Vol. 78 Friday, 

No. 22 February 1, 2013 

Part II 

Environmental Protection Agency 

40 CFR Part 63 

National Emission Standards for Hazardous Air Pollutants for Area 

Sources: Industrial, Commercial, and Institutional Boilers; Final Rule 


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7488 Federal Register / Vol. 78, No. 22 / Friday, February 1, 2013 / Rules and Regulations 

ENVIRONMENTAL PROTECTION 

AGENCY 

40 CFR Part 63 

[EPA–HQ–OAR–2006–0790; FRL–9698–5] 

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 

taking final action on reconsideration of 

certain issues related to the emission 

standards to control hazardous air 

pollutants from new and existing 

industrial, commercial and institutional 

boilers at area sources which were 

issued under section 112 of the Clean 

Air Act. As part of this action, the EPA 

is amending certain compliance dates 

for 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. The EPA today is taking final 

action on the proposed reconsideration. 

DATES: This final rule is effective on 

February 1, 2013. The incorporation by 

reference of certain publications listed 

in this final rule were approved by the 

Director of the Federal Register as of 

February 1, 2013. 

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 Web 

site. Although listed in the index, some 

information is not publicly available, 

e.g., confidential business information 

or other information whose disclosure is 

restricted by statute. Certain other 

material, such as copyrighted material, 

is not placed on the Internet and will be 

publicly available only in hard copy 

form. Publicly available docket 

materials are available either 

electronically through http:// 

www.regulations.gov or in hard 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 

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 

source boilers, 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. Section 112(c)(6) requires the 

EPA to regulate sources listed pursuant 

to that provision by issuing standards 

under section 112(d)(2) or (d)(4). The 

final rule meets this requirement by 

setting MACT standards for Hg and CO 

(as a surrogate for POM) for units in the 

coal-fired subcategory. Further, the final 

rule sets standards based on GACT for 

the urban HAP, other than Hg and POM, 

emitted from coal-fired boilers that pose 

the greatest public health risk, pursuant 

to section 112(c)(3) of the CAA, 

including arsenic, beryllium, cadmium, 

lead, chromium, manganese, nickel, 

ethylene dioxide, and PCBs. In addition, 

the final rule sets standards based on 

GACT for boilers combusting oil or 

biomass for urban HAP, including Hg, 

arsenic, beryllium, cadmium, lead, 

chromium, manganese, nickel, POM, 

ethylene dioxide, and PCBs. 

In developing the MACT standards for 

coal-fired boilers, the EPA considered 

section 112(h) of the CAA, which allows 

the EPA to establish work practice 

standards in lieu of numerical emission 

limits under section 112(d)(2) only in 

cases where the agency determines that 

it is not feasible to prescribe or enforce 

an emission standard. The EPA has set 

work practice standards for emissions of 

Hg and POM from small coal-fired 

boilers, pursuant to section 112(h), in 

the form of periodic tune-ups. 

This final rule amends certain 

provisions of the final rule issued by 

EPA on March 11, 2011, and responds 

to petitions for reconsideration filed by 

a number of different entities. 

Summary of Major Reconsideration 

Provisions 

In general, the final rule requires 

facilities classified as area sources of 

HAP with 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, the EPA 

is establishing seven subcategories for 

boilers based on the design of the 

combustion equipment and operating 

schedules of the unit. In addition to the 

coal, biomass, and oil subcategories in 

the March 2011 final rule, we are 

establishing subcategories for seasonal 

boilers, limited-use boilers, oil-fired 

boilers with heat input capacity of equal 

to or less than 5 MMBtu/hr, and certain 

boilers that use a continuous oxygen 

trim system. 

Numerical emission limits, based on 

MACT, are established for Hg and CO at 

new and existing large coal-fired boilers 

(i.e., with a design heat input capacity 

of 10 MMBtu/hr or more). A review of 

the data has resulted in changes to the 

Hg and CO emission limits contained in 

the March 2011 final rule. The EPA is 

also establishing a CEMS alternative 

compliance option for the numeric CO 

emission limit. Coal-fired boilers subject 

to a CO emission limit can comply with 

the limit using a periodic stack test and 

CPMS, or by using CEMS. The CO 

CEMS alternative compliance option is 

based on a 10-day rolling average and 

provides additional compliance 

flexibility to sources with existing CO 

CEMS equipment. New and existing 

small coal-fired units (i.e., with a design 

heat input capacity of less than 10 

MMBtu/hr) are subject to periodic tuneup work practices for CO and Hg in lieu 

of numeric emission limits because the 

EPA found that it was technologically 


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and economically impracticable to 

apply measurement methodology to 

these small sources, pursuant to CAA 

section 112(h). 

Numerical emission limits, based on 

GACT, are established for PM as a 

surrogate for urban metal HAP other 

than Hg for new large coal-fired boilers. 

New and existing small coal-fired 

boilers are subject to periodic tune-up 

management practices for PM as a 

surrogate for urban metal HAP other 

than Hg, and for CO as a surrogate for 

urban organic HAP other than POM, 

based on GACT. 

New large biomass- and oil-fired 

boilers are subject to numerical 

emission limits for PM as a surrogate for 

urban metal HAP, based on GACT. 

Existing biomass and oil-fired boilers 

and new small biomass- and oil-fired 

boilers are subject to periodic tune-up 

management practices for PM as a 

surrogate for urban metal HAP, based on 

GACT. New and existing biomass- and 

oil-fired boilers are subject to periodic 

tune-up management practices for CO as 

a surrogate for urban organic HAP, 

based on GACT. Certain other 

subcategories (seasonal boilers, limiteduse boilers, oil-fired boilers with heat 

input capacity of equal to or less than 

5 MMBtu/hr, and boilers with an 

oxygen trim system) are subject to 

periodic tune-up work practice or 

management practice requirements 

tailored to their schedule of operation 

and types of fuel. 

The compliance date for existing 

sources is March 21, 2014. The 

compliance date for new sources that 

began operations on or before May 20, 

2011 is May 20, 2011. For new sources 

that start up after May 20, 2011, the 

compliance date is the date of startup. 

New sources are defined as sources that 

began operation after June 4, 2010. 

Costs and Benefits 

This final action is intended to clarify 

definitions, references, applicability and 

compliance issues, but not change the 

coverage of the final rule. The final rule 

will affect an estimated 180,000 existing 

area source boilers and the EPA projects 

that approximately an additional 6,800 

new boilers will be subject to the rule 

over the initial 3-year period. The 

clarifications should make it easier for 

owners and operators and for local and 

state authorities to understand and 

implement the rule’s requirements. As 

compared to the March 2011 final rule, 

this final rule will not affect the 

estimated emission reductions, control 

costs or the benefits of the rule in 

substance. This final rule does not 

impose any additional regulatory 

requirements beyond those imposed by 

the previously promulgated boiler area 

source rule and, in fact, will result in a 

decrease in regulatory requirements for 

certain subcategories of boilers. A more 

detailed discussion of the costs and 

benefits of the March 2011 final rule is 

provided at 76 FR 15579, March 21, 

2011, and 76 FR 80542, December 23, 

2011. Section VI of this preamble 

provides a discussion of the impacts of 

this final rule. 

