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

2060-AR14 Final Rule 20120921

6560-50-P

ENVIRONMENTAL PROTECTION AGENCY

40 CFR Part 63

[EPA-HQ-OAR-2006-0790; FRL- ]

RIN 2060-AR14

National Emission Standards for Hazardous Air Pollutants for 

Area Sources: Industrial, Commercial, and Institutional Boilers

AGENCY: Environmental Protection Agency (EPA).

ACTION: Final rule; notice of final action on reconsideration.

SUMMARY: In this action, the EPA is finalizing amendments for 

emission standards to control hazardous air pollutants from new 

and existing industrial, commercial and institutional boilers at 

area sources of hazardous air pollutants, which were issued 

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

the EPA is amending effective dates of the standard and making 

technical corrections to the final rule to clarify definitions, 

references, applicability and compliance issues raised by 

petitioners and other stakeholders affected by the rule. This 

action also takes final action on reconsideration of specific 

elements of the final rule. 

DATES: This final rule is effective on [INSERT THE DATE OF 

PUBLICATION IN THE FEDERAL REGISTER].
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ADDRESSES: The EPA established a single docket under Docket ID 

No. EPA-HQ-OAR-2006-0790 for this action. All documents in the 

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

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 

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) 566–1741.

FOR FURTHER INFORMATION CONTACT: Ms. Mary Johnson, Energy 

Strategies Group (D243-01), Sector Policies and Programs 

Division, Office of Air Quality Planning and Standards, 

Environmental Protection Agency, Research Triangle Park, North 

Carolina 27711; telephone number: (919) 541-5025; fax number: 

(919) 541-5450; email address: johnson.mary@epa.gov. 

EXECUTIVE SUMMARY:

Purpose of this Regulatory Action
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The EPA is taking final action on its proposed 

reconsideration of certain provisions of its March 21, 2011,

final rule that established emission standards for the source 

category of new and existing industrial, commercial, and 

institutional boilers located at area source facilities listed 

pursuant to CAA sections 112(c)(3), 112(c)(6), and 112(k)(3)(B). 

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

from both major and area stationary sources. Section 112(d)(5)

of the CAA allows the EPA to establish standards for area 

sources of HAP “which provide for the use of generally available 

control technologies (GACT) or management practices by such 

sources to reduce emissions of hazardous air pollutants.” While 

GACT serves as the basis for standards of most emissions from 

area sources, two pollutants emitted by coal-fired boilers, POM 

as 7-PAH and Hg, must be regulated based on the performance of 

MACT. These two pollutants are regulated based on MACT because 

area source industrial, commercial and institutional boilers 

combusting coal were listed under section 112(c)(6) of the CAA 

due to the source categories’ emissions of POM and Hg. Sections 

112(d)(2) or (d)(4) of the CAA require the EPA to regulate 

pollutants listed under section 112(c)(6) based on MACT. The 

final rule meets the requirements of section 112(d) of the CAA 

by setting MACT standards for Hg and CO — as a surrogate for POM 

for units in the coal-fired subcategory. Further, the final rule 
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sets standards based on GACT for all of the other urban HAP 

emitted from coal-fired boilers that pose the greatest public 

health risk, pursuant to section 112(c)(3) of the CAA. In 

addition, the final rule sets standards based on GACT for 

boilers combusting oil or biomass for all urban HAP, including 

Hg, arsenic, beryllium, cadmium, lead, chromium, manganese, 

nickel, POM, ethylene dioxide, and PCBs.

In developing these MACT standards for coal-fired boilers, 

the EPA also considered section 112(h) of the CAA, which 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 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 has found that work practices are appropriate under 

certain circumstances, pursuant to section 112(h) of the CAA, in 

the form of periodic tune-ups for small boilers.

This final rule replaces the provisions of the final rule 

issued by the EPA on March 21, 2011, for those provisions which 

the EPA is revising in this action. 

Summary of Major Provisions

In general, the final rule as amended by this action 

requires facilities classified as area sources of HAP with 
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affected boilers to reduce emissions of harmful toxic air 

emissions from these combustion sources, improving air quality,

and protecting public health in communities where these 

facilities are located. Recognizing the diversity of this source 

category and the multiple sectors of the economy this rule 

affects, in the March 2011 final rule, the EPA established 

subcategories for boilers based on the design of the combustion 

equipment and operating schedules of the unit.

Numerical emission limits, based on MACT, were established 

for Hg and CO at new and existing coal-fired boilers with a 

design heat input capacity of 10 MMBtu/hr or more. Small coal 

units with a design heat input capacity of less than 10 MMBtu/hr 

are subject to periodic tune-up work practices for CO and Hg in 

lieu of numeric emission limits because the EPA found that it 

was technologically and economically impracticable to apply 

measurement methodology to these small sources, pursuant to 

section 112(h).

Numerical emission limits, based on GACT, were established for 

PM as a surrogate for other urban HAP for new coal, biomass and 

oil-fired boilers with a design heat input capacity of 10 

MMBtu/hr or greater. Existing biomass and oil-fired boilers and 

new small biomass- and oil-fired boilers are subject to periodic 

tune-up management practices for PM based on GACT. New and 

existing seasonal boilers firing oil or biomass are subject to 
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periodic tune-up management practices, based on GACT, in lieu of 

numerical emission limits, for all HAP. Certain other 

subcategories (seasonal boilers, oil-fired boilers with heat 

input capacity of equal to or less than 5 MMBtu/hr, boilers with 

an oxygen trim system, limited-use boilers) have work practice 

or management practice requirements such as tune-ups tailored to 

their schedule of operation and types of fuel.

The EPA also finalized alternative compliance options for 

the numeric CO emission limit. Coal-fired boilers subject to CO 

emission limits can comply with this limit using a periodic 

stack test and continuous parametric monitoring, or by using 

CEMS. This alternative standard is based on a 10-day rolling 

average and provides additional compliance flexibility to 

sources with existing CO CEMS equipment or load following 

operations. The numerical emission limits in this final rule 

apply at all times except during periods of startup and 

shutdown, at which time alternative work practice standards 

apply since the EPA has determined that it is technologically 

and economically impracticable to apply measurement methodology 

during periods of startup and shutdown. The rule also requires

periodic testing, parametric monitoring, recordkeeping and 

reporting to ensure compliance with the emission standards and 

work practices. The final rule also employs a one-time energy 

assessment standard on all existing facilities that have one or 
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more existing coal, biomass or oil-fired boilers with a heat 

input capacity of 10 MMBtu/hr or greater. The energy assessment 

is a beyond-the-floor requirement for the MACT-based standards 

for coal-fired boilers and a GACT-based requirement for biomassand oil-fired boilers. The length of time needed to conduct the 

energy assessment depends on the total energy consumption of the 

affected boilers at the facility.

The compliance dates for the rule are March 21, 2014, for 

existing sources, May 20, 2011, for new sources that started up 

on or before May 20, 2011, and upon startup for new sources that 

start up after May 20, 2011. New sources are defined as sources 

that began operation after June 4, 2010.

Costs and Benefits

The amendments contained in this final action are 

corrections that are intended to clarify, but not change, the 

coverage of the final rule. The final rule will affect 

approximately an estimated 180,000 existing area source boilers 

and the EPA projects approximately an additional 6,800 new 

boilers to be subject to the rule over the initial 3-year 

period. The clarifications and corrections should make it easier 

for owners and operators and for local and state authorities to 

understand and implement the requirements. As compared to the 

control costs estimated in the March 2011 final rule, these

amendments will result in a decrease in the capital and annual 
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costs due to the increase in emission limits and the decrease in 

burden on small facilities. A more detailed discussion of the 

costs and benefits of the final rule is provided at 76 FR 15579, 

March 21, 2011, and 76 FR 80542, December 23, 2011. Section VI

of this preamble discusses the impacts of the amendments.

Exposure to toxic air pollutants regulated under this 

standard can cause respiratory problems such as bronchitis and 

asthma, and other serious health issues.

SUPPLEMENTARY INFORMATION:

Acronyms and Abbreviations. The following acronyms and 

abbreviations are used in this document.

7-PAH 7-polynuclear aromatic hydrocarbons

ASTM American Society for Testing and Materials

Btu British thermal unit

CO carbon monoxide

CEMS continuous emissions monitoring system

CDX Central Data Exchange

CAA Clean Air Act

CFR Code of Federal Regulations 

COMS continuous opacity monitoring system

CPMS continuous parameter monitoring system

DOE Department of Energy

ERT Electronic Reporting Tool

ESP electrostatic precipitator

FR Federal Register

GACT generally available control technologies

HAP hazardous air pollutants

Hg mercury

HQ Headquarters

ISO International Standards Organization

lb pounds

MACT maximum achievable control technology

MMBtu million British thermal units

NAICS North American Industry Classification System

NESHAP national emission standards for hazardous air 

pollutants
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NSPS new source performance standard

NTTAA National Technology Transfer and Advancement Act

OMB Office of Management and Budget

PCBs polychlorinated biphenyls

PM particulate matter

POM polycyclic organic matter

ppm parts per million

PSD prevention of significant deterioration

RFA Regulatory Flexibility Act

RIN Regulatory Information Number 

TBtu trillion British thermal unit

TTN Technology Transfer Network

tpy tons per year

UMRA Unfunded Mandates Reform Act of 1995

UPL upper prediction limit

VCS Voluntary Consensus Standards

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

III. Summary of Final Action on Reconsideration

A. Affected Sources

B. Source Category Exclusions

C. Emission Limits

D. Tune-up Work Practice and Management Practice Standards

E. Energy Assessment Work Practice and Management Practice 

Standards

F. GACT-Based Standards

G. Initial Compliance

H. Operating Limits

I. Continuous Compliance

J. Periods of Startup, Shutdown and Malfunction

K. Notification, Recordkeeping, and Reporting Requirements

L. Title V Permitting Requirements

M. Definition of Period of Gas Curtailment or Supply 

Interruption

N. Miscellaneous Technical Corrections
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O. Other Issues

IV. Summary of Significant Changes Since Proposed Action on 

Reconsideration

A. Applicability

B. Tune-Up Requirements

C. Energy Assessment

D. Clarification of Oxygen Concentration Operating Limits

E. Definitions Regarding Averaging Times

F. Fuel Sampling Frequency

G. Performance Testing Frequency

H. Startup and Shutdown Definitions

I. Notifications

J. Miscellaneous Definitions

V. Other Actions the EPA is Taking

VI. Impacts associated with this 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

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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Industry 

Category

NAICS 

Codea Examples of Regulated Entities

Any area 

source 

facility 

using a 

boiler as 

defined in 

the final

rule

321 Wood product manufacturing.

11 Agriculture, greenhouses.

311 Food manufacturing.

327 Nonmetallic mineral product

manufacturing.

424 Wholesale trade, nondurable

goods.

531 Real estate.

611 Educational services.

813 Religious, civic, professional,

and similar organizations.

92 Public administration.

722 Food services and drinking

places.

62 Health care and social assistance.

22111 Electric power generation.

a 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 63.11193 

of subpart JJJJJJ (National Emission Standards for Hazardous Air 

Pollutants for Industrial, Commercial, and Institutional Boilers 

Area Sources). If you have any questions regarding the 

applicability of the final rule to a particular entity, consult 

either the air permit authority for the entity or your EPA 
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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 May 20, 2011. 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.

Under CAA section 307(b)(2), the requirements established

by this final rule may not be challenged separately in any civil 

or criminal proceedings brought by EPA to enforce these 

requirements.

II. Background Information
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Section 112(d) of the CAA requires the EPA to establish 

NESHAP for both major and area sources of HAP that are listed 

for regulation under CAA section 112(c). A major source is any 

stationary source that emits or has the potential to emit 10 tpy 

or more of any single HAP or 25 tpy or more of any combination 

of HAP. An area source is a stationary source that is not a 

major source.

On March 21, 2011 (76 FR 15554), the EPA issued the NESHAP 

for industrial, commercial and institutional area source boilers 

pursuant to CAA sections 112(c)(3), 112(c)(6), and 112(k)(3)(B).

CAA section 112(k)(3)(B) directs the EPA to identify at 

least 30 HAP that, as a result of emissions from area sources, 

pose the greatest threat to public health in the largest number 

of urban areas. The EPA implemented this provision in 1999 in 

the Integrated Urban Air Toxics Strategy, (64 FR 38715, July 19, 

1999) (Strategy). Specifically, in the Strategy, the EPA 

identified 30 HAP that pose the greatest potential health threat 

in urban areas, and these HAP are referred to as the “30 urban 

HAP.” Section 112(c)(3) of the CAA requires the EPA to list 

sufficient categories or subcategories of area sources to ensure 

that area sources representing 90 percent of the emissions of 

the 30 urban HAP are subject to regulation. Under CAA section 

112(d)(5), the EPA may elect to promulgate standards or

requirements for area sources “which provide for the use of 
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generally available control technologies (“GACT”) or management 

practices by such sources to reduce emissions of hazardous air 

pollutants.”

While GACT may be a basis for standards for most types of 

HAP emitted from area sources, CAA section 112(c)(6) requires 

that the EPA list categories and subcategories of sources

assuring that sources accounting for not less than 90 percent of 

the aggregate emissions of each of seven specified HAP are 

subject to standards under CAA sections 112(d)(2) or (d)(4), 

which require the application of the more stringent MACT. The 

seven HAP specified in CAA section 112(c)(6) are as follows: 

alkylated lead compounds, POM as PAH, hexachlorobenzene, Hg,

PCBs, 2,3,7,8-tetrachlorodibenzofurans, and 2,3,7,8-

tetrachlorodibenzo-p-dioxin.

As noted in the preamble to the final rule, (76 FR 15556, 

March 21, 2011), we listed area source industrial boilers and 

commercial/institutional boilers combusting coal under CAA 

section 112(c)(6) based on the source categories’ contribution 

of mercury and POM, and under CAA section 112(c)(3) for their 

contribution of arsenic, beryllium, cadmium, lead, chromium, 

manganese, nickel, ethylene dioxide, and PCBs, as well as Hg and 

POM. We promulgated final standards for coal-fired area source 

boilers to reflect the application of MACT for Hg and POM, and 

to reflect GACT for the urban HAP other than Hg and POM. 
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We listed industrial and commercial/institutional boilers 

combusting oil or biomass under CAA section 112(c)(3) for their 

contribution of Hg, arsenic, beryllium, cadmium, lead, chromium, 

manganese, nickel, POM, ethylene dioxide, and PCBs. For boilers 

firing oil or biomass, the final standards reflect GACT for all 

of the urban HAP.

On March 21, 2011, we also published a notice to initiate 

the reconsideration of certain aspects of the final rule for 

area source industrial, commercial and institutional boilers (76 

FR 15266). The reconsideration notice identified several 

provisions of the final rule where additional public comment was 

appropriate. The notice also identified several issues of 

central relevance to the rulemaking where reconsideration was 

appropriate under CAA section 307(d). 

Following promulgation of the final rule, the EPA also 

received petitions for reconsideration from the following 

organizations (Petitioners): American Sugar Cane League of the 

U.S.A., Alaska Oil and Gas Association, American Coke and Coal 

Chemicals Institute, American Iron and Steel Institute, American 

Petroleum Institute, Council of Industrial Boiler Owners, 

Industry Coalition (American Forest and Paper Association

(AF&PA) et. al.), National Petrochemical and Refiners 

Association, Sierra Club, and the State of Washington Department 

of Ecology. Petitioners, pursuant to CAA section 307(d)(7)(B), 
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requested that the EPA reconsider numerous provisions in the 

rules. 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:

 Establishing separate requirements for seasonally operated 

boilers.

 Solicitation of new data or corrections to existing data to 

revise emission standards calculations.

 Exempting temporary boilers.

 Clarifying the initial compliance schedule for existing 

boilers subject to tune-ups.

 Defining periods of gas curtailment.

 Providing an optional CO compliance mechanism using CEMS.

 Averaging times for parameter monitoring. 

 Providing an affirmative defense for malfunction events.

 Adjusting frequency of tune-up work practices for very 

small units.
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 Selecting a 99 percent confidence interval for setting the 

CO emission limit.

 Establishing GACT-based limits for biomass and oil-fired 

boilers.

 Scope and duration of the energy assessment and deadline 

for completing the assessment.

 Establishing GACT-based limits for PM at new oil-fired 

boilers.

 Exempting area sources from title V permitting 

requirements.

In this action, the EPA is finalizing multiple changes to 

this NESHAP after considering public comments on the items under 

reconsideration.

III. Summary of Final Action on Reconsideration

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 

agency’s final action 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 (76 FR 15554, March 21, 2011).
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A. Affected Sources

 This final rule amends 40 CFR 63.11194 to specify that an 

existing dual-fuel fired boiler (i.e., commenced construction or 

reconstruction on or before June 4, 2010) meeting the definition 

of gas-fired boiler, as defined in 40 CFR 63.11237, that meets 

the applicability requirements of subpart JJJJJJ after June 4, 

2010 due to a fuel switch from gaseous fuel to solid fossil fuel, 

biomass, or liquid fuel is considered to be an existing source

under this subpart as long as the boiler was designed to 

accommodate the alternate fuel. A new or reconstructed dual-fuel 

fired boiler (i.e., commenced construction or reconstruction 

after June 4, 2010) meeting the definition of gas-fired boiler, 

as defined in 40 CFR 63.11237, that meets the applicability 

criteria of subpart JJJJJJ after June 4, 2010 due to a fuel 

switch from gaseous fuel to solid fossil fuel, biomass, or liquid 

fuel is considered to be a new source under this subpart.

B. Source Category Exclusions

This final rule amends the list of boilers excluded from 

the source categories subject to subpart JJJJJJ in 40 CFR 

63.11195 to include certain boilers that may be located at an 

industrial, commercial or institutional area source facility. 

These clarifications of the source categories are described 

below.

1. Electric Boilers.
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The EPA is amending 40 CFR 63.11195 by adding electric 

boilers to the list of boilers not subject to subpart JJJJJJ. 

Electric boilers are defined in 40 CFR 63.11237 as follows:

Electric boiler means a boiler in which electric heating 

serves as the source of heat. Electric boilers that burn 

gaseous or liquid fuel during periods of electrical power 

curtailment or failure are included in this definition.

2. Residential Boilers.

The EPA is amending 40 CFR 63.11195 by adding residential

boilers to the list of boilers not subject to subpart JJJJJJ. We 

are clarifying that a residential boiler may be part of a 

residential combined heat and power system and that a boiler 

serving a single unit residence dwelling that has since been

converted or subdivided into condominiums or apartments may also 

be considered a residential boiler. Residential boilers are 

defined in 40 CFR 63.11237 as follows:

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 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:

(i) a dwelling containing four or fewer families, or

(ii) a single unit residence dwelling that has since 

been converted or subdivided into condominiums or 

apartments.

3. Temporary Boilers.

The EPA is amending 40 CFR 63.11195 by adding temporary 

boilers to the list of boilers not subject to subpart JJJJJJ. 
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Similar to residential boilers, we did not intend to regulate

temporary boilers under the area source standards because they 

are not part of either the industrial boiler source category or 

the commercial/institutional boiler source category. By their 

nature of being temporary, these boilers are operating in place 

of another non-temporary boiler while that boiler is being 

constructed, replaced or repaired, in which case we would have 

counted the non-temporary boiler as one being regulated.

Additionally, the final major source rule for boilers excludes 

temporary boilers from the source category and we are now 

providing the same exclusion in the area source rule.

The definition of “temporary boiler” specifies that a 

boiler is not a temporary boiler if it 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. The definition of “temporary boiler” also 

specifies that any temporary boiler that replaces a temporary 

boiler at a location within the facility and performs the same 

or similar function will be included in calculating the 

consecutive time period unless there is a gap in operation of 12 

months or more. Temporary boilers are defined in 40 CFR 63.11237 

as follows:

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 
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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 regulatory 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 within the facility and performs the 

same or similar function will be included in calculating 

the consecutive time period unless there is a gap in 

operation of 12 months or more.

(3) The equipment is located at a seasonal facility 

and operates during the full annual operating period of the 

seasonal facility, remains at the facility for at least 2 

years, and operates at that facility for at least 3 months 

each year.

(4) The equipment is moved from one location to 

another 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.

4. Boilers with Section 3005 Permits.

The EPA is clarifying the language in 40 CFR 63.11195(c) to 

provide an exclusion stating “unless such units do not combust 

hazardous waste and combust comparable fuels” such that it 

reads: “A boiler required to have a permit under section 3005 of 

the Solid Waste Disposal Act or covered by subpart EEE of this 

part (e.g., hazardous waste boilers), unless such units do not 

combust hazardous waste and combust comparable fuels.”

