulfur dioxide (SO2) CEMS for the applicable fuel 

analysis, annual performance test, and operating limits 

specified in Table 4 to this subpart to demonstrate compliance 

with HCl emissions limit.

(m) If your unit is subject to a HCl emission limit in 

Tables 1, 2, or 11 through 13 of this subpart and you have an 

acid gas wet scrubber or dry sorbent injection control 

technology and you use an SO2 CEMS, you must install the monitor 

at the outlet of the boiler or process heater, downstream of all 

emission control devices, and you must install, certify, 

operate, and maintain the CEMS according to part 75 of this 

chapter.

(1) The SO2 CEMS must be installed by the compliance date 

specified in §63.7495.
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(2) For on-going quality assurance (QA), the SO2 CEMS must 

meet the applicable daily, quarterly, and semiannual or annual 

requirements in sections 2.1 through 2.3 of appendix B to part 

75 of this chapter, with the following addition: You must 

perform the linearity checks required in section 2.2 of appendix 

B to part 75 of this chapter if the SO2 CEMS has a span value of 

30 ppm or less.

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

shall be completed no later than [INSERT THE DATE 180 DAYS AFTER 

THE DATE OF PUBLICATION 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 THE DATE OF PUBLICATION IN THE FEDERAL REGISTER].

(4) For purposes of collecting SO2 data, you must operate 

the SO2 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 SO2 data are 

unavailable may constitute monitoring deviations as specified in 

§63.7535(d).

(5) Collect CEMS hourly averages for all operating hours on 

a 30-day rolling average basis.
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(6) Use only unadjusted, quality-assured SO2 concentration 

values in the emissions calculations; do not apply bias 

adjustment factors to the part 75 SO2 data and do not use part 75 

substitute data values.

19. Section 63.7530 is amended by:

a. Revising paragraph (a).

b. Revising paragraph (b) introductory text.

c. Redesignating paragraph (b)(3) as paragraph (b)(4) and 

revising newly designated paragraph (b)(4).

d. Adding paragraph (b)(3).

e. Revising paragraphs (c) introductory text, (c)(2),

(c)(3), and (c)(4).

f. Adding paragraph (c)(5).

g. Revising paragraph (d).

h. Revising paragraph (e).

i. Revising paragraph (g).

j. Revising paragraph (h).

k. Adding paragraph (i).

The revisions read as follows:

§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 
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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. The 

requirement to conduct a fuel analysis is not applicable for 

units that burn a single type of fuel, as specified by 

§63.7510(a)(2)(i). If applicable, you must also install, 

operate, and maintain all applicable CMS (including CEMS, COMS, 

and CPMS) 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 

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 TSM 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).

* * * * *
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(3) If you opt to comply with the alternative TSM limit, 

you must establish the maximum TSM fuel input (TSMinput) for 

solid or liquid 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 TSM.

(ii) During the fuel analysis for TSM, 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 

TSM, and the average TSM concentration of each fuel type burned 

(TSMi).

(iii) You must establish a maximum TSM input level using 

Equation 9 of this section.

 



 

n

i

TSMinput TSMi Qi

1 (Eq. 9)

Where:

TSMinput = Maximum amount of TSM entering the boiler or process 

heater through fuels burned in units of pounds per 

million Btu.

TSMi = Arithmetic average concentration of TSM 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 TSM. If you do not burn multiple fuel 
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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 TSM.

(4) You must establish parameter operating limits according 

to paragraphs (b)(4)(i) through (ix) 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 

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 performance test 

during which you demonstrate compliance with your applicable 

limit. If you use a wet scrubber and you conduct separate 

performance tests for HCl 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 HCl

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.
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(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 PM CPMS operating limit and 

determine compliance with it according to paragraphs 

(b)(4)(ii)(A) through (F) of this section.

(A) Determine your operating limit as the average PM CPMS 

output value recorded during the most recent performance test

run demonstrating compliance with the filterable PM emission 

limit or at the PM CPMS output value corresponding to 75 percent

of the emission limit if your PM performance test demonstrates 

compliance below 75 percent of the emission limit. You must 

verify an existing or establish a new operating limit after each 

repeated performance test. You must repeat the performance test 

annually and reassess and adjust the site-specific operating 

limit in accordance with the results of the performance test.

1. Your PM CPMS must provide a 4-20 milliamp output and the 

establishment of its relationship to manual reference 

method measurements must be determined in units of 

milliamps.

2. Your PM CPMS operating range must be capable of reading 

PM concentrations from zero to a level equivalent to at 

least two times your allowable emission limit. If your PM 

CPMS is an auto-ranging instrument capable of multiple 

scales, the primary range of the instrument must be 
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capable of reading PM concentration from zero to a level 

equivalent to two times your allowable emission limit.

3. During the initial performance test or any such 

subsequent performance test that demonstrates compliance 

with the PM limit, record and average all milliamp output 

values from the PM CPMS for the periods corresponding to 

the compliance test runs (e.g., average all your PM CPMS 

output values for three corresponding 2-hour Method 5I 

test runs).

(B) If the average of your three PM performance test runs 

are below 75 percent of your PM emission limit, you must 

calculate an operating limit by establishing a relationship of 

PM CPMS signal to PM concentration using the PM CPMS instrument 

zero, the average PM CPMS values corresponding to the three 

compliance test runs, and the average PM concentration from the 

Method 5 or performance test with the procedures in 

(B)(i)through (B)(iv)of this section.

i. Determine your instrument zero output with one of the 

following procedures:

a. Zero point data for in-situ instruments should be 

obtained by removing the instrument from the 

stack and monitoring ambient air on a test bench.
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b. Zero point data for extractive instruments should 

be obtained by removing the extractive probe from 

the stack and drawing in clean ambient air.

c. The zero point may also be established by 

performing manual reference method measurements 

when the flue gas is free of PM emissions or 

contains very low PM concentrations (e.g., when 

your process is not operating, but the fans are 

operating or your source is combusting only

natural gas) and plotting these with the 

compliance data to find the zero intercept.

d. If none of the steps in paragraphs (i)(a) through 

(c) of this section are possible, you must use a 

zero output value provided by the manufacturer.

ii. Determine your PM CPMS instrument average in 

milliamps, and the average of your corresponding three 

PM compliance test runs, using equation 10.

 =









,  =









(Eq. 10)

 Where:

X1 = the PM CPMS data points for the three runs 

constituting the performance test,

Y1 = the PM concentration value for the three runs 

constituting the performance test, and
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n = the number of data points.

iii. With your instrument zero expressed in milliamps, your 

three run average PM CPMS milliamp value, and your 

three run average PM concentration from your three 

compliance tests, determine a relationship of lb/MMBtu 

per milliamp with equation 11.

X z

Y





1

1 R

 

(Eq. 11)

Where:

R = the relative lb/MMBtu per milliamp for your 

PM CPMS, 

Y1 = the three run average lb/MMBtu PM 

concentration,

X1 = the three run average milliamp output from 

you PM CPMS, and

z = the milliamp equivalent of your instrument 

zero determined from (B)(i).

iv. Determine your source specific 30-day rolling average 

operating limit using the lb/MMBtu per milliamp value 

from Equation 11 in equation 12, below. This sets your 

operating limit at the PM CPMS output value 

corresponding to 75 percent of your emission limit.

 =  +

0.75()



(Eq. 12)
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Where:

Ol = the operating limit for your PM CPMS on a 30-

day rolling average, in milliamps.

L = your source emission limit expressed in 

lb/MMBtu,

z = your instrument zero in milliamps, determined 

from (B)(i), and

R = the relative lb/MMBtu per milliamp for your 

PM CPMS, from Equation 11.

(C) If the average of your three PM compliance test runs is 

at or above 75 percent of your PM emission limit you must 

determine your 30-day rolling average operating limit by 

averaging the PM CPMS milliamp output corresponding to your 

three PM performance test runs that demonstrate compliance with 

the emission limit using equation 13 and you must submit all 

compliance test and PM CPMS data according to the reporting 

requirements in section (F) below.

 =









(Eq. 13)

 Where:

X1 = the PM CPMS data points for all runs i,

n = the number of data points, and

Oh = your site specific operating limit, in 

milliamps.

(D) To determine continuous compliance, you must record the 

PM CPMS output data for all periods when the process is 

operating and the PM CPMS is not out-of-control. You must 
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demonstrate continuous compliance by using all quality-assured 

hourly average data collected by the PM CPMS for all operating 

hours to calculate the arithmetic average operating parameter in 

units of the operating limit (milliamps) on a 30-day rolling 

average basis, updated at the end of each new operating hour. 

Use Equation 14 to determine the 30-day rolling average.

n

n

Hpv

i

 i

 

1

30 day (Eq. 14)

Where:

30-day = 30-day average.

Hpvi = is the hourly parameter value for hour i

n = is the number of valid hourly parameter values 

collected over the previous 720 operating hours. 

(E) Use EPA Method 5 of appendix A to part 60 of this 

chapter to determine PM emissions. For each performance test, 

conduct three separate runs under the conditions that exist when 

the affected source is operating at the highest load or capacity 

level reasonably expected to occur. Conduct each test run to 

collect a minimum sample volume specified in Tables 1, 2, or 11 

through 13 to this subpart, as applicable, for determining 

compliance with a new source limit or an existing source limit. 

Calculate the average of the results from three runs to 

determine compliance. You need not determine the PM collected in 

the impingers (“back half”) of the Method 5 particulate sampling 
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train to demonstrate compliance with the PM standards of this 

subpart. This shall not preclude the permitting authority from 

requiring a determination of the “back half” for other purposes.

(F) For PM performance test reports used to set a PM CPMS 

operating limit, the electronic submission of the test report 

must also include the make and model of the PM CPMS instrument, 

serial number of the instrument, analytical principle of the 

instrument (e.g. beta attenuation), span of the instruments 

primary analytical range, milliamp value equivalent to the 

instrument zero output, technique by which this zero value was 

determined, and the average milliamp signals corresponding to 

each PM compliance test run.(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 PM

and TSM 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 HCl 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. 
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(iv) For an electrostatic precipitator (ESP) operated with 

a wet scrubber, you must establish the minimum total secondary 

electric power input, as defined in §63.7575, as your operating 

limit during the three-run performance test during which you 

demonstrate compliance with your applicable limit. (These 

operating limits do not apply to ESP that are operated as dry 

controls without a wet scrubber.)

(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 alert is not activated more than 5 percent 

of the operating time during a 6-month period.
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(viii) For a minimum oxygen level, if you conduct multiple 

performance tests, you must set the minimum oxygen level at the 

lower of the minimum values established during the performance 

tests. 

(ix) The operating limit for boilers or process heaters 

that demonstrate continuous compliance with the HCl emission 

limit using a SO2 CEMS is to install and operate the SO2

according to the requirements in §63.7525(m) establish a maximum 

SO2 emission rate equal to the highest hourly average SO2

measurement during the most recent three-run performance test 

for HCl. 

(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.

* * * * *

(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 t-statistic test 

described in Equation 15 of this section.

P90  mean  SD  t (Eq. 15)

Where:

P90 = 90th percentile confidence level pollutant 

concentration, in pounds per million Btu.
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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 mean of pollutant 

concentration in the fuel samples analyzed according 

to §63.7521, in units of pounds per million Btu. SD 

is calculated as the sample standard deviation 

divided by the square root of the number of samples.

t = t distribution critical value for 90th percentile 

(t0.1) probability for the appropriate degrees of 

freedom (number of samples minus one) as obtained 

from a t-Distribution Critical Value Table.

(3) To demonstrate compliance with the applicable emission 

limit for HCl, the HCl emission rate that you calculate for your 

boiler or process heater using Equation 16 of this section must 

not exceed the applicable emission limit for HCl.

  



  

n

i

HCl Ci Qi

1

90 1.028

(Eq. 16)

Where:

HCl = HCl emission rate from the boiler or process heater 

in units of pounds per million Btu.

Ci90 = 90th percentile confidence level concentration of 

chlorine in fuel type, i, in units of pounds per 

million Btu as calculated according to Equation 11 of 

this section.

Qi = Fraction of total heat input from fuel type, i, based 

on the fuel mixture that has the highest content of 

chlorine. If you do not burn multiple fuel types, it 

is not necessary to determine the value of this term. 

Insert a value of “1” for Qi.

n = Number of different fuel types burned in your boiler 

or process heater for the mixture that has the 

highest content of chlorine.

1.028 = Molecular weight ratio of HCl to chlorine.
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(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 17 of this 

section must not exceed the applicable emission limit for 

mercury.

 



 

n

i

Mercury Hgi Qi

1

90

(Eq. 17)

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 11 of this 

section.

Qi = Fraction of total heat input from fuel type, i, 

based on the fuel mixture that has the highest 

mercury content. If you do not burn multiple fuel 

types, it is not necessary to determine the value of 

this term. Insert a value of “1” for Qi.

n = Number of different fuel types burned in your boiler 

or process heater for the mixture that has the 

highest mercury content.

(5) To demonstrate compliance with the applicable emission 

limit for TSM for solid or liquid fuels, the TSM emission rate 

that you calculate for your boiler or process heater from solid 

fuels using Equation 18 of this section must not exceed the 

applicable emission limit for TSM.
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 



 

n

i

Metals TSM i Qi

1

90

(Eq. 18)

Where:

Metals = TSM emission rate from the boiler or process heater 

in units of pounds per million Btu.

TSMi90 = 90th percentile confidence level concentration of 

TSM in fuel, i, in units of pounds per million Btu 

as calculated according to Equation 11 of this 

section.

Qi = Fraction of total heat input from fuel type, i, 

based on the fuel mixture that has the highest TSM

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 TSM content.

(d) If you own or operate an existing unit with a heat 

input capacity of less than 10 million Btu per hour or a unit in 

the unit designed to burn gas 1 subcategory, you must submit a 

signed statement in the Notification of Compliance Status report 

that indicates that you conducted a tune-up of the unit.

(e) You must 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 at the time of the 

assessment.

* * * * *
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(g) If you elect to demonstrate that a gaseous fuel meets 

the specifications of another gas 1 fuel as defined in §63.7575, 

you must conduct an initial fuel specification analyses 

according to §63.7521(f) through (i) and according to the 

frequency listed in §63.7540(c) and maintain records of the 

results of the testing as outlined in §63.7555(g). For samples 

where the initial mercury specification has not been exceeded, 

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.

(h) If you own or operate a unit subject to emission limits 

in Tables 1 or 2 or 11 through 13 to this subpart, you must meet 

the work practice standard according to Table 3 of this subpart. 

During startup and shutdown, you must only follow the work 

practice standards according to item 5 of Table 3 of this 

subpart. 

(i) If you opt to comply with the alternative SO2 CEMS 

operating limit in Tables 4 and 8 to this subpart, you may do so 

only if your affected boiler or process heater:

(1) Has a system using wet scrubber or dry sorbent 

injection and SO2 CEMS installed on the unit; and
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(2) At all times, you operate the wet scrubber or dry 

sorbent injection for acid gas control on the unit consistent 

with §63.7500(a)(3); and

(3) You establish a unit-specific maximum SO2 operating 

limit by collecting the minimum hourly SO2 emission rate on the 

SO2 CEMS during the paired 3-run test for HCl. The maximum SO2

operating limit is equal to the highest hourly average SO2

concentration measured during the most recent HCl performance 

test.

20. Section 63.7533 is amended by:

a. Revising the section heading.

b. Revising paragraph (a).

c. Revising paragraphs (b)(1) and (b)(4).

d. Revising paragraph (c) introductory text, paragraph 

(c)(1)(i), paragraph (c)(1)(ii), paragraph (c)(2)(i), and 

paragraph (c)(3).

e. Revising paragraph (d).

f. Revising paragraph (e).

g. Revising paragraph (f).

h. Adding paragraph (g).

The revisions read as follows:

§63.7533 Can I use efficiency credits earned from implementation 

of energy conservation measures to comply with this subpart?
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(a) If you elect to comply with the alternative equivalent 

output-based emission limits, instead of the heat input-based 

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 

efficiency 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 efficiency credits, develop an Implementation Plan, 

comply with the general reporting requirements, and apply the 

efficiency 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. Additional 

guidance from the Department of Energy on emission credits is

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

(b) * * *

(1) The benchmark from which efficiency 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 
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demonstrated that a different time period is more representative 

of historical operations.

* * * * *

(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 

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 efficiency 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) Efficiency credits on shut-down boilers. Boilers that 

are shut down cannot be used to generate credits unless the 

facility provides documentation linking the permanent shutdown

to energy conservation measures identified in the energy 

assessment. In this case, the bench established for the affected 
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boiler to which the credits from the shutdown will be applied 

must be revised to include the benchmark established for the 

shutdown boiler.

(2) * * *

(i) Calculate annual credits for all energy demand points. 

Use Equation 19 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 

actual energy demand reductions from energy conservation 

measures implemented after January 1, 2008. Credits shall be 

calculated using Equation 19 of this section as follows:

(i) The overall equation for calculating credits is:

baseline

n

i

ECredits EISiactual  EI 















 1

(Eq. 19)

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.
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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 upon request by the Administrator, 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 savings. If requested, you 

must submit the implementation plan for efficiency credits to 

the Administrator for review and approval no later than 180 days 

before the date on which the facility intends to demonstrate 

compliance using the efficiency credit approach.

(e) The emissions rate as calculated using Equation 20 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 the affected unit is 

operating, following the compliance date specified in §63.7495.
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(f) You must use Equation 20 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. 20)

where:

Eadj = Emission level adjusted by applying the efficiency 

credits earned, lb per million Btu steam output (or 

lb per MWh) for the affected boiler.

Em = Emissions measured during the performance test, lb 

per million Btu steam output (or lb per MWh) for the 

affected boiler.

ECredits = Efficiency credits from Equation 19 for the affected 

boiler.

(g) As part of each compliance report submitted as

required under §63.7550, you must include documentation that the 

energy conservation measures implemented continue to generate 

the credit for use in demonstrating compliance with the emission 

limits.

21. Section 63.7535 is amended by revising the section 

heading, paragraphs (b), (c), and (d) to read as follows: 

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

obtain?

* * * * *
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(b) You must operate the monitoring system and collect data 

at all required intervals at all times that each boiler or 

process heater 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 

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 
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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. In calculating monitoring results, do 

not use any data collected during periods when the monitoring 

system is out of control as specified in your site-specific 

monitoring plan, while conducting repairs associated with 

periods when the monitoring system is out of control, or while 

conducting required monitoring system quality assurance or 

quality control activities. You must calculate monitoring 

results using all other monitoring data collected while the 

process is operating. You must report all periods when the 

monitoring system is out of control in your annual report.

22. Section 63.7540 is revised to read as follows: 
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§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 or 11 through 13 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 to the methods specified in Table 8 to this 

subpart and paragraphs (a)(1) through (19) 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: 
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(i) Lower emissions of HCl, mercury, and TSM than the 

applicable emission limit for each pollutant, if you demonstrate 

compliance through fuel analysis. 

(ii) Lower fuel input of chlorine, mercury, and TSM than 

the maximum values calculated during the last performance test, 

if you demonstrate compliance through performance testing.

(3) If you demonstrate compliance with an applicable HCl

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 HCl emission rate using Equation 12 of 

§63.7530 according to paragraphs (a)(3)(i) through (iii) of this 

section. You are not required to conduct 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 HCl 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 HCl emission rate from your boiler or 

process heater under these new conditions using Equation 12 of 
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§63.7530. The recalculated HCl emission rate must be less than 

the applicable emission limit.

(4) If you demonstrate compliance with an applicable HCl

emission limit through performance testing and you plan to burn 

a new type of fuel or a new mixture of fuels, you must 

recalculate the maximum chlorine input using Equation 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 HCl emissions 

do not exceed the emission limit. You must also establish new 

operating limits based on this performance test according to the 

procedures in §63.7530(b). In recalculating the maximum chlorine 

input and establishing the new operating limits, you are not 

required to conduct 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 13 of §63.7530 according to the 

procedures specified in paragraphs (a)(5)(i) through (iii) of 

this section. You are not required to conduct fuel analyses for 
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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.