SUPPLEMENTARY INFORMATION: 

Acronyms and Abbreviations. The 

following acronyms and abbreviations 

are used in this document. 

7–PAH 7-polynuclear aromatic 

hydrocarbons 

ACI activated carbon injection 

ASTM American Society for Testing and 

Materials 

Btu British thermal unit 

CO carbon monoxide 

CEMS continuous emission 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 

NAA No Action Assurance 

NAICS North American Industry 

Classification System 

NESHAP national emission standards for 

hazardous air pollutants 

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 units 

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 and Shutdown 

K. Affirmative Defense Language 

L. Notification, Recordkeeping and 

Reporting Requirements 

M. Title V Permitting Requirements 

N. Definition of Period of Gas Curtailment 

or Supply Interruption 

O. Miscellaneous Technical Corrections 

P. 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 Code a Examples of regulated entities 

Any area source facility using a boiler as defined in the final rule. ............................. 321 

11 

311 

327 

Wood product manufacturing. 

Agriculture, greenhouses. 

Food manufacturing. 

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 final action. To 

determine whether your facility may be 

affected by this 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 this final rule to a 

particular entity, consult either the air 

permit authority for the entity or your 

EPA regional representative, as listed in 

40 CFR 63.13 of subpart A (General 

Provisions). 

B. Where can I get a copy of this 

document? 

In addition to being available in the 

docket, an electronic copy of this action 

will also be available on the WWW 

through the TTN. Following signature, a 

copy of the action will be posted on the 

TTN’s policy and guidance page for 

newly proposed or promulgated rules at 

the following address: http:// 

www.epa.gov/ttn/oarpg/. The TTN 

provides information and technology 

exchange in various areas of air 

pollution control. 

C. Judicial Review 

Under the CAA section 307(b)(1), 

judicial review of this final rule is 

available only by filing a petition for 

review in the U.S. Court of Appeals for 

the District of Columbia Circuit by April 

2, 2013. 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 

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 generally available control 

technologies (‘‘GACT’’) or management 

practices by such sources to reduce 

emissions of hazardous air pollutants.’’ 

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, 

hexachlorobenzene, Hg, PCBs, 2,3,7,8- 

tetrachlorodibenzofuran, 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 Hg 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. 

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 


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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), 

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. 

• Addressing 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. 

• 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. 

• Revising 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 

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. 

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 gasfired 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 that are not part of the source 

categories subject to subpart JJJJJJ. We 

are revising this list (as set forth in 40 

CFR 63.11195) to clarify certain boiler 

types and to include certain additional 

boilers that may be located at an 

industrial, commercial or institutional 

area source facility. These revisions of 

the source categories are described 

below. 

1. Electric Boilers 

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: 

(1) A dwelling containing four or fewer 

families, or 

(2) A single unit residence dwelling that 

has since been converted or subdivided into 

condominiums or apartments. 

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. 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. We note that neither the CAA 

section 112(c)(6) inventory nor the CAA 

section 112(c)(3) inventory included 

temporary boilers. In this final action, 

the EPA is simply clarifying the scope 

of categories regulated by subpart JJJJJJ. 

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. 

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 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 


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1 Generally, boilers are initially installed 

optimized for efficiency, i.e., ‘‘in tune.’’ Periodic 

tune-ups restore a boiler to its efficient state, given 

its age and other parameters. We do not require a 

tune-up upon startup because boilers normally 

would already be efficient at that time. Emission 

reductions are projected to occur by maintaining 

efficient combustion through periodic tune-ups. 

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 amending the language in 

40 CFR 63.11195(g) to clarify that any 

boiler that is used as a control device to 

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 large coal-fired boilers to 

0.000022 lb per MMBtu based on a 

revised analysis. The revised analysis 

excludes data for a utility boiler that 

were 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 

Analysis for Mercury and Carbon 

Monoxide’’ located in the docket for the 

rulemaking describes our beyond-thefloor analysis for Hg and CO emissions 

from new and existing area source coalfired boilers with heat input capacity of 

10 MMBtu/hr or greater. In the beyondthe-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, it is 

expected that an affected boiler would 

need to employ fabric filter control 

along with ACI. In summary, we 

determined that the beyond-the-floor 

option of installing ACI for Hg control 

from area source coal-fired boilers is not 

economically feasible. 

As discussed in the preamble to the 

June 2010 proposed rule (75 FR 31896) 

and the preamble to the March 2011 

final rule (76 FR 15554), we also 

considered whether fuel switching was 

an appropriate control technology for 

purposes of determining either the 

MACT floor level or beyond-the-floor 

level of control. We determined that fuel 

switching was not an appropriate floor 

or beyond-the-floor control. As also 

discussed in the June 2010 and March 

2011 preambles, we determined that an 

energy assessment requirement was an 

appropriate beyond-the-floor option for 

existing large boilers. These previous 

analyses continue to be applicable for 

mercury. 

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 

99 percent confidence level in 

determining the UPL. Based on the 

results of the revised analysis, we are 

amending the CO emission limit for new 

and existing coal-fired 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. 

As discussed in the ‘‘Beyond-theFloor Analysis for Mercury and Carbon 

Monoxide’’ memorandum, to comply 

with a limit more stringent than the 

MACT floor based CO limit, it is 

expected that new and existing area 

source coal-fired boilers with heat input 

capacity of 10 MMBtu/hr or greater may 

need to install an oxidation catalyst. As 

fully explained in the memorandum, we 

determined that the beyond-the-floor 

option of installing an oxidation catalyst 

for CO control was technically 

infeasible. Other methods of reducing 

CO emissions, such as upgrading new 

burners and overfire air systems, were 

also considered and determined to be 

technically infeasible options. As 

explained earlier in this preamble, we 

determined that fuel switching was not 

an appropriate floor or beyond-the-floor 

control and that an energy assessment 

requirement was an appropriate beyondthe-floor option for existing large 

boilers. These previous analyses 

continue to be applicable for CO. 

3. Compliance Alternative for PM for 

Certain Oil-Fired Boilers 

The EPA is amending the 

applicability of PM emission limit 

requirements for certain new or 

reconstructed oil-fired boilers. We are 

amending 40 CFR 63.11210 to specify 

that new or reconstructed oil-fired 

boilers satisfy GACT for PM when they 

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 

do not use a post-combustion 

technology (except a wet scrubber) to 

reduce PM or sulfur dioxide emissions. 

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 these boilers 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 tuneup by March 21, 2014, and a subsequent 

tune-up every 5 years after the initial 

tune-up. 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.1 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 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 


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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 subcategory of oilfired 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 subcategory 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 

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 subcategory of boilers is 

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 these boilers are required to 

complete a tune-up every 5 years. 

Specifically, existing limited-use boilers 

are required to complete the initial tuneup 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 

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 (e.g., 

production area or building) and not by 

a total aggregation of all individual 

energy using segments of a facility. 

The definition of ‘‘boiler system’’ is 

being revised in this 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 

energy clearly produced by affected 

boilers. 