5. Boilers used as Control Devices.

The EPA is clarifying the language in 40 CFR 63.11195(g) to 

clarify that any boiler that is used as a control device to 
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comply with a subpart under part 60, 61, or 65 of chapter 40 is

not subject to subpart JJJJJJ provided that at least 50 percent 

of the heat input to the boiler is provided by the gas stream 

that is regulated under another subpart.

C. Emission Limits

1. Hg Emission Limit for Coal-Fired Boilers.

The EPA is amending the Hg emission limit for coal-fired 

boilers to 0.000022 lb per MMBtu based on a revised analysis. 

The revised analysis excludes data for a utility boiler that was 

erroneously used as the basis for the Hg emission limit included 

in the March 2011 final rule. Further discussion of this 

revision to the Hg emission limit is located in the December 23, 

2011, proposal (76 FR 80541).

A memorandum “Beyond-the-Floor Technology Analysis for 

Mercury” located in the docket for the rulemaking describes our 

beyond-the-floor technology analysis for Hg emissions from new 

and existing area source coal-fired boilers with heat input 

capacity of 10 MMBtu/hr or greater. In the beyond-the-floor 

option for Hg emissions, new and existing coal-fired boilers 

would be required to comply with a Hg emission limit more 

stringent than the MACT floor-based emission limit of 2.2 X 10-5

lb of Hg per MMBtu. To comply with a limit more stringent than 

the fabric filter-based MACT floor limit (e.g., to meet a limit 

such as the utility boiler-based limit in the March 2011 final 
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rule), it is expected that an affected boiler would need to 

employ fabric filter control along with activated carbon 

injection (ACI). In summary, we determined that the beyond-thefloor option of installing ACI for Hg control from area source 

coal-fired boilers is not economically feasible.

2. Using the UPL for Setting the CO Emission Limit. 

The EPA is amending the CO emission limit for coal-fired 

boilers to reflect a revised analysis that uses the original 99 

percent confidence level in determining the UPL. We have also 

removed from our analysis the data from a boiler for which only 

two test runs were completed in measuring CO emissions. The 

required number of test runs for accurately measuring emissions 

and demonstrating compliance is three test runs. Therefore, we 

determined that the datum from this unit was not representative 

and we excluded it from the data set upon which we performed the 

revised analysis. Based on the results of the revised analysis, 

we are amending the CO emission limit for new and existing coalfired boilers from 400 ppm by volume on a dry basis, corrected 

to 3 percent oxygen, to 420 ppm by volume on a dry basis, 

corrected to 3 percent oxygen.

3. Applicability of PM Emission Limit to Certain Oil-Fired 

Boilers.

The EPA is amending the applicability of PM emission limit 

requirements for certain new or reconstructed oil-fired boilers. 
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We are amending 40 CFR 63.11210 to specify that new or 

reconstructed oil-fired boilers that combust only oil that 

contains no more than 0.50 weight percent sulfur or a mixture of 

0.50 weight percent sulfur oil with other fuels not subject to a 

PM emission limit under this subpart and that do not use a postcombustion technology (except a wet scrubber) to reduce PM or 

sulfur dioxide emissions are not subject to the PM emission 

limit. 

D. Tune-up Work Practice and Management Practice Standards

1. Requirements for Seasonally Operated Boilers. 

The EPA is establishing separate requirements for a 

subcategory of boilers that are seasonally operated. For 

seasonally operated boilers, we are amending 40 CFR 63.11223 to 

specify that they are required to complete a tune-up every 5 

years, instead of on a biennial basis as is required for most 

non-seasonal boilers. Specifically, existing seasonal boilers 

are required to complete the initial tune-up by March 21, 2014, 

and a subsequent tune-up every 5 years after the initial tuneup. New and reconstructed seasonal boilers are not required to 

complete an initial tune-up, but are required to complete a 

tune-up every 5 years after the initial startup of the new or 

reconstructed boiler. A combined total of 15 days of periodic 

testing of the seasonal boiler during the 7-month shutdown is 

allowed. The definition of “seasonal boiler” clarifies that it 
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only applies to biomass- or oil-fired boilers. Seasonally 

operated boilers are defined in 40 CFR 63.11237 as follows:

Seasonal boiler means a boiler that undergoes a shutdown 

for a period of at least 7 consecutive months (or 210 

consecutive days) each 12-month period due to seasonal 

conditions, except for periodic testing. Periodic testing 

shall not exceed a combined total of 15 days during the 7-

month shutdown. This definition only applies to boilers 

that would otherwise be included in the biomass subcategory 

or the oil subcategory.

2. Requirements for Small Oil-Fired Units.

The EPA is establishing separate requirements for a subset 

of oil-fired boilers with a heat input capacity of equal to or 

less than 5 MMBtu/hr. We are amending 40 CFR 63.11223 to specify 

that this subset of small oil-fired boilers are required to 

complete a tune-up every 5 years, instead of on a biennial basis 

as is required for most larger oil-fired boilers. Specifically, 

existing oil-fired boilers with a heat input capacity of equal 

to or less than 5 MMBtu/hr are required to complete the initial 

tune-up by March 21, 2014, and a subsequent tune-up every 5

years after the initial tune-up. New and reconstructed oil-fired 

boilers with a heat input capacity of equal to or less than 5 

MMBtu/hr are not required to complete an initial tune-up, but 

are required to complete a tune-up every 5 years after the 

initial startup of the new or reconstructed boiler.

3. Requirements for Boilers with Oxygen Trim Systems.
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The EPA is establishing separate requirements for boilers 

with oxygen trim systems that maintain an optimum air-to-fuel 

ratio that would otherwise be subject to a biennial tune-up. We 

are amending 40 CFR 63.11223 to specify that this subset of 

boilers are required to complete a tune-up every 5 years. 

Specifically, existing boilers with oxygen trim systems are

required to complete the initial tune-up by March 21, 2014, and 

a subsequent tune-up every 5 years after the initial tune-up.

New and reconstructed boilers with oxygen trim systems are not 

required to complete an initial tune-up, but are required to 

complete a tune-up every 5 years after the initial startup of 

the new or reconstructed boiler.

4. Requirements for Limited-Use Boilers.

The EPA is establishing separate requirements for a 

subcategory of boilers that operate on a limited basis. The 

limited-use subcategory includes any boiler that burns any 

amount of solid or liquid fuels and has a federally enforceable 

average annual capacity factor of no more than 10 percent. For 

limited-use boilers, we are amending 40 CFR 63.11223 of the 

final rule to specify that they are required to complete a tuneup every 5 years. Specifically, existing limited-use boilers are

required to complete the initial tune-up by March 21, 2014, and 

a subsequent tune-up every 5 years after the initial tune-up.

New and reconstructed limited-use boilers are not required to 
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complete an initial tune-up, but are required to complete a 

tune-up every 5 years after the initial startup of the new or 

reconstructed boiler. Limited-use boilers are not subject to the 

emission limits in Table 1 to the subpart, the energy assessment 

requirements in Table 2 to the subpart, or the operating limits 

in Table 4 to the subpart.

E. Energy Assessment Work Practice and Management Practice 

Standards

1. Scope.

The EPA is amending the definition of “energy assessment” 

to clarify that the scope of the energy assessment does not 

encompass energy use systems located off-site or energy use 

systems using electricity purchased from an off-site source. The 

energy assessment is limited to only those energy use systems, 

located on-site, associated with the affected boilers. We are 

also clarifying that the scope of the assessment is based on 

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

aggregation of all individual energy using segments of a 

facility.

The definition of “boiler system” is being revised in the 

final rule to clarify that it means the boiler and associated 

components directly connected to and serving the energy use 

systems. We are amending the definition of “energy use system” 

to clarify that energy use systems are only those systems using 
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energy clearly produced by affected boilers. We are also 

revising the definition of “qualified energy assessor” such that 

the assessor is only required to have knowledge and capabilities 

specific to the processes at the facility and that the qualified 

energy assessor may be a company employee or an outside 

specialist.

We are clarifying that energy assessor approval and 

qualification requirements are waived in instances where past or 

amended energy assessments are used to meet the energy 

assessment requirements. Finally, we are specifying that a 

source operating under an energy management program developed 

according to the ENERGY STAR guideline for energy management, 

DOE Save Energy Now, or ISO 50001 compatible energy management 

systems, that includes the affected boilers, is allowed as an 

alternative to a one-time energy assessment.

2. Compliance Date. 

As specified in 40 CFR 63.11196(a)(3), existing boilers 

that are subject to the energy assessment requirement must 

achieve compliance with the energy assessment requirement no 

later than March 21, 2014. Thus, in order to meet the 

requirements of the rule, energy assessments must, therefore, be 

completed by the compliance date (March 21, 2014) for existing 

sources.

3. Maximum Duration Requirements.
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The EPA is amending the definition of “energy assessment” 

for facilities with affected boilers with less than 0.3 TBtu/yr 

heat input capacity and for facilities with affected boilers 

with 0.3 to 1 TBtu/yr heat input capacity to change the maximum 

time to conduct the energy assessment from one day to 8 on-site 

technical hours and from three days to 24 on-site technical 

hours, respectively, and to allow sources to perform longer 

assessments at their discretion. We are also amending the 

definition “energy assessment” for facilities with affected 

boilers with greater than 1 TBtu/yr heat input capacity to 

specify that the maximum time to conduct the assessment is up to 

24 on-site technical hours for the first TBtu/yr plus 8 on-site 

technical 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.

F. GACT-Based Standards

1. Establishing GACT-Based Emission Limits for Biomass- and OilFired Boilers. 

The EPA is not amending the GACT-based standards, as 

specified in the March 21, 2011, final rule, for biomass- and 

oil-fired boilers. Specifically, the final standards for 

biomass- and oil-fired area source boilers are based on GACT 

instead of based on MACT as were the proposed standards for all 

pollutants except PAH. Our rationale for the changes between 
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proposal and promulgation for the biomass- and oil-fired 

boilers, including not requiring MACT for PAH, can be found in 

the preamble to the promulgated area source standards (76 FR 

15565-15567 and 15574-15575, March 21, 2011). The final 

standards for area source biomass- and oil-fired boilers require 

these boilers to meet the following standards:

New boilers with heat input capacity greater than 10 

MMBtu/hr that are biomass-fired or oil-fired must meet GACTbased numerical emission limits for PM.

New boilers with heat input capacity greater than 10 

MMBtu/hr that are biomass-fired or oil-fired must comply with 

work practice standards to minimize the boiler’s startup and 

shutdown periods following the manufacturer’s recommendations, 

or the manufacturer’s recommendations for a unit of similar 

design. 

Existing boilers with heat input capacity greater than 10 

MMBtu/hr that are biomass-fired or oil-fired must have a onetime energy assessment performed by a qualified energy assessor 

or must have an energy management plan under which the owner or 

operator currently operates. 

All new and existing units, regardless of size, that are 

biomass-fired or oil-fired must have a GACT-based periodic tuneup.

2. Setting GACT-Based PM Standards for New Oil-Fired Boilers. 
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The EPA is not making any changes to the PM limit for new 

oil-fired boilers. New oil-fired boilers with heat input 

capacity greater than 10 MMBtu/hr must meet a GACT-based 

numerical emission limit for PM (0.03 lb per MMBtu of heat 

input). New oil-fired units, regardless of size, must have a 

GACT-based periodic tune-up. Our rationale for finalizing GACTbased PM emissions limits can be found in the preamble to the 

promulgated area source standards (76 FR 15574, March 21, 2011).

G. Initial Compliance

1. Dates.

 Commenters have argued that the 3-year compliance deadline 

the EPA is establishing for existing sources to meet the 

standards does not provide them with sufficient time to meet the 

standards in view of the 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 standards should be able to meet the standards within 3

years, even those that need to install pollution control 

technologies to do so. In addition, many sources subject to the 

standards are biomass- or oil-fired boilers or small coal-fired 

boilers (less than 10 MMBtu/hr) and will not need to install 
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controls in order to demonstrate compliance. For these sources, 

the 3-year compliance deadline is highly unlikely to be 

unachievable or even particularly challenging 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, as commenters have noted correctly, the 

CAA allows title V permitting authorities to grant sources, on a 

case-by-case basis, extensions to the compliance time of up to 1 

year if such time is needed for the installation of controls. 

See CAA section 112(i)(3)(B)). Permitting authorities are 

already familiar with, and in many cases have experience with, 

applying the 1-year extension authority under section 

112(i)(3)(B) since the provision applies to all NESHAP. See 40 

CFR 63.6(i)(4)(A). We believe that should the range of 

circumstances that commenters have cited as impeding sources’ 

ability to install controls within 3 years materialize, then 

permitting authorities can 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, 

permitting authorities can make the 1-year extension available 

to applicants.

In making a determination as to whether an extension is 

appropriate, we believe it is reasonable for permitting 
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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 the Major Source Boilers Standards and the Mercury 

and Air Toxics Standards 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 that it may be 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 sum, the EPA believes that although most, if not all,

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

2. Demonstrating Initial Compliance. 

The EPA is amending 40 CFR 63.11210 to clarify the dates by 

which new and reconstructed boilers need to demonstrate initial 

compliance. We are amending 40 CFR 63.11210(d) to clarify that 

only boilers that are subject to emission limits for PM, Hg or 

CO in Table 1 to subpart JJJJJJ have a 180-day period after the 

applicable compliance date to demonstrate initial compliance.

We are adding a new paragraph (i) to 40 CFR 63.11210 to 

clarify the initial compliance requirements for boilers located 

at existing major sources of HAP that become area sources on a 

timely basis. Such major sources would limit their potential to 

emit (e.g., make a physical change or take a permit limit) 

before the first substantive compliance date for the Major 

Source Boiler Rule. Any such existing boiler at the existing 

source must demonstrate compliance with subpart JJJJJJ within 

180 days of the later of March 21, 2014 or the effective date of 

becoming an area source. Any new or reconstructed boiler at the 

existing source must demonstrate compliance with subpart JJJJJJ 

within 180 days of the later of March 21, 2011 or startup.
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Notification of such changes must be submitted according to 40 

CFR 63.11225(g).

We are adding a new paragraph (j) to 40 CFR 63.11210 that 

specifies initial compliance demonstration requirements for 

existing affected boilers that have not operated between the 

effective date of the rule and the source’s compliance date.

Owners and operators of boilers subject to emission limits must 

complete the initial compliance demonstration no later than 180 

days after the re-start of the affected boiler, sources subject 

to tune-up requirements must complete the initial performance 

tune-up no later than 30 days after the re-start of the affected 

boiler, and sources subject to the one-time energy assessment 

must complete the assessment no later than the compliance date 

specified in 40 CFR 63.11196.

3. Schedule for Existing Boilers Subject to Tune-up 

Requirements. 

The EPA is amending 40 CFR 63.11196 to specify that all 

existing boilers subject to the tune-up requirement have 3 years 

(by March 21, 2014) in which to demonstrate initial compliance, 

instead of 1 year as specified in the 2011 final rule (76 FR 

15554, March 21, 2011) or 2 years as specified in the proposed 

reconsideration of final rule action (76 FR 80532, December 23, 

2011). In the December 23, 2011, proposal, we specifically 
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requested comment on whether the initial compliance period for 

the tune-up requirement should be extended to 3 years.

4. Conducting Initial Tune-ups at New and Reconstructed Sources. 

The EPA is removing the requirement for an initial tune-up 

for new and reconstructed boilers. Thus, new and reconstructed 

units are required to complete the applicable biennial or 5-year 

tune-up no later than 25 months or 61 months, respectively, 

after the initial startup of the new or reconstructed boiler.

5. Fuel Requirements. 

The EPA is amending 40 CFR 63.11223(a) to specify that 

boiler tune-ups must be conducted while burning the type of fuel 

that provided the majority of the heat input to the boiler over 

the 12 months prior to the tune-up.

H. Operating Limits

1. Operating Limits for Oxygen Concentration. 

The EPA is clarifying that the oxygen concentration must be 

at or above the minimum established during a performance stack 

test. These limits have also been clarified to be applicable 

when the unit is firing the fuel or fuel mixture utilized during 

the CO performance test.

2. Maximum Operating Load. 

The EPA is including provisions for establishing a unitspecific limit for maximum operating load that apply to any 

boiler subject to an emission limit for which compliance is 
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demonstrated by a performance stack test. Operating load data 

includes fuel feed rate data or steam generation rate data.

3. Establishing Operating Limits for Wet Scrubbers. 

The EPA is amending the operating limit provisions in 40 

CFR 63.11211(b)(2) for an ESP operated with a wet scrubber to 

remove the statement that the operating limits for ESP do not 

apply to dry ESP systems operated without a wet scrubber.

I. Continuous Compliance

1. CO Emission Limit.

The final rule requires sources subject to a CO emission 

limit to demonstrate compliance by measuring CO emissions while 

also monitoring the oxygen content of the exhaust. We are 

amending the monitoring requirements in 40 CFR 63.11224(a) to 

allow sources subject to a CO emission limit the option to 

install, operate, and maintain CO and oxygen CEMS. The CEMS must 

be installed, operated and maintained according to Performance 

Specifications 3 and 4, 4A, or 4B at 40 CFR part 60, appendix B, 

and according to the site-specific monitoring plan that each 

facility is required to develop. The CEMS will also be required 

to complete a performance evaluation, also according to 

Performance Specifications 3 and 4, 4A, or 4B. 

Sources have the option to demonstrate continuous 

compliance by monitoring both CO and oxygen using CEMS to 

demonstrate compliance with the CO emission limit, corrected to 
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3 percent oxygen, or monitoring and complying with an oxygen 

content operating limit that is established during the 

performance stack test. Sources that use CO and oxygen CEMS are 

exempt from initial CO performance testing and oxygen content 

operating limit requirements. Sources that choose to demonstrate 

continuous compliance by monitoring and complying with an oxygen 

content operating limit must install, operate, and maintain an 

oxygen analyzer system at or above the minimum percent oxygen by 

volume that is established as the operating limit for oxygen 

when firing the fuel or fuel mixture utilized during the most 

recent CO performance stack test. We have removed the 

requirement that the oxygen monitor be located at the outlet of 

the boiler, so that it can be located either within the 

combustion zone or at the outlet as a flue gas oxygen monitor.

We are amending the oxygen monitoring requirements to allow 

for the use of oxygen trim systems and have included oxygen trim 

systems in the definition of “oxygen analyzer system.” We have 

clarified that operation of oxygen trim systems to meet the 

oxygen monitoring requirements shall not be done in a manner 

that compromises furnace safety. The definitions of “oxygen 

analyzer system” and “oxygen trim system” in 40 CFR 63.11237 

read as follows:

 Oxygen analyzer system means all equipment required to 

determine the oxygen content of a gas stream and used to 

monitor oxygen in the boiler flue gas, boiler firebox, or 
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other appropriate intermediate 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 carbon monoxide monitor that automatically provides 

a feedback signal to the combustion air controller.

2. Tune-up Standards.

The EPA is amending the requirements for demonstrating 

continuous compliance with the work practice and management 

practice tune-up standards in 40 CFR 63.11223 to clarify that CO 

measurements that are required before and after tune-up 

adjustments may be taken using a portable CO analyzer. We are 

clarifying that the requirements to inspect the burner and the 

system controlling the air-to-fuel ratio may be delayed until 

the next scheduled shutdown. We are also clarifying that units 

that produce electricity for sale may delay these inspections 

until the first outage, not to exceed 36 months from the 

previous inspection. In addition, we are clarifying that 

optimization of CO emissions should be consistent with any NOX

requirements to which the unit is subject. Finally, we are 

specifying for units that are not operating on the required date 

for a tune-up, the tune-up must be conducted within 30 calendar 

days of startup.

3. Performance Testing Frequency.
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The EPA is amending 40 CFR 63.11220 to specify in paragraph 

(b) that the owner or operator of an affected boiler does not 

need to conduct further PM emissions testing if, when 

demonstrating initial compliance with the PM emission limit, the 

performance test results show that the PM emissions are equal to 

or less than half of the PM emission limit. The owner or 

operator must continue to comply with all applicable operating 

limits and monitoring requirements. If the initial performance 

test results show that the PM emissions are greater than half of 

the PM emission limit, the owner or operator must conduct 

subsequent performance tests as specified in 40 CFR 63.11220(a).

We are clarifying in 40 CFR 63.11220(d) that existing 

affected boilers that have not operated since the previous 

compliance demonstration must complete their subsequent 

compliance demonstration no later than 180 days after the restart of the affected boiler.

4. Fuel Analysis. 

The EPA is amending 40 CFR 63.11220 to specify in paragraph 

(c) that the owner or operator of an affected coal-fired boiler 

does not need to conduct further fuel analysis sampling if, when 

demonstrating initial compliance with the Hg emission limit, the 

Hg constituents in the fuel or fuel mixture are measured to be 

equal to or less than half of the Hg emission limit. The owner 
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or operator must continue to comply with all applicable 

operating limits and monitoring requirements.