(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 13 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 
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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 conduct 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 alert and complete corrective actions 

as soon as practical, and operate and maintain the fabric filter 

system such that the periods which would cause an alert are no 

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 alert, the time corrective action was initiated 

and completed, and a brief description of the cause of the alert 

and the corrective action taken. You must also record the 

percent of the operating time during each 6-month period that 

the conditions exist for an alert. In calculating this operating 

time percentage, if inspection of the fabric filter demonstrates 

that no corrective action is required, no alert time is counted. 

If corrective action is required, each alert shall be counted as 

a minimum of 1 hour. If you take longer than 1 hour to initiate 
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corrective action, the alert time shall be counted as the actual 

amount of time taken to initiate corrective action.

(8) To demonstrate compliance with the applicable 

alternative CO CEMS emission limit listed in Tables 1, 2, or 11 

through 13 to this subpart, you must meet the requirements in 

paragraphs (a)(8)(i) through (iv) 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 

or 11 through 13 to this subpart at all times the affected unit 

is operating.

(iii) Keep records of CO levels according to §63.7555(b).

(iv) You must record and make available upon request 

results of CO CEMS performance audits, dates and duration of 

periods when the CO CEMS is out of control to completion of the 

corrective actions necessary to return the CO CEMS to operation 

consistent with your site-specific monitoriong plan.

(9) The owner or operator of a boiler or process heater 

using a PM CPMS or a PM CEMS to meet requirements of this 

subpart shall install, certify, operate, and maintain the PM 

CPMS or PM CEMS in accordance with your site-specific monitoring 

plan as required in §63.7505(d).
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(10) If your boiler or process heater has a heat input 

capacity of 10 million Btu per hour or greater, you must conduct 

an annual tune-up of the boiler or process heater to demonstrate 

continuous compliance as specified in paragraphs (a)(10)(i) 

through (a)(10)(vi) of this section. This frequency does not 

apply to limited-use boilers and process heaters, as defined in 

§63.7575, or units with continuous oxygen trim systems that 

maintain an optimum air to fuel ratio.

(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 unit shutdown). Units 

that produce electricity for sale may delay the burner 

inspection until the first outage, not to exceed 36 months from 

the previous inspection. At units where entry into a piece of 

process equipment or into a storage vessel is required to 

complete the tune-up inspections, inspections are required only 

during planned entries into the storage vessel or process 

equipment;

(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 
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functioning properly (you may delay the inspection until the 

next scheduled unit shutdown). Units that produce electricity 

for sale may delay the inspection until the first outage, not to 

exceed 36 months from the previous inspection;

(iv) Optimize total emissions of CO. This optimization 

should be consistent with the manufacturer’s specifications, if 

available, and with any NOx requirement to which the unit is 

subject;

(v) Measure the concentrations in the effluent stream of CO

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). Measurements may be 

taken using a portable CO analyzer; and

(vi) Maintain on-site and submit, if requested by the 

Administrator, an annual report containing the information in 

paragraphs (a)(10)(vi)(A) through (C) of this section,

(A) The concentrations of CO in the effluent stream in 

parts per million by volume, and oxygen in volume percent, 

measured at high fire or typical operating load, before and 

after the tune-up of the boiler or process heater;

(B) A description of any corrective actions taken as a part 

of the tune-up; and
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(C) The type and amount of fuel used over the 12 months 

prior to the tune-up, 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), 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 continuous 

oxygen trim system that maintains an optimum air to fuel ratio, 

or a heat input capacity of less than or equal to 5 million Btu 

per hour and the unit is in the units designed to burn gas 1;

units designed to burn gas 2 (other); or units designed to burn 

light liquid subcategories, or meets the definition of limiteduse boiler or process heater in §63.7575, you must conduct a 

tune-up of the boiler or process heater every 5 years as 

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.
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(13) If the unit is not operating on the required date for 

a tune-up, the tune-up must be conducted within 30 calendar days 

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 the maximum of 30 unit 

operating days or 720 hours. For each day 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 

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 HCl emissions to 

meet requirements of this subpart, you must install, certify, 

operate, and maintain the HCl CEMS as specified in paragraphs 
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(a)(15)(i) and (ii) of this section. This option for an affected 

unit takes effect on the date a final performance specification 

for an HCl 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 the maximum of 30 unit operating days or 720 hours. For 

each day in which the unit operates, you must obtain hourly HCl

concentration data, and stack gas volumetric flow rate data.

(ii) If you are using a HCl CEMS, you must install, 

operate, calibrate, and maintain an instrument for continuously 

measuring and recording the HCl 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.

(16) If you demonstrate compliance with an applicable TSM

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 TSM input using Equation 9 of §63.7530. 

If the results of recalculating the maximum TSM 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 
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days of burning the new fuel type or fuel mixture according to 

the procedures in §63.7520 to demonstrate that the TSM 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 conduct 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 TSM emission rate.

(17) If you demonstrate compliance with an applicable TSM

emission limit through fuel analysis for solid or liquid fuels, 

and you plan to burn a new type of fuel, you must recalculate 

the TSM emission rate using Equation 14 of §63.7530 according to 

the procedures specified in paragraphs (a)(5)(i) through (iii) 

of this section. You are not required to conduct 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 TSM emission rate.

(i) You must determine the TSM 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 TSM.
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(iii) Recalculate the TSM emission rate from your boiler or 

process heater under these new conditions using Equation 14 of 

§63.7530. The recalculated TSM emission rate must be less than 

the applicable emission limit. 

(18) If you demonstrate continuous PM emissions compliance 

with a PM CPMS you will use a PM CPMS to establish a sitespecific operating limit corresponding to the results of the 

performance test demonstrating compliance with the PM limit. You 

will conduct your performance test using the test method 

criteria in Table 5 of this subpart. You will use the PM CPMS to 

demonstrate continuous compliance with this operating limit. You 

must repeat the performance test annually and reassess and 

adjust the site-specific operating limit in accordance with the 

results of the performance test. 

(i) To determine continuous compliance, you must record the 

PM CPMS output data for all periods when the process is 

operating and the PM CPMS is not out-of-control. You must 

demonstrate continuous compliance by using all quality-assured 

hourly average data collected by the PM CPMS for all operating 

hours to calculate the arithmetic average operating parameter in 

units of the operating limit (milliamps) on a 30-day rolling 

average basis, updated at the end of each new boiler or process 

heater operating hour.
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(ii) For any deviation of the 30-day rolling PM CPMS 

average value from the established operating parameter limit, 

you must:

(A) Within 48 hours of the deviation, visually inspect the 

air pollution control device (APCD);

(B) If inspection of the APCD identifies the cause of the 

deviation, take corrective action as soon as possible and return 

the PM CPMS measurement to within the established value; and

(C) Within 30 days of the deviation or at the time of the 

annual compliance test, whichever comes first, conduct a PM 

emissions compliance test to determine compliance with the PM 

emissions limit and to verify or re-establish the CPMS operating 

limit. You are not required to conduct additional testing for 

any deviations that occur between the time of the original 

deviation and the PM emissions compliance test required under 

this paragraph.

(iii) PM CPMS deviations from the operating limit leading 

to more than four required performance tests in a 12-month 

operating period constitute a separate violation of this 

subpart.

(19) If you choose to comply with the PM filterable 

emissions limit by using PM CEMS you must install, certify, 

operate, and maintain a PM CEMS and record the output of the PM 

CEMS as specified in paragraphs (a)(19)(i) through (vii) of this 
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section. The compliance limit will be expressed as a 30-day 

rolling average of the numerical emissions limit value 

applicable for your unit in Tables 1 or 2 or 11 through 13 of 

this subpart.

(i) Install and certify your PM CEMS according to the 

procedures and requirements in Performance Specification 11 —

Specifications and Test Procedures for Particulate Matter

Continuous Emission Monitoring Systems at Stationary Sources in 

Appendix B to part 60 of this chapter, using test criteria 

outlined in Table V of this rule. The reportable measurement 

output from the PM CEMS must be expressed in units of the 

applicable emissions limit (e.g., lb/MMBtu, lb/MWh).

(ii) Operate and maintain your PM CEMS according to the 

procedures and requirements in Procedure 2 — Quality Assurance 

Requirements for Particulate Matter Continuous Emission

Monitoring Systems at Stationary Sources in Appendix F to part 

60 of this chapter.

(A) You must conduct the relative response audit (RRA) for 

your PM CEMS at least once annually.

(B) You must conduct the relative correlation audit (RCA) for 

your PM CEMS at least once every 3 years.

(iii) Collect PM CEMS hourly average output data for all 

boiler operating hours except as indicated in paragraph (i) of 

this section.
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(iv) Calculate the arithmetic 30-day rolling average of all 

of the hourly average PM CEMS output data collected during all 

nonexempt boiler or process heater operating hours.

(v) You must collect data using the PM CEMS at all times 

the unit is operating and at the intervals specified in 

paragraph (a) of this section, except for periods of monitoring 

system malfunctions, repairs associated with monitoring system 

malfunctions, and required monitoring system quality assurance 

or quality control activities.

(vi) You must use all the data collected during all boiler

or process heater operating hours in assessing the compliance 

with your operating limit except:

(A) Any data collected during monitoring system 

malfunctions, repairs associated with monitoring system 

malfunctions, or required monitoring system quality assurance or 

control activities conducted during monitoring system 

malfunctions in calculations and report any such periods in your 

annual deviation report;

(B) Any data collected during periods when the monitoring 

system is out of control as specified in your site-specific 

monitoring plan, repairs associated with periods when the 

monitoring system is out of control, or required monitoring 

system quality assurance or control activities conducted during 

out of control periods in calculations used to report emissions 
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or operating levels and report any such periods in your annual 

deviation report;

(C) Any data recorded during periods of startup or 

shutdown.

(vii) You must record and make available upon request 

results of PM CEMS system performance audits, dates and duration 

of periods when the PM CEMS is out of control to completion of 

the corrective actions necessary to return the PM CEMS to 

operation consistent with your site-specific monitoring plan.

(b) You must report each instance in which you did not meet 

each emission limit and operating limit in Tables 1 through 4 or 

11 through 13 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 unit designed to burn gas 1 

subcategory, you must follow the sampling frequency specified in 

paragraphs (1) through (4) of this section and conduct this 

sampling according to the procedures in §63.7521(f) through (i).

(1) If the initial mercury constituents in the gaseous 

fuels are measured to be equal to or less than half of the 

mercury specification as defined in §63.7575, you do not need to 

conduct further sampling. 
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(2) If the initial mercury constituents are greater than 

half but equal to or less than 75 percent of the mercury 

specification as defined in §63.7575, you will conduct semiannual sampling. If 6 consecutive semi-annual fuel analyses

demonstrate 50 percent or less of the mercury specification, you 

do not need to conduct further sampling. If any semi-annual 

sample exceeds 75 percent of the mercury specification, you must 

return to monthly sampling for that fuel, until 12 months of 

fuel analyses again are less than 75 percent of the compliance 

level.

(3) If the initial mercury constituents are greater than 75

percent of the mercury specification as defined in §63.7575, you 

will conduct monthly sampling. If 12 consecutive monthly fuel 

analyses demonstrate 75 percent or less of the mercury 

specification, you may decrease the fuel analysis frequency to 

semi-annual for that fuel. 

(4) If the initial sample exceeds the mercury specification 

as defined in §63.7575, each affected boiler or process heater 

combusting this fuel is not part of the unit designed to burn 

gas 1 subcategory and must be in compliance with the emission 

and operating limits for the appropriate subcategory. You may 

elect to conduct additional monthly sampling while complying 

with these emissions and operating limits to demonstrate that 

the fuel qualifies as an other gas 1 fuel. If 12 consecutive 
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monthly fuel analyses samples are at or below the mercury 

specification as defined in §63.7575, each affected boiler or 

process heater combusting the fuel can elect to switch back into 

the unit designed to burn gas 1 subcategory until the mercury 

specification is exceeded. 

(d) For startup and shutdown, you must meet the work 

practice standards according to item 5 of Table 3 of this 

subpart.

23. Section 63.7541 is amended by revising paragraphs 

(a)(3) and (a)(4) to read as follows:

§63.7541 How do I demonstrate continuous compliance under the 

emissions averaging provision?

* * * * *

(a) * * *

(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 above 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 

parameter, maintain the 30-day rolling average parameter values 

consistent with the approved monitoring plan.

* * * * *
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24. Section 63.7545 is amended by:

a. Revising paragraph (a).

b. Revising paragraph (b).

c. Revising paragraph (c).

d. Revising paragraphs (e) introductory text, (e)(1), 

(e)(2), (e)(3), (e)(4), (e)(5) introductory text, and (e)(5)(i).

e. Adding paragraph (e)(5)(ii).

f. Revising paragraphs (e)(8)(i) and (e)(8)(iii).

g. Revising paragraph (f) introductory text.

h. Revising paragraphs (g)(1) and (g)(2).

i. Revising paragraphs (h) introductory text and (h)(1).

j. Revising paragraph (h)(3).

k. Removing paragraph (h)(4).

The revisions read as follows:

§63.7545 What notifications must I submit and when?

(a) You must submit to the Administrator 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 OF PUBLICATION IN THE 

FEDERAL REGISTER], you must submit an Initial Notification not 

later than 120 days after [INSERT THE DATE OF PUBLICATION IN THE 

FEDERAL REGISTER].
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(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 OF PUBLICATION 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.

* * * * *

(e) If you are required to conduct an initial compliance 

demonstration as specified in §63.7530, you must submit a 

Notification of Compliance Status according to §63.9(h)(2)(ii). 

For the initial compliance demonstration for each boiler or 

process heater, you must submit the Notification of Compliance 

Status, including all performance test results and fuel 

analyses, before the close of business on the 60th day following 

the completion of all performance test and/or other initial 

compliance demonstrations for all boiler or process heaters at 

the facility 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. If 

you are not required to conduct an initial compliance 

demonstration as specified in §63.7530(a), the Notification of 

Compliance Status must only contain the information specified in 

paragraphs (e)(1) and (e)(8).

(1) A description of the affected unit(s) including 

identification of which subcategories the unit is in, the design 
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heat input capacity of the unit, a description of the add-on 

controls used on the unit to comply with this subpart, 

description of the fuel(s) burned, including whether the fuel(s) 

were a secondary material determined by you or the EPA through a 

petition process to be a non-waste under §241.3 of this chapter, 

whether the fuel(s) were a secondary material processed from 

discarded non-hazardous secondary materials within the meaning 

of §241.3 of this chapter, 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, 

and including:

(i) Identification of whether you are complying with the PM 

emission limit or the alternative TSM emission limit.

(ii) Identification of whether you are complying with the 

output-based emission limits or the heat input-based (i.e., 

lb/MMBtu or ppm) emission limits,

(3) A summary of the maximum CO emission levels recorded 

during the performance test to show that you have met any 

applicable emission standard in Tables 1, 2, or 11 through 13 to 

this subpart, if you are not using a CO CEMS to demonstrate 

compliance.
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(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 efficiency 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 OF 

PUBLICATION IN THE FEDERAL REGISTER].

(ii) [Reserved]

* * * * *

(8) * * *

(i) “This facility complies with the required initial tuneup according to the procedures in §63.7540(a)(10)(i) through 

(vi).”

* * * * *

(iii) Except for units that burn only natural gas, refinery 

gas, or other gas 1 fuel, or 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.”
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(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, part 60, 61, or 65, 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.

* * * * *

(g) * * *

(1) The name of the owner or operator of the affected 

source, as defined in §63.7490, 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 subcategories under this 

subpart. 

* * * * *

(h) If you have switched fuels or made a physical change to 

the boiler and the fuel switch or physical change resulted in 

the applicability of a different subcategory, you must provide 
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notice of the date upon which you switched fuels or made the 

physical change within 30 days of the switch/change. The 

notification must identify:

(1) The name of the owner or operator of the affected 

source, as defined in §63.7490, the location of the source, the 

boiler(s) and process heater(s) that have switched fuels, were 

physically changed, and the date of the notice.

* * * * *

(3) The date upon which the fuel switch or physical change 

occurred.

25. Section 63.7550 is revised to read as follows:

§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, according to paragraph (h), by the date in 

Table 9 to this subpart and according to the requirements in 

paragraphs (b)(1) through (4) 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 
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specified in paragraphs (b)(1) through (4) 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 each 

boiler or process heater in §63.7495 and ending on July 31 or 

January 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 

submitted 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 each boiler or 

process heater in §63.7495. The first annual, biennial, or 5-

year compliance report must be postmarked or submitted 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.
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(4) Each subsequent compliance report must be postmarked or 

submitted 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 or submitted no later than January 31.

(c) A compliance report must contain the following 

information depending on how the facility chooses to comply with 

the limits set in this rule. 

(1) If the facility is subject to a the requirements of a

tune up they must submit a compliance report with the 

information in (c)(5)(i)-(iv), and (xiv). 

(2) If a facility is complying with the fuel analysis they 

must submit a compliance report with the information in 

(c)(5)(i)-(iv), (vi), (x), (xi), (xiii), (xv) and paragraph (d). 

(3) If a facility is complying with the applicable 

emissions limit with performance testing they must submit a 

compliance report with the information in (c)(5)(i)-(iv), (vi), 

(vii), (ix), (xi), (xiii), (xv) and paragraph (d). 

(4) If a facility is complying with an emissions limit 

using a CMS the compliance report must contain the information 

required in paragraphs (c)(5)(i)–(vi), (xi), (xiii), (xv)-

(xvii), and paragraph (e).

(5)(i) Company and Facility name and address.
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(ii) Process unit information, emissions limitations, and 

operating parameter limitations.

(iii) Date of report and beginning and ending dates of the 

reporting period.

(iv) The total operating time during the reporting period.

(v) If you use a CMS, including CEMS, COMS, or CPMS, you 

must include the monitoring equipment manufacturer(s) and model 

numbers and the date of the last CMS certification or audit.

(vi) The total fuel use by each individual boiler or 

process heater subject to an emission limit within the reporting 

period, including, but not limited to, a description of the 

fuel, whether the fuel has received a non-waste determination by 

the EPA or your basis for concluding that the fuel is not a 

waste, and the total fuel usage amount with units of measure.

(vii) 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 and a statement as to whether there have been 

any operational changes since the last performance test that 

could increase emissions.

(viii) A statement indicating that you burned no new types 

of fuel in an individual boiler or process heater subject to an 

emission limit. Or, if you did burn a new type of fuel and are 

subject to a HCl emission limit, you must submit the calculation 

of chlorine input, using Equation 7 of §63.7530, that 
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demonstrates that your source is still within its maximum 

chlorine input level established during the previous performance 

testing (for sources that demonstrate compliance through 

performance testing) or you must submit the calculation of HCl

emission rate using Equation 12 of §63.7530 that demonstrates 

that your source is still meeting the emission limit for HCl

emissions (for boilers or process heaters that demonstrate 

compliance through fuel analysis). If you burned a new type of 

fuel and are subject to a mercury emission limit, you must 

submit the calculation of mercury 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 13 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 TSM emission limit, you 

must submit the calculation of TSM input, using Equation 9 of 

§63.7530, that demonstrates that your source is still within its 

maximum TSM input level established during the previous 

performance testing (for sources that demonstrate compliance 

through performance testing), or you must submit the calculation 
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of TSM emission rate, using Equation 14 of §63.7530, that 

demonstrates that your source is still meeting the emission 

limit for TSM emissions (for boilers or process heaters that 

demonstrate compliance through fuel analysis).

(ix) If you wish to burn a new type of fuel in an 

individual boiler or process heater 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 limit using Equation 8 of 

§63.7530, or the maximum TSM 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.

(x) A summary of any monthly fuel analyses conducted to 

demonstrate compliance according to §§63.7521 and 63.7530 for 

individual boilers or process heaters subject to emission 

limits, and any fuel specification analyses conducted according 

to §63.7521(f) and §63.7530(g).

(xi) 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.