We are clarifying that energy assessor 

approval and qualification requirements 

are waived in instances where an energy 

assessment completed on or after 

January 1, 2008 meets or is amended to 

meet the energy assessment 

requirements in this final rule by March 

21, 2014. Finally, we are specifying that 

a source that is operating under an 

energy management program 

established through energy management 

systems compatible with ISO 50001, 

that includes the affected boilers, by 

March 21, 2014, satisfies the energy 

assessment requirement. We consider 

these energy management programs to 

be equivalent to the one-time energy 

assessment because facilities having 

these programs operate under a set of 

practices and procedures designed to 

manage energy use on an ongoing basis. 

These programs contain energy 

performance measurements and tracking 

plans with periodic reviews. 

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 

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 of ‘‘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 Oil-Fired 

Boilers 

The EPA is not amending the GACTbased standards, as specified in the 

March 21, 2011, final rule, for biomassand oil-fired boilers. Specifically, the 

final standards for biomass- and oilfired area source boilers are based on 

GACT instead of MACT as were the 

proposed standards for all pollutants 

except POM. Our rationale for the 

changes between proposal and 

promulgation for the biomass- and oilfired boilers, including not requiring 

MACT for POM, 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 biomassand 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 

GACT-based 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 


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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 one-time energy assessment performed 

by a qualified energy assessor, an energy 

assessment completed on or after 

January 1, 2008 that meets or is 

amended to meet the energy assessment 

requirements in this final rule by March 

21, 2014, or an energy management 

program established through energy 

management systems compatible with 

ISO 50001, that includes the affected 

boilers, by March 21, 2014, 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 

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 

GACT-based 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 

Some commenters have argued that 

the 3-year compliance deadline of 

March 21, 2014, for existing sources to 

meet the standards does not provide 

sufficient time for sources to meet the 

standards in view of the large number 

of sources subject to the rule and that 

these sources 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 (i.e., by March 21, 2014), 

even those that need to install pollution 

control technologies to do so. In 

addition, many sources subject to the 

standards are existing biomass- or oilfired boilers or small coal-fired boilers 

(less than 10 MMBtu/hr) and will not 

need to install controls in order to 

demonstrate compliance, as these 

sources are subject only to work 

practices or management practices. 

At the same time, the CAA allows title 

V permitting authorities to grant 

sources, on a case-by-case basis, 

extensions to the compliance time of up 

to 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 an 

existing 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 

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 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. 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 upon the existing major source 

commencing operation as 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. 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 


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FR 80532, December 23, 2011). In the 

December 23, 2011, proposal, we 

specifically requested comment on 

whether the initial compliance period 

for the tune-up requirement should be 

extended to March 21, 2014. 

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 tuneups 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 unit-specific limit for 

maximum operating load that applies to 

any boiler subject to an emission limit 

for which compliance is 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 March 2011 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 sitespecific 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 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 not required to perform initial CO 

performance testing nor are they subject 

to 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 other appropriate 

intermediate location. This definition 

includes oxygen trim systems. 

• 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 tuneup 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 days of 

startup. 

3. Performance Testing Frequency 

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 re-start 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 


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mixture are measured to be equal to or 

less than half of the Hg emission limit. 

The owner 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 and periods when 

the unit is not operating in the 

calculation of the arithmetic mean. 

6. Monitoring Data 

The EPA is clarifying in 40 CFR 

63.11221 the monitoring data collection 

requirements. 

J. Periods of Startup and Shutdown 

1. Definitions 

The EPA is revising the definitions of 

‘‘startup’’ and ‘‘shutdown’’ such that 

they are tailored for industrial boilers 

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. We are 

defining startup as the period between 

either the first-ever firing of fuel in the 

boiler or the firing of fuel in the boiler 

after a shutdown and when the boiler 

first supplies steam or heat. We are 

defining shutdown as the period 

between either when no more steam or 

heat is supplied by the boiler or no fuel 

is being fired in the boiler and when 

there is no steam and no heat being 

supplied and no fuel being fired in the 

boiler. 

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(g) to include biomass- and oilfired boilers in the requirement to 

minimize the time spent in startup and 

shutdown periods. Specifically, the 

requirement is to 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, 

recommended procedures for a unit of 

similar design for which manufacturer’s 

recommended procedures are available 

must be followed. 

K. 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. We have 

made certain changes to 40 CFR 

63.11226 to clarify the circumstances 

under which a source may assert an 

affirmative defense. The changes clarify 

that a source may assert an affirmative 

defense to a claim for civil penalties for 

violations of standards that are caused 

by malfunctions. A source can avail 

itself of the affirmative defense when 

there has been a violation of the 

emission standards due to an event that 

meets the definition of malfunction 

under 40 CFR 63.2 and qualifies for 

assertion of an affirmative defense 

under 40 CFR 63.11226. In the March 

2011 final rule, we used terms such as 

‘‘exceedance’’ or ‘‘excess emissions’’ in 

40 CFR 63.11226, which created 

unnecessary confusion as to when the 

affirmative defense could be used. In 

this final rule, we have eliminated those 

terms and used the word ‘‘violation’’ to 

make clear that the affirmative defense 

to civil penalties is available only where 

an event that causes a violation of the 

emissions standard meets the criteria for 

the assertion of an affirmative defense 

under 40 CFR 63.11226. 

This final rule requires that to 

establish the affirmative defense the 

owner must prove by a preponderance 

of evidence that repairs were made as 

expeditiously as possible when a 

violation occurs. We have re-evaluated 

the language concerning the use of offshift and overtime labor, to the extent 

practicable, to make the repairs and 

believe that the language is not 

necessary. Thus, the language has been 

eliminated from this final rule. 

We have also eliminated the 2-day 

notification requirement that was 

included in 40 CFR 63.11226(b) of the 

March 2011 final rule because we 

expect to receive sufficient notification 

of malfunction events that result in 

violations in other required compliance 

reports as specified under 40 CFR 

63.11225. In addition, we have revised 

the 45-day affirmative defense reporting 

requirement that was included in 40 

CFR 63.11226(b) of the March 2011 final 

rule. This final rule requires sources to 

include the report in the first 

compliance, deviation or excess 

emission report due after the initial 

occurrence of the violation, unless the 

compliance, deviation or excess 

emission report is due less than 45 days 

after the violation. In that case, the 

affirmative defense report may be 

included in the second compliance, 

deviation or excess emission report due 

after the initial occurrence of the 

violation. Because the affirmative 

defense report is now included in a 

subsequent compliance, deviation or 

excess emission report, there is no 

longer a need for the 30-day extension 

for submitting a stand-alone affirmative 

defense report. Consequently, we are 

not including that provision in this final 

rule. 

L. 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. 

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, as applicable, 

that a copy of the energy assessment, 

records documenting the days of 

operation for each boiler that meets the 

definition of a seasonal boiler, and a 

copy of the federally enforceable permit 

for each boiler that meets the definition 

of a limited-use boiler must be 

maintained. 

We are revising 40 CFR 63.11225(d) to 

remove the requirement that the most 

recent 2 years of records be 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. 


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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. 

M. 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 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 a reason other 

than subpart JJJJJJ. For example, area 

source boilers could be major sources of 

non-HAP pollutants or could be located 

at sources that are subject to 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). 