When demonstrating initial compliance with the Hg emission 

limit, if the Hg constituents in the fuel or fuel mixture are 

greater than half of the Hg emission limit, the owner or 

operator must conduct quarterly sampling.

5. Averaging Times.

The EPA is amending the averaging time for parameter 

monitoring and compliance with operating limits to a 30-day 

rolling average.

The EPA is revising the definitions of “30-day rolling 

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

and shutdown or downtime in the calculation of the arithmetic 

mean.

6. Monitoring Data. 

The EPA is clarifying in 40 CFR 63.11221 the monitoring 

data collection requirements and the meaning of a “deviation” 

with respect to collecting monitoring data.

J. Periods of Startup, Shutdown and Malfunction

We are not changing the malfunction provisions in the March 

2011 final rule.

1. Definitions. 

The EPA is revising the definitions of “startup” and 

“shutdown” such that they are tailored for industrial boilers 
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and are consistent with the definitions of “startup” and 

“shutdown” in the 40 CFR part 63, subpart A General Provisions. 

The revised definitions reflect the fact that industrial boilers 

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

electricity, and, thus, should be considered to be operating 

normally at all times steam of the proper pressure, temperature, 

and flow rate is being provided for use as process steam or for 

the cogeneration of electricity.

2. Compliance with Operating Limits. 

The EPA has clarified that operating limits must be met at 

all times except during periods of startup and shutdown.

3. Minimization of Startup and Shutdown Periods. 

The EPA is amending 40 CFR 63.11223(e) to include biomassand oil-fired boilers in the requirement to minimize the time 

spent in startup and shutdown periods.

4. Affirmative Defense Language. 

In this final rule, the EPA is updating the affirmative 

defense provisions for malfunctions that were included in the 

March 21, 2011 final rule.

K. Notification, Recordkeeping and Reporting Requirements

The EPA is amending 40 CFR 63.11225(a)(2) to specify that 

existing affected boilers have until January 20, 2014 to submit 

their Initial Notification.
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The EPA is amending 40 CFR 63.11225(c)(2) to specify that 

records of fuel use and type are required only for boilers that 

are subject to numerical emission limits. We are also amending 

40 CFR 63.11223(b) to clarify that the type and amount of fuel 

needs to be included in reports only if the boiler was 

physically and legally capable of using more than one type of 

fuel during that time period and that the report should include 

concentrations of CO and oxygen, measured at high fire or 

typical operating load, before and after the tune-up of the 

boiler. Finally, we are specifying that for units sharing a fuel 

meter, the fuel use by each boiler may be estimated.

The EPA is amending 40 CFR 63.11225(b) to clarify the 

requirements for submitting a biennial or 5-year report for 

units that are only subject to tune-up requirements and to 

specify the information that must be included in the annual, 

biennial, or 5-year compliance report.

We are amending 40 CFR 63.11225(c)(2) to specify that a 

copy of the energy assessment and records documenting the days 

of operation for each boiler that meets the definition of a 

seasonal boiler must be maintained. We are also amending 40 CFR 

63.11214(c) to remove the requirement for submitting, upon 

request, the energy assessment.

We are revising 40 CFR 63.11225(d) to remove the 

requirement that the most recent 2 years of records be 
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maintained on site and are adding language that allows for 

computer access or other means of immediate access of records 

stored in a centralized location.

We are adding a new paragraph 40 CFR 63.11225(g) to require

that boilers that switch fuels, make a physical change, or take 

a permit limit that results in the applicability of a different

subcategory within subpart JJJJJJ, a switch out of subpart 

JJJJJJ, or the applicability of subpart JJJJJJ must provide 

notification within 30 days of the fuel switch, physical change, 

or permit limit. 40 CFR 63.11225(g) also specifies what 

information the notification must include.

L. Title V Permitting Requirements

For the reasons stated in our March 21, 2011, final rule 

(76 FR 15554) as well as our reconsideration proposal (76 FR 

80532, December 23, 2011), the EPA is not making any changes to 

the title V exemption for natural and synthetic area sources. 

Thus, no area sources subject to subpart JJJJJJ are required to 

obtain a title V permit as a result of being subject to subpart 

JJJJJJ.

Facilities that are synthetic area sources for HAP under 

subpart JJJJJJ may already be covered by a title V permit or may 

be required to obtain a title V permit in the future. For 

example, area source boilers could be major sources of non-HAP 

pollutants or could be located at sources that are subject to 
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title V. Thus, the title V exemption in subpart JJJJJJ does not 

affect whether or not these area sources under subpart JJJJJJ 

are otherwise required to obtain a permit under part 70 or part 

71. See 40 CFR 70.3(a) and (b) or 71.3(a) and (b). 

Moreover, it is important to note that synthetic area

sources under subpart JJJJJJ could be subject to more stringent 

permitting and monitoring requirements than natural area sources 

if federally-enforceable controls are applied in order for the 

source to become a synthetic area source.

M. Definition of Period of Gas Curtailment or Supply 

Interruption

We are amending the definition of “period of natural gas 

curtailment or supply interruption” in 40 CFR 63.11237 to 

clarify that a curtailment does not include normal market 

fluctuations in the price of gas that are not associated with 

periods of supplier delivery restrictions. We are also amending 

the definition to indicate that periods of supply interruption 

that are beyond control of the facility can also include on-site 

natural gas system emergencies and equipment failures, and that 

legitimate periods of supply interruption are not limited to 

off-site circumstances. We are revising the term and the 

definition so that it includes the curtailment of any gaseous 

fuel, and is not limited to just natural gas. Finally, we are 

clarifying that the supply of gaseous fuel is to an “affected 
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boiler” rather than “affected facility“ and that the supply of 

gaseous fuel is “restricted or halted” for reasons beyond the 

control of the facility. The definition is amended to read as 

follows:

Period of gas curtailment or supply interruption means a 

period of time during which the supply of gaseous fuel to 

an affected boiler 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 

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.

N. Miscellaneous Technical Corrections

In addition to the above summary of the EPA’s final action 

regarding provisions identified for reconsideration and on other 

discrete matters identified in response to comments or data 

received during the comment period, other definitional and 

regulatory text revisions are being made. These clarifications 

will help affected sources determine their applicability and 

better understand the rule requirements. In some instances, 

definitions and regulatory text have been revised or added to 

correspond with other related rules, especially the emission 

standards for industrial, commercial, and institutional boilers 

at major sources of HAP (40 CFR part 63, subpart DDDDD). Section 
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IV of this preamble includes additional details regarding these 

miscellaneous technical corrections.

O. Other Issues

40 CFR 63.11196(a)(1) of the March 21, 2011, final rule (76 

FR 15554) requires that owners and operators of existing 

affected boilers subject to the tune-up requirement complete the 

initial boiler tune-up by March 21, 2012. In addition, 40 CFR 

63.11225(a)(4) requires that owners and operators of existing 

affected boilers subject to the tune-up requirement submit their

Notification of Compliance Status no later than 120 days after 

the applicable compliance date specified in 40 CFR 63.11196. 

That means that those owners and operators were required to

submit their Notification of Compliance Status by July 19, 2012.

The Notification must include, among other information, a 

certification that states “This facility complies with the

requirements in §63.11214 to conduct an initial tune-up of the 

boiler.”

On March 13, 2012, the EPA issued a No Action Assurance 

(NAA) to all owners and/or operators of existing industrial 

boilers and commercial and institutional boilers at area sources 

of HAP emissions stating that we would not enforce the 

requirement to conduct an initial tune-up by March 21, 2012. The 

NAA was primarily based upon the EPA’s concern that sources were 

reporting a shortage of qualified individuals to prepare boilers 
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for tune-ups and then conduct those tune-ups by the regulatory 

deadline, as well as upon the uncertainty in the regulated 

community resulting from the pending reconsideration of the Area 

Source Boiler Rule. The March 13, 2012, NAA states that it 

remains in effect until either (1) 11:59 PM EDT, October 1, 

2012, or (2) the effective date of a final rule addressing the 

proposed reconsideration of the Area Source Boiler Rule, 

whichever occurs earlier.

As the July 19, 2012, Notification of Compliance Status 

deadline approached, a final rule addressing the proposed 

reconsideration of the Area Source Boiler Rule had not been 

issued, and thus the NAA continued to remain in effect. Nothing 

that the EPA learned since the issuance of the original NAA 

letter led us to question our original concerns about the 

feasibility of all sources timely completing an initial tune-up. 

Further, sources that did not complete a tune-up could not 

certify that they conducted one. Thus, on July 18, 2012, the EPA

extended the NAA for sources required to complete an initial 

tune-up by March 21, 2012, to also include the deadline for 

submitting the Notification of Compliance Status regarding the 

initial tune-up. In addition, given that no final rule 

addressing the proposed reconsideration of the Area Source 

Boiler Rule had been issued as of July 18, 2012, the pending 

reconsideration continued to create uncertainty in the regulated 
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community. Thus, the NAA letter also amended the expiration date 

of the March 13, 2012, NAA, such that the NAA would remain in 

effect until either (1) 11:59 PM EST, December 31, 2012, or (2) 

the effective date of a final rule addressing the proposed 

reconsideration of the Area Source Boiler Rule, whichever occurs 

earlier.

This final rule revises the compliance date for existing 

affected boilers subject to a tune-up from March 21, 2012, to 

March 21, 2014. The July 19, 2012, deadline for submitting the 

Notification of Compliance Status regarding the initial tune-up 

is reset to July 19, 2014, as a result of revising the 

compliance date for existing affected boilers subject to a tuneup to March 21, 2014. Owners or operators that had not yet 

conducted their boiler tune-up, but submitted a Notification of 

Compliance Status by July 19, 2012, simply to notify the EPA 

that the tune-up had not been completed, will need to submit a 

revised Notification of Compliance Status after their boiler 

tune-up is conducted.

IV. Summary of Significant Changes Since Proposed Action on 

Reconsideration

Numerous changes are being made to the final rule based on 

the public comments received. Most are editorial changes to 

clarify applicability and implementation issues raised by the 

commenters. The public comments received on the proposed changes 
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and the responses to them can be viewed in the memorandum 

“Response to Comments for Industrial, Commercial, and 

Institutional Area Source Boilers National Emission Standards 

for Hazardous Air Pollutants” located in the docket.

A. Applicability

Since proposal, changes to the applicability of this final 

rule have been made.

1. Dual-Fuel Fired Boilers.

 The March 2011 final rule includes as a new affected source 

a boiler that commences fuel switching from natural gas to solid 

fossil fuel, biomass, or liquid fuel after June 4, 2010. For 

example, under the March 2011 final rule, if an unaffected gasfired boiler currently burns oil as allowed under the definition 

of gas-fired boiler, but after June 4, 2010 burns oil for 

reasons not allowed under the definition of gas-fired, these 

boilers would become new affected oil-fired units. The December 

2011 reconsideration action did not propose any revisions to the 

provisions regarding boilers that fuel switch after June 4, 

2010. The EPA has been made aware through public comments that 

many dual-fuel fired units presently burn primarily natural gas 

with limited or no amounts of oil, but these units may want to 

burn oil in the future for reasons not allowed under subpart 

JJJJJJ’s definition of gas-fired (e.g. cost). Under the March 

2011 final rule, such an existing dual-fuel gas-fired boiler 
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that wanted to avoid being subject to the new source 

requirements would notify as an existing oil-fired unit and be 

subject to the requirements for existing oil-fired boilers.

 We received public comments regarding rule applicability 

and compliance requirements for these existing dual-fuel fired 

boilers. One commenter asserted that regardless of the fuel 

capability identified in an initial notification, the 

distinction between a new source and an existing source should 

only be made based upon a source’s capability to burn a 

particular fuel as of the effective date of the rule. The 

commenter explained that many facilities have boilers that can 

burn either gas or liquid and, because the price of gas is 

currently lower than the price of most liquid fuels, they likely 

are currently firing gas during normal operation, with liquid 

being fired only during periods of curtailment. The commenter 

pointed out that, in the future, the price of liquid fuel may be 

lower than the price of gaseous fuel, and facilities may want to 

preferentially burn liquid fuel over gas fuel. The commenter 

asserted that a change in the fuel from the initial notification 

should not, in and of itself, reclassify a source as a new 

source for purposes of subpart JJJJJJ. Further, the commenter 

asserted that their interpretation is comparable to the fuel 

switching provisions in the EPA’s NSPS and PSD regulations. The 

same commenter asserted that if a source already has oil or 
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alternate fuel capability, then that source would not be 

commencing construction or making a modification to the source.

The commenter explained that many of these facilities with 

boilers capable of burning fuel oil as a back-up for natural gas 

may not have submitted an initial notification since gaseous 

fuel-fired boilers that only burn liquid during periods of 

curtailment are not covered by the Area Source Boiler Rule. The 

commenter maintained the EPA’s guidance, that a dual-fuel fired 

boiler that fails to file an initial notification and then plans 

to burn oil in the future would be considered to be a new 

source, appears to be contrary to regulatory text stating that

an affected source is a new source if construction or 

reconstruction of the affected source is commenced after June 4, 

2010 and the applicability criteria are met at the time 

construction is commenced. The commenter suggested that the EPA 

clarify that to become a new source, the source must be modified 

to be capable of accommodating a new fuel, so that new sources 

are not created simply by failing to submit an initial 

notification or a notice of fuel switching for a unit that is 

already capable of accommodating that fuel. Another commenter 

explained that owners and operators of dual-fuel fired boilers

anticipate firing natural gas for many years to come, or until 

gas supply is temporarily curtailed outside of their control or 

until such a time when fuel oil becomes more cost effective to 
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burn than gas. The commenter asserted that, based on common 

sense and increased flexibility, these dual-fuel fired boilers 

normally burning gas could not be considered subject to any oilfired requirements as long as they continue to fire only gas, 

except under the regulation’s stated exemptions for burning oil.

In addition to carefully considering the public comments 

received regarding dual-fuel fired boilers, the EPA reconsidered 

its overall intent with regard to existing dual-fuel fired 

boilers that fuel switch after June 4, 2010. Consequently, in 

this final rule, we are revising the provisions regarding 

existing boilers that fuel switch after June 4, 2010. This final 

rule amends 40 CFR 63.11194 to specify that an existing dual-fuel 

fired boiler (i.e., commenced construction or reconstruction on 

or before June 4, 2010) meeting the definition of gas-fired 

boiler, as defined in 40 CFR 63.11237, that meets the

applicability requirements of subpart JJJJJJ after June 4, 2010

due to a fuel switch from gaseous fuel to solid fossil fuel, 

biomass, or liquid fuel is considered to be an existing source

under this subpart as long as the boiler was designed to 

accommodate the alternate fuel. A new or reconstructed dual-fuel 

fired boiler (i.e., commenced construction or reconstruction 

after June 4, 2010) meeting the definition of gas-fired boiler, 

as defined in 40 CFR 63.11237, that meets the applicability 

criteria of subpart JJJJJJ after June 4, 2010 due to a fuel 
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switch from gaseous fuel to solid fossil fuel, biomass, or liquid 

fuel is considered to be a new source under this subpart. This 

revision maintains consistency with the rule’s applicability 

criteria for determining new versus existing sources, eliminates 

the requirement that existing dual-fuel fired boilers notify as 

affected sources although, at the time, they are not subject to 

subpart JJJJJJ, and promotes flexibility in that these existing 

dual-fuel fired sources that were designed to accommodate an 

alternate fuel may fire the alternate fuel and move into subpart 

JJJJJJ without being subject to the more stringent requirements 

for new boilers.

 

2. Residential Boilers.

One commenter suggested that the definition of “residential 

boiler” be revised to acknowledge the use of combined heat and 

power systems which function with heat and/or hot water systems. 

The EPA agrees and is amending the definition in the final rule 

to clarify that a boiler that operates as part of a residential 

combined heat and power system (and that meets other 

definitional requirements) is a residential boiler. Another 

commenter explained that historical buildings may be subdivided 

into more than four units but boilers serving those units should 

still be considered residential boilers. We agree and are 

amending the definition in the final rule to clarify that a 
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boiler serving a single unit residence dwelling that has since 

been converted or subdivided into condominiums or apartments may

also be considered a residential boiler.

3. Temporary Boilers. 

One commenter supported the EPA’s 12-month threshold above 

which the boiler would no longer be considered temporary but 

pointed out that a boiler used on a temporary basis during 

construction of a commercial building may be needed for more 

than 12 months due to the length of the construction period. The 

commenter suggested that the definition of temporary boiler be

revised to allow owners or operators to petition for an 

extension beyond 12 months. We agree with the commenter and are 

amending the definition in the final rule to allow an owner or 

operator to submit to their regulatory agency a petition for an 

extension beyond 12 months. Another commenter suggested that the 

EPA expand on the intent of “location” in the definition of 

“temporary boiler.” We are amending the definition to clarify 

that “location” means “location within the facility.” This 

clarification will allow a boiler to be moved from one location 

to another within a facility and be considered a different 

temporary boiler (i.e., a new time period begins) as long as the 

boiler does not continue to perform the same or similar function 

and to serve the same electricity, steam, and/or hot water 

system. Another commenter pointed out that our definition, as 
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proposed, does not specify a time period associated with the 

statement “Any temporary boiler that replaces a temporary boiler 

at a location within the facility and performs the same or 

similar function will be included in calculating the consecutive 

time period.” The commenter explained that it is not unusual for 

a temporary boiler to be used for short periods during 

turnarounds or other maintenance activities that recur several 

years apart. Under the proposal, these boilers would not be 

considered temporary because each boiler replaces the previous 

one and performs the same function, even though there is a 

multi-year gap between the occurrences. The commenter suggested 

that replacements that occur after a gap of at least one year 

should not be considered consecutive for the purposes of the

definition. We agree with the commenter and are amending 

numbered paragraph (2) in the definition of “temporary boiler” 

such that it specifies that “Any temporary boiler that replaces 

a temporary boiler at a location within the facility and 

performs the same or similar function will be included in 

calculating the consecutive time period unless there is a gap in 

operation of 12 months or more.”.

4. Seasonal Boilers. 

Several commenters explained that boilers subject to semiannual testing requirements would not meet the proposed 7 

consecutive month shutdown criteria, but otherwise would be 
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considered seasonal boilers. Commenters suggested that seasonal 

boiler be defined to allow periodic testing during the 7-month 

shutdown period. We agree with the commenters and are revising 

the definition of seasonal boiler in the final rule to allow for 

a combined total of 15 days of use during the shutdown period 

for periodic testing.

Another commenter pointed out that the EPA’s seasonal 

boiler definition, as proposed, would potentially allow more 

regular use. The commenter specifically suggested that the 

definition be revised to clarify that there must be a 7 

consecutive month shutdown every 12 months. It was the EPA’s 

intent that the shutdown period of at least 7 consecutive months

be on a 12-month basis. In response to this comment, we are 

clarifying in the definition of seasonal boiler that the 

shutdown must be for a period of at least 7 consecutive months 

(or 210 consecutive days) each 12-month period.

5. Limited-use Boilers.

Several commenters asserted that the EPA should also 

include a limited-use subcategory in the area source rule for 

the same reasons we determined a seasonal boiler subcategory was 

appropriate. Commenters suggested that we should apply the same 

5-year tune-up cycle for limited-use units such as auxiliary 

boilers that we proposed for seasonally-operated units and small 

oil-fired units. Commenters explained that in the electric 
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utility industry, auxiliary boilers are typically used to 

generate the steam necessary to bring a main EGU on line during 

startup and, since auxiliary boilers are primarily operated 

during unit startup, operation for many of these boilers is 

typically very limited and sporadic. Commenters also pointed out 

that the major source boiler rule includes a limited-use 

subcategory.

The EPA has determined that a limited-use subcategory is 

appropriate and is including a limited-use subcategory in the 

final area source boiler rule. Specifically, a limited-use 

boiler is defined in the final rule to mean any boiler that 

burns any amount of solid or liquid fuels and has a federally 

enforceable average annual capacity factor of no more than 10 

percent. We are using a capacity-factor approach for the same 

reasons that the approach is being used in the major source 

boiler rule. A capacity-factor approach allows operational

flexibility for units that operate on standby mode or low loads 

for periods longer than would be allowed under an approach that 

limited hours of operation (e.g., the 876 hours per year 

included in the proposed limited-use definition for major source 

boilers). The operational flexibility associated with a 

capacity-factor approach can be achieved without increasing 

emissions or harm to human health and the environment. Units 

operating at 10 percent load for 8,760 hours per year would emit 
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the same amount of emissions as units operating at full load for 

876 hours per year. Further, it is technically infeasible to 

test these limited-use boilers since these units serve as back 

up energy sources and their operating schedules can be 

intermittent and unpredictable.