(xii) If there were no deviations from the monitoring 

requirements including no periods during which the CMSs, 
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including CEMS, COMS, and CPMS, were out of control as specified 

in §63.8(c)(7), a statement that there were no deviations and no 

periods during which the CMS were out of control during the 

reporting period.

(xiii) 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 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.

(xiv) 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.

(xv) 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 
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control technology contained in the notification of compliance 

status in §63.7545(e)(5)(i).

(xvi) For each reporting period, the compliance reports 

must include all of the calculated 30 day rolling average values 

based on the daily CEMS (CO and mercury) and CPMS (PM CPMS 

output, scrubber pH, scrubber liquid flow rate, scrubber 

pressure drop) data.

(xvii) 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.

(d) For each deviation from an emission limit or operating 

limit in this subpart that occurs at an individual boiler or 

process heater 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 (3) of this section.

(1) A description of the deviation and which emission limit 

or operating limit from which you deviated.

(2) Information on the number, duration, and cause of 

deviations (including unknown cause), as applicable, and the 

corrective action taken.

(3) If the deviation occurred during an annual performance 

test, provide the date the annual performance test was 

completed.
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(e) For each deviation from an emission limit, operating 

limit, and monitoring requirement in this subpart occurring at 

an individual boiler or process heater where you are using a CMS 

to comply with that emission limit or operating limit, the 

compliance report must additionally contain the information 

required in paragraphs (e)(1) through (9) of this section. This 

includes any deviations from your site-specific monitoring plan 

as required in §63.7505(d).

(1) The date and time that each deviation started and 

stopped and description of the nature of the deviation (i.e., 

what you deviated from).

(2) The date and time that each CMS was inoperative, except 

for zero (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) A characterization 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.
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(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) A brief description of the source for which there was a 

deviation.

(9) 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) [Reserved]

(g) [Reserved]

(h) You must submit the reports according to the procedures 

specified in paragraphs (h)(1) through (3) of this section.

(1) Within 60 days after the date of completing each 

performance test (defined in §63.2) as required by this subpart 

you must submit the results of the performance tests, including 

any associated fuel analyses, required by this subpart and the 

compliance reports required in §63.7550(b) to the EPA’s WebFIRE 

database by using the Compliance and Emissions Data Reporting 

Interface (CEDRI) that is accessed through the EPA’s Central 

Data Exchange (CDX)(www.epa.gov/cdx). Performance test data must 

be submitted in the file format generated through use of the 

EPA’s Electronic Reporting Tool (ERT) (see 

http://www.epa.gov/ttn/chief/ert/index.html). Only data 
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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 the EPA via CDX as 

described earlier in this paragraph. At the discretion of the

Administrator, you must also submit these reports, including the 

confidential business information, to the Administrator in the 

format specified by the Administrator. For any performance test 

conducted using test methods that are not listed on the ERT 

website, the owner or operator shall submit the results of the 

performance test in paper submissions to the Administrator.

(2) Within 60 days after the date of completing each CEMS 

performance evaluation test (defined in 63.2) you must submit 

the relative accuracy test audit (RATA) data to the EPA’s 

Central Data Exchange by using CEDRI as mentioned in paragraph 

(h)(1) of this section. Only RATA pollutants that can be 
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documented with the ERT (as listed on the ERT website) are 

subject to this requirement. For any performance evaluations 

with no corresponding RATA pollutants listed on the ERT website, 

the owner or operator shall submit the results of the 

performance evaluation in paper submissions to the 

Administrator.

(3) You must submit all reports required by Table 9 of this 

subpart electronically using CEDRI that is accessed through the 

EPA’s Central Data Exchange (CDX)(www.epa.gov/cdx). However, if 

the reporting form specific to this subpart is not available in 

CEDRI at the time that the report is due the report you must 

submit the report to the Administrator at the appropriate 

address listed in §63.13. At the discretion of the 

Administrator, you must also submit these reports, to the 

Administrator in the format specified by the Administrator.

26. Section 63.7555 is amended by:

a. Revising paragraphs (d) introductory text, (d)(2), 

(d)(3), (d)(4), (d)(5), and (d)(6). 

b. Adding paragraphs (d)(9), (d)(10), and (d)(11).

c. Revising paragraph (f).

d. Revising paragraph (g).

e. Revising paragraph (h).

f. Adding paragraph (i).

g. Adding paragraph (j).
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The revisions read as follows: 

§63.7555 What records must I keep?

* * * * *

(d) For each boiler or process heater subject to an

emission limit in Tables 1, 2, or 11 through 13 to this subpart, 

you must also keep the applicable records in paragraphs (d)(1) 

through (11) of this section.

* * * * *

(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) of this chapter, you must keep a record 

that documents how the secondary material meets each of the 

legitimacy criteria under §241.3(d)(1) of this chapter. If you 

combust a fuel that has been processed from a discarded nonhazardous secondary material pursuant to §241.3(b)(4) of this 

chapter, you must keep records as to how the operations that 

produced the fuel satisfy the definition of processing in §241.2 

of this chapter. If the fuel received a non-waste determination 

pursuant to the petition process submitted under §241.3(c) of 

this chapter, you must keep a record that documents how the fuel 

satisfies the requirements of the petition process. For 

operating units that combust non-hazardous secondary materials 

as fuel per §241.4 of this chapter, you must keep records 

documenting that the material is listed as a non-waste under 
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§241.4(a) of this chapter. Units exempt from the incinerator 

standards under section 129(g)(1) of the Clean Air Act because 

they are qualifying facilities burning a homogeneous waste 

stream do not need to maintain the records described in this 

paragraph (d)(2).

(3) For units in the limited use subcategory, you must keep 

a copy of the federally enforceable permit that limits the 

annual capacity factor to less than or equal to 10 percent and 

fuel use records for the days the boiler or process heater was 

operating. 

(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 HCl

emission limit, for sources that demonstrate compliance through 

performance testing. For sources that demonstrate compliance 

through fuel analysis, a copy of all calculations and supporting 

documentation of HCl emission rates, using Equation 12 of 

§63.7530, that were done to demonstrate compliance with the HCl

emission limit. Supporting documentation should include results 

of any fuel analyses and basis for the estimates of maximum 

chlorine fuel input or HCl emission rates. You can use the 

results from one fuel analysis for multiple boilers and process 

heaters provided they are all burning the same fuel type. 
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However, you must calculate chlorine fuel input, or HCl emission 

rate, for each boiler and process heater.

(5) A copy of all calculations and supporting documentation 

of maximum mercury fuel input, using Equation 8 of §63.7530, 

that were done to demonstrate continuous compliance with the 

mercury emission limit for sources that demonstrate compliance 

through performance testing. For sources that demonstrate 

compliance through fuel analysis, a copy of all calculations and 

supporting documentation of mercury emission rates, using 

Equation 13 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), you choose to stack 

test less frequently than annually, you must keep a record that 

documents 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 or 11 through 13 to 

this subpart, less than the applicable emission limit), and 
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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.

* * * * *

(9) A copy of all calculations and supporting documentation 

of maximum TSM fuel input, using Equation 9 of §63.7530, that 

were done to demonstrate continuous compliance with the TSM

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 TSM emission rates, using Equation 14 of 

§63.7530, that were done to demonstrate compliance with the TSM

emission limit. Supporting documentation should include results 

of any fuel analyses and basis for the estimates of maximum TSM

fuel input or TSM 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 TSM fuel input, or TSM emission rates, for each 

boiler and process heater.

(10) You must maintain records of the calendar date, time,

occurrence and duration of each startup and shutdown.

(11) You must maintain records of the type(s) and amount(s) 

of fuels used during each startup and shutdown. 
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* * * * *

(f) If you elect to use efficiency 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 unit designed to burn gas 1 

subcategory, you must maintain monthly records (or at the 

frequency required by §63.7540(c)) of the calculations and 

results of the fuel specification for mercury in Table 6. 

(h) If you operate a unit in the unit designed to burn gas 

1 subcategory 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 part, other gas 1 

fuel, or gaseous fuel subject to another subpart of this part or 

part 60, 61, or 65, you must keep records of the total hours per 

calendar year that alternative fuel is burned and the total 

hours per calendar year that the unit operated during periods of 

gas curtailment or gas supply emergencies.

(i) You must maintain records of the calendar date, time,

occurrence and duration of each startup and shutdown.
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(j) You must maintain records of the type(s) and amount(s) 

of fuels used during each startup and shutdown. 

27. Section 63.7570 is amended by revising paragraph (a) 

and paragraph (b) introductory text. 

§63.7570 Who implements and enforces this subpart?

(a) This subpart can be implemented and enforced by the 

EPA, or an Administrator such as your state, local, or tribal 

agency. If the EPA Administrator has delegated authority to your 

state, local, or tribal agency, then that agency (as well as the 

EPA) has the authority to implement and enforce this subpart. 

You should contact your EPA Regional Office to find out if this 

subpart is delegated to your state, local, or tribal agency.

(b) In delegating implementation and enforcement authority 

of this subpart to a state, local, or tribal agency under 40 CFR 

part 63, subpart E, the authorities listed in paragraphs (b)(1) 

through (5) of this section are retained by the EPA 

Administrator and are not transferred to the state, local, or 

tribal agency, however, the EPA retains oversight of this 

subpart and can take enforcement actions, as appropriate.

* * * * *

28. Section 63.7575 is amended by:

a. Adding in alphabetical order definitions for “10-day 

rolling average,” “30-day rolling average,” “Annual capacity 

factor,” “Average annual heat input rate,” “Benchmark,” 
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“Biodiesel,” “Daily block average,” “Efficiency credit,” “Energy 

management program,” “Fluidized bed boiler with an integrated 

fluidized bed heat exchanger,” “Heavy liquid,” “Light liquid,” “ 

“Major source for oil and natural gas production facilities,” 

“Minimum oxygen level,” “Other combustor”, “Oxygen analyzer 

system”, “Oxygen trim system”, “Pile burner”, “Regulated gas 

stream”, “Residential boiler,” “Residual oil”, “Secondary 

material,” “Shutdown”, “Sloped grate”, “Startup”, “Stoker/sloped 

grate/other unit designed to burn kiln dried biomass,” 

Stoker/sloped grate/other unit designed to burn wet biomass,” 

“Suspension burner,” “Total selected metals (TSM),” “Traditional 

fuel,” “Ultra low sulfur liquid fuel,” “Unit designed to burn 

heavy liquid subcategory,” “Unit designed to burn light liquid 

subcategory,” and “Vegetable oil.”

b. Revising the definitions for “Boiler,” “Boiler system,” 

“Coal,” Commercial/institutional boiler,” “Deviation,” 

“Distillate oil,” “Dry scrubber,” “Dutch oven,” “Electric 

utility steam generating unit,” “Energy assessment,” “Energy use 

system,” “Equivalent,” “Federally enforceable,” “Fluidized bed 

boiler”, “Fuel cell,” “Fuel type,” “Gaseous fuel,” “Heat input,” 

“Hot water heater,” “Hybrid suspension grate boiler,” 

“Industrial boiler,” “Limited-use boiler or process heater,” 

“Liquid fuel,” “Load fraction,” “Metal process furnaces,” 

“Minimum activated carbon injection rate,” “Minimum scrubber 
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liquid flow rate,” “Minimum sorbent injection rate,” “Natural 

gas,” “Other gas 1 fuel,” “Period of natural gas curtailment or 

supply interruption,” “Process heater,” “Qualified energy 

assessor,” “Residual oil,” “Solid fossil fuel,” “Steam output,” 

“Stoker,” “Temporary boiler,” “Tune-up,” “Unit designed to burn 

gas 1 subcategory,” “Unit designed to burn gas 2 (other) 

subcategory,” “Unit designed to burn liquid subcategory,” “Unit 

designed to burn liquid fuel that is a non-continental unit,”

“Unit designed to burn solid fuel,” “Waste heat boiler,” “Waste 

heat process heater.”

c. Removing the definitions for “Benchmarking,” “Emission 

credit,” “Liquid fuel subcategory,” and “Suspension boiler.”

§63.7575 What definitions apply to this subpart?

* * * * *

10-day rolling average means the arithmetic mean of the 

previous 240 hours of valid operating data. Valid data excludes 

hours during startup and shutdown, data collected during periods 

when the monitoring system is out of control as specified in 

your site-specific monitoring plan, while conducting repairs 

associated with periods when the monitoring system is out of 

control, or while conducting required monitoring system quality 

assurance or quality control activities, and periods when this 

unit is not operating. The 240 hours should be consecutive, but 

not necessarily continuous if operations were intermittent. 
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30-day rolling average means the arithmetic mean of the 

previous 720 hours of valid operating data. Valid data excludes 

hours during startup and shutdown, data collected during periods 

when the monitoring system is out of control as specified in 

your site-specific monitoring plan, while conducting repairs 

associated with periods when the monitoring system is out of 

control, or while conducting required monitoring system quality 

assurance or quality control activities, and periods when this 

unit is not operating. The 720 hours should be consecutive, but 

not necessarily continuous if operations were intermittent. 

* * * * *

Annual capacity factor means the ratio between the actual 

heat input to a boiler or process heater from the fuels burned 

during a calendar year and the potential heat input to the 

boiler or process heater had it been operated for 8,760 hours 

during a year at the maximum steady state design heat input 

capacity.

Average annual heat input rate means total heat input 

divided by the hours of operation for the 12 months preceding 

the compliance demonstration.

* * * * *

Benchmark means the fuel heat input for a boiler or process 

heater for the one-year period before the date that an energy 

demand reduction occurs, unless it can be demonstrated that a 
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different time period is more representative of historical 

operations.

Biodiesel means a mono-akyl ester derived from biomass and 

conforming to ASTM D6751–11b, Standard Specification for 

Biodiesel Fuel Blend Stock (B100) for Middle Distillate Fuels 

(incorporated by reference, see §63.14).

* * * * *

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 of this 

chapter, 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 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 systems, steam systems, and condensate return systems. 

* * * * *

Coal means all solid fuels classifiable as anthracite, 

bituminous, sub-bituminous, or lignite by ASTM D388 
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(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, 

including but not limited to, solvent-refined coal, coal-oil 

mixtures, and coal-water mixtures. Coal derived gases are 

excluded from this definition.

* * * * *

Commercial/institutional boiler means a boiler used in 

commercial establishments or institutional establishments such 

as medical centers, nursing homes, research centers, 

institutions of higher education, elementary and secondary 

schools, libraries, religious establishments, governmental 

buildings, hotels, restaurants, and laundries to provide 

electricity, steam, and/or hot water.

* * * * *

Daily block average means the arithmetic mean of all valid 

emission concentrations or parameter levels recorded when a unit 

is operating measured over the 24-hour period from 12 am 

(midnight) to 12 am (midnight), except for periods of startup 

and shutdown or downtime. 

Deviation.

(1) Deviation means any instance in which an affected 

source subject to this subpart, or an owner or operator of such 

a source:
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(i) Fails to meet any applicable 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. 

* * * * *

Distillate oil means fuel oils that contain 0.05 weight 

percent nitrogen or less and comply with the specifications for 

fuel oil numbers 1 and 2, as defined by the American Society of 

Testing and Materials in ASTM D396 (incorporated by reference, 

see §63.14) or diesel fuel oil numbers 1 and 2, as defined by 

the American Society for Testing and Materials in ASTM D975

(incorporated by reference, see §63.14), kerosene, and biodiesel 

as defined by the American Society of Testing and Materials in 

ASTM D6751-11b (incorporated by reference, see §60.14).

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 used as control devices in fluidized bed 
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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 (EGU) means a fossil 

fuel-fired combustion unit of more than 25 megawatts electric 

(MWe) that serves a generator that produces electricity for 

sale. A fossil fuel-fired unit that cogenerates steam and 

electricity and supplies more than one-third of its potential 

electric output capacity and more than 25 MWe 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, 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 
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percent of the annual heat input during any one calendar year 

after April 16, 2012.

* * * * *

Efficiency credit means emission reductions above those 

required by this subpart. Efficiency 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. Boilers that are shut down cannot be used to 

generate credits unless the facility provides documentation 

linking the permanent shutdown to implementation of the energy 

conservation measures identified in the energy assessment.

Energy assessment means the following for the emission 

units covered by this subpart: 

(1) The energy assessment for facilities with affected 

boilers and process heaters with a combined heat input capacity 

of less than 0.3 trillion Btu (TBtu) per year capacity will be 8 

on-site 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(s) and any on-site energy use 

system(s) accounting for at least 50 percent of the affected 

boiler(s) energy (e.g., steam, hot water, process heat, or 

electricity) production, as applicable, will be evaluated to 

identify energy savings opportunities, within the limit of 

performing an 8-hour on-site energy assessment.
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(2) The energy assessment for facilities with affected 

boilers and process heaters with a combined heat input capacity 

of 0.3 to 1.0 TBtu/year heat will be 24 on-site 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(s) and any on-site energy use system(s) accounting for at 

least 33 percent of the energy (e.g., steam, hot water, process 

heat, or electricity) production, as applicable, will be 

evaluated to identify energy savings opportunities, within the 

limit of performing a 24-hour on-site energy assessment.

(3) The energy assessment for facilities with affected 

boilers and process heaters with a combined heat input capacity 

greater than 1.0 TBtu/year will be up to 24 on-site technical 

labor hours in length for the first TBtu/yr plus 8 on-site 

technical labor hours for every additional 1.0 TBtu/yr not to 

exceed 160 on-site technical hours, but may be longer at the

discretion of the owner or operator of the affected source. The 

boiler system(s), process heater(s), and any on-site energy use 

system(s) accounting for at least 20 percent of the energy 

(e.g., steam, process heat, hot water, or electricity) 

production, as applicable, will be evaluated to identify energy 

savings opportunities.

(4) The on-site energy use systems serving as the basis for 

the percent of affected boiler(s) and process heater(s) energy 
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production in (1), (2), and (3) above may be segmented by 

production area or energy use area as most logical and 

applicable to the specific facility being assessed (e.g., 

product X manufacturing area; product Y drying area; Building 

Z).

* * * * *

Energy management program means a program that includes a 

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. Facilities may establish their program through 

energy management systems compatible with ISO 50001.

Energy use system includes the following systems located 

on-site that use energy (steam, hot water, or electricity)

provided by the affected boiler or process heater: (1)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; or (2) other systems that use steam, hot water, 

process heat, or electricity provided by the affected boiler or 
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process heater. Energy use systems are only those systems using 

energy clearly produced by affected boilers and process heaters.

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.

(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 
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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, HCl) 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.

* * * * *

Federally enforceable means all limitations and conditions 

that are enforceable by the EPA Administrator, including, but 

not limited to, the requirements of 40 CFR parts 60, 61, 63, and 

65, 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 boiler with an integrated fluidized bed heat 

exchanger means a boiler utilizing a fluidized bed combustion 
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where the entire tube surface area is located outside of the 

furnace section at the exit of the cyclone section and exposed 

to the flue gas stream for conductive heat transfer. This design 

applies only to boilers in the unit designed to burn coal/solid 

fossil fuel subcategory that fire coal refuse. 

* * * * *

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, distillate oil, residual oil. Individual fuel types 

received from different suppliers are not considered new fuel 

types. 

Gaseous fuel includes, but is not limited to, natural gas, 

process gas, landfill gas, coal derived gas, refinery gas, and 

biogas. Blast furnace gas and process gases that are regulated 

under another subpart of this part, or part 60, part 61, or part 

65 of this chapter, are exempted from this definition.
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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, returned 

condensate, 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.

* * * * *

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, liquid, or biomass/bio-based solid fuel 

and is withdrawn for use external to the vessel. Hot water 

boilers (i.e., not generating steam) combusting gaseous, liquid, 

or biomass fuel with a heat input capacity of less than 1.6 

million Btu per hour are included in this definition. The 120 

U.S. gallon capacity threshold to be considered a hot water 

heater is independent of the 1.6 MMBtu/hr heat input capacity 

threshold for hot water boilers. 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 biomass fuel 

combusted in these units exceeds a moisture content of 40 

percent on an as-fired annual heat input basis. The drying and 
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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, hot water, and/or electricity.

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 and has a federally enforceable average annual 

capacity factor of no more than 10 percent.