N. 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 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. 

O. 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 IV of this preamble includes 

additional details regarding these 

miscellaneous technical corrections. 

P. 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 for tuneups 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 p.m. 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 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 p.m. 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 tune-up 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 


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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 March 2011 final rule based on the 

public comments received. Most of the 

changes are editorial to clarify 

applicability and implementation issues 

raised by the commenters. The public 

comments received on the proposed 

changes and the responses to them can 

be viewed in the memorandum 

‘‘Summary of Public Comments and 

Responses for: National Emission 

Standards for Hazardous Air Pollutants 

for Area Sources: Industrial, 

Commercial, and Institutional Boilers’’ 

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 gas-fired 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 gasfired, 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. However, 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, 

and that these units may want to burn 

oil in the future for reasons not allowed 

under subpart JJJJJJ’s definition of gasfired (e.g. cost). Under the March 2011 

final rule, such an existing dual-fuel 

gas-fired boiler 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 alternate fuel 

capability, then that source would not 

be commencing construction or making 

a change 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 altered 

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 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 oil-fired 

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 gasfired 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. 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 dualfuel 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,’’ as 

proposed, 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 proposed 

definition 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 


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historical buildings may be subdivided 

into more than four units but boilers 

serving those units should still be 

considered residential boilers. We agree 

and, in this final rule, are amending the 

proposed definition to clarify 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. 

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, as 

proposed, be revised to allow owners or 

operators to petition for an extension 

beyond 12 months. We agree with the 

commenter and, in this final rule, are 

amending the proposed definition 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 proposed 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 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 multiyear 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 proposed 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 semi-annual testing 

requirements would not meet the 

proposed 7 consecutive month 

shutdown criteria, but otherwise would 

be 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, in this final rule, are revising the 

proposed definition of seasonal boiler 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 proposed 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 tuneup cycle for limited-use units such as 

auxiliary boilers that we proposed for 

seasonally-operated units and small oilfired units. Commenters explained that 

in the electric 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 this final Area Source 

Boiler Rule. Specifically, a limited-use 

boiler is defined in this 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 capacityfactor 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 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. 

This final rule specifies that limiteduse 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 tune-ups 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 fulltime boilers will operate between tuneups. 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. Alternative PM Emission Control for 

Certain Oil-Fired Boilers 

The EPA received a number of 

comments urging that we provide an 

exemption from the PM limit for units 

burning low-sulfur liquid fuel as is 

provided in subpart Dc of 40 CFR part 

60 (standards of performance for new 

small industrial-commercialinstitutional steam generating units). 

Commenters asserted that such an 

exemption is justified since the low 

sulfur content indicates low PM 

emissions and that boilers firing lowsulfur liquid fuel should only be subject 

to a requirement to maintain records 

documenting the liquid fuel fired. We 

agree burning low-sulfur liquid fuel can 

be an alternative method of meeting 

GACT for PM. We are amending 40 CFR 


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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 

meet GACT for PM 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 this 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 tuneups. 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-tofuel ratio which is the purpose of a 

tune-up. 

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 tuneup. 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 

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, this 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 tune-up 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 this final rule. 

C. Energy Assessment 

The EPA received a number of 

comments regarding the energy 

assessment requirements and in this 

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 this 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, which could vary significantly 

depending on the site and its 

complexity, and not by a total 

aggregation of all individual energy 

using elements of a facility. 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 

paragraphs (1), (2), and (3) of this 

definition 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).’’ 

In this final rule, we are revising 40 

CFR 63.11201 and Table 2 to subpart 

JJJJJJ to allow a source that is operating 

under an energy management program 

established through energy management 

systems compatible with ISO 50001, 

that includes the affected boilers, by 

March 21, 2014, to satisfy the energy 

assessment requirement. In addition, we 

are clarifying that energy assessor 

approval and qualification requirements 

are waived in instances where an energy 

assessment completed on or after 

January 1, 2008 meets or is amended to 

meet the energy assessment 

requirements in this final rule by March 

21. 

The definition of ‘‘boiler system’’ is 

being revised in this final rule to clarify 

that it means the boiler and associated 

components directly connected to and 

serving the energy use systems. 

The definition of ‘‘energy use system’’ 

is also being revised in this final rule to 

clarify that energy use systems are only 

those on-site systems using energy 

clearly produced by affected boilers. 

D. Clarification of Oxygen 

Concentration Operating Limits 

We are clarifying in this 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, in this 

final rule, are revising the definitions 

accordingly. 

F. Fuel Sampling Frequency 

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 this 

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 


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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 

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 

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. 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 subject to 

applicable standards 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 this 

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 no steam and no 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 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 this 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 63.11225(g) 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 this final rule, we are revising some 

definitions and adding others to help 

affected sources determine their 

applicability. 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,’’ ‘‘Fluidized bed 

combustion,’’ ‘‘Hourly average,’’ 

‘‘Limited-use boiler,’’ ‘‘Load fraction,’’ 


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‘‘Minimum scrubber pressure drop,’’ 

‘‘Minimum sorbent injection rate,’’ 

‘‘Minimum total secondary electric 

power,’’ ‘‘Operating day,’’ ‘‘Oxygen 

analyzer system,’’ ‘‘Oxygen trim 

system,’’ ‘‘Process heater,’’ ‘‘Regulated 

gas stream,’’ ‘‘Residential boiler,’’ 

‘‘Residual oil,’’ ‘‘Seasonal boiler,’’ 

‘‘Shutdown,’’ ‘‘Solid fuel,’’ ‘‘Startup,’’ 

‘‘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 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 of five 

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 March 2011 final 

rule, and made appropriate revisions to 

the proposed rule after consideration of 

public comments received. It is well 

established that an agency may refine its 

proposed approach without providing 

an additional opportunity for public 

comment. See Community Nutrition 

Institute v. Block, 749 F.2d 50, 58 (DC 

Cir. 1984) and International Fabricare 

Institute v. EPA, 972 F.2d 384, 399 (DC 

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 (DC 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 (DC 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). 

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 

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 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 


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2Small 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 

Continued 

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 its 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, June 4, 2010). 

The petitioner raised this issue in its 

comments (Document ID: EPA–HQ– 

OAR–2006–0790–1982, Comments of 

Earthjustice, 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 

final 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 final amendments 

will not affect the estimated emission 

reductions, control costs or the benefits 

of the rule in substance. The 

amendments do not impose any 

additional regulatory requirements 

beyond those imposed by the previously 

promulgated boiler area source rule and, 

in fact, 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-tofuel ratio. Additionally, the burden will 

be reduced on facilities with existing 

large boilers that currently operate 

under an energy management program 

established through energy management 

systems compatible with ISO 50001, 

that includes the affected boilers, 

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, 

in lieu of needing to meet an emission 

limit, we consider low-sulfur oil 

combustion to be GACT for PM for those 

boilers. This change should allow 

sources currently complying with 40 

CFR 60 subpart Dc to use the same 

compliance approach rather than 

needing to monitor limits. 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) coalfired 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 limit for Hg. As 

explained in the December 2011 

proposal, we also revised our impacts 

analysis to be consistent with emission 

factor 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 Boiler Rule because of 

insufficient data for area sources. 