The final rule specifies that limited-use boilers are

required to complete a tune-up every 5 years. Boilers that 

operate no more than 10 percent of the year (i.e., a limited-use 

boiler) would operate for no more than 6 months in between tuneups on a 5-year tune-up cycle. The brief period of operations is 

even less than the number of operating months that seasonal 

boilers and full-time boilers will operate between tune-ups. The 

irregular schedule of operations also makes it difficult to 

schedule more frequent tune-ups. We believe that establishing a 

limited-use subcategory is reasonable.

6. Applicability of PM Emission Limit to Certain Oil-Fired 

Boilers.

The EPA received a number of comments urging that we 

provide an exemption from the PM limit for units burning lowsulfur liquid fuel as is provided in subpart Dc of 40 CFR part 

60 (standards of performance for new small industrialcommercial-institutional steam generating units). Commenters 

asserted that such an exemption is justified since the low 

sulfur content indicates low PM emissions and that boilers 
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firing low-sulfur liquid fuel should only be subject to a 

requirement to maintain records documenting the liquid fuel 

fired. We agree with commenters and are amending 40 CFR 63.11210 

to specify that new or reconstructed oil-fired boilers that 

combust only oil that contains no more than 0.50 weight percent 

sulfur or a mixture of 0.50 weight percent sulfur oil with other 

fuels not subject to a PM emission limit under this subpart and 

that do not use a post-combustion technology (except a wet 

scrubber) to reduce PM or sulfur dioxide emissions are not 

subject to the PM emission limit providing the type of fuel 

combusted is monitored and recorded on a monthly basis. Further, 

we are specifying that if you intend to burn a new type of fuel 

or fuel mixture that does not meet the requirements of this 

paragraph, you must conduct a performance test within 60 days of 

burning the new fuel.

B. Tune-Up Requirements 

1. Boilers with Oxygen Trim Systems.

In the final rule, the EPA is adding to the types of 

boilers that must conduct a tune-up every 5 years boilers that 

have an oxygen trim system that maintain an optimum air-to-fuel 

ratio that would otherwise be subject to biennial tune-ups. 

These units do not need to be tuned as frequently as other types 

of boilers because the trim system is designed to maintain an 

optimum air-to-fuel ratio which is the purpose of a tune-up.
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2. Initial Compliance for Existing Boilers.

The EPA is revising the initial compliance date for 

existing boilers subject to the work practice or management

practice standard of a tune-up. Under the proposed rule, owners 

and operators of existing affected boilers would have had to 

comply with the final rule by March 21, 2013. We also solicited 

comments on whether to extend the compliance date to March 21, 

2014. We received no comments objecting to either of these 

dates. Support for an extension until 2014 came from a variety 

of stakeholders affected by the rule. Therefore, the final rule 

requires that if you own or operate an existing boiler subject 

to a work practice or management practice standard of a tune-up,

you must comply with the final rule no later than March 21, 

2014.

3. Compliance Demonstration.

We solicited comment on the requirements for demonstrating 

compliance with the work practice and management practice tuneup standards, with one focus on clarifying how to measure CO. 

Commenters requested that we clarify that CO measurements may be 

taken with a portable CO analyzer. We agree that this 

clarification is appropriate and are including this 

clarification in the final rule.

C. Energy Assessment
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The EPA received a number of comments regarding the energy 

assessment requirements and in the final rule is making a series 

of changes to the energy assessment provisions and related 

definitions that clarify terms used and better set the scope of 

the assessment.

In the final rule, we are revising the definition of energy 

assessment by providing a duration for performing the energy 

assessment for numbered paragraph (3) in the definition of 

"energy assessment" in 40 CFR 63.11237 for facilities with units 

with greater than 1 TBtu/yr heat input capacity to specify time 

duration/size ratio and are including a cap to the maximum 

number of on-site technical hours that should be used in the 

energy assessment. The energy assessment for facilities with 

affected boilers and process heaters with greater than 1.0 

TBtu/yr heat input capacity will be up to 24 on-site technical 

labor hours in length 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 

facility. The applicable discrete segments of a facility could 
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vary significantly depending on the site and its complexity. We 

are adding the following language, as paragraph (4), to the 

“energy assessment” definition to help resolve current problems 

and allow for more streamlined assessments:

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

for the percent of affected boiler(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 are revising 40 CFR 63.11201 and Table 2 of the final 

rule to allow a source that is operating under an energy 

management program developed according to the ENERGY STAR 

guideline for energy management, DOE Save Energy Now, or ISO 

50001 compatible energy management systems, that includes the 

affected units, to satisfy the energy assessment requirement. In 

addition, we are clarifying that energy assessor approval and 

qualification requirements are waived in instances where past or 

amended energy assessments are used to meet the energy 

assessment requirements.

The definition of “boiler system” is being revised in the 

final rule to clarify that it means the boiler and associated 

components directly connected to and serving the energy use 

systems.
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The definition of “energy use system” is also being revised 

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

those on-site systems using energy clearly produced by affected 

boilers.

The definition of “qualified energy assessor” is being

revised in the final rule to be more general such that the 

assessor is only required to have knowledge and capabilities 

specific to the processes at the site and, to clarify, that 

qualified energy assessors may be company employees or outside 

specialists.

D. Clarification of Oxygen Concentration Operating Limits

We are clarifying in the final rule that operating limits 

for oxygen concentration must be at or above the minimum 

established during a performance stack test. We are also 

clarifying that these limits are applicable when the unit is 

firing the fuel or fuel mixture utilized during the CO 

performance test.

E. Definitions Regarding Averaging Times

The EPA received comments requesting that we clarify that 

periods of startup and shutdown are excluded from calculation of 

the arithmetic mean in the definitions of “30-day rolling 

average” and “daily block average.” We agree with the commenters 

and are revising the definitions in the final rule accordingly.

F. Fuel Sampling Frequency
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The EPA is amending the fuel sampling requirements in 40 

CFR 63.11220(c) because we realized that when performance stack 

testing requirements were revised in the March 2011 final rule 

we neglected to revise the fuel analysis requirements. In the 

final rule, we are specifying that the owner or operator does 

not need to conduct further fuel analysis sampling if, when 

demonstrating initial compliance with the Hg emission limit, the 

Hg constituents in the fuel or fuel mixture are measured to be 

equal to or less than half of the Hg emission limit. If, when 

demonstrating initial compliance, the Hg constituents in the 

fuel or fuel mixture are greater than half of the Hg emission 

limit, the owner or operator must conduct quarterly sampling.

G. Performance Testing Frequency.

The EPA is amending the PM performance testing requirements 

in 40 CFR 63.11220(b) to specify that the owner or operator of 

an affected boiler does not need to conduct further PM emission 

testing if, when demonstrating initial compliance with the PM 

emission limit, the performance test results show that the PM 

emissions are equal to or less than half of the PM emission 

limit. The owner or operator must continue to comply with all 

applicable operating limits and monitoring requirements. If the 

initial performance test results show that the PM emissions are 

greater than half of the PM emission limit, the owner or 
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operator must conduct subsequent performance tests as specified 

in 40 CFR 63.11220(a).

With respect to the reconsideration issue regarding the 

GACT-based PM standards for new oil-fired boilers, we received 

comments asserting that the most effective control strategy for 

small oil-fired boilers is the tune-up required by the standards 

and that establishing a PM limit for those boilers between 10 

MMBtu/hr and 30 MMBtu/hr just ensures that those boilers will do 

stack testing demonstrating that the boilers are in compliance 

without the need for controls; a fact already known. Commenters 

also asserted that establishing a PM limit imposes a stack test 

obligation on small facilities with the least resources to deal 

with the testing.

We have reviewed the comments and are not eliminating or 

revising the PM limit for new oil-fired boilers with heat input 

capacity between 10 MMBtu/hr and 30 MMBtu/hr. We do, however,

believe that adjustments to the PM performance test frequency as 

described above are appropriate for boilers that demonstrate 

during their initial performance test that their PM emissions 

are equal to or less than half of the PM limit. We believe that 

the performance test adjustment should not be potentially 

applicable to only new oil-fired boilers with heat input 

capacity between 10 MMBtu/hr and 30 MMBtu/hr, but to all new 

boilers. Owners or operators of boilers whose initial 
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performance test results show that their PM emissions are equal 

to or less than half of the PM emission limit and, thus, do not 

need to conduct further PM emissions testing, must continue to 

comply with all applicable operating limits and monitoring 

requirements to ensure that there are no changes in operation of 

the boiler or air pollution control equipment that could 

increase emissions. This adjustment in PM performance test 

frequency will potentially reduce the burden on small entities 

operating boilers that meet the adjustment criteria. 

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 

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 definitions 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. 
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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 

pressure, temperature and flow rate is being provided 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 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 is supplied for heating and/or 

producing electricity, or for any other purpose.

Shutdown means the cessation of operation of a boiler for 

any purpose. Shutdown begins either when none of the steam

or heat 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, whichever is 

earlier. Shutdown ends when there is both no steam or heat 

being supplied and no fuel being fired in the boiler.

I. Notifications

1.Initial Notification.

The EPA has been made aware that there are many affected 

boilers at area sources that are just becoming aware, or are not 

yet aware, that they are subject to emission standards. Thus, we 
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are amending 40 CFR 63.11225(a)(2) to allow these sources until 

January 20, 2014 to submit their Initial Notification.

2. Notification of Fuel Change, Physical Change, or Permit 

Limit.

The notification requirement in 40 CFR 63.11225(g) of the 

final rule for instances when a change in fuel or a physical 

change to a boiler results in the applicability of a different 

subcategory or a change out of subpart JJJJJJ is being revised. 

Under the proposed reconsideration action, a facility would have 

been required to provide 30 days prior notice of the date upon 

which the change was scheduled to occur. Commenters explained 

that an advanced notification requirement would delay such a 

change if the owner or operator decided to immediately make a 

change (e.g., switch to 100 percent natural gas) and could 

potentially restrict flexibility in manufacturing operations, 

and suggested that the owner or operator be allowed to make 

notification within 30 days after the change has occurred. We 

agree that notification within 30 days after a change that 

results in applicability of a different subcategory or a change 

out of subpart JJJJJJ will provide the EPA or state/local agency 

with the required information within a reasonable timeframe. 

Thus, in the final rule, we are requiring facilities making 

these types of changes to provide notification within 30 days 

following the change. The notification requirement in 40 CFR 
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63.11225(g) of the final rule is also being amended to clarify 

that it includes affected boilers that switch fuels or make a 

physical change to the boiler and the fuel switch or change

results in the applicability of a different subcategory within 

subpart JJJJJJ, in the boiler becoming subject to subpart 

JJJJJJ, or in the boiler switching out of subpart JJJJJJ due to

a change to 100 percent natural gas, as well as affected boilers 

that take a permit limit that results in the applicability of 

subpart JJJJJJ. Commenters requested that we make this 

clarification and we agree that it is appropriate.

J. Miscellaneous Definitions

In the final action, we are clarifying a number of 

definitions to help affected sources determine their 

applicability. In some cases, definitions have been revised or 

added to correspond with those used elsewhere in related rules. 

Specifically, definitions have been added for the terms “10-day 

rolling average,” “30-day rolling average,” “Annual heat input,” 

“Biodiesel,” “Calendar year,” “Common stack,” “Daily block 

average,” “Distillate oil,” “Electric boiler,” “Electric utility 

steam generating unit (EGU),” “Energy management program,” 

“Fluidized bed boiler,” “Hourly average,” “Limited-use boiler,” 

“Load fraction,” “Minimum scrubber pressure drop,” “Minimum 

sorbent injection rate,” “Minimum total secondary electric 

power,” “Operating day,” “Oxygen analyzer system,” “Oxygen trim 
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system,” “Process heater,” “Residential boiler,” “Residual oil,” 

“Seasonal boiler,” “Shutdown,” “Startup,” “Solid fuel,” 

“Temporary boiler,” “Tune-up,” “Vegetable oil,” “Voluntary 

Consensus Standards (VCS),” and “Wet scrubber.”

Definitions revised to clarify the term include “Bag leak 

detection system,” “Biomass subcategory,” “Boiler,” “Boiler 

system,” “Deviation,” “Dry scrubber,” “Electrostatic 

precipitator (ESP),” “Energy assessment,” “Energy use system,” 

“Federally enforceable,” “Gas-fired boiler,” “Heat input,” “Hot 

water heater,” “Institutional boiler,” “Liquid fuel,” “Minimum 

activated carbon injection rate,” “Minimum oxygen level,” 

“Minimum scrubber liquid flow rate,” “Natural gas,” “Oil 

subcategory,” “Particulate matter,” “Period of gas curtailment 

or supply interruption,” “Qualified Energy Assessor,” and “Waste 

heat boiler.”

V. Other Actions the EPA is 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 
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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

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 2010 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 
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Nutrition Institute v. Block, 749 F.2d 50, 58 (D.C. Cir. 1984) 

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. 

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).
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We are denying reconsideration on the following five 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: Use of RDL is Unlawful.

The petitioner (Sierra Club) objected to the EPA 

establishing a MACT floor emission limit at a level equal to 

three times the RDL as being unlawful and arbitrary. This issue 

is not of central relevance to the outcome of this final rule. 

The final emission limits in this rule are based on the UPL at a 

confidence interval of 99 percent. The RDL analysis was not used 

in this final rule.

Issue: MACT Floor for Existing Sources Must Reflect Average 

Performance of the Top 12 Percent of Units.

The petitioner (Sierra Club) stated that the MACT floor for 

existing sources must reflect the average performance of the top 

12 percent of units. The petitioner has not demonstrated that it 
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lacked the opportunity to comment on the EPA’s MACT floor 

analysis. The methods used to compute the MACT floors were 

subject to notice and comment. Rationale and responses to 

comments on the MACT floor methodology were provided at 75 FR 

31904, June 4, 2010; 76 FR 15571, March 21, 2011. Therefore, the 

EPA is denying the request for reconsideration.

Issue: Consider a de Minimis Size Threshold.

The petitioners (American Petroleum Institute, National 

Petrochemical and Refiners Association, Alaska Oil and Gas 

Association) requested that the EPA consider a de minimis size 

threshold using guidelines from insignificance thresholds 

authorized under CAA part 71. The EPA is denying the request for 

reconsideration on this issue. In the June 2010 proposed rule, 

it was readily apparent that we were not establishing de minimis 

size thresholds in the area source rulemaking. We received 

multiple comments on this issue and responded to them in the 

response to comments document for the March 2011 final rule. The 

issue on which petitioners seek reconsideration was one that 

could have been raised during the comment period and thus does 

not meet the requirements for reconsideration. Therefore, the 

EPA is denying this request for reconsideration.

Issue: MACT Standards Must be Set for all HAP.

The petitioner (Sierra Club) asserted that MACT standards 

must be set for all HAP including HAP not listed in CAA section 
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112(c)(6). The EPA is denying the request for reconsideration on 

this issue. We disagree with the petitioner that the EPA must 

issue emission standards for all HAP. MACT standards have been 

set for Hg and CO, as a surrogate for POM emissions, but the EPA 

does not interpret CAA section 112(c)(6) to compel regulation of 

all HAP emitted by area sources. The EPA’s position on this 

issue was clear in the proposed rule (75 FR 31900, 31904, 

31918). This commenter raised this issue in its comments (76 FR 

15567, March 21, 2011). Not only did the petitioner have an 

opportunity to present its theory in its comments, but also it 

did so.

Issue: CO is not a valid surrogate for POM.

The petitioner (Sierra Club) requested that the EPA remove 

the CO standard as a surrogate for POM and instead adopt a 

numeric limit for POM 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 

argument regarding the suitability of CO as a surrogate for POM, 

the petitioner has not demonstrated that it lacked the 

opportunity to comment on this issue. The EPA revised the final 

CO emission limit to ensure a more accurate correlation between 

POM and CO levels. The EPA made our position on this issue clear 

and explained the agency’s basis for concluding that CO was an 

appropriate surrogate in the proposed rule (75 FR 31900, 31904, 
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June 4, 2010). The petitioner raised this issue in its comments

(Document ID: EPA-HQ-OAR-2006-0790-1982, Comments of 

Earthjusice, Sierra Club, Clean Air Task Force, and Natural 

Resources Defense Council, p. 4). Therefore, the EPA is denying 

the request for reconsideration.

VI. Impacts associated with this Final Rule

The amendments contained in this action are corrections 

that are intended to clarify, but not change, the coverage of 

the final rule. The clarifications and corrections should make 

it easier for owners and operators and for local and state 

authorities to understand and implement the requirements. The 

amendments will not increase the costs for the final rule but 

will result in a decrease in the burden on small facilities as a 

result of the reduction in the frequency of conducting tune-ups 

for seasonal boilers, limited-use boilers, small (equal to or 

less than 5 MMBtu/hr) oil-fired boilers and boilers using an 

oxygen trim system that maintain an optimum air-to-fuel ratio.

Additionally, the burden will be reduced on facilities that 

currently operate under an energy management program developed 

according to the ENERGY STAR guideline for energy management, 

DOE Save Energy Now, or ISO 50001 compatible energy management 

systems because a one-time energy assessment will not be 

required. Burden will also be reduced on facilities with 

affected boilers that burn low-sulfur oil because those boilers 
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will not be subject to the PM emission limit. Further reduction 

in burden will occur in instances where initial compliance 

demonstrations with the Hg emission limit via fuel sampling or

with the PM emission limit via performance stack testing show 

that the emissions are equal to or less than half the respective 

emission limit because no further sampling or testing of those 

boilers will be required.

As discussed in section III, the Hg emission limits for new 

and existing large (10 MMBtu/hr or greater) coal-fired area 

source boilers were revised because of an error discovered in 

the analysis conducted for the final rule. This technical 

correction resulted in an increase in the emission limits for 

Hg. Concurrently, we revised our impacts analysis to be 

consistent with changes made to the major source boiler rule. 

The baseline emissions for area sources are calculated using the 

emission factors developed for the major source rule because of 

insufficient data for area sources. Since promulgation, the EPA 

has received and incorporated a significant amount of additional 

data and has corrected previous calculation errors that impacted 

the emission factors used to calculate baseline emissions 

resulting in a higher baseline emission for Hg from coal-fired 

area source boilers. Consequently, the result of the increase in 

both baseline Hg emissions and Hg emission limits in this action

is that the overall reduction in Hg emissions does not change 
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significantly from the estimated reduction for the promulgated 

rule. 

In summary, as compared to the control costs estimated in 

the March 2011 final rule, these amendments will result in a 

decrease in the capital and annual cost due to the increase in 

emission limits and the decrease in burden on small facilities.

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 a “significant 

regulatory action” because it is likely to raise novel legal or

policy issues. Accordingly, the EPA submitted this action to the 

OMB for review under Executive Order 12866 and Executive Order 

13563 (76 FR 3821, January 21, 2011), and any changes made in 

response to OMB recommendations have been documented in the 

docket for this action.

B. Paperwork Reduction Act

This action does not impose an information collection 

burden. This action results in no significant changes to the 

information collection requirements of the promulgated rule and 

will have no increased impact on the information collection 

estimate of projected cost and hour burden made and approved by 
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OMB. In fact, the reduction in tune-up frequency for some 

boilers will result in less information collection burden. 

Therefore, the information collection request has not been 

revised. However, the OMB has previously approved the 

information collection requirements contained in the existing 

regulation (40 CFR part 63, subpart JJJJJJ) under the provisions 

of the Paperwork Reduction Act, 44 U.S.C. 3501, et seq. and has 

assigned OMB control number 2060-0668. The OMB control numbers 

for the EPA’s regulations in 40 CFR are listed in 40 CFR part 9.

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 

 

1 Small entities include small businesses, small organizations, 

and small governmental jurisdictions. For purposes of assessing 

the impacts of this final rule on small entities, small entity 

is defined as: (1) a small business as defined by the Small 

Business Administration size standards for small businesses at 13 

CFR 121.201 (less than 500, 750, or 1,000 employees, depending on the 

specific NAICS Code under subcategory 325); (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 

that is independently owned and operated and is not dominant in its 

field.
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flexibility analysis) and 604 (final regulatory flexibility 

analysis) in order to avoid “duplicative action.” 5 U.S.C. 

§605(c). These final amendments and notice of final action on 

reconsideration are closely related to the boiler area source

rule, which the EPA signed on February 21, 2011, and that took 

effect on May 20, 2011. The EPA prepared a final regulatory 

flexibility analysis in connection with the boiler area source 

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

complete a final regulatory flexibility analysis for this rule 

(i.e., the amendments and final action).

The EPA has been concerned with potential small entity 

impacts since it began developing the boiler area source rule. 

The EPA conducted outreach to small entities and, pursuant to 

§609 of RFA, convened a Small Business Advocacy Review Panel 

(the Panel) on January 22, 2009, 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

boiler area 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. Finally, we note that this action, which amends the 
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boiler area source rule, will not impose any additional 

regulatory requirements beyond those imposed by the previously 

promulgated boiler area source rule and, in fact, the amendments 

will afford relief to some boilers.