Liquid fuel includes, but is not limited to, light liquid, 

heavy liquid, any form of liquid fuel derived from petroleum, 

used oil, liquid biofuels, biodiesel, vegetable oil, and 

comparable fuels as defined under 40 CFR 261.38.

Load fraction means the actual heat input of a boiler or 

process heater divided by heat input during the performance test 

that established the minimum sorbent injection rate or minimum 

activated carbon injection rate, expressed as a fraction (e.g., 

for 50 percent load the load fraction is 0.5). 
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Major source for oil and natural gas production facilities, 

as used in this subpart, shall have the same meaning as in 

§63.2, except that:

(1) Emissions from any oil or gas exploration or production 

well (with its associated equipment, as defined in this 

section), and emissions from any pipeline compressor station or 

pump station shall not be aggregated with emissions from other 

similar units to determine whether such emission points or 

stations are major sources, even when emission points are in a 

contiguous area or under common control;

(2) Emissions from processes, operations, or equipment that 

are not part of the same facility, as defined in this section, 

shall not be aggregated; and

(3) For facilities that are production field facilities, 

only HAP emissions from glycol dehydration units and storage 

vessels with the potential for flash emissions shall be 

aggregated for a major source determination. For facilities that 

are not production field facilities, HAP emissions from all HAP 

emission units shall be aggregated for a major source 

determination.

Metal process furnaces are a subcategory of process 

heaters, as defined in this subpart, which include natural gasfired annealing furnaces, preheat furnaces, reheat furnaces, 

aging furnaces, heat treat furnaces, and homogenizing furnaces.
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* * * * *

Minimum activated carbon injection rate means load fraction 

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 limit.

Minimum oxygen level means the lowest hourly average oxygen 

level measured according to Table 7 to this subpart during the 

most recent performance test demonstrating compliance with the 

applicable emission limit.

* * * * *

Minimum scrubber liquid flow rate means the lowest hourly 

average liquid flow rate (e.g., to the PM scrubber or to the 

acid gas scrubber) measured according to Table 7 to this subpart 

during the most recent performance stack test demonstrating 

compliance with the applicable emission limit.

* * * * *

Minimum sorbent injection rate means:

(1) The load fraction 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; or
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(2) For fluidized bed combustion, the lowest average ratio 

of sorbent to sulfur measured during the most recent performance 

test.

* * * * *

Natural gas means:

(1) A naturally occurring mixture of hydrocarbon and 

nonhydrocarbon gases found in geologic formations beneath the 

earth's surface, of which the principal constituent is methane; 

or

(2) Liquefied 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 35 and 41 megajoules (MJ) per dry 

standard cubic meter (950 and 1,100 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.

* * * * *

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, 
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stoker, sloped grate, or suspension boiler as defined in this 

subpart.

Other gas 1 fuel means a gaseous fuel that is not natural 

gas or refinery gas and does not exceed a 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 or process heater flue gas, boiler or 

process heater, firebox, or other appropriate location. 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 CO

monitor that automatically provides a feedback signal to the 

combustion air controller. 

* * * * *

Period of gas curtailment or supply interruption means a 

period of time during which the supply of gaseous fuel to an 

affected boiler or process heater is restricted or halted for 

reasons beyond the control of the facility. The act of entering 

into a contractual agreement with a supplier of natural gas 
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established for curtailment purposes does not constitute a 

reason that is under the control 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 (e.g., glycol or a mixture of glycol and 

water) for use in a process unit, instead of generating steam. 

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 of this chapter, is 
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not a process heater 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. 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 are excluded from this definition.

* * * * *

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

(B) Applied steam energy versus direct-fired energy versus 

electricity.

(v) Insulation issues.

(vi) Steam trap and steam leak management.

(vi) Condensate recovery.
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(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.

* * * * *

Regulated gas stream means an offgas stream that is routed 

to a boiler or process heater for the purpose of achieving 

compliance with a standard under another subpart of this part or 

part 60, part 61, or part 65 of this chapter.

Residential boiler means a boiler used to provide heat 

and/or hot water and/or as part of a residential combined heat 

and power system. This definition includes boilers located at an 
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institutional facility (e.g., university campus, military base, 

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

used primarily to provide heat and/or hot water for: 

(1) A dwelling containing four or fewer families; or

(2) A single unit residence dwelling that has since been 

converted or subdivided into condominiums or apartments. 

Residual oil means crude oil, fuel oil that does not comply 

with the specifications under the definition of distillate oil, 

and all fuel oil numbers 4, 5, and 6, as defined by the American 

Society of Testing and Materials in ASTM D396–10 (incorporated 

by reference, see §63.14(b)).

* * * * *

Secondary material means the material as defined in §241.2 

of this chapter.

Shutdown means the cessation of operation of a boiler or 

process heater for any purpose. Shutdown begins either when none 

of the steam from the boiler is supplied for heating and/or 

producing electricity, or for any other purpose, or at the point 

of no fuel being fired in the boiler or process heater, 

whichever is earlier. Shutdown ends when there is no steam and

no heat being supplied and no fuel being fired in the boiler or 

process heater. 

Sloped grate means a unit where the solid fuel is fed to 

the top of the grate from where it slides downwards; while 
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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. 

Solid fossil fuel includes, but is not limited to, coal, 

coke, petroleum coke, and tire derived fuel. 

* * * * *

Startup means either the first-ever firing of fuel in a 

boiler or process heater for the purpose of supplying steam or 

heat for heating and/or producing electricity, or for any other 

purpose, or the firing of fuel in a boiler after a shutdown 

event for any purpose. Startup ends when any of the steam or 

heat from the boiler or process heater is supplied for heating, 

and/or producing electricity, or for any other purpose. 

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 
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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 21 through 25 of this section, as appropriate:

(i) For emission limits for boilers in the unit designed to 

burn solid fuel subcategory use Equation 21 of this section:

ELOBE = ELT x 12.7 MMBtu/Mwh (Eq. 21)

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.

(ii) For PM and CO emission limits for boilers in one of 

the subcategories of units designed to burn coal use Equation 22

of this section:

ELOBE = ELT x 12.2 MMBtu/Mwh (Eq. 22)

Where:

ELOBE = Emission limit in units of pounds per megawatthour.

ELT = Appropriate emission limit from Table 1 or 2 of 

this subpart in units of pounds per million Btu heat 

input.

(iii) For PM and CO emission limits for boilers in one of 

the subcategories of units designed to burn biomass use Equation 

23 of this section:
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ELOBE = ELT x 13.9 MMBtu/Mwh (Eq. 23)

Where:

ELOBE = Emission limit in units of pounds per megawatthour.

ELT = Appropriate emission limit from Table 1 or 2 of 

this subpart in units of pounds per million Btu heat 

input.

(iv) For emission limits for boilers in the one of the 

subcategories of units designed to burn liquid fuels use 

Equation 24 of this section:

ELOBE = ELT x 13.8 MMBtu/Mwh (Eq. 24)

Where:

ELOBE = Emission limit in units of pounds per megawatthour.

ELT = Appropriate emission limit from Table 1 or 2 of 

this subpart in units of pounds per million Btu heat 

input.

(v) For emission limits for boilers in the unit designed to 

burn gas 2 (other) subcategory, use Equation 25 of this section:

ELOBE = ELT x 10.4 MMBtu/Mwh (Eq. 25)

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 
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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 

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 on an 

annual heat input basis. 

Suspension burner means a unit designed to fire dry 

biomass/biobased solid particles in suspension that are conveyed 

in an airstream to the furnace like pulverized coal. The 

combustion of the fuel material is completed on a grate or floor 
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below. The biomass/biobased fuel combusted in the unit shall not 

exceed 20 percent moisture on an annual heat input basis. 

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:

(1) The equipment is attached to a foundation.

(2) The boiler or a replacement remains at a location 

within the facility and performs the same or similar function 

for more than 12 consecutive months, unless the regulatory 

agency approves an extension. An extension may be granted by the 

regulating agency upon petition by the owner or operator of a 

unit specifying the basis for such a request. 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.
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(4) The equipment is moved from one location to another 

within the facility but continues to perform the same or similar 

function and serve the same electricity, steam, and/or hot water 

system in an attempt to circumvent the residence time 

requirements of this definition.

Total selected metals (TSM) means the sum of the following 

metallic hazardous air pollutants: arsenic, beryllium, cadmium, 

chromium, lead, manganese, nickel and selenium.

Traditional fuel means the fuel as defined in §241.2 of 

this chapter.

Tune-up means adjustments made to a boiler or process 

heater in accordance with the procedures outlined in 

§63.7540(a)(10).

* * * * *

Ultra low sulfur liquid fuel means a distillate oil that 

has less than or equal to 15 ppm sulfur.

* * * * *

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. 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, are 

included in this definition. Gaseous fuel boilers and process 
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heaters that burn liquid fuel during periods of gas curtailment 

or gas supply interruptions of any duration are also included in 

this definition.

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, and less than 10 percent biomass/bio-based solid fuel on 

an annual heat input basis, and no liquid fuels. Gaseous fuel 

boilers and process heaters that are not in the unit designed to 

burn gas 1 subcategory and 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, 

are included in this definition. Gaseous fuel boilers and 

process heaters that are not in the unit designed to burn gas 1 

subcategory and that burn liquid fuel during periods of gas 

curtailment or gas supply interruption of any duration are also 

included in this definition.

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.
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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. Units in the 

unit design to burn gas 1 or unit designed to burn gas 2 (other) 

subcategories 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 are not 

included in this definition. Units in the unit design to burn 

gas 1 or unit designed to burn gas 2 (other) subcategories

during periods of gas curtailment or gas supply interruption 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 meeting the definition of the unit designed to 

burn liquid subcategory 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 
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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.

* * * * *

Waste heat boiler means a device that recovers normally 

unused energy (i.e., hot exhaust gas) and converts it to usable 

heat. Waste heat boilers are also referred to as heat recovery 

steam generators. Waste heat boilers are heat exchangers 

generating steam from incoming hot exhaust gas from an 

industrial (e.g., thermal oxidizer, kiln, furnace) or power 

(e.g., combustion turbine, engine) equipment. Duct burners are 

sometimes used to increase the temperature of the incoming hot

exhaust gas.

Waste heat process heater means an enclosed device that 

recovers normally unused energy (i.e., hot exhaust gas) 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.

* * * * *

29. Table 1 to subpart DDDDD of part 63 is revised to read 

as follows:
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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 

startup and 

shutdown...

Or the 

emissions 

must not 

exceed the 

following 

alternative 

outputbased 

limits, 

except 

during 

startup and 

shutdown...

Using this 

specified 

sampling 

volume or 

test run 

duration...

1. Units in 

all 

subcategories 

designed to 

burn solid 

fuel.

a. HCl. 2.2E-02 lb 

per MMBtu 

of heat 

input.

2.5E-02 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.
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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 

startup and 

shutdown...

Or the 

emissions 

must not 

exceed the 

following 

alternative 

outputbased 

limits, 

except 

during 

startup and 

shutdown...

Using this 

specified 

sampling 

volume or 

test run 

duration...

b. 

Mercury.

8.0E-07a lb 

per MMBtu 

of heat 

input.

8.7E-07a lb 

per MMBtu 

of steam 

output or 

1.1E-05a 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. Units 

design to burn 

coal/solid 

fossil fuel.

a. 

Filterable 

PM (or 

TSM).

1.1E-03 lb 

per MMBtu 

of heat 

input; or 

(2.3E-05 lb 

per MMBtu 

of heat 

input). 

1.1E-03 lb 

per MMBtu 

of steam 

output or 

1.4E-02 lb 

per MWh; or 

(2.7E-05 lb 

per MMBtu 

of steam 

output or 

2.9E-04 lb 

per MWh).

Collect a 

minimum of 

3 dscm per 

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

Page 288 of 374

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 

startup and 

shutdown...

Or the 

emissions 

must not 

exceed the 

following 

alternative 

outputbased 

limits, 

except 

during 

startup and 

shutdown...

Using this 

specified 

sampling 

volume or 

test run 

duration...

3. Pulverized 

coal boilers 

designed to 

burn 

coal/solid 

fossil fuel.

a. Carbon 

monoxide 

(CO) (or 

CEMS).

130 ppm by 

volume on a 

dry basis 

corrected 

to 3 

percent 

oxygen, 3-

run 

average; or 

(320 ppm by 

volume on a 

dry basis 

corrected 

to 3 

percent 

oxygen, 30-

day rolling 

average).

0.11 lb per 

MMBtu of 

steam 

output or 

1.4 lb per 

MWh; 3-run 

average.

1 hr 

minimum 

sampling 

time.

4. Stokers 

designed to 

burn 

coal/solid 

fossil fuel.

a. CO (or 

CEMS).

130 ppm by 

volume on a 

dry basis 

corrected 

to 3 

percent 

oxygen, 3-

run 

average; or 

(340 ppm by 

volume on a 

dry basis 

corrected 

to 3 

percent 

oxygen, 30-

0.12 lb per 

MMBtu of 

steam 

output or 

1.4 lb per 

MWh; 3-run 

average.

1 hr 

minimum 

sampling 

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

Page 289 of 374

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 

startup and 

shutdown...

Or the 

emissions 

must not 

exceed the 

following 

alternative 

outputbased 

limits, 

except 

during 

startup and 

shutdown...

Using this 

specified 

sampling 

volume or 

test run 

duration...

day rolling 

average).

5. Fluidized 

bed units 

designed to 

burn 

coal/solid 

fossil fuel.

a. CO (or 

CEMS).

130 ppm by 

volume on a 

dry basis 

corrected 

to 3 

percent 

oxygen, 3-

run 

average; or 

(230 ppm by 

volume on a 

dry basis 

corrected 

to 3 

percent 

oxygen, 30-

day rolling 

average).

0.11 lb per 

MMBtu of 

steam 

output or 

1.4 lb per 

MWh; 3-run 

average.

1 hr 

minimum 

sampling 

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

Page 290 of 374

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 

startup and 

shutdown...

Or the 

emissions 

must not 

exceed the 

following 

alternative 

outputbased 

limits, 

except 

during 

startup and 

shutdown...

Using this 

specified 

sampling 

volume or 

test run 

duration...

6. Fluidized 

bed units with 

an integrated 

heat exchanger 

designed to 

burn 

coal/solid 

fossil fuel.

a. CO (or 

CEMS).

140 ppm by 

volume on a 

dry basis 

corrected 

to 3 

percent 

oxygen, 3-

run 

average; or 

(150 ppm by 

volume on a 

dry basis 

corrected 

to 3 

percent 

oxygen, 30-

day rolling 

average).

1.2E-01 lb 

per MMBtu 

of steam 

output or 

1.5 lb per 

MWh; 3-run 

average.

1 hr 

minimum 

sampling 

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

Page 291 of 374

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 

startup and 

shutdown...

Or the 

emissions 

must not 

exceed the 

following 

alternative 

outputbased 

limits, 

except 

during 

startup and 

shutdown...

Using this 

specified 

sampling 

volume or 

test run 

duration...

7. 

Stokers/sloped 

grate/others 

designed to 

burn wet 

biomass fuel.

a. CO (or 

CEMS).

620 ppm by 

volume on a 

dry basis

corrected 

to 3 

percent 

oxygen, 3-

run 

average; or 

(390 ppm by 

volume on a 

dry basis 

corrected 

to 3 

percent 

oxygen, 30-

day rolling 

average).

5.8E-01 lb 

per MMBtu 

of steam 

output or 

6.8 lb per 

MWh; 3-run 

average.

1 hr 

minimum 

sampling 

time.

b. 

Filterable 

PM (or 

TSM).

3.0E-02 lb 

per MMBtu 

of heat 

input; or 

(2.6E-05 lb 

per MMBtu 

of heat 

input).

3.5E-02 lb 

per MMBtu 

of steam 

output or 

4.2E-01 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.
***E.O. 12866 Review – Draft – Do Not Cite, Quote, or Release During Review***

Page 292 of 374

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 

startup and 

shutdown...

Or the 

emissions 

must not 

exceed the 

following 

alternative 

outputbased 

limits, 

except 

during 

startup and 

shutdown...

Using this 

specified 

sampling 

volume or 

test run 

duration...

8. 

Stokers/sloped 

grate/others 

designed to 

burn kilndried biomass 

fuel.

a. CO. 460 ppm by 

volume on a 

dry basis 

corrected 

to 3 

percent 

oxygen.

4.2E-01 lb 

per MMBtu 

of steam 

output or 

5.1 lb per 

MWh.

1 hr 

minimum 

sampling 

time.

b. 

Filterable 

PM (or 

TSM).

3.0E-02 lb 

per MMBtu 

of heat 

input; or 

(4.0E-03 lb 

per MMBtu 

of heat 

input).

3.5E-02 lb 

per MMBtu 

of steam 

output or 

4.2E-01 lb 

per MWh; or 

(4.2E-03 lb 

per MMBtu 

of steam 

output or 

5.6E-02 lb 

per MWh).

Collect a 

minimum of 

2 dscm per 

run.

9. 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 

(310 ppm by 

volume on a 

dry basis 

corrected 

to 3 

percent 

2.2E-01 lb 

per MMBtu

of steam 

output or 

2.6 lb per 

MWh; 3-run 

average.

1 hr 

minimum 

sampling 

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

Page 293 of 374

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 

startup and 

shutdown...

Or the 

emissions 

must not 

exceed the 

following 

alternative 

outputbased 

limits, 

except 

during 

startup and 

shutdown...

Using this 

specified 

sampling 

volume or 

test run 

duration...

oxygen, 30-

day rolling 

average).

b. 

Filterable 

PM (or 

TSM).

9.8E-03 lb 

per MMBtu 

of heat 

input; or 

(8.3E-05a

lb per 

MMBtu of 

heat 

input).

1.2E-02 lb 

per MMBtu 

of steam 

output or 

0.14 lb per 

MWh; or 

(1.1E-04

a

lb per 

MMBtu of 

steam 

output or 

1.2E-03a lb 

per MWh).

Collect a 

minimum of 

3 dscm per 

run.

10. Suspension 

burners 

designed to 

burn 

biomass/biobased solids.

a. CO (or 

CEMS).

2,400 ppm 

by volume 

on a dry 

basis 

corrected 

to 3 

percent 

oxygen, 3-

run 

average; or 

(2,000 ppm 

by volume 

on a dry 

basis 

corrected 

to 3 

percent 

oxygen, 10-

1.9 lb per 

MMBtu of 

steam 

output or 

27 lb per 

MWh; 3-run 

average.

1 hr 

minimum 

sampling 

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

Page 294 of 374

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 

startup and 

shutdown...

Or the 

emissions 

must not 

exceed the 

following 

alternative 

outputbased 

limits, 

except 

during 

startup and 

shutdown...

Using this 

specified 

sampling 

volume or 

test run 

duration...

day rolling 

average).

b. 

Filterable 

PM (or 

TSM).

3.0E-02 lb 

per MMBtu 

of heat 

input; or

(6.5E-03 lb 

per MMBtu 

of heat 

input).

3.1E-02 lb 

per MMBtu 

of steam 

output or 

4.2E-01 lb 

per MWh; or 

(6.6E-03 lb 

per MMBtu 

of steam 

output or 

9.1E-02 lb 

per MWh).

Collect a 

minimum of 

2 dscm per 

run.

11. Dutch 

Ovens/Pile 

burners 

designed to 

burn 

biomass/biobased solids.

a. CO (or 

CEMS).

330 ppm by 

volume on a 

dry basis 

corrected 

to 3 

percent 

oxygen, 3-

run 

average; or 

(520 ppm by 

volume on a 

dry basis 

corrected 

to 3 

percent 

oxygen, 10-

day rolling 

average).

3.5E-01 lb 

per MMBtu 

of steam 

output or 

3.6 lb per 

MWh; 3-run 

average.

1 hr 

minimum 

sampling 

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

Page 295 of 374

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 

startup and 

shutdown...

Or the 

emissions 

must not 

exceed the 

following 

alternative 

outputbased 

limits, 

except 

during 

startup and 

shutdown...