Emission factor changes resulted 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 is that the overall 

reduction in Hg emissions does not 

change significantly from the estimated 

reduction for the promulgated rule. 

In summary, as compared to the 

control costs estimated for the March 

2011 final rule, this final rule will not 

result in any meaningful change 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 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.2


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small organization that is any not-for-profit 

enterprise that is independently owned and 

operated and is not dominant in its field. 

The RFA also allows an agency to 

‘‘consider a series of closely related 

rules as one rule for the purposes of 

sections’’ 603 (initial regulatory 

flexibility analysis) and 604 (final 

regulatory flexibility analysis) in order 

to avoid ‘‘duplicative action.’’ 5 U.S.C. 

section 605(c). These amendments and 

notice of final action on reconsideration 

are closely related to the final Area 

Source Boiler 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 final 

Area Source Boiler Rule. Therefore, 

pursuant to section 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 Area Source 

Boiler Rule. The EPA conducted 

outreach to small entities and, pursuant 

to section 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 final 

Area Source Boiler 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 Area Source Boiler Rule, 

will not impose any additional 

regulatory requirements beyond those 

imposed by the previously promulgated 

Area Source Boiler 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 

costs on state or local governments, and 

will not preempt state law. Thus, 

Executive Order 13132 does not apply 

to this action. 

F. Executive Order 13175: Consultation 

and Coordination With Indian Tribal 

Governments 

This action does not have tribal 

implications, as specified in Executive 

Order 13175 (65 FR 67249, November 9, 

2000). It 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 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 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 


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publication of the rule in the Federal 

Register. A Major rule cannot take effect 

until 60 days after it is published in the 

Federal Register. This action is a 

reconsideration of a previous action that 

was a major rule under the CRA. 

However, today’s action makes only 

certain limited revisions to the March 

2011 rule and those revisions do not 

qualify as a major rule under the CRA. 

Therefore, this action is not a ‘‘major 

rule’’ as defined by 5 U.S.C. 804(2). This 

rule will be effective February 1, 2013. 

List of Subjects in 40 CFR Part 63 

Environmental protection, 

Administrative practice and procedure, 

Air pollution control, Hazardous 

substances, Incorporation by reference. 

Dated: December 20, 2012. 

Lisa P. Jackson, 

Administrator. 

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). 

The revisions and additions read as 

follows: 

§ 63.14 Incorporations by reference. 

* * * * * 

(b) * * * 

(19) ASTM D95–05 (Reapproved 

2010), Standard Test Method for Water 

in Petroleum Products and Bituminous 

Materials by Distillation, approved May 

1, 2010, IBR approved for § 63.10005(i) 

and table 6 to subpart DDDDD. 

* * * * * 

(23) ASTM D4006–11, Standard Test 

Method for Water in Crude Oil by 

Distillation, including Annex A1 and 

Appendix X1, approved June 1, 2011, 

IBR approved for § 63.10005(i) and table 

6 to subpart DDDDD. 

* * * * * 

(35) ASTM D6784–02 (Reapproved 

2008) Standard Test Method for 

Elemental, Oxidized, Particle-Bound 

and Total Mercury in Flue Gas 

Generated from Coal-Fired Stationary 

Sources (Ontario Hydro Method), 

approved April 1, 2008, IBR approved 

for table 1 to subpart DDDDD of this 

part, table 2 to subpart DDDDD of this 

part, table 5 to subpart DDDDD, table 11 

to subpart DDDDD of this part, table 12 

to subpart DDDDD of this part, table 13 

to subpart DDDDD of this part, and table 

4 to subpart JJJJJJ of this part. 

* * * * * 

(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 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. 

(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) * * * 

(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. 

(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, 


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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 (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 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. 

* * * * * 

■ 4. Section 63.11195 is amended by 

revising the introductory text and 

paragraphs (c) and (g) and by adding 

paragraphs (h) through (k) to read as 

follows: 

§ 63.11195 Are any boilers not subject to 

this subpart? 

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) and (d) to read 

as follows: 

§ 63.11196 What are my compliance 

dates? 

(a) * * * 

(1) If the existing affected boiler is 

subject to a work practice or 

management practice standard of a tuneup, you must achieve compliance with 

the work practice or management 

practice standard no later than March 

21, 2014. 

* * * * * 

(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. 

■ 6. Section 63.11200 is revised 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. 

(c) Oil. 

(d) Seasonal boilers. 

(e) Oil-fired boilers with heat input 

capacity of equal to or less than 5 

million British thermal units (Btu) per 

hour. 

(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. 

■ 7. 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 

established through energy management 

systems compatible with ISO 50001, 

that includes the affected units, also 

satisfies the energy assessment 

requirement. 

* * * * * 

(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. 

■ 8. Section 63.11205 is amended by 

revising paragraphs (b), (c) introductory 


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text, (c)(1) introductory text, 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 stack testing, fuel 

analysis, or a continuous monitoring 

system (CMS), including a continuous 

emission monitoring system (CEMS), a 

continuous opacity monitoring system 

(COMS), or a continuous parameter 

monitoring system (CPMS), where 

applicable. You may demonstrate 

compliance with the 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 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); 

* * * * * 

■ 9. Section 63.11210 is amended by 

revising paragraphs (b) through (e) and 

adding paragraphs (f) through (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 days 

after March 21, 2011 or within 180 days 

after startup of the source, whichever is 

later, according to § 63.7(a)(2)(ix). 

(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 tuneup, 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 

§ 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 

the existing major source becomes an 

area source, you must comply with the 

applicable provisions as specified in 

paragraphs (i)(1) through (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 upon the existing major source 

commencing operation as an area 

source. 

(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 


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later than the compliance date specified 

in § 63.11196. 

■ 10. 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) * * * 

(1) For a wet scrubber, you must 

establish the minimum scrubber liquid 

flow rate and minimum scrubber 

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 scrubber 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 total secondary 

electric power (secondary voltage and 

secondary current), as defined in 

§ 63.11237, as your operating limits 

during the three-run performance stack 

test. 

* * * * * 

■ 11. 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 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 FFactor 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 per 

million Btu heat input emission rates. 

■ 12. 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 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. 

* * * * * 

■ 13. Section 63.11220 is revised 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 million British thermal 

units per hour 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 in 

paragraphs (c)(1) and (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 and more 

than 3 years have passed 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. 

■ 14. Section 63.11221 is revised to read 

as follows: 

§ 63.11221 Is there a minimum amount of 

monitoring data I must obtain? 

(a) You must monitor and collect data 

according to this section and the sitespecific 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 


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adjustments, and scheduled CMS 

maintenance as defined in your sitespecific monitoring plan. A monitoring 

system malfunction is any sudden, 

infrequent, not reasonably preventable 

failure of the monitoring system to 

provide valid data. Monitoring system 

failures that are caused in part by poor 

maintenance or careless operation are 

not malfunctions. You are required to 

complete monitoring system repairs in 

response to monitoring system 

malfunctions or out-of-control periods 

and to return the monitoring system to 

operation as expeditiously as 

practicable. 