D. Unfunded Mandates Reform Act

This action contains no new federal mandates under the 

provisions of Title II of the UMRA of 1995, 2 U.S.C. 1531-1538 

for state, local, or tribal governments or the private sector. 

This action imposes no new enforceable duty on any state, local,

or tribal governments or the private sector. Therefore, this 

action is not subject to the requirements of sections 202 and 

205 of the UMRA.

This action is also not subject to the requirements of 

section 203 of UMRA because it contains no regulatory 

requirements that might significantly or uniquely affect small 

governments. This rule finalizes amendments to aid with 

compliance.

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 new direct compliance 
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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 final action does not have tribal implications, as 

specified in Executive Order 13175 (65 FR 67249, November 9, 

2000). It will not have substantial new 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 Executive Order

13045 because it is based solely on technology performance.

H. Executive Order 13211: Actions Concerning Regulations That 

Significantly Affect Energy Supply, Distribution, or Use

This action is not a “significant energy action” as defined 

in Executive Order 13211 (66 FR 28355, May 22, 2001), because it 
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is not likely to have a significant adverse effect on the 

supply, distribution, or use of energy. We estimate no 

significant changes for the energy sector for price, production, 

or imports.

I. National Technology Transfer and Advancement Act

Section 12(d) of the NTTAA of 1995, 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 OMB, explanations when the agency decides not 

use available and applicable VCS.

This action does not involve any new technical standards. 

Therefore, the EPA did not consider the use of any VCS.

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 
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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.

The EPA has determined that this final rule will not have 

disproportionately high and adverse human health or 

environmental effects on minority or low-income populations

because the level of protection provided to human health or the 

environment through the rule’s requirements does not vary. 

Therefore, it does not have any disproportionately high or 

adverse human health or environmental effects on any population, 

including any minority or low-income population.

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. The EPA 

will submit a report containing this 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 
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published in the Federal Register. Because this action makes 

small changes to the rule and does not revise the entire rule, 

this action is not a “major rule” as defined by 5 U.S.C. 804(2). 

This rule will be effective [INSERT THE DATE OF PUBLICATION IN 

THE FEDERAL REGISTER].

List of Subjects in 40 CFR Part 63

Environmental protection, Administrative practice and 

procedure, Air pollution control, Hazardous substances, 

Incorporation by reference.

Dated:

Lisa P. Jackson,

Administrator.
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For the reasons stated 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 citation for part 63 continues to read 

as follows:

Authority: 42 U.S.C. 7401 et seq.

Subpart A—[Amended]

2. 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 paragraph (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.

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 
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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.

* * * * *

(40) ASTM D396–10 Standard Specification for Fuel Oils, 

approved October 1, 2010, IBR approved for §63.7575 and 

§6311237.

* * * * *

(46) ASTM D4606–03(2007), Standard Test Method for 

Determination of Arsenic and Selenium in Coal by the Hydride 
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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.

* * * * *

(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.
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(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.

(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) * * *
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(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 

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.
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(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 

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 
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(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 JJJJJJ-[AMENDED]

3. Section 63.11194 is amended by revising paragraphs

(a)(1), (c) and (d), by redesignating paragraph (e) as paragraph 

(f) and by adding new paragraph (e) to read as follows:

§63.11194 What is the affected source of this subpart?

(a) * * *

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

of all existing industrial, commercial, and institutional 

boilers within a subcategory, as listed in §63.11200 and defined 

in §63.11237, located at an area source.

* * * * *

(c) An affected source is a new source if you commenced 

construction of the affected source after June 4, 2010, and the 

boiler meets the applicability criteria at the time you commence 

construction.

 (d) An affected source is a reconstructed source if the 

boiler meets the reconstruction criteria as defined in §63.2, you 
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commenced reconstruction after June 4, 2010, and the boiler meets

the applicability criteria at the time you commence 

reconstruction.

(e) An existing dual-fuel fired boiler meeting the 

definition of gas-fired boiler, as defined in §63.11237, that 

meets the applicability requirements of this subpart after June 

4, 2010 due to a fuel switch from gaseous fuel to solid fossil 

fuel, biomass, or liquid fuel is considered to be an existing 

source under this subpart as long as the boiler was designed to 

accommodate the alternate fuel.

(f) If you are an owner or operator of an area source 

subject to this subpart, you are exempt from the obligation to 

obtain a permit under 40 CFR part 70 or part 71 as a result of 

this subpart. You may, however, be required to obtain a title V 

permit due to another reason or reasons. See 40 CFR 70.3(a) and 

(b) or 71.3(a) and (b). Notwithstanding the exemption from title 

V permitting for area sources under this subpart, you must 

continue to comply with the provisions of this subpart.

4. Section 63.11195 is amended by revising the 

introductory text and paragraphs (c) and (g) and by adding 

paragraphs (h), (i), (j), and (k) to read as follows:

§63.11195 Are any boilers not subject to this subpart?
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The types of boilers listed in paragraphs (a) through (k) 

of this section are not subject to this subpart and to any 

requirements in this subpart.

* * * * *

(c) A boiler required to have a permit under section 3005 

of the Solid Waste Disposal Act or covered by subpart EEE of 

this part (e.g., hazardous waste boilers), unless such units do 

not combust hazardous waste and combust comparable fuels.

* * * * *

(g) Any boiler 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 is provided by regulated gas streams that 

are subject to another standard.

(h) Temporary boilers as defined in this subpart.

(i) Residential boilers as defined in this subpart.

(j) Electric boilers as defined in this subpart.

(k) An electric utility steam generating unit (EGU) covered 

by subpart UUUUU of this part.

5. Section 63.11196 is amended by revising paragraphs

(a)(1), (b) and (d) to read as follows:

§63.11196 What are my compliance dates? 

(a) * * *
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(1) If the existing affected boiler is subject to a work 

practice or management practice standard of a tune-up, you must 

achieve compliance with the work practice or management standard 

no later than March 21, 2014.

* * * * *

(b) If you start up a new affected source on or before May 

20, 2011, you must achieve compliance with the provisions of 

this subpart no later than May 20, 2011.

* * * * *

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

institutional boiler and would be subject to this subpart except 

for the exemption in §63.11195(b) for commercial and industrial 

solid waste incineration units covered by 40 CFR part 60, 

subpart CCCC or subpart DDDD, and you cease combusting solid 

waste, you must be in compliance with this subpart on the 

effective date of the waste to fuel switch as specified in 

§§60.2145(a)(2) and (3) of subpart CCCC or §§60.2710(a)(2) and 

(3) of subpart DDDD.

5. Section 63.11200 is amended by revising the paragraph 

to read as follows:

§63.11200 What are the subcategories of boilers?

The subcategories of boilers, as defined in §63.11237 are:

(a) Coal.

(b) Biomass.
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(c) Oil.

(d) Seasonal boilers.

(e) Oil-fired boilers with heat input capacity of equal to 

or less than 5 MMBtu/hr.

(f) Boilers with an oxygen trim system that maintains an 

optimum air-to-fuel ratio that would otherwise be subject to a 

biennial tune-up.

(g) Limited-use boilers.

6. Section 63.11201 is amended by revising paragraphs (b) 

and (d) to read as follows:

§63.11201 What standards must I meet?

* * * * *

(b) You must comply with each work practice standard, 

emission reduction measure, and management practice specified in 

Table 2 to this subpart that applies to your boiler. An energy 

assessment completed on or after January 1, 2008 that meets or 

is amended to meet the energy assessment requirements in Table 2 

to this subpart satisfies the energy assessment requirement. A 

facility that operates under an energy management program 

developed according to the ENERGY STAR guideline for energy 

management, DOE Save Energy Now, or ISO 50001 compatible energy 

management systems, that includes the affected units, also 

satisfies the energy assessment requirement.

* * * * *
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(d) These standards apply at all times the affected boiler 

is operating, except during periods of startup and shutdown as 

defined in §63.11237, during which time you must comply only 

with Table 2 to this subpart.

7. Section 63.11205 is amended by revising paragraphs 

(b), (c) introductory text, (c)(1), and (c)(1)(i) to read as 

follows:

§63.11205 What are my general requirements for complying with 

this subpart?

* * * * *

(b) You must demonstrate compliance with all applicable 

emission limits using performance testing, fuel analysis, or a 

continuous monitoring system (CMS), including a continuous 

emissions monitoring system (CEMS), a continuous opacity 

monitoring system (COMS), or a continuous parameter monitoring 

system (CPMS), where applicable. You may demonstrate compliance 

with any applicable mercury emission limit using fuel analysis 

if the emission rate calculated according to §63.11211(c) is 

less than the applicable emission limit. Otherwise, you must 

demonstrate compliance using stack testing.

(c) If you demonstrate compliance with any applicable 

emission limit through performance stack testing and subsequent 

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

with a CEMS, or with a COMS, you must develop a site-specific 
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monitoring plan according to the requirements in paragraphs 

(c)(1) through (3) of this section for the use of any CEMS, 

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

petition the EPA Administrator for alternative monitoring 

parameters under §63.8(f).

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

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

Administrator for approval upon request, a site-specific 

monitoring plan that addresses paragraphs (c)(1)(i) through (vi) 

of this section. You must submit this site-specific monitoring 

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

performance evaluation of your CMS. This requirement to develop 

and submit a site specific monitoring plan does not apply to 

affected sources with existing CEMS or COMS operated according 

to the performance specifications under Appendix B to part 60 of 

this chapter and that meet the requirements of §63.11224.

(i) Installation of the CMS sampling probe or other 

interface at a measurement location relative to each affected 

process unit such that the measurement is representative of 

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

last control device);

* * * * *
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8. Section 63.11210 is amended by revising paragraphs (b)

through (d), by redesignating paragraph (e) as paragraph (g) and 

adding paragraphs (e), (f), (h), (i) and (j) to read as follows:

§63.11210 What are my initial compliance requirements and by 

what date must I conduct them?

* * * * *

(b) For existing affected boilers that have applicable 

emission limits, you must demonstrate initial compliance with 

the applicable emission limits no later than 180 days after the 

compliance date that is specified in §63.11196 and according to 

the applicable provisions in §63.7(a)(2), except as provided in 

paragraph (j) of this section.

(c) For existing affected boilers that have applicable work 

practice standards, management practices, or emission reduction 

measures, you must demonstrate initial compliance no later than 

the compliance date that is specified in §63.11196 and according 

to the applicable provisions in §63.7(a)(2), except as provided 

in paragraph (j) of this section.

(d) For new or reconstructed affected boilers that have 

applicable emission limits, you must demonstrate initial 

compliance with the applicable emission limits no later than 180 

calendar days after March 21, 2011 or within 180 calendar days 

after startup of the source, whichever is later, according to 

§63.7(a)(2)(ix).
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(e) For new or reconstructed oil-fired boilers that combust 

only oil that contains no more than 0.50 weight percent sulfur 

or a mixture of 0.50 weight percent sulfur oil with other fuels 

not subject to a PM emission limit under this subpart and that 

do not use a post-combustion technology (except a wet scrubber) 

to reduce particulate matter (PM) or sulfur dioxide emissions, 

you are not subject to the PM emission limit in Table 1 of this 

subpart providing you monitor and record on a monthly basis the 

type of fuel combusted. If you intend to burn a new type of fuel 

or fuel mixture that does not meet the requirements of this 

paragraph, you must conduct a performance test within 60 days of 

burning the new fuel.

(f) For new or reconstructed affected boilers that have 

applicable work practice standards or management practices, you 

are not required to complete an initial performance tune-up, but 

you are required to complete the applicable biennial or 5-year 

tune-up as specified in §63.11223 no later than 25 months or 61 

months, respectively, after the initial startup of the new or 

reconstructed affected source.

(g) For affected boilers that ceased burning solid waste 

consistent with §63.11196(d) and for which your initial 

compliance date has passed, you must demonstrate compliance 

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

as specified in §60.2145(a)(2) and (3) of subpart CCCC or 
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§60.2710(a)(2) and (3) of subpart DDDD. 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.

(h) For affected boilers that switch fuels or make a 

physical change to the boiler that results in the applicability 

of a different subcategory within subpart JJJJJJ or the boiler 

becoming subject to subpart JJJJJJ, you must demonstrate 

compliance within 180 days of the effective date of the fuel

switch or the physical change. Notification of such changes must 

be submitted according to §63.11225(g).

(i) For boilers located at existing major sources of HAP 

that limit their potential to emit (e.g., make a physical change 

or take a permit limit) such that they become area sources 

before the first substantive compliance date for the Major 

Source Boiler Rule, you must comply with the applicable 

provisions as specified in paragraphs (i)(1) through (i)(3) of 

this section.

(1) Any such existing boiler at the existing source must 

demonstrate compliance with subpart JJJJJJ within 180 days of 

the later of March 21, 2014 or the effective date of becoming an 

area source.
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(2) Any new or reconstructed boiler at the existing source 

must demonstrate compliance with subpart JJJJJJ within 180 days 

of the later of March 21, 2011 or startup.

(3) Notification of such changes must be submitted 

according to §63.11225(g).

(j) For existing affected boilers that have not operated 

between the effective date of the rule and the compliance date 

that is specified for your source in §63.11196, you must comply 

with the applicable provisions as specified in paragraphs (j)(1) 

through (3) of this section.

(1) You must complete the initial compliance demonstration, 

if subject to the emission limits in Table 1 to this subpart, as 

specified in paragraphs (a) and (b) of this section, no later 

than 180 days after the re-start of the affected boiler and 

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

(2) You must complete the initial performance tune-up, if 

subject to the tune-up requirements in §63.11223, by following 

the procedures described in §63.11223(b) no later than 30 days 

after the re-start of the affected boiler.

(3) You must complete the one-time energy assessment, if 

subject to the energy assessment requirements specified in Table 

2 to this subpart, no later than the compliance date specified 

in §63.11196.
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9. Section 63.11211 is amended by revising paragraphs 

(a), (b)(1), and (b)(2) to read as follows:

§63.11211 How do I demonstrate initial compliance with the 

emission limits?

(a) For affected boilers that demonstrate compliance with 

any of the emission limits of this subpart through performance 

(stack) testing, your initial compliance requirements include 

conducting performance tests according to §63.11212 and Table 4 

to this subpart, conducting a fuel analysis for each type of 

fuel burned in your boiler according to §63.11213 and Table 5 to 

this subpart, establishing operating limits according to 

§63.11222 , Table 6 to this subpart and paragraph (b) of this 

section, as applicable, and conducting CMS performance 

evaluations according to §63.11224. For affected boilers that 

burn a single type of fuel, you are exempted from the compliance 

requirements of conducting a fuel analysis for each type of fuel 

burned in your boiler. For purposes of this subpart, boilers 

that use a supplemental fuel only for startup, unit shutdown, 

and transient flame stability purposes still qualify as affected 

boilers that burn a single type of fuel, and the supplemental 

fuel is not subject to the fuel analysis requirements under 

§63.11213 and Table 5 to this subpart.

(b) * * *
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(1) For a wet scrubber, you must establish the minimum 

liquid flow rate and pressure drop as defined in §63.11237, as 

your operating limits during the three-run performance stack 

test. If you use a wet scrubber and you conduct separate 

performance stack tests for PM and mercury emissions, you must 

establish one set of minimum scrubber liquid flow rate and 

pressure drop operating limits. If you conduct multiple 

performance stack tests, you must set the minimum liquid flow

rate and pressure drop operating limits at the highest minimum 

values established during the performance stack tests.

(2) For an electrostatic precipitator operated with a wet 

scrubber, you must establish the minimum secondary voltage and 

secondary amperage (or total secondary electric power), as 

defined in §63.11237, as your operating limits during the threerun performance stack test. 

* * * * *

10. Section 63.11212 is amended by revising paragraphs (b) 

and (e) to read as follows:

§63.11212 What stack tests and procedures must I use for the 

performance tests?

* * * * *

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

requirements in Table 4 to this subpart. Boilers that use a CEMS

for carbon monoxide (CO) are exempt from the initial CO
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performance testing in Table 4 to this subpart and the oxygen 

concentration operating limit requirement specified in Table 3

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 of appendix A-7 to part 60 of this 

chapter to convert the measured PM concentrations and the 

measured mercury concentrations that result from the performance 

test to pounds (lb) per million British thermal units (MMBtu)

heat input emission rates.

11. Section 63.11214 is amended by revising paragraph (c) 

to read as follows:

§63.11214 How do I demonstrate initial compliance with the work 

practice standard, emission reduction measures, and management 

practice?

* * * * *

(c) If you own or operate an existing affected boiler with 

a heat input capacity of 10 million Btu per hour (MMBtu/hr) or

greater, you must submit a signed certification in the 

Notification of Compliance Status report that an energy

assessment of the boiler and its energy use systems was 

completed according to Table 2 to this subpart and is an 

accurate depiction of your facility.
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* * * * *

12. Section 63.11220 is amended by revising the section 

heading and paragraphs (a) through (d) and removing paragraph

(e) to read as follows:

§63.11220 When must I conduct subsequent performance tests or 

fuel analyses?

(a) If your boiler has a heat input capacity of 10 MMBtu/hr

or greater, you must conduct all applicable performance (stack) 

tests according to §63.11212 on a triennial basis, except as 

specified in paragraphs (b) through (d) of this section. 

Triennial performance tests must be completed no more than 37 

months after the previous performance test.

(b) When demonstrating initial compliance with the PM 

emission limit, if your boiler’s performance test results show 

that your PM emissions are equal to or less than half of the PM 

emission limit, you do not need to conduct further performance 

tests for PM but must continue to comply with all applicable 

operating limits and monitoring requirements. If your initial 

performance test results show that your PM emissions are greater 

than half of the PM emission limit, you must conduct subsequent 

performance tests as specified in paragraph (a) of this section.

(c) If you demonstrate compliance with the mercury emission 

limit based on fuel analysis, you must conduct a fuel analysis 

according to §63.11213 for each type of fuel burned as specified 
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in paragraphs (c)(1) and (c)(2) of this section. If you plan to 

burn a new type of fuel or fuel mixture, you must conduct a fuel 

analysis before burning the new type of fuel or mixture in your 

boiler. You must recalculate the mercury emission rate using 

Equation 1 of §63.11211. The recalculated mercury emission rate 

must be less than the applicable emission limit.

(1) When demonstrating initial compliance with the mercury 

emission limit, if the mercury constituents in the fuel or fuel 

mixture are measured to be equal to or less than half of the 

mercury emission limit, you do not need to conduct further fuel 

analysis sampling but must continue to comply with all 

applicable operating limits and monitoring requirements.

(2) When demonstrating initial compliance with the mercury 

emission limit, if the mercury constituents in the fuel or fuel 

mixture are greater than half of the mercury emission limit, you 

must conduct quarterly sampling.

(d) For existing affected boilers that have not operated 

since the previous compliance demonstration, you must complete 

your subsequent compliance demonstration no later than 180 days 

after the re-start of the affected boiler.

13. Section 63.11221 is amended by revising the section 

heading, and paragraphs (a) through (d) to read as follows:

§63.11221 Is there a minimum amount of monitoring data I must 

obtain? 
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(a) You must monitor and collect data according to this 

section and the site-specific monitoring plan required by 

§63.11205(c). 

(b) You must operate the monitoring system and collect data 

at all required intervals at all times the affected source is 

operating and compliance is required, except for periods of 

monitoring system malfunctions or out-of-control periods (see 

§63.8(c)(7) of this part), repairs associated with monitoring 

system malfunctions or out-of-control periods, and required 

monitoring system quality assurance or quality 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-ofcontrol periods and to return the monitoring system to operation 

as expeditiously as practicable.

(c) You may not use data collected during monitoring 

system malfunctions or out-of-control periods, repairs 

associated with monitoring system malfunctions or out-of-control 
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periods, or required monitoring system quality assurance or 

quality control activities in calculations used to report 

emissions or operating levels. Any such periods must be reported 

according to the requirements in §63.11225. You must use all the 

data collected during all other periods in assessing the 

operation of the control device and associated control system.

(d) Except for periods of monitoring system malfunctions or 

monitoring system out-of-control periods, repairs associated 

with monitoring system malfunctions or monitoring system out-ofcontrol periods, and required monitoring system quality 

assurance or quality control activities (including, as 

applicable, calibration checks, required zero and span 

adjustments, and scheduled CMS maintenance as defined in your 

site-specific monitoring plan), failure to collect required data 

is a deviation of the monitoring requirements.

14. Section 63.11223 is amended by revising paragraphs 

(a), (b) introductory text, (b)(1), (b)(3) through (b)(5), 

(b)(6) introductory text, (b)(6)(i), (b)(6)(iii), (b)(7) and 

(c), and adding paragraphs (d) through (g) to read as follows:

§63.11223 How do I demonstrate continuous compliance with the 

work practice and management practice standards?