Using this 

specified 

sampling 

volume or 

test run 

duration...

b. 

Filterable 

PM (or 

TSM).

3.2E-03 lb 

per MMBtu 

of heat 

input; or 

(3.9E-05 lb 

per MMBtu 

of heat 

input).

4.3E-03 lb 

per MMBtu 

of steam 

output or 

4.5E-02 lb 

per MWh; or 

(5.2E-05 lb 

per MMBtu 

of steam 

output or 

5.5E-04 lb 

per MWh).

Collect a 

minimum of 

3 dscm per 

run.

12. Fuel cell 

units designed 

to burn 

biomass/biobased solids.

a. CO 910 ppm by 

volume on a 

dry basis 

corrected 

to 3 

percent 

oxygen.

1.1 lb per 

MMBtu of 

steam 

output or 

1.0E+01 lb 

per MWh.

1 hr

minimum 

sampling 

time.

b. 

Filterable 

PM (or 

TSM).

2.0E-02 lb 

per MMBtu 

of heat 

input; or 

(2.9E-05a

lb per 

MMBtu of 

heat 

input).

3.0E-02 lb 

per MMBtu 

of steam 

output or 

2.8E-01 lb 

per MWh; or 

(5.1E-05 lb 

per MMBtu 

of steam 

output or 

4.1E-04 lb 

per MWh).

Collect a 

minimum of 

2 dscm per 

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

Page 296 of 374

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 

startup and 

shutdown...

Or the 

emissions 

must not 

exceed the 

following 

alternative 

outputbased 

limits, 

except 

during 

startup and 

shutdown...

Using this 

specified 

sampling 

volume or 

test run 

duration...

13. Hybrid 

suspension 

grate boiler 

designed to 

burn 

biomass/biobased solids.

a. CO (or 

CEMS).

1,100 ppm 

by volume 

on a dry 

basis 

corrected 

to 3 

percent 

oxygen, 3-

run 

average; or 

(900 ppm by 

volume on a 

dry basis 

corrected 

to 3 

percent 

oxygen, 30-

day rolling 

average).

1.4 lb per 

MMBtu of 

steam 

output or 

12 lb per 

MWh; 3-run 

average.

1 hr 

minimum 

sampling 

time.

b. 

Filterable 

PM (or 

TSM).

2.6E-02 lb 

per MMBtu 

of heat 

input; or 

(4.4E-04 lb 

per MMBtu 

of heat 

input).

3.3E-02 lb 

per MMBtu 

of steam 

output or 

3.7E-01 lb 

per MWh; or 

(5.5E-04 lb 

per MMBtu 

of steam 

output or 

6.2E-03 lb 

per MWh). 

Collect a 

minimum of 

3 dscm per 

run.

14. Units 

designed to 

burn liquid 

a. HCl 4.4E-04 lb 

per MMBtu 

of heat 

4.8E-04 lb 

per MMBtu 

of steam 

For M26A: 

Collect a 

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

Page 297 of 374

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 

startup and 

shutdown...

Or the 

emissions 

must not 

exceed the 

following 

alternative 

outputbased 

limits, 

except 

during 

startup and 

shutdown...

Using this 

specified 

sampling 

volume or 

test run 

duration...

fuel. input. output or 

6.1E-03 lb 

per MWh.

2 dscm per 

run; for 

M26, 

collect a 

minimum of 

240 liters 

per run.

b. 

Mercury.

4.8E-07a lb 

per MMBtu 

of heat 

input.

5.3E-07a lb 

per MMBtu 

of steam 

output or 

6.7E-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 

method; for 

ASTM D6784b

collect a 

minimum of 

4 dscm.

15. Units 

designed to 

burn heavy 

liquid fuel.

a. CO. 130 ppm by 

volume on a 

dry basis 

corrected 

to 3 

percent 

oxygen, 3-

run 

average.

0.13 lb per 

MMBtu of 

steam 

output or 

1.4 lb per 

MWh; 3-run 

average.

1 hr 

minimum 

sampling 

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

Page 298 of 374

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 

startup and 

shutdown...

Or the 

emissions 

must not 

exceed the 

following 

alternative 

outputbased 

limits, 

except 

during 

startup and 

shutdown...

Using this 

specified 

sampling 

volume or 

test run 

duration...

b. 

Filterable 

PM (or 

TSM).

1.3E-02 lb 

per MMBtu 

of heat 

input; or 

(7.5E-05 lb 

per MMBtu 

of heat 

input).

1.5E-02 lb 

per MMBtu 

of steam 

output or 

1.8E-01 lb 

per MWh; or 

(8.2E-05 lb 

per MMBtu 

of steam 

output or 

1.1E-03 lb 

per MWh).

Collect a 

minimum of 

3 dscm per 

run.

16. Units 

designed to 

burn light 

liquid fuel.

a. CO. 130 ppm by 

volume on a 

dry basis 

corrected 

to 3 

percent 

oxygen.

0.13 lb per 

MMBtu of 

steam 

output or 

1.4 lb per 

MWh.

1 hr 

minimum 

sampling 

time.

b. 

Filterable 

PM (or 

TSM).

1.1E-03a lb 

per MMBtu 

of heat 

input; or 

(2.9E-05 lb 

per MMBtu 

of heat 

input).

1.2E-03a lb 

per MMBtu 

of steam 

output or 

1.6E-02a lb 

per MWh; or 

(3.2E-05 lb 

per MMBtu 

of steam 

output or 

4.0E-04 lb 

per MWh).

Collect a 

minimum of 

3 dscm per 

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

Page 299 of 374

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 

startup and 

shutdown...

Or the 

emissions 

must not 

exceed the 

following 

alternative 

outputbased 

limits, 

except 

during 

startup and 

shutdown...

Using this 

specified 

sampling 

volume or 

test run 

duration...

17. Units 

designed to 

burn liquid 

fuel that are 

noncontinental 

units.

a. CO. 130 ppm by 

volume on a 

dry basis 

corrected 

to 3 

percent 

oxygen, 3-

run average 

based on 

stack test.

0.13 lb per 

MMBtu of 

steam 

output or 

1.4 lb per 

MWh; 3-run 

average.

1 hr 

minimum 

sampling 

time.

b. 

Filterable 

PM (or 

TSM). 

2.3E-02 lb 

per MMBtu 

of heat 

input; or 

(8.6E-04 lb 

per MMBtu 

of heat 

input).

2.5E-02 lb 

per MMBtu 

of steam 

output or 

3.2E-01 lb 

per MWh; or 

(9.4E-04 lb 

per MMBtu 

of steam 

output or 

1.2E-02 lb 

per MWh).

Collect a 

minimum of 

4 dscm per 

run.

18. Units 

designed to 

burn gas 2 

(other) gases.

a. CO. 130 ppm by 

volume on a 

dry basis 

corrected 

to 3 

percent 

oxygen.

0.16 lb per 

MMBtu of 

steam 

output or 

1.0 lb per 

MWh.

1 hr 

minimum 

sampling 

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

Page 300 of 374

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 

startup and 

shutdown...

Or the 

emissions 

must not 

exceed the 

following 

alternative 

outputbased 

limits, 

except 

during 

startup and 

shutdown...

Using this 

specified 

sampling 

volume or 

test run 

duration...

b. HCl. 1.7E-03 lb 

per MMBtu 

of heat 

input.

2.9E-03 lb 

per MMBtu 

of steam 

output or 

1.8E-02 lb 

per MWh

For M26A,

Collect a 

minimum of 

2 dscm per 

run; for 

M26, 

collect a 

minimum of 

240 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 

in the 

method; for 

ASTM D6784b

collect a 

minimum of 

3 dscm.

d. 

Filterable 

PM (or 

TSM).

6.7E-03 lb 

per MMBtu 

of heat 

input; or 

(2.1E-04 lb 

per MMBtu 

1.2E-02 lb 

per MMBtu 

of steam 

output or 

7.0E-02 lb 

per MWh; or 

Collect a 

minimum of 

3 dscm per 

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

Page 301 of 374

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 

startup and 

shutdown...

Or the 

emissions 

must not 

exceed the 

following 

alternative 

outputbased 

limits, 

except 

during 

startup and 

shutdown...

Using this 

specified 

sampling 

volume or 

test run 

duration...

of heat 

input).

(3.5E-04 lb 

per MMBtu 

of steam 

output or 

2.2E-03 lb 

per MWh).

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 below 75 percent of this limit in order 

to qualify for skip testing. 

b Incorporated by reference, see §63.14.

c If your affected source is a new or reconstructed affected 

source that commenced construction or reconstruction after June 

4, 2010, and before [INSERT THE DATE OF PUBLICATION IN THE 

FEDERAL REGISTER], you may comply with the emission limits in 

Tables 11, 12 or 13 to this subpart until [INSERT THE DATE 3 

YEARS AFTER THE DATE OF PUBLICATION IN THE FEDERAL REGISTER]. On 

and after [INSERT THE DATE 3 YEARS AFTER THE DATE OF PUBLICATION 

IN THE FEDERAL REGISTER], you must comply with the emission 

limits in Table 1 to this subpart.

30. Table 2 to subpart DDDDD of part 63 is revised to read 

as follows:
***E.O. 12866 Review – Draft – Do Not Cite, Quote, or Release During Review***

Page 302 of 374

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 

startup and 

shutdown...

The 

emissions 

must not 

exceed the 

following 

alternative 

outputbased 

limits, 

except 

during 

startup and 

shutdown...

Using this 

specified 

sampling 

volume or 

test run 

duration...

1. Units in 

all 

subcategories 

designed to 

burn solid 

fuel.

a. HCl 2.2E-02 lb 

per MMBtu 

of heat 

input.

2.5E-02 lb 

per MMBtu 

of steam 

output or 

0.27 lb per 

MWh.

For M26A, 

Collect a 

minimum of 

1 dscm per 

run; for 

M26, 

collect a 

minimum of 

120 liters 

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

Page 303 of 374

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 

startup and 

shutdown...

The 

emissions 

must not 

exceed the 

following 

alternative 

outputbased 

limits, 

except 

during 

startup and 

shutdown...

Using this 

specified 

sampling 

volume or 

test run 

duration...

b. 

Mercury.

5.7E-06 lb 

per MMBtu 

of heat 

input.

6.4E-06 lb 

per MMBtu 

of steam 

output or 

7.3E-05 lb 

per MWh.

For M29, 

collect a 

minimum of 

3 dscm per 

run; for 

M30A or 

M30B, 

collect a 

minimum 

sample as 

specified 

in the 

method; for 

ASTM D6784b

collect a 

minimum of 

3 dscm.

2. Units 

design to burn 

coal/solid 

fossil fuel.

a. 

Filterable 

PM (or 

TSM).

4.0E-02 lb 

per MMBtu 

of heat 

input; or 

(5.3E-05 lb 

per MMBtu 

of heat 

input).

4.2E-02 lb 

per MMBtu 

of steam 

output or 

4.9E-01 lb 

per MWh; or 

(5.6E-05 lb 

per MMBtu 

of steam 

output or 

6.5E-04 lb 

per MWh).

Collect a 

minimum of 

2 dscm per 

run.

3. Pulverized 

coal boilers 

designed to 

burn 

a. CO (or 

CEMS).

130 ppm by 

volume on a 

dry basis 

corrected 

0.11 lb per 

MMBtu of 

steam 

output or 

1 hr 

minimum 

sampling 

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

Page 304 of 374

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 

startup and 

shutdown...

The 

emissions 

must not 

exceed the 

following 

alternative 

outputbased 

limits, 

except 

during 

startup and 

shutdown...

Using this 

specified 

sampling 

volume or 

test run 

duration...

coal/solid 

fossil fuel.

to 3 

percent 

oxygen, 3-

run 

average; or 

(320 ppm by 

volume on a 

dry basis 

corrected 

to 3 

percent 

oxygen, 30-

day rolling 

average).

1.4 lb per 

MWh; 3-run 

average.

4. Stokers 

designed to 

burn 

coal/solid 

fossil fuel.

a. CO (or 

CEMS).

160 ppm by 

volume on a 

dry basis 

corrected 

to 3 

percent 

oxygen, 3-

run 

average; or 

(340 ppm by 

volume on a 

dry basis 

corrected 

to 3 

percent 

oxygen, 30-

day rolling 

average).

0.14 lb per 

MMBtu of 

steam 

output or 

1.7 lb per 

MWh; 3-run 

average.

1 hr 

minimum 

sampling 

time.

5. Fluidized 

bed units 

a. CO (or 

CEMS).

130 ppm by 

volume on a 

0.12 lb per 

MMBtu of 

1 hr 

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

Page 305 of 374

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 

startup and 

shutdown...

The 

emissions 

must not 

exceed the 

following 

alternative 

outputbased 

limits, 

except 

during 

startup and 

shutdown...

Using this 

specified 

sampling 

volume or 

test run 

duration...

designed to 

burn coal/ 

solid fossil 

fuel.

dry basis 

corrected 

to 3 

percent 

oxygen, 3-

run 

average; or 

(230 ppm by 

volume on a 

dry basis 

corrected 

to 3 

percent 

oxygen, 30-

day rolling 

average).

steam 

output or 

1.4 lb per 

MWh; 3-run 

average.

sampling 

time.

6. Fluidized 

bed units with 

an integrated 

heat exchanger 

designed to 

burn 

coal/solid 

fossil fuel.

a. CO (or 

CEMS).

140 ppm by 

volume on a 

dry basis 

corrected 

to 3 

percent 

oxygen, 3-

run 

average; or 

(150 ppm by 

volume on a 

dry basis 

corrected 

to 3 

percent 

oxygen, 30-

day rolling 

average).

1.3E-01 lb 

per MMBtu 

of steam 

output or 

1.5 lb per 

MWh; 3-run 

average.

1 hr 

minimum 

sampling 

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

Page 306 of 374

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 

startup and 

shutdown...

The 

emissions 

must not 

exceed the 

following 

alternative 

outputbased 

limits, 

except 

during 

startup and 

shutdown...

Using this 

specified 

sampling 

volume or 

test run 

duration...

7. 

Stokers/sloped 

grate/others 

designed to 

burn wet 

biomass fuel.

a. CO (or 

CEMS).

1,500 ppm 

by volume 

on a dry 

basis 

corrected 

to 3 

percent 

oxygen, 3-

run 

average; or 

(720 ppm by 

volume on a 

dry basis 

corrected 

to 3 

percent 

oxygen, 30-

day rolling 

average).

1.4 lb per 

MMBtu of 

steam 

output or 

17 lb per 

MWh; 3-run 

average.

1 hr 

minimum 

sampling 

time.

b. 

Filterable 

PM (or 

TSM).

3.7E-02 lb 

per MMBtu 

of heat 

input; or 

(2.4E-04 lb 

per MMBtu 

of heat 

input).

4.3E-02 lb 

per MMBtu 

of steam 

output or 

5.2E-01 lb 

per MWh; or 

(2.8E-04 lb 

per MMBtu 

of steam 

output or 

3.4E-04 lb 

per MWh).

Collect a 

minimum of 

2 dscm per 

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

Page 307 of 374

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 

startup and 

shutdown...

The 

emissions 

must not 

exceed the 

following 

alternative 

outputbased 

limits, 

except 

during 

startup and 

shutdown...

Using this 

specified 

sampling 

volume or 

test run 

duration...

8. 

Stokers/sloped 

grate/others 

designed to 

burn kilndried biomass 

fuel.

a. CO. 460 ppm by 

volume on a 

dry basis 

corrected 

to 3 

percent 

oxygen.

4.2E-01 lb 

per MMBtu 

of steam 

output or 

5.1 lb per 

MWh.

1 hr 

minimum 

sampling 

time.

b. 

Filterable 

PM (or 

TSM).

3.2E-01 lb 

per MMBtu 

of heat 

input; or 

(4.0E-03 lb 

per MMBtu 

of heat 

input).

3.7E-01 lb 

per MMBtu 

of steam 

output or 

4.5 lb per 

MWh; or 

(4.6E-03 lb 

per MMBtu 

of steam 

output or 

5.6E-02 lb 

per MWh). 

Collect a 

minimum of 

1 dscm per 

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

Page 308 of 374

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 

startup and 

shutdown...

The 

emissions 

must not 

exceed the 

following 

alternative 

outputbased 

limits, 

except 

during 

startup and 

shutdown...

Using this 

specified 

sampling 

volume or 

test run 

duration...

9. Fluidized 

bed units 

designed to 

burn 

biomass/biobased solid.

a. CO (or 

CEMS).

470 ppm by 

volume on a 

dry basis 

corrected 

to 3 

percent 

oxygen, 3-

run 

average; or 

(310 ppm by 

volume on a 

dry basis 

corrected 

to 3 

percent 

oxygen, 30-

day rolling 

average).

4.6E-01 lb 

per MMBtu 

of steam 

output or 

5.2 lb per 

MWh; 3-run 

average.

1 hr 

minimum 

sampling 

time.

b. 

Filterable 

PM (or 

TSM).

1.1E-01 lb 

per MMBtu 

of heat 

input; or 

(1.2E-03 lb 

per MMBtu 

of heat 

input). 

1.4E-01 lb 

per MMBtu 

of steam 

output or 

1.6 lb per 

MWh; or 

(1.5E-03 lb 

per MMBtu 

of steam 

output or 

1.7E-02 lb 

per MWh).

Collect a 

minimum of 

1 dscm per 

run.

10. Suspension 

burners 

designed to 

burn 

a. CO (or 

CEMS).

2,400 ppm 

by volume 

on a dry 

basis 

1.9 lb per 

MMBtu of 

steam 

output or 

1 hr 

minimum 

sampling 

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

Page 309 of 374

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 

startup and 

shutdown...

The 

emissions 

must not 

exceed the 

following 

alternative 

outputbased 

limits, 

except 

during 

startup and 

shutdown...

Using this 

specified 

sampling 

volume or 

test run 

duration...

biomass/biobased solid.corrected 

to 3 

percent 

oxygen, 3-

run 

average; or 

(2,000 ppm 

by volume 

on a dry 

basis 

corrected 

to 3 

percent 

oxygen, 10-

day rolling 

average).

27 lb per 

MWh; 3-run 

average.

b. 

Filterable 

PM (or 

TSM).

5.1E-02 lb 

per MMBtu 

of heat 

input; or 

(6.5E-03 lb 

per MMBtu 

of heat 

input). 

5.2E-02 lb 

per MMBtu 

of steam 

output or 

7.1E-01 lb 

per MWh; or 

(6.6E-03 lb 

per MMBtu 

of steam 

output or 

9.1E-02 lb 

per MWh).

Collect a 

minimum of 

2 dscm per 

run.

11. Dutch 

Ovens/Pile 

burners 

designed to 

burn 

biomass/bioa. CO (or 

CEMS).

770 ppm by 

volume on a 

dry basis 

corrected

to 3 

percent 

8.4E-01 lb 

per MMBtu 

of steam 

output or 

8.4 lb per 

MWh; 3-run 

1 hr 

minimum 

sampling 

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

Page 310 of 374

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 

startup and 

shutdown...

The 

emissions 

must not 

exceed the 

following 

alternative 

outputbased 

limits, 

except 

during 

startup and 

shutdown...

Using this 

specified 

sampling 

volume or 

test run 

duration...

based solid. oxygen, 3-

run 

average; or 

(520 ppm by 

volume on a 

dry basis 

corrected 

to 3 

percent 

oxygen, 10-

day rolling 

average).

average.

b. 

Filterable 

PM (or 

TSM).

2.8E-01 lb 

per MMBtu 

of heat 

input; or 

(2.0E-03 lb 

per MMBtu 

of heat 

input).

3.9E-01 lb 

per MMBtu 

of steam 

output or 

3.9 lb per 

MWh; or 

(2.8E-03 lb 

per MMBtu 

of steam 

output or 

2.8E-02 lb 

per MWh). 

Collect a 

minimum of 

1 dscm per 

run.

12. Fuel cell 

units designed 

to burn 

biomass/ biobased solid.

a. CO. 1,100 ppm 

by volume 

on a dry 

basis 

corrected 

to 3 

percent 

oxygen.