(c) You may not use data collected 

during monitoring system malfunctions 

or out-of-control periods, repairs 

associated with monitoring system 

malfunctions or out-of-control periods, 

or required monitoring system quality 

assurance or 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 outof-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), 

failure to collect required data is a 

deviation of the monitoring 

requirements. 

■ 15. Section 63.11223 is amended by 

revising paragraphs (a), (b) introductory 

text, (b)(1), (b)(3) through (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 

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, not to exceed 

36 months from the previous 

inspection). 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 next scheduled unit 

shutdown, not to exceed 36 months 

from the previous inspection). 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 on-site 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 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 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 tuneup 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 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. 

(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 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 

million Btu per hour 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 million Btu per hour, 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 


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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. 

(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 

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. 

■ 16. Section 63.11224 is amended by: 

■ a. Revising paragraphs (a) 

introductory text, (a)(1) through (3), 

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

■ b. Adding paragraph (a)(7). 

■ c. Revising paragraphs (c)(1) 

introductory text, (c)(2) introductory 

text, and (d). 

■ d. Revising paragraphs (e) 

introductory text, (e)(6), and (e)(7). 

■ e. Adding paragraph (e)(8). 

■ f. Revising paragraph (f)(7). 

The revisions and additions 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, calibrate, operate, and 

maintain an oxygen analyzer system, as 

defined in § 63.11237, according to the 

manufacturer’s recommendations and 

paragraphs (a)(7) and (d) of this section, 

as applicable, 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 

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 site-specific 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 

(sampling, analyzing, and data 

recording) every 15 minutes. You must 

have CEMS data values from a 

minimum of four successive cycles of 

operation representing each of the four 

15-minute periods in an hour, or at least 

two 15-minute data values during an 

hour when CEMS calibration, quality 

assurance, or maintenance activities are 

being performed, to have a valid hour of 

data. 

* * * * * 

(5) You must calculate hourly 

averages, corrected to 3 percent oxygen, 

from each hour of CO CEMS data in 

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 

hourly averages collected for the 10-day 

operating period using Equation 2 of 

this section. 

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 oxygen level that is 

established as the operating limit 

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. 

* * * * * 

(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. 

* * * * * 


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(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 data 

values from a minimum of four 

successive cycles of operation 

representing each of the four 15-minute 

periods in an hour, or at least two 15- 

minute data values during an hour 

when CMS calibration, quality 

assurance, or maintenance activities are 

being performed, to have a valid hour of 

data. 

(2) You must calculate hourly 

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 average from all of the 

hourly averages collected for the 30-day 

operating period using Equation 3 of 

this section. 

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 § 63.8(e). You 

must identify periods the COMS is out 

of control including any periods that the 

COMS fails to pass a daily calibration 

drift assessment, a quarterly 

performance audit, or an annual zero 

alignment audit. 

(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. 

* * * * * 

■ 17. Section 63.11225 is amended by: 

■ a. Revising paragraphs (a) 

introductory text, (a)(1), (a)(2), (a)(4), 

(a)(5), (b) introductory text, (b)(2), (c) 

introductory text, (c)(2) introductory 

text, and (c)(2)(ii). 

■ b. Adding paragraphs (c)(2)(iii) 

through (vi). 

■ c. Revising paragraphs (d), (e), and (g). 

The revisions and additions 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 

(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 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 (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 


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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. 

* * * * * 

(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(g) 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. 

* * * * * 

(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 nonhazardous secondary materials as fuel 

per § 241.4, you must keep records 

documenting that the material is a listed 

non-waste under § 241.4(a). 

(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 limited-use 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 on-site 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. 

(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 Web site 

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 CBI, to the delegated 

authority in the format specified by the 

delegated authority. For any 

performance test conducted using test 

methods that are not listed on the ERT 

Web site, 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 Web site) 

are subject to this requirement. For any 

performance evaluations with no 

corresponding RATA pollutants listed 

on the ERT Web site, 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 


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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 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. 

18. Section 63.11226 is revised 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 40 CFR 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) Assertion of affirmative defense. 

To establish the affirmative defense in 

any action to enforce such a standard, 

you must timely meet the reporting 

requirements in paragraph (b) of this 

section, and must prove by a 

preponderance of evidence that: 

(1) The violation: 

(i) Was caused by a sudden, 

infrequent, and unavoidable failure of 

air pollution control equipment, process 

equipment, or a process to operate in a 

normal or usual manner; and 

(ii) Could not have been prevented 

through careful planning, proper design 

or better operation and maintenance 

practices; and 

(iii) Did not stem from any activity or 

event that could have been foreseen and 

avoided, or planned for; and 

(iv) Was not part of a recurring pattern 

indicative of inadequate design, 

operation, or maintenance; and 

(2) Repairs were made as 

expeditiously as possible when a 

violation occurred; and 

(3) The frequency, amount, and 

duration of the violation (including any 

bypass) were minimized to the 

maximum extent practicable; and 

(4) If the violation resulted from a 

bypass of control equipment or a 

process, then the bypass was 

unavoidable to prevent loss of life, 

personal injury, or severe property 

damage; and 

(5) All possible steps were taken to 

minimize the impact of the violation on 

ambient air quality, the environment, 

and human health; and 

(6) All emissions monitoring and 

control systems were kept in operation 

if at all possible, consistent with safety 

and good air pollution control practices; 

and 

(7) All of the actions in response to 

the violation were documented by 

properly signed, contemporaneous 

operating logs; and 

(8) At all times, the affected source 

was operated in a manner consistent 

with good practices for minimizing 

emissions; and 

(9) A written root cause analysis has 

been prepared, the purpose of which is 

to determine, correct, and eliminate the 

primary causes of the malfunction and 

the violation resulting from the 

malfunction event at issue. The analysis 

shall also specify, using best monitoring 

methods and engineering judgment, the 

amount of any emissions that were the 

result of the malfunction. 

(b) Report. The owner or operator 

seeking to assert an affirmative defense 

shall submit a written report to the 

Administrator with all necessary 

supporting documentation, that it has 

met the requirements set forth in 

paragraph (a) of this section. This 

affirmative defense report shall be 

included in the first periodic 

compliance, deviation report or excess 

emission report otherwise required after 

the initial occurrence of the violation of 

the relevant standard (which may be the 

end of any applicable averaging period). 

If such compliance, deviation report or 

excess emission report is due less than 

45 days after the initial occurrence of 

the violation, the affirmative defense 

report may be included in the second 

compliance, deviation report or excess 

emission report due after the initial 

occurrence of the violation of the 

relevant standard. 

■ 19. 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. 

* * * * * 

■ 20. Section 63.11237 is amended as 

follows: 

■ a. By adding 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,’’ ‘‘Regulated gas stream,’’ 

‘‘Residential boiler,’’ ‘‘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,’’ ‘‘Gasfired 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,’’ ‘‘Solid 

fossil fuel,’’ and ‘‘Waste heat boiler.’’ 

■ c. By removing 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. 

* * * * * 


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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. 

Biodiesel means a mono-alkyl 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 the 

definition of Boiler. 

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. 

* * * * * 

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 a.m. (midnight) to 12 a.m. 