(a) For affected sources subject to the work practice 

standard or the management practices of a tune-up, you must 

conduct a performance tune-up according to paragraph (b) of this 
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section and keep records as required in §63.11225(c) to 

demonstrate continuous compliance. You must conduct the tune-up 

while burning the type of fuel (or fuels in the case of boilers 

that routinely burn two types of fuels at the same time) that 

provided the majority of the heat input to the boiler over the 

12 months prior to the tune-up.

(b) Except as specified in paragraphs (c) through (f) of 

this section, you must conduct a tune-up of the boiler 

biennially to demonstrate continuous compliance as specified in 

paragraphs (b)(1) through (7) of this section. Each biennial

tune-up must be conducted no more than 25 months after the 

previous tune-up. For a new or reconstructed boiler, the first 

biennial tune-up must be no later than 25 months after the 

initial startup of the new or reconstructed boiler.

(1) 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.

* * * * *

(3) Inspect the system controlling the air-to-fuel ratio, 

as applicable, and ensure that it is correctly calibrated and 

functioning properly (you may delay the inspection until the 
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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.

(4) Optimize total emissions of CO. This optimization 

should be consistent with the manufacturer’s specifications, if 

available, and with any nitrogen oxide requirement to which the 

unit is subject.

(5) 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.

(6) Maintain onsite and submit, if requested by the 

Administrator, a report containing the information in paragraphs 

(b)(6)(i) through (iii) of this section.

(i) 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.

* * * * *

(iii) The type and amount of fuel used over the 12 months 

prior to the tune-up of the boiler, but only if the unit was 

physically and legally capable of using more than one type of 
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fuel during that period. Units sharing a fuel meter may estimate 

the fuel use by each unit.

(7) 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.

(c) Boilers with an oxygen trim system that maintains an 

optimum air-to-fuel ratio that would otherwise be subject to a 

biennial tune-up must conduct a tune-up of the boiler every 5 

years as specified in paragraphs (b)(1) through (7) of this 

section. Each 5-year tune-up must be conducted no more than 61

months after the previous tune-up. For a new or reconstructed 

boiler with an oxygen trim system, the first 5-year tune-up must 

be no later than 61 months after the initial startup. You may 

delay the burner inspection specified in paragraph (b)(1) of 

this section and inspection of the system controlling the airto-fuel ratio specified in paragraph (b)(3) of this section 

until the next scheduled unit shutdown, but you must inspect 

each burner and system controlling the air-to-fuel ratio at 

least once every 72 months.

(d) Seasonal boilers must conduct a tune-up every 5 years 

as specified in paragraphs (b)(1) through (7) of this section. 

Each 5-year tune-up must be conducted no more than 61 months 

after the previous tune-up. For a new or reconstructed seasonal 

boiler, the first 5-year tune-up must be no later than 61 months 
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after the initial startup. You may delay the burner inspection 

specified in paragraph (b)(1) of this section and inspection of 

the system controlling the air-to-fuel ratio specified in 

paragraph (b)(3) of this section until the next scheduled unit 

shutdown, but you must inspect each burner and system 

controlling the air-to-fuel ratio at least once every 72 months.

Seasonal boilers are not subject to the emission limits in Table 

1 to this subpart or the operating limits in Table 3 to this 

subpart.

(e) Oil-fired boilers with a heat input capacity of equal 

to or less than 5 MMBtu/hr must conduct a tune-up every 5 years 

as specified in paragraphs (b)(1) through (7) of this section. 

Each 5-year tune-up must be conducted no more than 61 months 

after the previous tune-up. For a new or reconstructed oil-fired

boiler with a heat input capacity of equal to or less than 5 

MMBtu/hr, the first 5-year tune-up must be no later than 61 

months after the initial startup. You may delay the burner 

inspection specified in paragraph (b)(1) of this section and 

inspection of the system controlling the air-to-fuel ratio 

specified in paragraph (b)(3) of this section until the next 

scheduled unit shutdown, but you must inspect each burner and 

system controlling the air-to-fuel ratio at least once every 72 

months.
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(f) Limited-use boilers must conduct a tune-up every 5 

years as specified in paragraphs (b)(1) through (7) of this 

section. Each 5-year tune-up must be conducted no more than 61

months after the previous tune-up. For a new or reconstructed 

limited-use boiler, the first 5-year tune-up must be no later 

than 61 months after the initial startup. You may delay the 

burner inspection specified in paragraph (b)(1) of this section 

and inspection of the system controlling the air-to-fuel ratio 

specified in paragraph (b)(3) of this section until the next 

scheduled unit shutdown, but you must inspect each burner and 

system controlling the air-to-fuel ratio at least once every 72 

months. Limited-use boilers are not subject to the emission 

limits in Table 1 to this subpart, the energy assessment 

requirements in Table 2 to this subpart, or the operating limits 

in Table 3 to this subpart.

(g) If you own or operate a boiler subject to emission 

limits in Table 1 of this subpart, you must minimize the 

boiler’s startup and shutdown periods following the 

manufacturer’s recommended procedures, if available. If 

manufacturer’s recommended procedures are not available, you 

must follow recommended procedures for a unit of similar design 

for which manufacturer’s recommended procedures are available. 

You must submit a signed statement in the Notification of 

Compliance Status report that indicates that you conducted 
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startups and shutdowns according to the manufacturer’s 

recommended procedures or procedures specified for a boiler of 

similar design if manufacturer’s recommended procedures are not 

available.

15. Section 63.11224 is amended by deleting paragraph 

(d)(5), revising paragraphs (a) introductory text, (a)(1) 

through (a)(3), (a)(5), (a)(6), (c)(1) introductory text, (c)(2) 

introductory text, (d) introductory text, (d)(1) through (d)(4), 

(e) introductory text, (e)(6), (e)(7) and (f)(7), and adding 

paragraphs (a)(7) and (e)(8) to read as follows:

§63.11224 What are my monitoring, installation, operation, and 

maintenance requirements? 

(a) If your boiler is subject to a CO emission limit in 

Table 1 to this subpart, you must either install, operate, and 

maintain a CEMS for CO and oxygen according to the procedures in 

paragraphs (a)(1) through (6) of this section, or install, 

operate, and maintain an oxygen analyzer system as defined in 

§63.11237 according to paragraphs (a)(7) and (d) of this section

by the compliance date specified in §63.11196. Where a certified 

CO CEMS is used, the CO level shall be monitored at the outlet 

of the boiler, after any add-on controls or flue gas 

recirculation system and before release to the atmosphere. 

Boilers that use a CO CEMS are exempt from the initial CO 

performance testing and oxygen concentration operating limit 
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requirements specified in §63.11211(a) of this subpart. Oxygen 

monitors and oxygen trim systems must be installed to monitor 

oxygen in the boiler flue gas, boiler firebox, or other 

appropriate intermediate location.

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

maintained according to the applicable procedures under 

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

appendix B, and each oxygen CEMS must be installed, operated, 

and maintained according to Performance Specification 3 at 40 

CFR part 60, appendix B. Both the CO and oxygen CEMS must also 

be installed, operated, and maintained according to the sitespecific monitoring plan developed according to paragraph (c) of 

this section.

(2) You must conduct a performance evaluation of each CEMS 

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

Performance Specifications 3 and 4, 4A, or 4B at 40 CFR part 60, 

appendix B.

(3) Each CEMS 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.

* * * * *

(5) You must calculate 1-hour arithmetic averages, 

corrected to 3 percent oxygen, from each hour of CO CEMS data in 
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parts per million CO concentrations and determine the 10-day 

rolling average of all recorded readings, except as provided in 

§63.11221(c). Calculate a 10-day rolling average from all of the 

1-hour averages collected for the 10-day operating period using 

Equation 2 of this section.

10-day average =

∑  





 (Eq.2)

Where:

Hpvi = the hourly parameter value for hour i

n = the number of valid hourly parameter values

collected over 10 boiler operating days

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

the CO CEMS as specified in §63.11221(b). For purposes of 

calculating data averages, you must use all the data collected 

during all periods in assessing compliance, except that you must 

exclude certain data as specified in §63.11221(c). Periods when 

CO data are unavailable may constitute monitoring deviations as 

specified in §63.11221(d). 

(7) You must operate the oxygen analyzer system at or above 

the minimum percent oxygen by volume that is established as the 

operating limit for oxygen according to Table 6 to this subpart

when firing the fuel or fuel mixture utilized during the most 

recent CO performance stack test. Operation of oxygen trim 

systems to meet these requirements shall not be done in a manner 

which compromises furnace safety.

* * * * *
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(c) * * *

(1) For each CMS required in this section, you must 

develop, and submit to the EPA Administrator for approval upon 

request, a site-specific monitoring plan that addresses 

paragraphs (c)(1)(i) through (iii) of this section. You must 

submit this site-specific monitoring plan (if requested) at 

least 60 days before your initial performance evaluation of your 

CMS.

* * * * *

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

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

* * * * *

(d) If you have an operating limit that requires the use of 

a CMS, you must install, operate, and maintain each CPMS

according to the procedures in paragraphs (d)(1) through (4) of 

this section.

(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 calculate 1-hour arithmetic averages from 

each hour of CPMS data in units of the operating limit and 

determine the 30-day rolling average of all recorded readings, 

except as provided in §63.11221(c). Calculate a 30-day rolling 
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average from all of the 1-hour averages collected for the 30-day 

operating period using Equation 3 of this section.

30-day average =

∑  





 (Eq.3)

Where:

Hpvi = the hourly parameter value for hour i

n = the number of valid hourly parameter values

collected over 30 boiler operating days

(3) For purposes of collecting data, you must operate the 

CPMS as specified in §63.11221(b). For purposes of calculating 

data averages, you must use all the data collected during all 

periods in assessing compliance, except that you must exclude 

certain data as specified in §63.11221(c). Periods when CPMS 

data are unavailable may constitute monitoring deviations as 

specified in §63.11221(d).

(4) Record the results of each inspection, calibration, and 

validation check.

(e) If you have an applicable opacity operating limit under 

this rule, you must install, operate, certify and maintain each 

COMS according to the procedures in paragraphs (e)(1) through 

(8) of this section by the compliance date specified in 

§63.11196.

* * * * *

(6) You must operate and maintain each COMS according to 

the requirements in the monitoring plan and the requirements of 
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§63.8(e). Identify periods the COMS is out of control including 

any periods that the COMS fails to pass a daily calibration 

drift assessment, a quarterly performance audit, or an annual 

zero alignment audit.

(7) You must calculate and record 6-minute averages from 

the opacity monitoring data and determine and record the daily 

block average of recorded readings, except as provided in 

§63.11221(c).

(8) For purposes of collecting opacity data, you must 

operate the COMS as specified in §63.11221(b). For purposes of 

calculating data averages, you must use all the data collected 

during all periods in assessing compliance, except that you must 

exclude certain data as specified in §63.11221(c). Periods when 

COMS data are unavailable may constitute monitoring deviations 

as specified in §63.11221(d).

(f) * * *

(7) For positive pressure fabric filter systems that do not 

duct all compartments or cells to a common stack, a bag leak 

detection system must be installed in each baghouse compartment 

or cell.

* * * * *

16. Section 63.11225 is amended by revising paragraphs (a) 

introductory text, (a)(1), (a)(2), (a)(4), (a)(5), (b) 

introductory text, (b)(2), (c) introductory text, (c)(2) 
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introductory text, (c)(2)(ii), (d), (e), and (g); and by adding 

paragraphs (a)(6), and (c)(2)(iii) through (vi) to read as 

follows:

§63.11225 What are my notification, reporting, and 

recordkeeping, requirements?

(a) You must submit the notifications specified in 

paragraphs (a)(1) through (a)(5) of this section to the 

administrator.

(1) You must submit all of the notifications in §§63.7(b); 

63.8(e) and (f); and 63.9(b) through (e), (g) and (h) that apply 

to you by the dates specified in those sections except as 

specified in paragraphs (a)(2) and (4) of this section.

(2) An Initial Notification must be submitted no later than 

January 20, 2014 or within 120 days after the source becomes 

subject to the standard.

* * * * *

(4) You must submit the Notification of Compliance Status 

no later than 120 days after the applicable compliance date 

specified in §63.11196 unless you must conduct a performance 

stack test. If you must conduct a performance stack test, you 

must submit the Notification of Compliance Status within 60 days 

of completing the performance stack test. You must submit the 

Notification of Compliance Status in accordance with paragraphs

(a)(4)(i) and (vi) of this section. The Notification of 
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Compliance Status must include the information and 

certification(s) of compliance in paragraphs (a)(4)(i) through

(v) of this section, as applicable, and signed by a responsible 

official: 

(i) You must submit the information required in 

§63.9(h)(2), except the information listed in §63.9(h)(2)(i)(B), 

(D), (E) and (F). If you conduct any performance tests or CMS 

performance evaluations, you must submit that data as specified 

in paragraph (e) of this section. If you conduct any opacity or 

visible emission observations, or other monitoring procedures or 

methods, you must submit that data to the Administrator at the 

appropriate address listed in §63.13. 

(ii)‘‘This facility complies with the requirements in 

§63.11214 to conduct an initial tune-up of the boiler.’’

(iii) ‘‘This facility has had an energy assessment 

performed according to §63.11214(c).’’ 

(iv) For units that install bag leak detection systems: 

‘‘This facility complies with the requirements in §63.11224(f).”

(v) For units that do not qualify for a statutory exemption 

as provided in section 129(g)(1) of the Clean Air Act: ‘‘No 

secondary materials that are solid waste were combusted in any 

affected unit.’’

(vi) The notification must be submitted electronically 

using the Compliance and Emissions Data Reporting Interface 
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(CEDRI) that is accessed through 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 written Notification of Compliance Status 

must be submitted to the Administrator at the appropriate 

address listed in §63.13.

(5) If you are using data from a previously conducted 

emission test to serve as documentation of conformance with the 

emission standards and operating limits of this subpart, you 

must include in the Notification of Compliance Status the date 

of the test and a summary of the results, not a complete test 

report, relative to this subpart.

(b) You must prepare, by March 1 of each year, and submit 

to the delegated authority upon request, an annual compliance 

certification report for the previous calendar year containing 

the information specified in paragraphs (b)(1) through (4) of 

this section. You must submit the report by March 15 if you had 

any instance described by paragraph (b)(3) of this section. For 

boilers that are subject only to a requirement to conduct a 

biennial or 5-year tune-up according to § 63.11223(a) and not 

subject to emission limits or operating limits, you may prepare 

only a biennial or 5-year compliance report as specified in 

paragraphs (b)(1) and (2) of this section.

* * * * *
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(2) Statement by a responsible official, with the 

official’s name, title, phone number, email address, and 

signature, certifying the truth, accuracy and completeness of 

the notification and a statement of whether the source has 

complied with all the relevant standards and other requirements 

of this subpart. Your notification must include the following 

certification(s) of compliance, as applicable, and signed by a 

responsible official:

(i) “This facility complies with the requirements in 

§63.11223 to conduct a biennial or 5-year tune-up, as 

applicable, of each boiler.”

(ii) For units that do not qualify for a statutory 

exemption as provided in section 129(g)(1) of the Clean Air Act: 

“No secondary materials that are solid waste were combusted in 

any affected unit.”

(iii) “This facility complies with the requirement in 

§63.11214(d) and §63.11223(f) to minimize the boiler’s time 

spent during startup and shutdown and to conduct startups and 

shutdowns according to the manufacturer’s recommended procedures

or procedures specified for a boiler of similar design if 

manufacturer’s recommended procedures are not available.”

* * * * *

(c) You must maintain the records specified in paragraphs 

(c)(1) through (7) of this section.
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* * * * *

(2) You must keep records to document conformance with the 

work practices, emission reduction measures, and management 

practices required by §63.11214 and §63.11223 as specified in 

paragraphs (c)(2)(i) through (vi) of this section.

* * * * *

(ii) For operating units that combust non-hazardous 

secondary materials that have been determined not to be solid 

waste pursuant to §241.3(b)(1) of this chapter, you must keep a 

record which documents how the secondary material meets each of

the legitimacy criteria under §241.3(d)(1). If you combust a 

fuel that has been processed from a discarded non-hazardous 

secondary material pursuant to §241.3(b)(4) of this chapter, you 

must keep records as to how the operations that produced the 

fuel satisfies the definition of processing in §241.2 and each 

of the legitimacy criteria in §241.3(d)(1) 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, 

you must keep records documenting that the material is a listed 

non-waste under §241.4(a).
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(iii) For each boiler required to conduct an energy 

assessment, you must keep a copy of the energy assessment 

report.

(iv) For each boiler subject to an emission limit in Table 

1 to this subpart, you must also keep records of monthly fuel 

use by each boiler, including the type(s) of fuel and amount(s) 

used.

(v) For each boiler that meets the definition of seasonal 

boiler, you must keep records of days of operation per year.

(vi) For each boiler that meets the definition of limiteduse boiler, 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 records of fuel use for the days the 

boiler is operating.

* * * * *

(d) Your records must be in a form suitable and readily 

available for expeditious review. You must keep each record for 

5 years following the date of each recorded action. You must 

keep each record onsite or be accessible from a central location 

by computer or other means that instantly provide access at the 

site for at least 2 years after the date of each recorded 

action. You may keep the records off site for the remaining 3 

years.
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(e)(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 to EPA’s 

WebFIRE database by using CEDRI that is accessed through EPA’s 

CDX (www.epa.gov/cdx). Performance test data must be submitted 

in the file format generated through use of EPA’s Electronic 

Reporting Tool (ERT) (see 

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

collected using test methods on the ERT website are subject to 

this requirement for submitting reports electronically to 

WebFIRE. Owners or operators who claim that some of the 

information being submitted for performance tests is 

confidential business information (CBI) must submit a complete 

ERT file including information claimed to be CBI on a compact 

disk or other commonly used electronic storage media (including, 

but not limited to, flash drives) to EPA. The electronic media 

must be clearly marked as CBI and mailed to U.S. EPA/OAPQS/CORE 

CBI Office, Attention: WebFIRE Administrator, MD C404-02, 4930 

Old Page Rd., Durham, NC 27703. The same ERT file with the CBI 

omitted must be submitted to EPA via CDX as described earlier in 

this paragraph. At the discretion of the delegated authority, 

you must also submit these reports, including the confidential 

business information, to the delegated authority in the format 
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specified by the delegated authority. 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 at 

the appropriate address listed in §63.13.

(2) Within 60 days after the date of completing each CEMS 

performance evaluation test as defined in §63.2, you must submit 

relative accuracy test audit (RATA) data to EPA’s CDX by using 

CEDRI in accordance with paragraph (e)(1) of this section. Only 

RATA pollutants that can be 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 at the appropriate address listed in 

§63.13.

* * * * *

(g) If you have switched fuels or made a physical change to 

the boiler and the fuel switch or change resulted in the

applicability of a different subcategory within subpart JJJJJJ, 

in the boiler becoming subject to subpart JJJJJJ, or in the 

boiler switching out of subpart JJJJJJ due to a change to 100 

percent natural gas, or you have taken a permit limit that 

resulted in you being subject to subpart JJJJJJ, you must 
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provide notice of the date upon which you switched fuels, made 

the physical change, or took a permit limit within 30 days of 

the change. The notification must identify:

(1) The name of the owner or operator of the affected 

source, the location of the source, the boiler(s) that have

switched fuels, were physically changed, or took a permit limit, 

and the date of the notice.

(2) The date upon which the fuel switch, physical change, 

or permit limit occurred.

17. Section 63.11226 is amended by revising the section,

including the section heading, to read as follows:

§63.11226 Affirmative Defense for Violation of Emission 

Standards During Malfunction

In response to an action to enforce the standards set forth 

in §63.11201 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 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
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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. Off-shift and overtime labor were used, to 

the extent practicable to make these repairs; 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 

prevent loss of life, personal injury, or severe property 

damage; and
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(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 

it has met the requirements set forth in paragraph (a) of this 

section. This affirmative defense report shall be included in 
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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.

18. Section 63.11236 is amended by revising paragraph (a) 

to read as follows:

§63.11236 Who implements and enforces this subpart? 

(a) This subpart can be implemented and enforced by 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 has the authority to 

implement and enforce this subpart. You should contact your EPA 

Regional Office to find out if implementation and enforcement of 

this subpart is delegated to your state, local, or tribal 

agency.