2.4 lb per 

MMBtu of 

steam 

output or 

12 lb per 

MWh.

1 hr 

minimum 

sampling 

time.

b. 

Filterable 

2.0E-02 lb 

per MMBtu 

5.5E-02 lb 

per MMBtu 

Collect a 

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

Page 311 of 374

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 

startup and 

shutdown...

The 

emissions 

must not 

exceed the 

following 

alternative 

outputbased 

limits, 

except 

during 

startup and 

shutdown...

Using this 

specified 

sampling 

volume or 

test run 

duration...

PM (or 

TSM).

of heat 

input; or 

(5.8E-03 lb 

per MMBtu 

of heat 

input). 

of steam 

output or 

2.8E-01 lb 

per MWh; or 

(1.6E-02 lb 

per MMBtu 

of steam 

output or 

8.1E-02 lb 

per MWh). 

2 dscm per 

run.

13. Hybrid 

suspension 

grate units 

designed to 

burn biomass/ 

bio-based 

solid.

a. CO (or 

CEMS).

2,800 ppm 

by volume 

on a dry 

basis 

corrected 

to 3 

percent 

oxygen, 3-

run 

average; or 

(900 ppm by 

volume on a 

dry basis 

corrected 

to 3 

percent 

oxygen, 30-

day rolling 

average).

2.8 lb per 

MMBtu of 

steam 

output or 

31 lb per 

MWh; 3-run 

average.

1 hr 

minimum 

sampling 

time.

b. 

Filterable 

PM (or 

TSM).

4.4E-01 lb 

per MMBtu 

of heat 

input; or 

(4.5E-04 lb 

5.5E-01 lb 

per MMBtu 

of steam 

output or 

6.2 lb per 

Collect a 

minimum of 

1 dscm per 

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

Page 312 of 374

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 

startup and 

shutdown...

The 

emissions 

must not 

exceed the 

following 

alternative 

outputbased 

limits, 

except 

during 

startup and 

shutdown...

Using this 

specified 

sampling 

volume or 

test run 

duration...

per MMBtu 

of heat 

input). 

MWh; or 

(5.7E-04 lb 

per MMBtu 

of steam 

output or 

6.3E-03 lb 

per MWh).

14. Units 

designed to 

burn liquid 

fuel.

a. HCl. 1.1E-03 lb 

per MMBtu 

of heat 

input.

1.4E-03 lb 

per MMBtu 

of steam 

output or 

1.6E-02 lb 

per MWh.

For M26A, 

collect a 

minimum of 

2 dscm per 

run; for 

M26, 

collect a 

minimum of 

240 liters 

per run.

b. 

Mercury.

2.0E-06 lb 

per MMBtu 

of heat 

input.

2.5E-06 lb 

per MMBtu 

of steam 

output or 

2.8E-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 
***E.O. 12866 Review – Draft – Do Not Cite, Quote, or Release During Review***

Page 313 of 374

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 

startup and 

shutdown...

The 

emissions 

must not 

exceed the 

following 

alternative 

outputbased 

limits, 

except 

during 

startup and 

shutdown...

Using this 

specified 

sampling 

volume or 

test run 

duration...

2 dscm.

15. Units 

designed to 

burn heavy 

liquid fuel.

a. CO. 130 ppm by 

volume on a 

dry basis 

corrected 

to 3 

percent 

oxygen, 3-

run 

average.

0.13 lb per 

MMBtu of 

steam 

output or 

1.4 lb per 

MWh; 3-run 

average.

1 hr 

minimum 

sampling 

time.

b. 

Filterable 

PM (or 

TSM).

6.2E-02 lb 

per MMBtu 

of heat 

input; or 

(2.0E-04 lb 

per MMBtu 

of heat 

input).

7.5E-02 lb 

per MMBtu 

of steam 

output or 

8.6E-01 lb 

per MWh; or 

(2.5E-04 lb 

per MMBtu 

of steam 

output or 

2.8E-03 lb 

per MWh).

Collect a 

minimum of 

1 dscm per 

run.

16. Units 

designed to 

burn light 

liquid fuel.

a. CO. 130 ppm by 

volume on a 

dry basis 

corrected 

to 3 

percent 

oxygen.

0.13 lb per 

MMBtu of 

steam 

output or 

1.4 lb per 

MWh.

1 hr 

minimum 

sampling 

time.

b. 

Filterable 

PM (or 

TSM).

7.9E-03 lb 

per MMBtu 

of heat 

input; or 

(6.2E-05 lb 

9.6E-03 lb 

per MMBtu 

of steam 

output or 

1.1E-01 lb 

Collect a 

minimum of 

3 dscm per 

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

Page 314 of 374

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 

startup and 

shutdown...

The 

emissions 

must not 

exceed the 

following 

alternative 

outputbased 

limits, 

except 

during 

startup and 

shutdown...

Using this 

specified 

sampling 

volume or 

test run 

duration...

per MMBtu 

of heat 

input).

per MWh; or 

(7.5E-05 lb 

per MMBtu 

of steam 

output or 

8.6E-04 lb 

per MWh).

17. Units 

designed to 

burn liquid 

fuel that are 

noncontinental 

units.

a. CO. 130 ppm by 

volume on a 

dry basis 

corrected 

to 3 

percent 

oxygen, 3-

run average 

based on 

stack test.

0.13 lb per 

MMBtu of 

steam 

output or 

1.4 lb per 

MWh; 3-run 

average.

1 hr 

minimum 

sampling 

time.

b. 

Filterable 

PM (or 

TSM).

2.7E-01 lb 

per MMBtu 

of heat 

input; or 

(8.6E-04 lb 

per MMBtu 

of heat 

input).

3.3E-01 lb 

per MMBtu 

of steam 

output or 

3.8 lb per 

MWh; or 

(1.1E-03 lb 

per MMBtu 

of steam 

output or 

1.2E-02 lb 

per MWh).

Collect a 

minimum of 

2 dscm per 

run.

18. Units 

designed to 

burn gas 2 

(other) gases

a. CO. 130 ppm by 

volume on a 

dry basis 

corrected 

to 3 

0.16 lb per 

MMBtu of 

steam 

output or 

1.0 lb per 

1 hr 

minimum 

sampling 

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

Page 315 of 374

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 

startup and 

shutdown...

The 

emissions 

must not 

exceed the 

following 

alternative 

outputbased 

limits, 

except 

during 

startup and 

shutdown...

Using this 

specified 

sampling 

volume or 

test run 

duration...

percent 

oxygen.

MWh.

b. HCl. 1.7E-03 lb 

per MMBtu 

of heat 

input.

2.9E-03 lb 

per MMBtu 

of steam 

output or 

1.8E-02 lb 

per MWh.

For M26A, 

collect a 

minimum of 

2 dscm per 

run; for 

M26, 

collect a 

minimum of 

240 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 

in the 

method; for 

ASTM D6784b

collect a 

minimum of 

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

Page 316 of 374

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 

startup and 

shutdown...

The 

emissions 

must not 

exceed the 

following 

alternative 

outputbased 

limits, 

except 

during 

startup and 

shutdown...

Using this 

specified 

sampling 

volume or 

test run 

duration...

d. 

Filterable 

PM (or 

TSM).

6.7E-03 lb 

per MMBtu 

of heat 

input or 

(2.1E-04 lb 

per MMBtu 

of heat 

input). 

1.2E-02 lb 

per MMBtu 

of steam 

output or 

7.0E-02 lb 

per MWh; or 

(3.5E-04 lb 

per MMBtu 

of steam 

output or 

2.2E-03 lb 

per MWh). 

Collect a 

minimum of 

3 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 below 75 percent of this limit in order 

to qualify for skip testing. 

b Incorporated by reference, see §63.14.

31. Table 3 to subpart DDDDD of part 63 is revised to read 

as follows:
***E.O. 12866 Review – Draft – Do Not Cite, Quote, or Release During Review***

Page 317 of 374

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 a 

continuous oxygen trim 

system that maintains an 

optimum air to fuel ratio, or 

a heat input capacity of less 

than or equal to 5 million Btu 

per hour in any of the 

following subcategories: unit 

designed to burn gas 1; unit 

designed to burn gas 2 

(other); or unit designed to 

burn light liquid, or a 

limited use boiler or process 

heater.

Conduct a tune-up of the boiler 

or process heater every 5 years 

as specified in §63.7540.

2. A new or existing boiler or 

process heater without a 

continuous oxygen trim system 

and 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 

greater than 5 million Btu per 

hour, in any of the following 

subcategories: unit designed 

to burn gas 1; 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 without a 

continuous oxygen trim system 

and 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 

conduct this tune-up as a work 
***E.O. 12866 Review – Draft – Do Not Cite, Quote, or Release During Review***

Page 318 of 374

If your unit is... You must meet the following...

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, not 

including limited use units. 

Must have a one-time energy 

assessment performed by a 

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. A 

facility that operates under an 

energy management program 

compatible with ISO 50001 that 

includes the affected units also 

satisfies the energy assessment 

requirement. The energy 

assessment must include the 

following with extent of the 

evaluation for items a. to e. 

appropriate for the on-site 

technical hours listed in 

§63.7575: 

a. A visual inspection of the 

boiler or process heater 

system.

b. An evaluation of operating 

characteristics of the boiler 

or process heater systems, 

specifications of energy using 

systems, operating and 

maintenance procedures, and 

unusual operating constraints.

c. An inventory of major energy 

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

Page 319 of 374

If your unit is... You must meet the following...

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, if 

identified. 

f. A list of cost-effective 

energy conservation measures 

that are within the facility’s 

control.

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 boiler 

or process heater subject to 

emission limits in Table 1 or 

2 or 11 through 13 to this 

subpart during startup.

You must operate all CMS during 

startup. 

For startup of a boiler or 

process heater, you must use one 

or a combination of the following

clean fuels: natural gas, 

synthetic natural gas, propane, 

distillate oil, syngas, ultra-low 

sulfur diesel, fuel oil-soaked 

rags, kerosene, hydrogen, paper, 

cardboard, refinery gas, and 

liquefied petroleum gas. 

If you start firing coal/solid 

fossil fuel, biomass/bio-based 

solids, heavy liquid fuel, or gas 

2 (other) gases, you must vent 

emissions to the main stack(s) 

and engage all of the applicable 

control devices except limestone 

injection in fluidized bed 
***E.O. 12866 Review – Draft – Do Not Cite, Quote, or Release During Review***

Page 320 of 374

If your unit is... You must meet the following...

combustion (FBC) boilers, dry 

scrubber, fabric filter, 

selective non-catalytic reduction 

(SNCR), and selective catalytic 

reduction (SCR). You must start 

your limestone injection in FBC 

boilers, dry scrubber, fabric 

filter, SNCR, and SCR systems as 

expeditiously as possible.

Startup ends when steam or heat 

is supplied for any purpose.

You must comply with all 

applicable emission limits at all 

times except for startup or

shutdown periods conforming with 

this work practice. You must 

collect monitoring data during 

periods of startup, as specified 

in §63.7535(b). You must keep 

records during periods of 

startup. You must provide reports 

concerning activities and periods 

of startup, as specified in 

§63.7555.

6. An existing or new boiler 

or process heater subject to 

emission limits in Tables 1 or 

2 or 11 through 13 to this 

subpart during shutdown.

You must operate all CMS during 

shutdown. 

While firing coal/solid fossil 

fuel, biomass/bio-based solids, 

heavy liquid fuel, or gas 2 

(other) gases during shutdown, 

you must vent emissions to the 

main stack(s) and operate all 

applicable control devices, 

except limestone injection in FBC 

boilers, dry scrubber, fabric 

filter, SNCR, and SCR. 

You must comply with all 

applicable emissions limits at 

all times except for startup or 

shutdown periods conforming with 

this work practice. You must 

collect monitoring data during 

periods of shutdown, as specified 
***E.O. 12866 Review – Draft – Do Not Cite, Quote, or Release During Review***

Page 321 of 374

If your unit is... You must meet the following...

in §63.7535(b). You must keep 

records during periods of 

shutdown. You must provide 

reports concerning activities and 

periods of shutdown, as specified 

in §63.7555.

32. Table 4 to subpart DDDDD of part 63 is revised to read 

as follows:

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: 

When complying with a 

Table 1, 2, 11, 12, or 

13 numerical emission 

limit using . . . You must meet these operating limits . . .

1. Wet PM scrubber 

control on a boiler 

not using a PM CPMS. 

Maintain the 30-day rolling average 

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 HCl

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

Page 322 of 374

When complying with a 

Table 1, 2, 11, 12, or 

13 numerical emission 

limit using . . . You must meet these operating limits . . .

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 alert is not 

activated 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 

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

Page 323 of 374

When complying with a 

Table 1, 2, 11, 12, or 

13 numerical emission 

limit using . . . You must meet these operating limits . . .

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 highest hourly average 

operating load recorded during the most 

recent performance test.

9. Oxygen analyzer 

system

For boilers and process heaters subject to 

a CO emission limit that demonstrate 

compliance with an O2 analyzer system as 

specified in §63.7525(a), maintain the 30-

day rolling average oxygen content at or 

above the lowest hourly average oxygen 

concentration measured during the most 

recent CO performance test, as specified 

in Table 8. This requirement does not 

apply to units that install an oxygen trim 

system since these units will set the trim 

system to the level specified in 

§63.7525(a).

10. SO2 CEMS For boilers or process heaters subject to 

an HCl emission limit that demonstrate 

compliance with an SO2 CEMS, maintain the 

30-day rolling average SO2 emission rate 

at or below the highest hourly average SO2

concentration measured during the most 

recent HCl performance test, as specified 

in Table 8. 

33. Table 5 to subpart DDDDD of part 63 is amended by:

a. Revising the entry for “1. Particulate matter.”

b. Remove the entry for “5. Dioxins/Furans”.
***E.O. 12866 Review – Draft – Do Not Cite, Quote, or Release During Review***

Page 324 of 374

c. Redesignating the entries for “2. Hydrogen chloride,” 

“3. Mercury,” and “4. CO” as “3. Hydrogen chloride,” “4. 

Mercury,” and “5. CO,” respectively.

d. Revising the newly redesignated entries for “4. Mercury” 

and “5. CO.”

e. Add entry for “2. Total selected metals.”

The revisions read as follows:

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. Filterable 

PM

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 PM

emission 

concentration.

Method 5 or 17 (positive 

pressure fabric filters 

must use Method 5D) at 40 
***E.O. 12866 Review – Draft – Do Not Cite, Quote, or Release During Review***

Page 325 of 374

To conduct a 

performance 

test for the 

following 

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

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. TSM 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 TSM 

emission 

concentration.

Method 29 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. HCl 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-2 

of this chapter.

c. Determine oxygen Method 3A or 3B at 40 CFR 
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To conduct a 

performance 

test for the 

following 

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

or carbon dioxide 

concentration of 

the stack gas.

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 HCl

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.

4. 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 61, 

appendix B of this chapter, 

or ASTM Method D6784.a

f. Convert 

emissions 

concentration to lb 

Method 19 F-factor 

methodology at 40 CFR part 

60, appendix A-7 of this 
***E.O. 12866 Review – Draft – Do Not Cite, Quote, or Release During Review***

Page 327 of 374

To conduct a 

performance 

test for the 

following 

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

per MMBtu emission 

rates.

chapter.

5. 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 measurement 

span value of 2 times the 

concentration of the 

applicable emission limit.

* * * * *

34. Table 6 to subpart DDDDD of part 63 is revised to read 

as follows:

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

Page 328 of 374

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 D5192 a, or ASTM D7430

a, or ASTM D6883 a, or ASTM 

D2234/D2234Ma(for coal) or 

EPA 1631 or EPA 1631E or 

ASTM D6323a (for solid), or 

EPA 821-R-01-013 (for liquid 

or solid), or ASTM D4177a

(for liquid), or ASTM D4057a

(for liquid), 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 EPA 3050a (for solid 

fuel), or EPA 821-R-01-013a

(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 D5864a for liquids and 

other solids, or ASTM D240a

or equivalent.

e. Determine 

moisture content of 

the fuel type. 

ASTM D3173a, ASTM E871a, or 

ASTM D5864a, or ASTM D240, 

or ASTM D95a (for liquid 

fuels), or ASTM D4006a (for 

liquid fuels), or ASTM 

D4177a (for liquid fuels) or 

ASTM D4057a (for liquid 

fuels), or equivalent.

f. Measure mercury 

concentration in 

ASTM D6722a (for coal), EPA 
***E.O. 12866 Review – Draft – Do Not Cite, Quote, or Release During Review***

Page 329 of 374

To conduct a 

fuel analysis 

for the 

following

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

fuel sample. 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.

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. HCl. a. Collect fuel 

samples. 

Procedure in §63.7521(c) or 

ASTM D5192 a, or ASTM D7430

a, or ASTM D6883 a, or ASTM 

D2234/D2234Ma (for coal) or 

ASTM D6323a (for coal or 

biomass), ASTM D4177a,(for 

liquid fuels)or ASTM D4057a

(for liquid fuels), 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 EPA 3050

a or equivalent.

d. Determine heat 

content of the fuel 

type. 

ASTM D5865a (for coal) or 

ASTM E711a (for biomass), 

ASTM D5864, ASTM D240a or 
***E.O. 12866 Review – Draft – Do Not Cite, Quote, or Release During Review***

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To conduct a 

fuel analysis 

for the 

following

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

equivalent.

e. Determine 

moisture content of 

the fuel type. 

ASTM D3173a or ASTM E871a, 

or D5864a, or ASTM D240a, or 

ASTM D95a (for liquid 

fuels), or ASTM D4006a (for 

liquid fuels), or ASTM 

D4177a (for liquid fuels) or 

ASTM D4057a (for liquid 

fuels) or equivalent.

f. Measure chlorine 

concentration in 

fuel sample.

EPA SW–846–9250a, ASTM 

D6721a, ASTM D4208a(for 

coal), or EPA SW-846-5050a or 

ASTM E776a (for solid fuel), 

or EPA SW-846-9056a or SW846-9076a (for solids or 

liquids) or equivalent.

g. Convert 

concentrations into 

units of pounds of 

HCl per MMBtu of 

heat content.

Equation 7 in §63.7530.

h. Calculate the HCl

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.

Method 30B (M30B) at 40 CFR 

part 60, appendix A-8 of 

this chapter or ASTM D5954a,

ASTM D6350a, ISO 6978-

1:2003(E)a, or ISO 6978-

2:2003(E)a, or EPA-1631a or 

equivalent.

b. Measure mercury Method 29, 30A, or 30B (M29, 
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To conduct a 

fuel analysis 

for the 

following

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

concentration in the 

exhaust gas when 

firing only the 

other gas 1 fuel is 

fired in the boiler 

or process heater. 

M30A, or M30B) at 40 CFR 

part 60, appendix A-8 of 

this chapter or Method 101A 

or Method 102 at 40 CFR part 

61, appendix B of this 

chapter, or ASTM Method 

D6784a or equivalent.

4. TSM for 

solid fuels.

a. Collect fuel 

samples. 

Procedure in §63.7521(c) or 

ASTM D5192 a, or ASTM D7430

a, or ASTM D6883 a, or ASTM 

D2234/D2234Ma (for coal) or 

ASTM D6323a (for coal or 

biomass), or ASTM 

D4177a,(for liquid fuels)or 

ASTM D4057a (for liquid 

fuels),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 T266a

(for biomass), or EPA 3050a

or equivalent.

d. Determine heat 

content of the fuel 

type. 

ASTM D5865a (for coal) or 

ASTM E711a (for biomass), or 

ASTM D5864a for liquids and 

other solids, or ASTM D240a

or equivalent.

e. Determine 

moisture content of 

the fuel type. 

ASTM D3173a or ASTM E871a, 

or D5864, or ASTM D240a, or 

ASTM D95a (for liquid 

fuels), or ASTM D4006a (for 

liquid fuels), or ASTM 

D4177a (for liquid fuels) or 
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To conduct a 

fuel analysis 

for the 

following

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

ASTM D4057a (for liquid 

fuels), or equivalent.

f. Measure TSM

concentration in 

fuel sample.