(midnight), except for periods of startup 

and shutdown and periods when the 

unit is not operating. 

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. 

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 a generator that 

produces electricity for sale. A fossil 

fuel-fired unit that cogenerates steam 

and electricity and supplies more than 

one-third of its potential electric output 

capacity and more than 25 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 onsite 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: 

(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 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 


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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 paragraphs (1), (2), and (3) 

of this definition may be segmented by 

production area or energy use area as 

most logical and applicable to the 

specific facility being assessed (e.g., 

product X manufacturing area; product 

Y drying area; Building Z). 

Energy management program means a 

program that includes a set of practices 

and procedures designed to manage 

energy use that are demonstrated by the 

facility’s energy policies, a facility 

energy manager and other staffing 

responsibilities, energy performance 

measurement and tracking methods, an 

energy saving goal, action plans, 

operating procedures, internal reporting 

requirements, and periodic review 

intervals used at the facility. Facilities 

may establish their program through 

energy management systems compatible 

with ISO 50001. 

Energy use system (1) 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. 

(2) 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. 

* * * * * 

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. 

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 million Btu per 

hour heat input capacity threshold for 

hot water boilers. Hot water heater also 

means a tankless unit that provides ondemand hot water. 

Hourly average means the arithmetic 

average of at least four CMS data values 

representing the four 15-minute periods 

in an hour, or at least two 15-minute 

data values during an hour when CMS 

calibration, quality assurance, or 

maintenance activities are being 

performed. 

* * * * * 

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). 

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 limit. 

Minimum oxygen level means the 

lowest hourly average oxygen level 

measured according to Table 6 to this 

subpart during the most recent 

performance stack test demonstrating 

compliance with the applicable carbon 

monoxide emission limit. 

Minimum scrubber liquid flow rate 

means the lowest hourly average 

scrubber liquid flow rate (e.g., to the 

particulate matter 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 

(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 


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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 (i.e., a temperature of 288 

Kelvin, a relative humidity of 60 

percent, and a pressure of 101.3 

kilopascals). Additionally, natural gas 

must either be composed of at least 70 

percent methane by volume or have a 

gross calorific value between 35 and 41 

megajoules (MJ) per dry standard cubic 

meter (950 and 1,100 Btu per dry 

standard cubic foot); or 

(4) Propane or propane-derived 

synthetic natural gas. Propane means a 

colorless gas derived from petroleum 

and natural gas, with the molecular 

structure C3H8. 

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. 

Oxygen trim system means a system of 

monitors that is used to maintain excess 

air at the desired level in a combustion 

device. A typical system consists of a 

flue gas oxygen and/or carbon monoxide 

monitor that automatically provides a 

feedback signal to the combustion air 

controller. 

Particulate matter (PM) means any 

finely divided solid or liquid material, 

other than uncombined water, as 

measured by the test methods specified 

under this subpart, or an approved 

alternative method. 

* * * * * 

Period of gas curtailment or supply 

interruption means a period of time 

during which the supply of gaseous fuel 

to an affected 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. Onsite 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 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: 

(1) Someone who has demonstrated 

capabilities to evaluate energy savings 

opportunities for steam generation and 

major energy using systems, including, 

but not limited to: 

(i) Boiler combustion management. 

(ii) Boiler thermal energy recovery, 

including 

(A) Conventional feed water 

economizer, 

(B) Conventional combustion air 

preheater, and 

(C) Condensing economizer. 

(iii) Boiler blowdown thermal energy 

recovery. 

(iv) Primary energy resource selection, 

including 

(A) Fuel (primary energy source) 

switching, and 

(B) Applied steam energy versus 

direct-fired energy versus electricity. 

(v) Insulation issues. 

(vi) Steam trap and steam leak 

management. 

(vii) Condensate recovery. 

(viii) Steam end-use management. 

(2) Capabilities and knowledge 

includes, but is not limited to: 

(i) Background, experience, and 

recognized abilities to perform the 

assessment activities, data analysis, and 

report preparation. 

(ii) Familiarity with operating and 

maintenance practices for steam or 

process heating systems. 

(iii) Additional potential steam 

system improvement opportunities 

including improving steam turbine 

operations and reducing steam demand. 

(iv) Additional process heating system 

opportunities including effective 

utilization of waste heat and use of 

proper process heating methods. 

(v) Boiler-steam turbine cogeneration 

systems. 

(vi) Industry specific steam end-use 

systems. 

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: 

(1) A dwelling containing four or 

fewer families, or 

(2) A single unit residence dwelling 

that has since been converted or 

subdivided into condominiums or 

apartments. 

Residual oil means crude oil, fuel oil 

that does not comply with the 

specifications under the definition of 

distillate oil, and all fuel oil numbers 4, 

5, and 6, as defined by the American 

Society of Testing and Materials in 

ASTM D396–10 (incorporated by 

reference, see § 63.14(b)). 

* * * * * 

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 no steam and no 

heat being supplied and no fuel being 

fired in the boiler. 

Solid fossil fuel includes, but is not 

limited to, coal, coke, petroleum coke, 

and tire-derived fuel. 


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Federal Register / Vol. 78, No. 22 / Friday, February 1, 2013 / Rules and Regulations 7517 

Solid fuel means any solid fossil fuel 

or biomass or bio-based 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 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–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 VoieCreuse, 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 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. 

* * * * * 

■ 21. Table 1 to subpart JJJJJJ is revised 

to read as follows: 

As stated in § 63.11201, you must 

comply with the following applicable 

emission limits: 

TABLE 1 TO SUBPART JJJJJJ OF PART 63—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 

million British thermal units per hour (MMBtu/hr) or 

greater that do not meet the definition of limited-use 

boiler.

a. PM (Filterable) ................

b. Mercury 

c. CO 

3.0E–02 pounds(lb) per million British thermal units 

(MMBtu) of heat input. 

2.2E–05 lb per MMBtu of heat input. 

420 parts per million (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) ................

b. Mercury 

c. CO 

4.2E–01 lb per MMBtu of heat input. 

2.2E–05 lb per MMBtu of heat input. 

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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7518 Federal Register / Vol. 78, No. 22 / Friday, February 1, 2013 / Rules and Regulations 

TABLE 1 TO SUBPART JJJJJJ OF PART 63—EMISSION LIMITS—Continued 

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 biomass-fired boilers with heat input capacity of 

30 MMBtu/hr or greater that do not meet the definition 

of seasonal boiler or limited-use boiler.

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.

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.

PM (Filterable) .................... 3.0E–02 lb per MMBtu of heat input. 

6. Existing coal-fired boilers with heat input capacity of 

10 MMBtu/hr or greater that do not meet the definition 

of limited-use boiler.

a. Mercury ..........................

b. CO 

2.2E–05 lb per MMBtu of heat input. 

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

■ 22. Table 2 to subpart JJJJJJ is revised 

to read as follows: 

As stated in § 63.11201, you must 

comply with the following applicable 

work practice standards, emission 

reduction measures, and management 

practices: 

TABLE 2 TO SUBPART JJJJJJ OF PART 63—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. 

2. Existing coal-fired boilers with heat input capacity of less than 10 MMBtu/hr that do not 

meet the definition of 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. 