* * * * *

19. Section 63.11237 is amended as follows:
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a. By adding new definitions in alphabetical order for “10-

day rolling average,” “30-day rolling average,” “Annual heat 

input,” “Biodiesel,” “Calendar year,” “Common stack,” “Daily 

block average,” “Distillate oil,” “Electric boiler,” “Electric 

utility steam generating unit (EGU),” “Energy management 

program,” “Fluidized bed boiler,” “Fluidized bed combustion,” 

“Hourly average,” “Limited-use boiler,” “Load fraction,” 

“Minimum scrubber pressure drop,” “Minimum sorbent injection 

rate,” “Minimum total secondary electric power,” “Operating 

day,” “Oxygen analyzer system,” “Oxygen trim system,” “Process 

heater,” “Residential boiler,” “Regulated gas stream”, “Residual 

oil,” “Seasonal boiler,” “Shutdown,” “Solid fuel,” “Startup,”

“Temporary boiler,” “Tune-up,” “Vegetable oil,” “Voluntary 

Consensus Standards (VCS),” and “Wet scrubber.”

b. By revising the definitions for “Bag leak detection 

system,” “Biomass subcategory,” “Boiler,” “Boiler system,” 

“Deviation,” “Dry scrubber,” “Electrostatic precipitator (ESP),” 

“Energy assessment,” “Energy use system,” “Federally 

enforceable,” “Gas-fired boiler,” “Heat input,” “Hot water 

heater,” “Institutional boiler,” “Liquid fuel,” “Minimum 

activated carbon injection rate,” “Minimum oxygen level,” 

“Minimum scrubber liquid flow rate,” “Natural gas,” “Oil 

subcategory,” “Particulate matter,” “Period of natural gas 
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curtailment or supply interruption,” “Qualified Energy 

Assessor,” “Solid fossil fuel,” and “Waste heat boiler.”

c. By deleting the definitions for “Annual heat input 

basis,” “Minimum PM scrubber pressure drop,” “Minimum sorbent 

flow rate,” and “Minimum voltage or amperage.”

§63.11237 What definitions apply to this subpart? 

10-day rolling average means the arithmetic mean of all 

valid hours of data from 10 successive operating days, except 

for periods of startup and shutdown and periods when the unit is 

not operating.

30-day rolling average means the arithmetic mean of all 

valid hours of data from 30 successive operating days, except 

for periods of startup and shutdown and periods when the unit is 

not operating.

* * * * *

Annual heat input means the heat input for the 12 months

preceding the compliance demonstration.

Bag leak detection system means a group of instruments that 

are capable of monitoring particulate matter loadings in the 

exhaust of a fabric filter (i.e., baghouse) in order to detect 

bag failures. A bag leak detection system includes, but is not 

limited to, an instrument that operates on electrodynamic, 

triboelectric, light scattering, light transmittance, or other 

principle to monitor relative particulate matter loadings.
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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).

* * * * *

Biomass subcategory includes any boiler that burns any 

biomass and is not in the coal subcategory.

Boiler means an enclosed device using controlled flame 

combustion in which water is heated to recover thermal energy in 

the form of steam and/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, process heaters, and 

autoclaves are excluded from this definition.

Boiler system means the boiler and associated components, 

such as, feedwater systems, combustion air systems, fuel systems 

(including burners), blowdown systems, combustion control 

systems, steam systems, and condensate return systems, directly 

connected to and serving the energy use systems.

Calendar year means the period between January 1 and 

December 31, inclusive, for a given year.
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* * * * *

Common stack means the exhaust of emissions from two or 

more affected units through a single flue. Affected units with a 

common stack may each have separate air pollution control 

systems located before the common stack, or may have a single 

air pollution control system located after the exhausts come 

together in a single flue.

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) Means any instance in which an affected 

source subject to this subpart, or an owner or operator of such 

a source:

(i) Fails to meet any 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. The

determination of whether a deviation constitutes a violation of 
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the standard is up to the discretion of the entity responsible 

for enforcement of the standards.

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 §63.14).

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 

boilers and process heaters are included in this definition. A 

dry scrubber is a dry control system.

Electric boiler means a boiler in which electric heating 

serves as the source of heat. Electric boilers that burn gaseous 

or liquid fuel during periods of electrical power curtailment or 

failure are included in this definition.

Electric utility steam generating unit (EGU) means a fossil 

fuel-fired combustion unit of more than 25 megawatts that serves 
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a generator that produces electricity for sale. A fossil fuelfired unit that cogenerates steam and electricity and supplies 

more than one-third of its potential electric output capacity 

and more than 25 megawatts electrical output to any utility 

power distribution system for sale is considered an electric 

utility steam generating unit. To be “capable of combusting” 

fossil fuels, an EGU would need to have these fuels allowed in 

their operating permits and have the appropriate fuel handling 

facilities on-site or otherwise available (e.g., coal handling 

equipment, including coal storage area, belts and conveyers, 

pulverizers, etc.; oil storage facilities). In addition, fossil 

fuel-fired EGU means any EGU that fired fossil fuel for more 

than 10.0 percent of the average annual heat input in any 3 

consecutive calendar years or for more than 15.0 percent of the 

annual heat input during any one calendar year after April 16, 

2015.

Electrostatic precipitator (ESP) means an add-on air 

pollution control device used to capture particulate matter by 

charging the particles using an electrostatic field, collecting 

the particles using a grounded collecting surface, and 

transporting the particles into a hopper. An electrostatic 

precipitator is usually a dry control system.

Energy assessment means the following for the emission 

units covered by this subpart:
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(1) The energy assessment for facilities with affected 

boilers with less than 0.3 trillion Btu per year (TBtu/year) 

heat input 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, or 

electricity) production, as applicable, will be evaluated to 

identify energy savings opportunities, within the limit of 

performing an 8-hour energy assessment.

(2) The energy assessment for facilities with affected 

boilers with 0.3 to 1.0 TBtu/year heat input capacity 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 affected 

boiler(s) energy (e.g., steam, hot water, or electricity) 

production, as applicable, will be evaluated to identify energy 

savings opportunities, within the limit of performing a 24-hour

energy assessment.

(3) The energy assessment for facilities with affected 

boilers with greater than 1.0 TBtu/year heat input capacity will 

be up to 24 on-site technical labor hours in length for the 

first TBtu/year plus 8 on-site technical labor hours for every 
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additional 1.0 TBtu/year 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) and any 

on-site energy use system(s) accounting for at least 20 percent 

of the affected boiler(s) energy (e.g., steam, hot water, or 

electricity) production, as applicable, will be evaluated to 

identify energy savings opportunities.

(4) The on-site energy use system(s) serving as the basis 

for the percent of affected boiler(s) energy production, as 

applicable, 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 according to the 

ENERGY STAR guideline for energy management, DOE Save Energy 

Now, or ISO 50001 compatible energy management systems (e.g., 

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).
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Energy use system includes the following systems located on 

the site of the affected boiler that use energy provided by the 

boiler: (i) process heating; compressed air systems; machine 

drive (motors, pumps, fans); process cooling; facility heating, 

ventilation, and air conditioning systems; hot water systems; 

building envelop; and lighting; or (ii) other systems that use 

steam, hot water, process heat, or electricity, provided by the 

affected boiler. Energy use systems are only those systems using 

energy clearly produced by affected boilers.

* * * * *

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 combustion means a process where a fuel is 

burned in a bed of granulated particles, which are maintained in 

a mobile suspension by the forward flow of air and combustion 

products.

* * * * *
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Gas-fired boiler includes any boiler that burns gaseous 

fuels not combined with any solid fuels and burns liquid fuel 

only during periods of gas curtailment, gas supply interruption, 

startups, or periodic testing on liquid fuel. Periodic testing 

of liquid fuel shall not exceed a combined total of 48 hours 

during any calendar year.

Heat input means heat derived from combustion of fuel in a 

boiler 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.

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 fuel and hot water 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.

Hourly average means the arithmetic average of at least 

four CMS data values representing the four 15-minute periods in 
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an hour, or at least two 15-minute data values during an hour 

when CMS calibration, quality assurance, or maintenance 

activities are being performed.

* * * * *

Institutional boiler means a boiler used in institutional 

establishments such as, but not limited to, medical centers,

nursing homes, research centers, institutions of higher

education, elementary and secondary schools, libraries, 

religious establishments, and governmental buildings to provide 

electricity, steam, and/or hot water.

Limited-use boiler means any boiler that burns any amount 

of solid or liquid fuels and has a federally enforceable average 

annual capacity factor of no more than 10 percent.

Liquid fuel includes, but is not limited to, distillate 

oil, residual oil, any form of liquid fuel derived from 

petroleum, used oil meeting the specification in 40 CFR 279.11, 

liquid biofuels, biodiesel, and vegetable oil, and comparable 

fuels as defined under 40 CFR 261.38.

Load fraction means the actual heat input of a boiler 

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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Minimum activated carbon injection rate means load fraction 

multiplied by the lowest hourly average activated carbon 

injection rate measured according to Table 6 to this subpart 

during the most recent performance stack test demonstrating 

compliance with the applicable emission limits.

Minimum oxygen level means the lowest hourly average oxygen 

level measured according to Table 6 of this subpart during the 

most recent performance stack test demonstrating compliance with 

the applicable CO emission limit.

Minimum scrubber liquid flow rate means the lowest hourly

average scrubber liquid flow rate (e.g., to the PM scrubber) 

measured according to Table 6 to this subpart during the most 

recent performance stack test demonstrating compliance with the 

applicable emission limit.

Minimum scrubber pressure drop means the lowest hourly

average scrubber pressure drop measured according to Table 6 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 6 to this subpart during the most recent 

performance stack 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.

Minimum total secondary electric power means the lowest 

hourly average total secondary electric power determined from 

the values of secondary voltage and secondary current to the 

electrostatic precipitator measured according to Table 6 to this 

subpart during the most recent performance stack test 

demonstrating compliance with the applicable emission limits.

Natural gas means: 

(1) A naturally occurring mixture of hydrocarbon and 

nonhydrocarbon gases found in geologic formations beneath the 

earth’s surface, of which the principal constituent is methane; 

or 

(2) Liquefied petroleum gas, as defined by the American 

Society for Testing and Materials 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
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(4) Propane or propane-derived synthetic natural gas. 

Propane means a colorless gas derived from petroleum and natural 

gas, with the molecular structure C3H8.

Oil subcategory includes any boiler that burns any liquid 

fuel and is not in either the biomass or coal subcategories. 

Gas-fired boilers that burn liquid fuel only during periods of 

gas curtailment, gas supply interruptions, startups, or for 

periodic testing are not included in this definition. Periodic 

testing on liquid fuel shall not exceed a combined total of 48 

hours during any calendar year..

* * * * *

Operating day means a 24-hour period between 12 midnight 

and the following midnight during which any fuel is combusted at 

any time in the boiler unit. It is not necessary for fuel to be 

combusted for the entire 24-hour period.

Oxygen analyzer system means all equipment required to 

determine the oxygen content of a gas stream and used to monitor 

oxygen in the boiler flue gas, boiler firebox, or other 

appropriate intermediate 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 
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device. A typical system consists of a flue gas oxygen and/or 

carbon monoxide monitor that automatically provides a feedback 

signal to the combustion air controller.

Particulate matter (PM) means any finely divided solid or 

liquid material, other than uncombined water, as measured by the 

test methods specified under this subpart, or an approved 

alternative method.

* * * * *

Period of gas curtailment or supply interruption means a 

period of time during which the supply of gaseous fuel to an 

affected boiler 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 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.

Process heater means an enclosed device using controlled 

flame, and the unit’s primary purpose is to transfer heat 
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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. Process heaters 

include units that heat water/water mixtures for pool heating, 

sidewalk heating, cooling tower water heating, power washing, or 

oil heating.

Qualified energy assessor means a person or persons who 

have demonstrated capabilities to evaluate energy savings 

opportunities for steam generation, process heat, and major 

steam and process heat using systems, as applicable to the 

facility. Qualified energy assessors may be company employees or 

outside specialists.

Regulated gas stream means an offgas stream that is routed 

to a boiler 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 

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:
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(i) a dwelling containing four or fewer families, or

(ii) 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)).

* * * * *

Seasonal boiler means a boiler that undergoes a shutdown 

for a period of at least 7 consecutive months (or 210 

consecutive days) each 12-month period due to seasonal

conditions, except for periodic testing. Periodic testing shall 

not exceed a combined total of 15 days during the 7-month 

shutdown. This definition only applies to boilers that would 

otherwise be included in the biomass subcategory or the oil 

subcategory. 

Shutdown means the cessation of operation of a boiler for 

any purpose. Shutdown begins either when none of the steam or 

heat 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, whichever is earlier. Shutdown 

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

fuel being fired in the boiler.
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Solid fossil fuel includes, but is not limited to, coal, 

coke, petroleum coke, and tire derived fuel.

Solid fuel means any solid fossil fuel or biomass or biobased solid fuel.

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

boiler 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 is supplied for heating and/or producing electricity, or 

for any other purpose.

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 
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boiler that replaces a temporary boiler at a location within the 

facility and performs the same or similar function will be 

included in calculating the consecutive time period unless there 

is a gap in operation of 12 months or more.

(3) The equipment is located at a seasonal facility and 

operates during the full annual operating period of the seasonal 

facility, remains at the facility for at least 2 years, and 

operates at that facility for at least 3 months each year.

(4) The equipment is moved from one location to another 

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.

Tune-up means adjustments made to a boiler in accordance 

with the procedures outlined in §63.11223(b).

Vegetable oil means oils extracted from vegetation.

Voluntary Consensus Standards (VCS) mean technical 

standards (e.g., materials specifications, test methods, 

sampling procedures, business practices) developed or adopted by 

one or more voluntary consensus bodies. EPA/Office of Air 

Quality Planning and Standards, by precedent, has only used VCS 

that are written in English. Examples of VCS bodies are: 

American Society of Testing and Materials (ASTM 100 Barr Harbor 

Drive, P.O. Box CB700, West Conshohocken, Pennsylvania 19428–
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B2959, (800) 262–1373, http://www.astm.org), American Society of 

Mechanical Engineers (ASME ASME, Three Park Avenue, New York, NY 

10016–5990, (800) 843–2763, http://www.asme.org), International 

Standards Organization (ISO 1, ch. de la Voie-Creuse, Case 

postale 56, CH-1211 Geneva 20, Switzerland, +41 22 749 01 11, 

http://www.iso.org/iso/home.htm), Standards Australia (AS Level 

10, The Exchange Centre, 20 Bridge Street, Sydney, GPO Box 476, 

Sydney NSW 2001, + 61 2 9237 6171 http://www.stadards.org.au), 

British Standards Institution (BSI, 389 Chiswick High Road, 

London, W4 4AL, United Kingdom, +44 (0)20 8996 9001, 

http://www.bsigroup.com), Canadian Standards Association (CSA 

5060 Spectrum Way, Suite 100, Mississauga, Ontario L4W 5N6, 

Canada, 800-463-6727, http://www.csa.ca), European Committee for 

Standardization (CEN CENELEC Management Centre Avenue Marnix 17 

B-1000 Brussels, Belgium +32 2 550 08 11, 

http://www.cen.eu/cen), and German Engineering Standards (VDI 

VDI Guidelines Department, P.O. Box 10 11 39 40002, Duesseldorf, 

Germany, +49 211 6214-230, http://www.vdi.eu). The types of 

standards that are not considered VCS are standards developed 

by: the United States, e.g. , California (CARB) and Texas 

(TCEQ); industry groups, such as American Petroleum Institute 

(API), Gas Processors Association (GPA), and Gas Research 

Institute (GRI); and other branches of the U.S. government, 

e.g., Department of Defense (DOD) and Department of 
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Transportation (DOT). This does not preclude EPA from using 

standards developed by groups that are not VCS bodies within 

their rule. When this occurs, EPA has done searches and reviews 

for VCS equivalent to these non-EPA methods.

Waste heat boiler means a device that recovers normally 

unused energy (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.

Wet scrubber means any add-on air pollution control device 

that mixes an aqueous stream or slurry with the exhaust gases 

from a boiler to control emissions of particulate matter or to 

absorb and neutralize acid gases, such as hydrogen chloride. A 

wet scrubber creates an aqueous stream or slurry as a byproduct 

of the emissions control process.

* * * * *

20. Tables 1, 2, 6, 7 and 8 to subpart JJJJJJ are revised 

to read as follows:
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Table 1 to Subpart JJJJJJ of Part 63 — Emission Limits

As stated in § 63.11201, you must comply with the following 

applicable emission limits:

If your boiler is 

in this 

subcategory...

For the following 

pollutants...

You must achieve less 

than or equal to the 

following emission 

limits, except during 

periods of startup and 

shutdown ...

1. New coal-fired 

boilers with 

heat input 

capacity of 30 

MMBtu/hr or 

greater that 

do not meet 

the definition 

of limited-use 

boiler

a. PM 

(Filterable)

3.0E-02 lb per MMBtu of 

heat input.

b. Mercury 2.2E-05 lb per MMBtu of 

heat input.

c. CO 420 ppm by volume on a 

dry basis corrected to 3 

percent oxygen (3-run 

average or 10-day rolling

average).

2. New coal-fired 

boilers with 

heat input 

capacity of 

between 10 and 

30 MMBtu/hr

that do not 

meet the 

definition of 

limited-use 

boiler

a. PM

(Filterable)

4.2E-01 lb per MMBtu of 

heat input.

b. Mercury 2.2E-05 lb per MMBtu of 

heat input.

c. CO 420 ppm by volume on a 

dry basis corrected to 3 

percent oxygen (3-run 

average or 10-day rolling

average).
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If your boiler is 

in this 

subcategory...

For the following 

pollutants...

You must achieve less 

than or equal to the 

following emission 

limits, except during 

periods of startup and 

shutdown ...

3. New biomassfired boilers

with heat 

input capacity 

of 30 MMBtu/hr

or greater

that do not 

meet the 

definition of 

seasonal 

boiler or 

limited-use 

boiler

a. PM

(Filterable)

3.0E-02 lb per MMBtu of 

heat input.

4. New biomass 

fired boilers

with heat 

input capacity 

of between 10 

and 30 

MMBtu/hr that 

do not meet 

the definition 

of seasonal 

boiler or 

limited-use 

boiler

a. PM

(Filterable)

7.0E-02 lb per MMBtu of 

heat input.

5. New oil-fired 

boilers with 

heat input 

capacity of 10 

MMBtu/hr or 

greater that 

do not meet 

the definition 

of seasonal 

boiler or 

limited-use 

boiler

a. PM

(Filterable)

3.0E-02 lb per MMBtu of 

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

Page 157 of 177

If your boiler is 

in this 

subcategory...

For the following 

pollutants...

You must achieve less 

than or equal to the 

following emission 

limits, except during 

periods of startup and 

shutdown ...

6. Existing coalfired boilers

with heat 

input capacity 

of 10 MMBtu/hr

or greater

that do not 

meet the 

definition of 

limited-use 

boiler

a. Mercury 2.2E-05 lb per MMBtu of 

heat input.

b. CO

420 ppm by volume on a 

dry basis corrected to 3 

percent oxygen.

Table 2 to Subpart JJJJJJ of Part 63 — Work Practice Standards, 

Emission Reduction Measures, and Management Practices

As stated in § 63.11201, you must comply with the following 

applicable work practice standards, emission reduction measures, 

and management practices:

If your boiler is in 

this subcategory... You must meet the following...

1. Existing or new 

coal-fired, new 

biomass-fired, or new 

oil-fired boilers

(units with heat input 

capacity of 10 

MMBtu/hr or greater)

Minimize the boiler’s startup and 

shutdown periods and conduct startups and 

shutdowns according to the manufacturer’s 

recommended procedures. If manufacturer’s 

recommended procedures are not available, 

you must follow recommended procedures 

for a unit of similar design for which 

manufacturer’s recommended procedures are 

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

Page 158 of 177

If your boiler is in 

this subcategory... You must meet the following...

2. Existing coal-fired 

boilers with heat 

input capacity of less 

than 10 MMBtu/hr that 

do not meet the 

definition of limiteduse boiler, or use an 

oxygen trim system 

that maintains an 

optimum air-to-fuel 

ratio

Conduct an initial tune-up as specified 

in §63.11214, and conduct a tune-up of 

the boiler biennially as specified in 

§63.11223.

3. New coal-fired 

boilers with heat 

input capacity of less 

than 10 MMBtu/hr that 

do not meet the 

definition of limiteduse boiler, or use an 

oxygen trim system 

that maintains an 

optimum air-to-fuel 

ratio

Conduct a tune-up of the boiler 

biennially as specified in §63.11223.

4. Existing oil-fired 

boilers with heat 

input capacity greater 

than 5 MMBtu/hr that 

do not meet the 

definition of seasonal 

boiler or limited-use 

boiler, or use an 

oxygen trim system 

that maintains an 

optimum air-to-fuel 

ratio

Conduct an initial tune-up as specified 

in §63.11214, and conduct a tune-up of 

the boiler biennially as specified in 

§63.11223.
***E.O. 12866 Review – Draft – Do Not Cite, Quote, or Release During Review***

Page 159 of 177

If your boiler is in 

this subcategory... You must meet the following...