ASTM D3683a, or ASTM D4606 a, 

or ASTM D6357a or EPA 200.8a

or EPA SW-846-6020 a, or EPA 

SW-846-6020Aa, or EPA SW846-6010Ca, EPA 7060a or EPA 

7060Aa (for arsenic only), 

or EPA SW-846-7740a (for 

selenium only), 

g. Convert 

concentrations into 

units of pounds of 

TSM per MMBtu of 

heat content.

Equation 9 in §63.7530.

h. Calculate the TSM

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.

35. Table 7 to subpart DDDDD of part 63 is amended by:

a. Revising the entry for “1. Particulate matter or 

mercury,”. 

b. Revising the entry for “2. Hydrogen Chloride,”. 

c. Revising the entry for “3. Mercury,”. 

d. Revising the entry for “4. Carbon monoxide”.

The revisions read as follows:
***E.O. 12866 Review – Draft – Do Not Cite, Quote, or Release During Review***

Page 333 of 374

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 

applicabl

e 

emission 

limit for 

. . .

And your 

operating 

limits are 

based on . . 

.

You must. . 

. Using . . .

According to 

the 

following 

requirements

1. PM, 

TSM, 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 PM

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

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If you 

have an 

applicabl

e 

emission 

limit for 

. . .

And your 

operating 

limits are 

based on . . 

.

You must. . 

. Using . . .

According to 

the 

following 

requirements

taken during 

each 

performance 

test.

b. 

Electrostati

c 

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 

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

Page 335 of 374

If you 

have an 

applicabl

e 

emission 

limit for 

. . .

And your 

operating 

limits are 

based on . . 

.

You must. . 

. Using . . .

According to 

the 

following 

requirements

each 

performance 

test.

2. HCl a. Wet 

scrubber 

operating 

parameters.

i. 

Establish 

sitespecific 

minimum 

pressure 

drop, 

effluent 

pH, and 

flow rate 

operating 

limits 

according 

to 

§63.7530(b)

.

(1) Data 

from the 

pressure 

drop, pH, 

and liquid 

flow-rate 

monitors 

and the HCl

performance 

test.

(a) You must 

collect pH 

and liquid 

flow-rate 

data every 

15 minutes 

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 

(1) Data 

from the 

sorbent 

injection 

(a) You must 

collect 

sorbent 

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

Page 336 of 374

If you 

have an 

applicabl

e 

emission 

limit for 

. . .

And your 

operating 

limits are 

based on . . 

.

You must. . 

. Using . . .

According to 

the 

following 

requirements

minimum 

sorbent 

injection 

rate 

operating 

limit 

according 

to 

§63.7530(b)

. If 

different 

acid gas 

sorbents 

are used 

during the 

HCl

performance 

test, the 

average 

value for 

each 

sorbent 

becomes the 

sitespecific 

operating 

limit for 

that 

sorbent.

rate 

monitors 

and HCl or 

mercury 

performance 

test.

rate data 

every 15 

minutes 

during the 

entire 

period of 

the 

performance 

tests.

 (b) 

Determine 

the hourly 

average 

sorbent 

injection 

rate by 

computing 

the hourly 

averages 

using all of 
***E.O. 12866 Review – Draft – Do Not Cite, Quote, or Release During Review***

Page 337 of 374

If you 

have an 

applicabl

e 

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 of 

the three 

test run 

averages 

established 

during the 

performance 

test as your 

operating 

limit. When 

your unit 

operates at 

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

Page 338 of 374

If you 

have an 

applicabl

e 

emission 

limit for 

. . .

And your 

operating 

limits are 

based on . . 

.

You must. . 

. Using . . .

According to 

the 

following 

requirements

the required 

injection 

rate.

c. 

Alternative 

Maximum SO2 

emission 

rate

i. 

Establish a 

sitespecific 

maximum SO2

emission 

rate 

operating 

limit 

according 

to 

§63.7530(b)

. 

(1) Data 

from SO2

CEMS and 

the HCl

performance 

test.

(a) You must 

collect the 

SO2 emissions 

data 

according to 

§63.7525(m) 

during the 

most recent 

HCl

performance 

tests.

(b) The 

maximum SO2

emission 

rate is 

equal to the 

lowest 

hourly 

average SO2

emission 

rate 

measured 

during the 

most recent 

HCl

performance 

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

Page 339 of 374

If you 

have an 

applicabl

e 

emission 

limit for 

. . .

And your 

operating 

limits are 

based on . . 

.

You must. . 

. Using . . .

According to 

the 

following 

requirements

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 

the 15-

minute 

readings 

taken during 

each 

performance 

test.

(c) 

Determine 

the lowest 

hourly 

average 

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

Page 340 of 374

If you 

have an 

applicabl

e 

emission 

limit for 

. . .

And your 

operating 

limits are 

based on . . 

.

You must. . 

. Using . . .

According to 

the 

following 

requirements

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 

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

Page 341 of 374

If you 

have an 

applicabl

e 

emission 

limit for 

. . .

And your 

operating 

limits are 

based on . . 

.

You must. . 

. Using . . .

According to 

the 

following 

requirements

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 

concentratio

n

by computing 

the hourly 

averages 

using all of 

the 15-

minute 

readings 

taken during 

each 

performance 

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

Page 342 of 374

If you 

have an 

applicabl

e 

emission 

limit for 

. . .

And your 

operating 

limits are 

based on . . 

.

You must. . 

. Using . . .

According to 

the 

following 

requirements

(c) 

Determine 

the lowest 

hourly 

average 

established 

during the 

performance 

test as your 

minimum 

operating 

limit.

* * * * * * *

36. Table 8 to subpart DDDDD of part 63 is revised to read 

as follows: 

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 each boiler or process heater 

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

Page 343 of 374

If you must meet the 

following operating 

limits or work 

practice

standards . . .

You must demonstrate continuous compliance 

by . . .

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(b)(4).

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 

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

Page 344 of 374

If you must meet the 

following operating 

limits or work 

practice

standards . . .

You must demonstrate continuous compliance 

by . . .

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. Emission limits

using fuel analysis.

a. Conduct monthly fuel analysis for HCl or 

mercury or TSM according to Table 6 to this 

subpart; and

b. Reduce the data to 12-month rolling 

averages; and

c. Maintain the 12-month rolling average at 

or below the applicable emission limit for 

HCl or mercury or TSM in Tables 1 and 2 or 

11 through 13 to this subpart.

9. Oxygen content. a. Continuously monitor the oxygen content 

using an oxygen analyzer system according to 

§63.7525(a). This requirement does not apply 
***E.O. 12866 Review – Draft – Do Not Cite, Quote, or Release During Review***

Page 345 of 374

If you must meet the 

following operating 

limits or work 

practice

standards . . .

You must demonstrate continuous compliance 

by . . .

to units that install an oxygen trim system 

since these units will set the trim system 

to the level specified in §63.7525(a)(2).

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 CO performance test.

10. 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 

highest hourly average operating load 

recorded during the most recent performance 

test according to §63.7520(c).

11. SO2 emissions 

using SO2 CEMS

a. Collecting the SO2 CEMS output data 

according to §63.7525; 

b. Reducing the data to 30-day rolling 

averages; and

c. Maintaining the 30-day rolling average 

SO2 CEMS emission rate to a level at or 

below the minimum hourly SO2 rate measured 

during the most recent HCl performance test 

according to §63.7530.

37. Table 9 to subpart DDDDD of part 63 is amended by 

revising the entry for “1. Compliance report” to read as 

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

Page 346 of 374

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 (5); 

and

Semiannually, 

annually, 

biennially, or 

every 5 years 

according to the 

requirements in 

§63.7550(b).

* * * * * * *

38. Table 10 to subpart DDDDD of part 63 is amended by:

a. Revising the entry for “§63.6(i)”.

b. Revising the entry for “§63.7(e)(1)”. 

c. Revising the entry for “63.8(g)”. 

d. Revising the entry for “§63.10(e) and (f)”. 

e. Adding an entry for “§63.10(e)”.

The revisions read as follows.

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

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

Page 347 of 374

Citation Subject

Applies to subpart 

DDDDD

§63.6(i) Extension of 

compliance.

Yes. Note: 

Facilities may also 

request extensions 

of compliance for 

the installation of 

combined heat and 

power, waste heat 

recovery, or gas 

pipeline or fuel 

feeding 

infrastructure as a 

means of complying 

with this subpart.

* * * * * * *

§63.7(e)(1) Conditions for 

conducting 

performance 

tests.

No. Subpart DDDDD 

specifies 

conditions for 

conducting 

performance tests 

at §63.7520(a) to 

(c).

* * * * * * *

§63.8(g) Reduction of 

monitoring data.

Yes.

* * * * * * *

§63.10(e) Additional 

reporting 

requirements for 

sources with CMS

Yes.

§63.10(f) Waiver of 

recordkeeping or 

reporting 

requirements

Yes.

* * * * * * *

39. Add Table 11 to subpart DDDDD of part 63 to read as 

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

Page 348 of 374

Table 11 to Subpart DDDDD of Part 63—Alternative Emission Limits 

for New or Reconstructed Boilers and Process Heaters that 

Commenced Construction or Reconstruction after June 4, 2010, and 

Before May 20, 2011

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...

Using this 

specified 

sampling volume 

or test run 

duration...

1. Units in all 

subcategories 

designed to burn 

solid fuel.

a. HCl. 0.022 lb per 

MMBtu of heat 

input.

For M26A, 

collect a 

minimum of 1 

dscm per run; 

for M26 collect 

a minimum of 

120 liters per 

run.

2. Units in all 

subcategories 

designed to burn 

solid fuel that 

combust at least 10 

percent 

biomass/bio-based 

solids on an annual 

heat input basis 

and less than 10 

percent coal/solid 

fossil fuels on an 

annual heat input 

basis.

a. 

Mercury.

8.0E-07a lb per 

MMBtu of heat 

input.

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

Page 349 of 374

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...

Using this 

specified 

sampling volume 

or test run 

duration...

3. Units in all 

subcategories 

designed to burn 

solid fuel that 

combust at least 10 

percent coal/solid 

fossil fuels on an 

annual heat input 

basis and less than 

10 percent 

biomass/bio-based 

solids on an annual 

heat input basis.

a. 

Mercury.

2.0E-06 lb per 

MMBtu of heat 

input.

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.

4. Units design to 

burn coal/solid 

fossil fuel.

a. 

Filterable 

PM (or 

TSM).

1.1E-03 lb per 

MMBtu of heat 

input; or 

(2.3E-05 lb per 

MMBtu of heat 

input). 

Collect a 

minimum of 3 

dscm per run.

5. Pulverized coal 

boilers designed to 

burn coal/solid 

fossil fuel.

a. Carbon 

monoxide 

(CO) (or 

CEMS).

130 ppm by 

volume on a dry 

basis corrected 

to 3 percent 

oxygen, 3-run 

average; or 

(320 ppm by 

volume on a dry 

basis corrected 

to 3 percent 

oxygen, 30-day 

rolling 

average).

1 hr minimum 

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

Page 350 of 374

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...

Using this 

specified 

sampling volume 

or test run 

duration...

6. Stokers designed 

to burn coal/solid 

fossil fuel.

a. CO (or 

CEMS).

130 ppm by 

volume on a dry 

basis corrected 

to 3 percent 

oxygen, 3-run 

average; or 

(340 ppm by 

volume on a dry 

basis corrected 

to 3 percent 

oxygen, 10-day 

rolling 

average).

1 hr minimum 

sampling time.

7. Fluidized bed

units designed to 

burn coal/solid 

fossil fuel.

a. CO (or 

CEMS).

130 ppm by 

volume on a dry 

basis corrected 

to 3 percent 

oxygen, 3-run 

average; or 

(230 ppm by 

volume on a dry 

basis corrected 

to 3 percent 

oxygen, 30-day 

rolling 

average).

1 hr minimum 

sampling time.

8. Fluidized bed 

units with an 

integrated heat 

exchanger designed 

to burn coal/solid 

fossil fuel.

a. CO (or 

CEMS).

140 ppm by 

volume on a dry 

basis corrected 

to 3 percent 

oxygen, 3-run 

average; or 

(150 ppm by 

volume on a dry 

basis corrected 

to 3 percent 

oxygen, 30-day 

rolling 

average).

1 hr minimum 

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

Page 351 of 374

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...

Using this 

specified 

sampling volume 

or test run 

duration...

9. Stokers/sloped 

grate/others 

designed to burn 

wet biomass fuel.

a. CO (or 

CEMS).

620 ppm by 

volume on a dry 

basis corrected 

to 3 percent 

oxygen, 3-run 

average; or 

(390 ppm by 

volume on a dry 

basis corrected 

to 3 percent 

oxygen, 30-day 

rolling 

average).

1 hr minimum 

sampling time.

b. 

Filterable 

PM (or 

TSM).

3.0E-02 lb per 

MMBtu of heat 

input; or 

(2.6E-05 lb per 

MMBtu of heat 

input).

Collect a 

minimum of 2 

dscm per run.

10. Stokers/sloped 

grate/others 

designed to burn 

kiln-dried biomass 

fuel.

a. CO. 560 ppm by 

volume on a dry 

basis corrected 

to 3 percent 

oxygen.

1 hr minimum 

sampling time.

b. 

Filterable 

PM (or 

TSM).

3.0E-02 lb per 

MMBtu of heat 

input; or 

(4.0E-03 lb per 

MMBtu of heat 

input).

Collect a 

minimum of 2 

dscm per run.
***E.O. 12866 Review – Draft – Do Not Cite, Quote, or Release During Review***

Page 352 of 374

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...

Using this 

specified 

sampling volume 

or test run 

duration...

11. 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 

(310 ppm by 

volume on a dry 

basis corrected 

to 3 percent 

oxygen, 30-day 

rolling 

average).

1 hr minimum 

sampling time.

b. 

Filterable 

PM (or 

TSM)

9.8E-03 lb per 

MMBtu of heat 

input; or 

(8.3E-05a lb 

per MMBtu of 

heat input).

Collect a 

minimum of 3 

dscm per run

12. Suspension 

burners designed to 

burn biomass/biobased solids.

a. CO (or 

CEMS).

2,400 ppm by 

volume on a dry 

basis corrected 

to 3 percent 

oxygen, 3-run 

average; or 

(2,000 ppm by 

volume on a dry 

basis corrected 

to 3 percent 

oxygen, 10-day 

rolling 

average).

1 hr minimum 

sampling time.

b. 

Filterable 

PM (or 

TSM).

3.0E-02 lb per 

MMBtu of heat 

input; or 

(6.5E-03 lb per 

MMBtu of heat 

input).

Collect a 

minimum of 2 

dscm per run.
***E.O. 12866 Review – Draft – Do Not Cite, Quote, or Release During Review***

Page 353 of 374

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...

Using this 

specified 

sampling volume 

or test run 

duration...

13. Dutch 

Ovens/Pile burners 

designed to burn 

biomass/bio-based 

solids.

a. CO (or 

CEMS).

1,010 ppm by 

volume on a dry 

basis corrected 

to 3 percent 

oxygen, 3-run 

average; or 

(520 ppm by 

volume on a dry 

basis corrected 

to 3 percent 

oxygen, 10-day 

rolling 

average).

1 hr minimum 

sampling time.

b. 

Filterable 

PM (or 

TSM).

8.0E-03 lb per 

MMBtu of heat 

input; or 

(3.9E-05 lb per 

MMBtu of heat 

input).

Collect a 

minimum of 3 

dscm per run.

14. Fuel cell units 

designed to burn 

biomass/bio-based 

solids.

a. CO. 910 ppm by 

volume on a dry 

basis corrected 

to 3 percent 

oxygen.

1 hr minimum 

sampling time.

b. 

Filterable 

PM (or 

TSM).

2.0E-02 lb per 

MMBtu of heat 

input; or 

(2.9E-05 lb per 

MMBtu of heat 

input).

Collect a 

minimum of 2 

dscm per run.
***E.O. 12866 Review – Draft – Do Not Cite, Quote, or Release During Review***

Page 354 of 374

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...

Using this 

specified 

sampling volume 

or test run 

duration...

15. Hybrid 

suspension grate 

boiler designed to 

burn biomass/biobased solids.

a. CO (or 

CEMS).

1,100 ppm by 

volume on a dry 

basis corrected 

to 3 percent 

oxygen, 3-run 

average; or 

(900 ppm by 

volume on a dry 

basis corrected 

to 3 percent 

oxygen, 30-day 

rolling 

average).

1 hr minimum 

sampling time.

b. 

Filterable 

PM (or 

TSM).

2.6E-02 lb per 

MMBtu of heat 

input; or 

(4.4E-04 lb per 

MMBtu of heat 

input).

Collect a 

minimum of 3 

dscm per run

16. Units designed 

to burn liquid 

fuel.

a. HCl. 4.4E-04 lb per 

MMBtu of heat 

input.

For M26A: 

Collect a 

minimum of 2 

dscm per run; 

for M26, 

collect a 

minimum of 240 

liters per run

b. 

Mercury.

4.8E-07a lb per 

MMBtu of heat 

input.

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

Page 355 of 374

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...

Using this 

specified 

sampling volume 

or test run 

duration...

minimum of 4 

dscm.

17. Units designed 

to burn heavy 

liquid fuel.

a. CO. 130 ppm by 

volume on a dry 

basis corrected 

to 3 percent 

oxygen, 3-run 

average.

1 hr minimum 

sampling time.

b. 

Filterable 

PM (or 

TSM).

1.3E-02 lb per 

MMBtu of heat 

input; or 

(7.5E-05 lb per 

MMBtu of heat 

input).

Collect a 

minimum of 3 

dscm per run.

18. Units designed 

to burn light 

liquid fuel.

a. CO. 130 ppm by 

volume on a dry 

basis corrected 

to 3 percent 

oxygen.

1 hr minimum 

sampling time.

b. 

Filterable 

PM (or 

TSM).

2.0E-03a lb per 

MMBtu of heat 

input; or 

(2.9E-05 lb per 

MMBtu of heat 

input).

Collect a 

minimum of 3 

dscm per run

19. Units designed 

to burn liquid fuel 

that are noncontinental units.

a. CO. 130 ppm by 

volume on a dry 

basis corrected 

to 3 percent 

oxygen, 3-run 

average based 

on stack test .

1 hr minimum 

sampling time.

b. 

Filterable 

PM (or 

TSM).

2.3E-02 lb per 

MMBtu of heat 

input; or 

(8.6E-04 lb per 

MMBtu of heat 

input).

Collect a 

minimum of 4 

dscm per run
***E.O. 12866 Review – Draft – Do Not Cite, Quote, or Release During Review***

Page 356 of 374

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...

Using this 

specified 

sampling volume 

or test run 

duration...

20. Units designed 

to burn gas 2 

(other) gases

a. CO 130 ppm by 

volume on a dry 

basis corrected 

to 3 percent 

oxygen.

1 hr minimum 

sampling time.

b. HCl 1.7E-03 lb per 

MMBtu of heat 

input.

For M26A, 

Collect a 

minimum of 2 

dscm per run; 

for M26, 

collect a 

minimum of 240 

liters per run 

c. Mercury 7.9E-06 lb per 

MMBtu of heat 

input.

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.

d. 

Filterable 

PM (or 

TSM)

6.7E-03 lb per 

MMBtu of heat 

input; or 

(2.1E-04 lb per 

MMBtu of heat 

input).

Collect a 

minimum of 3 

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

Page 357 of 374

this pollutant for at least 2 consecutive years must show that 

your emissions are at or below 75 percent of this limit in order 

to qualify for skip testing.

b Incorporated by reference, see §63.14.

40. Add Table 12 to subpart DDDDD of part 63 to read as 

follows:

Table 12 to Subpart DDDDD of Part 63—Alternative Emission Limits 

for New or Reconstructed Boilers and Process Heaters that 

Commenced Construction or Reconstruction after May 20, 2011, and 

Before December 23, 2011

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...

Using this 

specified 

sampling volume 

or test run 

duration...

1. Units in all 

subcategories 

designed to burn 

solid fuel.

a. HCl. 0.022 lb per 

MMBtu of heat 

input.