3. New coal-fired boilers with heat input capacity of less than 10 MMBtu/hr that do not meet 

the definition of 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. 

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. 

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 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 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 limited-use 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. 

11. New limited-use boilers ................................ Conduct a tune-up of the boiler every 5 years as specified in § 63.11223. 

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. 


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Federal Register / Vol. 78, No. 22 / Friday, February 1, 2013 / Rules and Regulations 7519 

TABLE 2 TO SUBPART JJJJJJ OF PART 63—WORK PRACTICE STANDARDS, EMISSION REDUCTION MEASURES, AND

MANAGEMENT PRACTICES—Continued 

If your boiler is in this subcategory . . . You must meet the following . . . 

14. Existing coal-fired, 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 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 a tune-up of the boiler every 5 years as specified in § 63.11223. 

16. Existing coal-fired, 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. 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 assessment requirements. A facility that operates under an energy management program compatible with 

ISO 50001 that includes the affected units also satisfies the energy assessment requirement. The energy assessment must include the following with extent of the evaluation for 

items (1) to (4) appropriate for the on-site technical hours listed in § 63.11237: 

(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. 

■ 23.Table 3 to subpart JJJJJJ is revised 

to read as follows: 

As stated in § 63.11201, you must 

comply with the applicable operating 

limits: 

TABLE 3 TO SUBPART JJJJJJ OF PART 63—OPERATING LIMITS FOR BOILERS WITH EMISSION LIMITS

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 of the electrostatic precipitator at or above the minimum total secondary electric power as defined in § 63.11237. 

3. Wet scrubber control ...................................... Maintain the 30-day rolling average pressure drop across the wet scrubber at or above the 

minimum scrubber pressure drop as defined in § 63.11237 and the 30-day rolling average 

liquid flow rate at or above the minimum scrubber liquid flow rate as defined in § 63.11237. 

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 as defined in 

§ 63.11237. When 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 

the 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 rate 

calculated according to § 63.11211(c) are less than the applicable emission limit 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 it 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 as defined in § 63.11237. This requirement does not 

apply to units that install an oxygen trim system since these units will set the trim system to 

the level specified in § 63.11224(a)(7). 


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7520 Federal Register / Vol. 78, No. 22 / Friday, February 1, 2013 / Rules and Regulations 

* * * * * ■ 24. Table 6 to subpart JJJJJJ is revised 

to read as follows: 

As stated in § 63.11211, you must 

comply with the following requirements 

for establishing operating limits: 

TABLE 6 TO SUBPART JJJJJJ OF PART 63—ESTABLISHING OPERATING LIMITS

If you have an applicable emission 

limit for . . . 

And your operating limits are 

based on . . . 

You must . . . Using . . . According to the following requirements 

1. PM or mercury .. a. Wet scrubber 

operating parameters.

Establish site-specific minimum scrubber pressure 

drop and minimum scrubber liquid flow rate operating limits according to 

§ 63.11211(b).

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; 

(b) Determine the average pressure drop 

and liquid flow rate for each individual 

test run in the three-run performance 

stack test by computing the average of 

all the 15-minute readings taken during 

each test run. 

b. Electrostatic 

precipitator operating parameters.

Establish a site-specific 

minimum total secondary 

electric power operating 

limit according to 

§ 63.11211(b).

Data from the secondary 

electric power monitors 

and the PM or mercury 

performance stack tests.

(a) You must collect secondary electric 

power data every 15 minutes during 

the entire period of the performance 

stack tests; 

(b) Determine the average total secondary electric power for each individual test run in the three-run performance stack test by computing the average of all the 15-minute readings taken 

during each test run. 

2. Mercury ............. Dry sorbent or activated carbon 

injection rate 

operating parameters.

Establish a site-specific 

minimum sorbent or activated carbon injection 

rate operating limit according to § 63.11211(b).

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; 

(b) Determine the average sorbent or activated carbon injection rate for each 

individual test run in the three-run performance stack test by computing the 

average of all the 15-minute readings 

taken during each test run. 

(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. 

3. CO ..................... Oxygen ............... Establish a unit-specific 

limit for minimum oxygen 

level.

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 

concentration for each individual test 

run in the three-run performance stack 

test by computing the average of all 

the 15-minute readings taken during 

each test run. 

4. Any pollutant for 

which compliance is demonstrated by a 

performance 

stack test.

Boiler operating 

load.

Establish a unit-specific 

limit for maximum operating load according to 

§ 63.11212(c).

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 

percent) as your operating limit. 


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Federal Register / Vol. 78, No. 22 / Friday, February 1, 2013 / Rules and Regulations 7521 

■ 25. Table 7 to subpart JJJJJJ is revised 

to read as follows: 

As stated in § 63.11222, you must 

show continuous compliance with the 

emission limitations for each boiler 

according to the following: 

TABLE 7 TO SUBPART JJJJJJ OF PART 63—DEMONSTRATING CONTINUOUS COMPLIANCE

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 

minimum pressure drop and minimum liquid flow rate 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 

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.

a. Collecting the total secondary electric power 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 at or above the minimum total secondary electric power 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 monitoring the oxygen content of flue gas according to § 63.11224 (This requirement does not apply to units that install an oxygen trim system since these units will 

set the trim system to the level specified in § 63.11224(a)(7)); and 

b. Reducing the data to 30-day rolling averages; and 

c. Maintaining the 30-day rolling average oxygen content at or above the minimum oxygen 

level established during the most recent CO performance test. 

8. CO emissions ................................................. a. Continuously monitoring the CO concentration in the combustion exhaust according to 

§§ 63.11224 and 63.11221; and 

b. Correcting the data to 3 percent oxygen, and reducing the data to 1-hour averages; and 

c. Reducing the data from the hourly averages to 10-day rolling averages; and 

d. Maintaining the 10-day rolling average CO concentration at or below the applicable emission limit in Table 1 to this subpart. 

9. Boiler operating load ...................................... a. Collecting operating load data (fuel feed rate or steam generation data) every 15 minutes; 

and 

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) and Table 6 to this subpart. 

■ 26. Table 8 to subpart JJJJJJ is amended 

by: 

■ a. Revising the entry for ‘‘§ 63.9’’. 

■ b. Revising the entry for ‘‘§ 63.10(e) 

and (f)’’. 

■ c. Adding an entry for ‘‘§ 63.10(f)’’. 

The revisions read as follows: 

* * * * * 


sroberts on DSK5SPTVN1PROD with RULES
7522 Federal Register / Vol. 78, No. 22 / Friday, February 1, 2013 / Rules and Regulations 

TABLE 8 TO SUBPART JJJJJJ OF PART 63—APPLICABILITY OF GENERAL PROVISIONS TO SUBPART JJJJJJ 

General 

provisions cite Subject Does it apply? 

*******

§ 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(e) ............................ Additional reporting requirements for sources with CMS Yes. 

§ 63.10(f) ............................. Waiver of recordkeeping or reporting requirements ....... Yes. 

* * * * * * * 

[FR Doc. 2012–31645 Filed 1–31–13; 8:45 am] 

BILLING CODE 6560–50–P 


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