5. New oil-fired 

boilers with heat 

input capacity greater 

than 5 MMBtu/hr that 

do not meet the 

definition of seasonal 

boiler or limited-use 

boiler, or use an 

oxygen trim system 

that maintains an 

optimum air-to-fuel 

ratio

Conduct a tune-up of the boiler 

biennially as specified in §63.11223.

6. Existing biomassfired boilers that do 

not meet the 

definition of seasonal 

boiler or limited-use 

boiler, or use an 

oxygen trim system 

that maintains an 

optimum air-to-fuel 

ratio

Conduct an initial tune-up as specified 

in §63.11214, and conduct a tune-up of 

the boiler biennially as specified in 

§63.11223.

7. New biomass-fired 

boilers that do not 

meet the definition of 

seasonal boiler or 

limited-use boiler, or 

use an oxygen trim 

system that maintains 

an optimum air-to-fuel 

ratio

Conduct a tune-up of the boiler 

biennially as specified in §63.11223.

8. Existing seasonal 

boilers

Conduct an initial tune-up as specified 

in §63.11214, and conduct a tune-up of 

the boiler every 5 years as specified in 

§63.11223.

9. New seasonal 

boilers

Conduct a tune-up of the boiler every 5 

years as specified in §63.11223.

10. Existing limiteduse boilersConduct an initial tune-up as specified 

in §63.11214, and conduct a tune-up of 

the boiler every 5 years as specified in 

§63.11223.

11. New limited-use 

boilers

Conduct a tune-up of the boiler every 5 

years as specified in §63.11223.
***E.O. 12866 Review – Draft – Do Not Cite, Quote, or Release During Review***

Page 160 of 177

If your boiler is in 

this subcategory... You must meet the following...

12. Existing oil-fired 

boilers with heat 

input capacity of 

equal to or less than 

5 MMBtu/hr

Conduct an initial tune-up as specified 

in §63.11214, and conduct a tune-up of 

the boiler every 5 years as specified in 

§63.11223.

13. New oil-fired 

boilers with heat 

input capacity of 

equal to or less than 

5 MMBtu/hr

Conduct a tune-up of the boiler every 5

years as specified in §63.11223.

14. Existing coalfired, biomass-fired, 

or oil-fired boilers 

with an oxygen trim 

system that maintains 

an optimum air-to-fuel 

ratio that would 

otherwise be subject 

to a biennial tune-up

Conduct an initial tune-up as specified 

in §63.11214, and conduct a tune-up of 

the boiler every 5 years as specified in 

§63.11223.

15. New coal-fired, 

biomass-fired, or oilfired boilers with an 

oxygen trim system 

that maintains an 

optimum air-to-fuel 

ratio that would 

otherwise be subject 

to a biennial tune-up

Conduct a tune-up of the boiler every 5

years as specified in §63.11223.

16. Existing coalfired, biomass-fired, 

or oil-fired boilers

(units with heat input 

capacity of 10 

MMBtu/hr and greater), 

not including limiteduse boilers

Must have a one-time energy assessment 

performed by a qualified energy assessor

or must operate under an energy 

management program developed according to 

the ENERGY STAR guideline for energy 

management, DOE Save Energy Now, or ISO 

50001 compatible energy management 

systems, that includes the affected 

units. 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. Energy 

assessor approval and qualification 

requirements are waived in instances 

where past or amended energy assessments 

are used to meet the energy 
***E.O. 12866 Review – Draft – Do Not Cite, Quote, or Release During Review***

Page 161 of 177

If your boiler is in 

this subcategory... You must meet the following...

assessment requirements. The energy 

assessment must include: 

(1) A visual inspection of the boiler 

system.

(2) An evaluation of operating 

characteristics of the affected boiler 

systems, specifications of energy use

systems, operating and maintenance 

procedures, and unusual operating 

constraints,

(3) An inventory of major energy use 

systems consuming energy from affected 

boiler(s) and which are under control of 

the boiler owner or operator,

(4) A review of available architectural 

and engineering plans, facility operation 

and maintenance procedures and logs, and 

fuel usage,

(5) A list of major energy conservation 

measures that are within the facility’s 

control,

(6) A list of the energy savings 

potential of the energy conservation 

measures identified, and

(7) A comprehensive report detailing the 

ways to improve efficiency, the cost of 

specific improvements, benefits, and the 

time frame for recouping those 

investments.

Table 3 to Subpart JJJJJJ of Part 63 — Operating Limits for 

Boilers with Emission Limits

As stated in §63.11201, you must comply with the applicable 

operating limits:

If you demonstrate 

compliance with 

applicable emission 

limits using...

You must meet these operating limits

except during periods of startup and 

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

Page 162 of 177

If you demonstrate 

compliance with 

applicable emission 

limits using...

You must meet these operating limits

except during periods of startup and 

shutdown...

1. Fabric filter control 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 

§63.11224 and operate the fabric 

filter such that the bag leak 

detection system alarm does not 

sound more than 5 percent of the 

operating time during each 6-month 

period.

2. Electrostatic 

precipitator control

a. Maintain opacity to less than or 

equal to 10 percent opacity (daily 

block average); OR 

b. Maintain the 30-day rolling 

average total secondary electric 

power input of the electrostatic 

precipitator at or above the minimum

total secondary electric power 

measured during the most recent 

performance test demonstrating 

compliance with the PM emission 

limitations. 

3. Wet PM scrubber 

control

Maintain the 30-day rolling average 

pressure drop at or above the minimum

scrubber pressure drop across the wet 

scrubber and the 30-day rolling 

average liquid flow rate at or above 

the minimum scrubber liquid flow rate 

measured during the most recent 

performance test demonstrating 

compliance with the PM emission 

limitation. 

4. Dry sorbent or 

activated carbon 

injection control

Maintain the 30-day rolling average 

sorbent or activated carbon injection 

rate at or above the minimum sorbent 

injection rate or minimum activated 

carbon injection rate measured during 

the most recent performance test 

demonstrating compliance with the 

mercury emissions limitation. When 
***E.O. 12866 Review – Draft – Do Not Cite, Quote, or Release During Review***

Page 163 of 177

If you demonstrate 

compliance with 

applicable emission 

limits using...

You must meet these operating limits

except during periods of startup and 

shutdown...

your boiler operates at lower loads, 

multiply your sorbent or activated 

carbon injection rate by the load 

fraction (e.g., actual heat input 

divided by the heat input during 

performance stack test, for 50 

percent load, multiply the injection 

rate operating limit by 0.5).

5. Any other add-on air 

pollution control type.

This option is for boilers that 

operate dry control systems. Boilers 

must maintain opacity to less than or 

equal to 10 percent opacity (daily 

block average).

6. Fuel analysis Maintain the fuel type or fuel 

mixture (annual average) such that 

the mercury emission rates calculated 

according to §63.11211(c) are less 

than the applicable emission limits 

for mercury.

7. Performance stack 

testing

For boilers that demonstrate 

compliance with a performance stack 

test, maintain the operating load of 

each unit such that is does not 

exceed 110 percent of the average 

operating load recorded during the 

most recent performance stack test.

8. Oxygen analyzer system For boilers subject to a CO emission 

limit that demonstrate compliance 

with an oxygen analyzer system as 

specified in §63.11224(a), maintain 

the 30-day rolling average oxygen 

level at or above the minimum oxygen 

level measured during the most recent 

CO performance stack test.

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

Page 164 of 177

Table 6 to Subpart JJJJJJ of Part 63 — Establishing Operating 

Limits

As stated in §63.11211, you must comply with the following 

requirements for establishing operating limits:

If you have 

an 

applicable 

emission 

limit for 

. . .

And your 

operating 

limits are 

based on 

. . . You must... Using . . .

According 

to the 

following 

requirement

s

1. PM or 

mercury

a. Wet 

scrubber 

operating 

parameters

i. 

Establish a 

sitespecific 

minimum 

scrubber

pressure

drop and 

minimum 

scrubber 

liquid flow 

rate 

operating 

limits 

according 

to 

§63.11211(b

)

(1) Data 

from the 

pressure 

drop and 

liquid flow 

rate 

monitors 

and the PM 

or mercury 

performance 

stack tests

(a) You 

must 

collect 

pressure 

drop and 

liquid flow 

rate data 

every 15 

minutes 

during the 

entire 

period of 

the 

performance 

stack 

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

Page 165 of 177

If you have 

an 

applicable 

emission 

limit for 

. . .

And your 

operating 

limits are 

based on 

. . . You must... Using . . .

According 

to the 

following 

requirement

s

(b) 

Determine 

the average 

pressure 

drop and 

liquid flow 

rate for 

each 

individual 

test run in 

the threerun 

performance 

stack test 

by 

computing 

the average 

of all the 

15-minute 

readings 

taken 

during each 

test run.

b. 

Electrostat

ic 

precipitato

r operating 

parameters 

i. 

Establish a 

sitespecific 

minimum

total

secondary 

electric 

power 

operating

limit

according 

to 

§63.11211(b

)

(1) Data 

from the 

secondary 

electric 

power 

monitors 

and the PM 

or mercury 

performance

stack tests

(a) You 

must 

collect 

secondary 

electric 

power input 

data every 

15 minutes 

during the 

entire 

period of 

the 

performance 

stack 

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

Page 166 of 177

If you have 

an 

applicable 

emission 

limit for 

. . .

And your 

operating 

limits are 

based on 

. . . You must... Using . . .

According 

to the 

following 

requirement

s

(b) 

Determine 

the average 

total 

secondary 

electric 

power input 

for each 

individual 

test run in 

the threerun 

performance 

stack test 

by 

computing 

the average 

of all the 

15-minute 

readings 

taken 

during each 

test run.

2. Mercury a. Dry 

sorbent or 

activated 

carbon 

injection 

rate 

operating 

parameters

i. 

Establish a 

sitespecific 

minimum 

sorbent or 

activated 

carbon 

injection 

rate 

operating 

limit 

according 

to 

§63.11211(b

)

(1) Data 

from the 

sorbent or 

activated 

carbon 

injection 

rate 

monitors 

and the 

mercury 

performance 

stack tests

(a) You 

must 

collect 

sorbent or 

activated 

carbon 

injection 

rate data 

every 15 

minutes 

during the 

entire 

period of 

the 

performance 

stack 

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

Page 167 of 177

If you have 

an 

applicable 

emission 

limit for 

. . .

And your 

operating 

limits are 

based on 

. . . You must... Using . . .

According 

to the 

following 

requirement

s

(b) 

Determine 

the average 

sorbent or 

activated 

carbon 

injection 

rate for 

each 

individual 

test run in 

the threerun 

performance 

stack test 

by 

computing 

the average 

of all the 

15-minute 

readings 

taken 

during each 

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

Page 168 of 177

If you have 

an 

applicable 

emission 

limit for 

. . .

And your 

operating 

limits are 

based on 

. . . You must... Using . . .

According 

to the 

following 

requirement

s

(c) When 

your unit 

operates at 

lower 

loads, 

multiply 

your 

sorbent or 

activated 

carbon 

injection 

rate by the 

load 

fraction 

(e.g., 

actual heat 

input 

divided by 

heat input 

during 

performance 

stack 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 169 of 177

If you have 

an 

applicable 

emission 

limit for 

. . .

And your 

operating 

limits are 

based on 

. . . You must... Using . . .

According 

to the 

following 

requirement

s

3. CO a. Oxygen i. 

Establish a 

unitspecific 

limit for 

minimum 

oxygen 

level.

(1) Data 

from the 

oxygen 

analyzer 

system 

specified 

in 

§63.11224(a

).

(a) You 

must 

collect 

oxygen data 

every 15 

minutes 

during the 

entire 

period of 

the 

performance 

stack 

tests;

(b) 

Determine 

the average 

hourly 

oxygen 

concentrati

on

for each 

individual 

test run in 

the threerun 

performance 

stack test 

by 

computing 

the average 

of all the 

15-minute 

readings 

taken 

during each 

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

Page 170 of 177

If you have 

an 

applicable 

emission 

limit for 

. . .

And your 

operating 

limits are 

based on 

. . . You must... Using . . .

According 

to the 

following 

requirement

s

4. Any 

pollutant 

for which

compliance 

is 

demonstrate

d

by a 

performance

stack test.

a. Boiler 

operating 

load.

i. 

Establish a 

unitspecific

limit for 

maximum 

operating

load 

according 

to

§63.11212(c

).

(1) Data 

from the 

operating

load 

monitors 

(fuel feed 

monitors or

steam 

generation 

monitors).

(a) You 

must 

collect 

operating

load data 

(fuel feed 

rate or 

steam 

generation

data) every 

15

minutes 

during the 

entire

period of 

the 

performance 

test.

(b) 

Determine 

the average

operating 

load by 

computing

the hourly 

averages 

using all 

of the 15-

minute 

readings 

taken 

during each 

performance 

test.

(c) 

Determine 

the average

of the 

three test 

run

averages 

during the 

performance

test, and 

multiply

this by 1.1 

(110
***E.O. 12866 Review – Draft – Do Not Cite, Quote, or Release During Review***

Page 171 of 177

Table 7 to Subpart JJJJJJ of Part 63 — Demonstrating Continuous 

Compliance

As stated in §63.11222, you must show continuous compliance 

with the emission limitations for each boiler according to the 

following:

If you must meet the 

following operating 

limits . . .

You must demonstrate continuous compliance 

by . . .

1. Opacity a. Collecting the opacity monitoring 

system data according to §63.11224(e) and 

§63.11221; and

b. Reducing the opacity monitoring data to 

6-minute averages; and

c. Maintaining opacity to less than or 

equal to 10 percent (daily block average).

2. Fabric Filter Bag 

Leak Detection 

Operation

Installing and operating a bag leak 

detection system according to §63.11224(f)

and operating the fabric filter such that

the requirements in §63.11222(a)(4) are 

met.

3. Wet Scrubber 

Pressure Drop and 

Liquid Flow Rate

a. Collecting the pressure drop and liquid 

flow rate monitoring system data according 

to §§63.11224 and 63.11221; 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 

§63.11211.

4. Dry Scrubber 

Sorbent or Activated 

Carbon Injection Rate

a. Collecting the sorbent or activated 

carbon injection rate monitoring system 

data for the dry scrubber according to 

§§63.11224 and 63.11221; and

b. Reducing the data to 30-day rolling

averages; and
***E.O. 12866 Review – Draft – Do Not Cite, Quote, or Release During Review***

Page 172 of 177

If you must meet the 

following operating 

limits . . .

You must demonstrate continuous compliance 

by . . .

c. Maintaining the 30-day rolling average 

sorbent or activated carbon injection rate 

at or above the minimum sorbent or 

activated carbon injection rate according 

to §63.11211.

5. Electrostatic 

Precipitator Total 

Secondary Electric

Power Input

a. Collecting the total secondary electric

power input monitoring system data for the 

electrostatic precipitator according to 

§§63.11224 and 63.11221; 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 

§63.11211.

6. Fuel Pollutant 

Content

a. Only burning the fuel types and fuel 

mixtures used to demonstrate compliance 

with the applicable emission limit 

according to §63.11213 as applicable; and

b. Keeping monthly records of fuel use 

according to §§63.11222(a)(2) and 

63.11225(b)(4).

7. Oxygen content a. Continuously monitor the oxygen content 

of flue gas according to §63.11224.

b. Reducing the data to 30-day rolling

averages; and

c. Maintain the 30-day rolling average 

oxygen content at or above the operating 

limit established during the most recent 

CO performance test.

8. CO emissions a. Continuously monitor the CO

concentration in the combustion exhaust 

according to §§63.11224 and 63.11221.

b. Correcting the data to 3 percent 

oxygen, and reducing the data to one-hour 

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

Page 173 of 177

If you must meet the 

following operating 

limits . . .

You must demonstrate continuous compliance 

by . . .

c. Reducing the data from the hourly

averages to 10-day rolling averages;

d. Maintaining the 10-day rolling average 

CO concentration at or below the 

applicable emission limit in Tables 1 of 

this subpart.

9. Boiler operating 

load 

a. Collecting operating load data (fuel 

feed rate or steam generation data) every 

15 minutes.

b. Reducing the data to 30-day rolling 

averages; and

c. Maintaining the 30-day rolling average 

at or below the operating limit 

established during the performance test 

according to §63.11212(c).

Table 8 to Subpart JJJJJJ of Part 63 — Applicability of 

General Provisions to Subpart JJJJJJ

As stated in §63.11235, you must comply with the applicable 

General Provisions according to the following:

General 

Provisions Cite 

Subject Does it apply?

§63.1 Applicability Yes.

§63.2 Definitions Yes. Additional terms 

defined in §63.11237.

§63.3 Units and 

Abbreviations

Yes.

§63.4 Prohibited 

Activities and 

Circumvention

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

Page 174 of 177

§63.5 Preconstruction 

Review and 

Notification 

Requirements

No

§63.6(a), (b)(1)-

(b)(5), (b)(7), 

(c), (f)(2)-(3), 

(g), (i), (j)

Compliance with 

Standards and 

Maintenance 

Requirements

Yes.

§63.6(e)(1)(i) General Duty to 

minimize emissions

No. See §63.11205 for 

general duty requirement.

§63.6(e)(1)(ii) Requirement to 

correct 

malfunctions ASAP

No.

§63.6(e)(3) SSM Plan No.

§63.6(f)(1) SSM exemption No.

§63.6(h)(1) SSM exemption No.

§63.6(h)(2) to 

(9)

Determining 

compliance with 

opacity emission 

standards

Yes.

§63.7(a),(b),(c),

(d),(e)(2)-

(e)(9), (f),(g), 

and (h)

Performance 

Testing 

Requirements

Yes.

 

§63.7(e)(1) Performance 

testing

No. See §63.11210.

§63.8(a),(b),(c)(

1),(c)(1)(ii),(c)

(2) to 

(c)(9),(d)(1)and(

d)(2), (e),(f), 

and (g)

Monitoring 

Requirements

Yes.

§63.8(c)(1)(i) General duty to 

minimize emissions 

and CMS operation

No.

§63.8(c)(1)(iii) Requirement to 

develop SSM Plan 

for CMS

No.
***E.O. 12866 Review – Draft – Do Not Cite, Quote, or Release During Review***

Page 175 of 177

§63.8(d)(3) Written procedures 

for CMS

Yes, except for the last 

sentence, which refers to 

an SSM plan. SSM plans are 

not required.

§63.9 Notification 

Requirements

Yes, excluding the 

information required in 

§63.9(h)(2)(i)(B), (D), (E) 

and (F). See §63.11225..

§63.10(a) and 

(b)(1) 

Recordkeeping and 

Reporting 

Requirements

Yes.

§63.10(b)(2)(i) Recordkeeping of 

occurrence and 

duration of 

startups or 

shutdowns

No.

§63.10(b)(2)(ii) Recordkeeping of 

malfunctions

No. See §63.11225 for 

recordkeeping of (1) 

occurrence and duration and 

(2) actions taken during 

malfunctions.

§63.10(b)(2)(iii) Maintenance 

records

Yes.

§63.10(b)(2)(iv) 

and (v)

Actions taken to 

minimize emissions 

during SSM

No.

§63.10(b)(2)(vi) Recordkeeping for 

CMS malfunctions

Yes.

§63.10(b)(2)(vii) 

to (xiv)

Other CMS 

requirements

Yes.

§63.10(b)(3) Recordkeeping 

requirements for 

applicability 

determinations

No.

§63.10(c)(1) to 

(9)

Recordkeeping for 

sources with CMS

Yes.

§63.10(c)(10) Recording nature 

and cause of 

malfunctions

No. See §63.11225 for 

malfunction recordkeeping 

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

Page 176 of 177

§63.10(c)(11) Recording 

corrective actions

No. See §63.11225 for 

malfunction recordkeeping 

requirements.

§63.10(c)(12) and 

(13)

Recordkeeping for 

sources with CMS

Yes.

§63.10(c)(15) Allows use of SSM 

plan

No.

§63.10(d)(1) and 

(2)

General reporting 

requirements

Yes.

§63.10(d)(3) Reporting opacity 

or visible 

emission 

observation 

results 

No.

§63.10(d)(4) Progress reports 

under an extension 

of compliance

Yes.

§63.10(d)(5) SSM reports No. See §63.11225 for 

malfunction reporting 

requirements.

§63.10(e) and (f) Yes.

§63.11 Control Device 

Requirements

No.

§63.12 State Authority 

and Delegation

Yes.

§63.13-63.16 Addresses, 

Incorporation by 

Reference, 

Availability of 

Information, 

Performance Track 

Provisions

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

Page 177 of 177

§63.1(a)(5),(a)(7

)-(a)(9), (b)(2), 

(c)(3)-(4), (d), 

63.6(b)(6), 

(c)(3), (c)(4), 

(d), (e)(2), 

(e)(3)(ii), 

(h)(3), 

(h)(5)(iv), 

63.8(a)(3), 

63.9(b)(3), 

(h)(4), 

63.10(c)(2)-(4), 

(c)(9).

Reserved No.