For M26A, 

collect a 

minimum of 1 

dscm per run; 

for M26 collect 

a minimum of 120 

liters per run.

b. 

Mercury.

3.5E-06a lb per 

MMBtu of heat 

input.

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. Units design 

to burn 

coal/solid 

fossil fuel.

a. 

Filterable 

PM (or 

TSM).

1.1E-03 lb per 

MMBtu of heat 

input; or (2.3E05 lb per MMBtu 

of heat input). 

Collect a 

minimum of 3 

dscm per run.
***E.O. 12866 Review – Draft – Do Not Cite, Quote, or Release During Review***

Page 358 of 374

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...

Using this 

specified 

sampling volume 

or test run 

duration...

3. Pulverized 

coal boilers 

designed to burn 

coal/solid 

fossil fuel.

a. Carbon 

monoxide 

(CO) (or 

CEMS).

130 ppm by 

volume on a dry 

basis corrected 

to 3 percent 

oxygen, 3-run 

average; or (320 

ppm by volume on 

a dry basis 

corrected to 3 

percent oxygen, 

30-day rolling 

average).

1 hr minimum 

sampling time.

4. Stokers 

designed to burn 

coal/solid 

fossil fuel.

a. CO (or 

CEMS).

130 ppm by 

volume on a dry 

basis corrected 

to 3 percent 

oxygen, 3-run 

average; or (340

ppm by volume on 

a dry basis 

corrected to 3 

percent oxygen, 

10-day rolling 

average).

1 hr minimum 

sampling time.

5. Fluidized bed 

units designed 

to burn 

coal/solid 

fossil fuel.

a. CO (or 

CEMS).

130 ppm by 

volume on a dry 

basis corrected 

to 3 percent 

oxygen, 3-run 

average; or (230 

ppm by volume on 

a dry basis 

corrected to 3 

percent oxygen, 

30-day rolling 

average).

1 hr minimum 

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

Page 359 of 374

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...

Using this 

specified 

sampling volume 

or test run 

duration...

6. Fluidized bed 

units with an 

integrated heat 

exchanger 

designed to burn 

coal/solid 

fossil fuel.

a. CO (or 

CEMS).

140 ppm by 

volume on a dry 

basis corrected 

to 3 percent 

oxygen, 3-run 

average; or (150 

ppm by volume on 

a dry basis 

corrected to 3 

percent oxygen, 

30-day rolling 

average).

1 hr minimum 

sampling time.

7. 

Stokers/sloped 

grate/others 

designed to burn 

wet biomass 

fuel.

a. CO (or 

CEMS).

620 ppm by 

volume on a dry 

basis corrected 

to 3 percent 

oxygen, 3-run 

average; or (390 

ppm by volume on 

a dry basis 

corrected to 3 

percent oxygen, 

30-day rolling 

average).

1 hr minimum 

sampling time.

b. 

Filterable 

PM (or 

TSM).

3.0E-02 lb per 

MMBtu of heat 

input; or (2.6E05 lb per MMBtu 

of heat input).

Collect a 

minimum of 2 

dscm per run.

8. 

Stokers/sloped 

grate/others 

designed to burn 

kiln-dried 

biomass fuel.

a. CO. 460 ppm by 

volume on a dry 

basis corrected 

to 3 percent 

oxygen.

1 hr minimum 

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

Page 360 of 374

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...

Using this 

specified 

sampling volume 

or test run 

duration...

b. 

Filterable 

PM (or 

TSM).

3.0E-02 lb per 

MMBtu of heat 

input; or (4.0E03 lb per MMBtu 

of heat input).

Collect a 

minimum of 2 

dscm per run.

9. Fluidized bed 

units designed 

to burn 

biomass/biobased solids.

a. CO (or 

CEMS).

260 ppm by 

volume on a dry 

basis corrected 

to 3 percent 

oxygen, 3-run 

average; or (310 

ppm by volume on 

a dry basis 

corrected to 3 

percent oxygen, 

30-day rolling 

average).

1 hr minimum 

sampling time.

b. 

Filterable 

PM (or 

TSM).

9.8E-03 lb per 

MMBtu of heat 

input; or (8.3E05a lb per MMBtu 

of heat input).

Collect a 

minimum of 3 

dscm per run.

10. Suspension 

burners designed 

to burn 

biomass/biobased solids.

a. CO (or 

CEMS).

2,400 ppm by 

volume on a dry 

basis corrected 

to 3 percent 

oxygen, 3-run 

average; or 

(2,000 ppm by 

volume on a dry 

basis corrected 

to 3 percent 

oxygen, 10-day 

rolling 

average).

1 hr minimum

sampling time.

b. 

Filterable 

PM (or 

TSM).

3.0E-02 lb per 

MMBtu of heat 

input; or (6.5E03 lb per MMBtu 

Collect a 

minimum of 2 

dscm per run.
***E.O. 12866 Review – Draft – Do Not Cite, Quote, or Release During Review***

Page 361 of 374

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...

Using this 

specified 

sampling volume 

or test run 

duration...

of heat input).

11. Dutch 

Ovens/Pile 

burners designed 

to burn 

biomass/biobased solids.

a. CO (or 

CEMS).

470 ppm by 

volume on a dry 

basis corrected 

to 3 percent 

oxygen, 3-run 

average; or (520 

ppm by volume on 

a dry basis 

corrected to 3 

percent oxygen, 

10-day rolling 

average).

1 hr minimum 

sampling time.

b. 

Filterable 

PM (or 

TSM).

3.2E-03 lb per 

MMBtu of heat 

input; or (3.9E05 lb per MMBtu 

of heat input).

Collect a 

minimum of 3 

dscm per run.

12. Fuel cell 

units designed 

to burn 

biomass/biobased solids.

a. CO. 910 ppm by 

volume on a dry 

basis corrected 

to 3 percent 

oxygen.

1 hr minimum 

sampling time.

b. 

Filterable 

PM (or 

TSM).

2.0E-02 lb per 

MMBtu of heat 

input; or (2.9E05 lb per MMBtu 

of heat input).

Collect a 

minimum of 2 

dscm per run.
***E.O. 12866 Review – Draft – Do Not Cite, Quote, or Release During Review***

Page 362 of 374

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...

Using this 

specified 

sampling volume 

or test run 

duration...

13. 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 (900 

ppm by volume on 

a dry basis 

corrected to 3 

percent oxygen, 

30-day rolling 

average).

1 hr minimum 

sampling time.

b. 

Filterable 

PM (or 

TSM).

2.6E-02 lb per 

MMBtu of heat 

input; or (4.4E04 lb per MMBtu 

of heat input).

Collect a 

minimum of 3 

dscm per run.

14. Units 

designed to burn 

liquid fuel.

a. HCl. 4.4E-04 lb per 

MMBtu of heat 

input.

For M26A: 

Collect a 

minimum of 2 

dscm per run; 

for M26, collect 

a minimum of 240 

liters per run.

b. 

Mercury.

4.8E-07a lb per 

MMBtu of heat 

input.

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.

15. Units 

designed to burn 

a. CO. 130 ppm by 

volume on a dry 

1 hr minimum 

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

Page 363 of 374

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...

Using this 

specified 

sampling volume 

or test run 

duration...

heavy liquid 

fuel.

basis corrected 

to 3 percent 

oxygen, 3-run 

average.

b. 

Filterable 

PM (or 

TSM).

1.3E-02 lb per 

MMBtu of heat 

input; or (7.5E05 lb per MMBtu 

of heat input).

Collect a 

minimum of 2 

dscm per run.

16. Units 

designed to burn 

light liquid 

fuel.

a. CO. 130 ppm by 

volume on a dry 

basis corrected 

to 3 percent 

oxygen.

1 hr minimum 

sampling time.

b. 

Filterable 

PM (or 

TSM).

1.3E-03a lb per 

MMBtu of heat 

input; or (2.9E05 lb per MMBtu 

of heat input).

Collect a 

minimum of 3 

dscm per run.

17. Units 

designed to burn 

liquid fuel that 

are noncontinental 

units.

a. CO. 130 ppm by 

volume on a dry 

basis corrected 

to 3 percent 

oxygen, 3-run 

average based on 

stack test.

1 hr minimum 

sampling time.

b. 

Filterable 

PM (or 

TSM)

2.3E-02 lb per 

MMBtu of heat 

input; or (8.6E04 lb per MMBtu 

of heat input).

Collect a 

minimum of 4 

dscm per run

18. Units 

designed to burn 

gas 2 (other) 

gases

a. CO 130 ppm by 

volume on a dry 

basis corrected 

to 3 percent 

oxygen.

1 hr minimum 

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

Page 364 of 374

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...

Using this 

specified 

sampling volume 

or test run 

duration...

b. HCl 1.7E-03 lb per 

MMBtu of heat 

input.

For M26A, 

Collect a 

minimum of 2 

dscm per run; 

for M26, collect 

a minimum of 240 

liters per run 

c. Mercury 7.9E-06 lb per 

MMBtu of heat 

input.

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.

d. 

Filterable 

PM (or 

TSM)

6.7E-03 lb per 

MMBtu of heat 

input; or (2.1E04 lb per MMBtu 

of heat input).

Collect a 

minimum of 3 

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 below 75 percent of this limit in order 

to qualify for skip testing.

b Incorporated by reference, see §63.14.
***E.O. 12866 Review – Draft – Do Not Cite, Quote, or Release During Review***

Page 365 of 374

41. Add Table 13 to subpart DDDDD of part 63 to read as 

follows:

Table 13 to Subpart DDDDD of Part 63—Alternative Emission Limits 

for New or Reconstructed Boilers and Process Heaters that 

Commenced Construction or Reconstruction after December 23, 

2011, and Before [INSERT THE DATE OF PUBLICATION IN FEDERAL 

REGISTER]

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...

Using this 

specified 

sampling volume 

or test run 

duration...

1. Units in all 

subcategories 

designed to burn 

solid fuel.

a. HCl. 0.022 lb per 

MMBtu of heat 

input.

For M26A, 

collect a 

minimum of 1 

dscm per run; 

for M26 collect 

a minimum of 

120 liters per 

run.

b. 

Mercury.

8.6E-07a lb per 

MMBtu of heat 

input.

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

Page 366 of 374

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...

Using this 

specified 

sampling volume 

or test run 

duration...

2. Pulverized 

coal boilers 

designed to burn 

coal/solid 

fossil fuel.

a. Carbon 

monoxide 

(CO) (or 

CEMS).

130 ppm by 

volume on a dry 

basis corrected 

to 3 percent 

oxygen, 3-run 

average; or (320 

ppm by volume on 

a dry basis 

corrected to 3 

percent oxygen, 

30-day rolling 

average).

1 hr minimum 

sampling time.

b. 

Filterable 

PM (or 

TSM).

1.1E-03 lb per 

MMBtu of heat 

input; or (2.8E05 lb per MMBtu 

of heat input).

Collect a 

minimum of 3 

dscm per run.

3. Stokers 

designed to burn 

coal/solid 

fossil fuel.

a. CO (or 

CEMS).

130 ppm by 

volume on a dry 

basis corrected 

to 3 percent 

oxygen, 3-run 

average; or (340

ppm by volume on 

a dry basis 

corrected to 3 

percent oxygen, 

10-day rolling 

average).

1 hr minimum 

sampling time.

b. 

Filterable

PM (or 

TSM).

2.8E-02 lb per 

MMBtu of heat 

input; or (2.3E05 lb per MMBtu 

of heat input).

Collect a 

minimum of 2 

dscm per run.
***E.O. 12866 Review – Draft – Do Not Cite, Quote, or Release During Review***

Page 367 of 374

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...

Using this 

specified 

sampling volume 

or test run 

duration...

4. Fluidized bed 

units designed 

to burn 

coal/solid 

fossil fuel.

a. CO (or 

CEMS).

130 ppm by 

volume on a dry 

basis corrected 

to 3 percent 

oxygen, 3-run 

average; or (230 

ppm by volume on 

a dry basis 

corrected to 3 

percent oxygen, 

30-day rolling 

average).

1 hr minimum 

sampling time.

b. 

Filterable 

PM (or 

TSM).

1.1E-03 lb per 

MMBtu of heat 

input; or (2.3E05 lb per MMBtu 

of heat input).

Collect a 

minimum of 3 

dscm per run.

5. Fluidized bed 

units with an 

integrated heat 

exchanger 

designed to burn 

coal/solid 

fossil fuel.

a. CO (or 

CEMS).

140 ppm by 

volume on a dry 

basis corrected 

to 3 percent 

oxygen, 3-run 

average; or (150 

ppm by volume on 

a dry basis 

corrected to 3 

percent oxygen, 

30-day rolling 

average).

1 hr minimum 

sampling time.

b. 

Filterable 

PM (or 

TSM).

1.1E-03 lb per 

MMBtu of heat 

input; or (2.3E05 lb per MMBtu 

of heat input).

Collect a 

minimum of 3 

dscm per run.
***E.O. 12866 Review – Draft – Do Not Cite, Quote, or Release During Review***

Page 368 of 374

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...

Using this 

specified 

sampling volume 

or test run 

duration...

6. 

Stokers/sloped 

grate/others 

designed to burn 

wet biomass 

fuel.

a. CO (or 

CEMS).

620 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).

1 hr minimum 

sampling time.

b. 

Filterable 

PM (or 

TSM).

3.0E-02 lb per 

MMBtu of heat 

input; or (2.6E05 lb per MMBtu 

of heat input).

Collect a 

minimum of 2 

dscm per run.

7. 

Stokers/sloped 

grate/others 

designed to burn 

kiln-dried 

biomass fuel.

a. CO. 460 ppm by 

volume on a dry 

basis corrected 

to 3 percent 

oxygen.

1 hr minimum 

sampling time.

b. 

Filterable 

PM (or 

TSM).

3.2E-01 lb per 

MMBtu of heat 

input; or (4.0E03 lb per MMBtu 

of heat input).

Collect a 

minimum of 2 

dscm per run.
***E.O. 12866 Review – Draft – Do Not Cite, Quote, or Release During Review***

Page 369 of 374

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...

Using this 

specified 

sampling volume 

or test run 

duration...

8. 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 (310 

ppm by volume on 

a dry basis 

corrected to 3 

percent oxygen, 

30-day rolling 

average).

1 hr minimum 

sampling time.

b. 

Filterable 

PM (or 

TSM).

9.8E-03 lb per 

MMBtu of heat 

input; or (8.3E05a lb per MMBtu 

of heat input).

Collect a 

minimum of 3 

dscm per run.

9. Suspension 

burners designed 

to burn 

biomass/biobased solids.

a. CO (or 

CEMS).

2,400 ppm by 

volume on a dry 

basis corrected 

to 3 percent 

oxygen, 3-run 

average; or 

(2,000 ppm by 

volume on a dry 

basis corrected 

to 3 percent 

oxygen, 10-day 

rolling 

average).

1 hr minimum 

sampling time.

b. 

Filterable 

PM (or 

TSM).

5.1E-02 lb per 

MMBtu of heat 

input; or (6.5E03 lb per MMBtu 

of heat input).

Collect a 

minimum of 2 

dscm per run.
***E.O. 12866 Review – Draft – Do Not Cite, Quote, or Release During Review***

Page 370 of 374

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...

Using this 

specified 

sampling volume 

or test run 

duration...

10. Dutch 

Ovens/Pile 

burners designed 

to burn 

biomass/biobased solids.

a. CO (or 

CEMS).

810 ppm by 

volume on a dry 

basis corrected 

to 3 percent 

oxygen, 3-run 

average; or (520 

ppm by volume on

a dry basis 

corrected to 3 

percent oxygen, 

10-day rolling 

average).

1 hr minimum 

sampling time.

b. 

Filterable 

PM (or 

TSM).

3.6E-02 lb per 

MMBtu of heat 

input; or (3.9E05 lb per MMBtu 

of heat input).

Collect a 

minimum of 2 

dscm per run.

11. Fuel cell 

units designed 

to burn 

biomass/biobased solids.

a. CO. 910 ppm by 

volume on a dry 

basis corrected 

to 3 percent 

oxygen.

1 hr minimum 

sampling time.

b. 

Filterable 

PM (or 

TSM).

2.0E-02 lb per 

MMBtu of heat 

input; or (2.9E05 lb per MMBtu 

of heat input).

Collect a 

minimum of 2 

dscm per run.
***E.O. 12866 Review – Draft – Do Not Cite, Quote, or Release During Review***

Page 371 of 374

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...

Using this 

specified 

sampling volume 

or test run 

duration...

12. 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 (900 

ppm by volume on 

a dry basis 

corrected to 3 

percent oxygen, 

30-day rolling 

average).

1 hr minimum 

sampling time.

b. 

Filterable 

PM (or 

TSM).

2.6E-02 lb per 

MMBtu of heat 

input; or (4.4E04 lb per MMBtu 

of heat input).

Collect a 

minimum of 3 

dscm per run.

13. Units 

designed to burn 

liquid fuel.

a. HCl. 1.2E-03 lb per 

MMBtu of heat 

input.

For M26A: 

Collect a 

minimum of 2 

dscm per run; 

for M26, 

collect a 

minimum of 240 

liters per run.

b. 

Mercury.

4.9E-07a lb per 

MMBtu of heat 

input.

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

Page 372 of 374

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...

Using this 

specified 

sampling volume 

or test run 

duration...

14. Units 

designed to burn 

heavy liquid 

fuel.

a. CO (or 

CEMS).

130 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).

1 hr minimum 

sampling time.

b. 

Filterable 

PM (or 

TSM).

1.3E-03 lb per 

MMBtu of heat 

input; or (7.5E05 lb per MMBtu 

of heat input).

Collect a 

minimum of 3 

dscm per run.

15. Units 

designed to burn 

light liquid 

fuel.

a. CO (or 

CEMS).

130a 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).

1 hr minimum 

sampling time.

b. 

Filterable 

PM (or 

TSM)

1.1E-03a lb per 

MMBtu of heat 

input; or (2.9E05 lb per MMBtu 

of heat input).

Collect a 

minimum of 3 

dscm per run
***E.O. 12866 Review – Draft – Do Not Cite, Quote, or Release During Review***

Page 373 of 374

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...

Using this 

specified 

sampling volume 

or test run 

duration...

16. Units 

designed to burn 

liquid fuel that 

are noncontinental 

units.

a. CO. 130 ppm by 

volume on a dry 

basis corrected 

to 3 percent 

oxygen, 3-run 

average based on 

stack test; or 

(91 ppm by 

volume on a dry 

basis corrected 

to 3 percent 

oxygen, 3-hour 

rolling 

average).

1 hr minimum 

sampling time.

b. 

Filterable 

PM (or 

TSM).

2.3E-02 lb per 

MMBtu of heat 

input; or (8.6E04 lb per MMBtu 

of heat input).

Collect a 

minimum of 2 

dscm per run.

17. Units 

designed to burn 

gas 2 (other) 

gases.

a. CO. 130 ppm by 

volume on a dry 

basis corrected 

to 3 percent 

oxygen.

1 hr minimum 

sampling time.

b. HCl. 1.7E-03 lb per 

MMBtu of heat 

input.

For M26A, 

Collect a 

minimum of 2 

dscm per run; 

for M26, 

collect a 

minimum of 240 

liters per run 

c. 

Mercury.

7.9E-06 lb per 

MMBtu of heat 

input.

For M29, 

collect a 

minimum of 3 

dscm per run; 

for M30A or 

M30B, collect a 

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

Page 374 of 374

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...

Using this 

specified 

sampling volume 

or test run 

duration...

as specified in 

the method; for 

ASTM D6784b

collect a 

minimum of 3 

dscm.

d. 

Filterable 

PM (or 

TSM).

6.7E-03 lb per 

MMBtu of heat 

input; or (2.1E04 lb per MMBtu 

of heat input).

Collect a 

minimum of 3 

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 and you are not required to conduct testing for CEMS or 

CPMS monitor certification, 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 below 75 percent 

of this limit in order to qualify for skip testing.

b Incorporated by reference, see §63.14.