*** E.O. 12866 Review – Do Not Cite, Quote or Release During 

Review***

EO12866 NESHAP AS-Industrial Commercial Institutional Boiler RIN 

2060-AR14 Proposed Rule – Reconsideration 20111128

6560-50-P

ENVIRONMENTAL PROTECTION AGENCY

40 CFR Part 63

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

RIN 2060-AR14

National Emission Standards for Hazardous Air Pollutants for 

Area Sources: Industrial, Commercial, and Institutional Boilers

AGENCY: Environmental Protection Agency (EPA).

ACTION: Proposed rule; Reconsideration of final rule.

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

emission standards for the control of hazardous air pollutants 

from two area source categories: industrial boilers, and 

commercial and institutional boilers. On that same date, the EPA 

announced that it was convening a proceeding for reconsideration 

of certain portions of those final emission standards. After 

promulgation, the Administrator received petitions for 

reconsideration of certain provisions in the final rule. In this 

action, the EPA is proposing for reconsideration specific 

elements and accepting public comment on those elements. We are 

not requesting comment on any other provisions of the final 

rule.

In this action, the EPA is proposing a limited number of 

amendments to the final rule. In addition, the EPA is proposing 
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amendments and technical corrections to the final rule to 

clarify some applicability and implementation issues raised by 

stakeholders subject to the final rule.

DATES: Comments. Comments must be received on or before

[INSERT THE DATE 45 DAYS AFTER DATE OF PUBLICATION IN THE 

FEDERAL REGISTER].

Public Hearing. If anyone contacts the EPA requesting to speak 

at a public hearing by [INSERT THE DATE 10 DAYS AFTER DATE OF

PUBLICATION IN THE FEDERAL REGISTER], a public hearing will be 

held on [INSERT THE DATE 15 DAYS AFTER DATE OF PUBLICATION IN 

THE FEDERAL REGISTER]. For further information on the public 

hearing and requests to speak, contact Ms. Pamela Garrett at 

(919) 541–7966 to verify that a hearing will be held. If a

public hearing is held, it will be held at 10 a.m. at the EPA’s

Environmental Research Center Auditorium, Research Triangle 

Park, North Carolina, or an alternate site nearby.

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

EPA-HQ-OAR-2006-0790, by one of the following methods: 

 www.regulations.gov: Follow the on-line instructions for 

submitting comments.

 E-mail: a-and-r-Docket@epa.gov, Attention Docket ID No. 

EPA-HQ-OAR-2006-0790. 

 Fax: (202) 566-9744, Attention Docket ID No. EPA-HQ-OAR2006-0790.
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 Mail: U.S. Postal Service, send comments to: Air and 

Radiation Docket and Information Center, Environmental 

Protection Agency, Mailcode: 2822T, 1200 Pennsylvania Ave., 

NW, Washington, DC 20460, Attention Docket ID No. EPA-HQOAR-2006-0790. 

 Hand Delivery: In person or by Courier, deliver comments 

to: EPA Docket Center (2822T), Room 3334, 1301 Constitution 

Ave., NW, Washington, DC 20004. Such deliveries are only 

accepted during the Docket’s normal hours of operation, and 

special arrangements should be made for deliveries of boxed 

information.

Instructions: Direct your comments to Docket ID No. EPA-HQ-OAR2006-0790. The EPA’s policy is that all comments received will 

be included in the public docket without change and may be made 

available online at www.regulations.gov, including any personal 

information provided, unless the comment includes information 

claimed to be confidential business information (CBI) or other 

information whose disclosure is restricted by statute. Do not 

submit information that you consider to be CBI or otherwise 

protected through www.regulations.gov or e-mail. The 

www.regulations.gov website is an “anonymous access” system, 

which means the EPA will not know your identity or contact 

information unless you provide it in the body of your comment. 

If you send an e-mail comment directly to the EPA without going 

through www.regulations.gov, your e-mail address will be 

automatically captured and included as part of the comment that 

is placed in the public docket and made available on the 

Internet. If you submit an electronic comment, the EPA 
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recommends that you include your name and other contact 

information in the body of your comment and with any disk or CDROM you submit. If the EPA cannot read your comment due to 

technical difficulties and cannot contact you for clarification, 

the EPA may not be able to consider your comment. Electronic 

files should avoid the use of special characters, any form of 

encryption, and be free of any defects or viruses. For 

additional information about the EPA’s public docket, visit the 

EPA Docket Center homepage at 

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

Docket: All documents in the docket are listed in the 

www.regulations.gov index. Although listed in the index, some 

information is not publicly available, e.g., CBI or other 

information whose disclosure is restricted by statute. Certain 

other material, such as copyrighted material, will be publicly 

available only in hard copy. Publicly available docket materials 

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

hard copy at the EPA Docket Center, EPA West Building, Room 

3334, 1301 Constitution Ave., NW, Washington, DC. The Public 

Reading Room is open from 8:30 a.m. to 4:30 p.m., Monday through 

Friday, excluding legal holidays. The telephone number for the 

Public Reading Room is (202) 566-1744, and the telephone number 

for the Docket Center is (202) 566-1742.
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FOR FURTHER INFORMATION CONTACT: Mr. James Eddinger, 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) 541-5426; fax number: 

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

SUPPLEMENTARY INFORMATION:

Organization of this Document. The following outline is 

provided to aid in locating information in this preamble. 

I. General Information

A. Does this notice of reconsideration apply to me?

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

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

 information?

II. Background Information

III. Actions We Are Taking

IV. Discussion of Issues for Reconsideration

A. Subcategory for Seasonally Operated Boilers

B. Exemption for Temporary Boilers

C. Initial Compliance Schedule for Existing Boilers

D. Definition of Natural Gas Curtailment

E. Monitoring Carbon Monoxide Emissions

F. Averaging Times

G. Affirmative Defense Language 

H. Tune-up Work Practices

I. Using the Upper Prediction Limit (UPL) for Setting Carbon 

Monoxide Emission Limits

J. Establishing GACT Emission Limits for Biomass and Oil-Fired 

Boilers

K. Energy Assessment

L. Setting PM Standards Under Generally Available Control 

Technology for Oil-Fired Area Source Boilers.

M. Title V Permitting Requirements

V. Technical Corrections and Clarifications

A. Electric and Residential Boilers

B. Establishing Operating Limits for Wet Scrubbers.
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C. Timing of Subsequent Performance Tests

D. Demonstrating Initial Compliance

E. Demonstrating Compliance with the Work Practice and 

Management Practice Standards

F. Monitoring Requirements

G. Notification, Recordkeeping, and Reporting Requirements

H. Definitions

I. Change to the Mercury Emission Limit for New Coal-Fired 

Boilers.

J. Changes to the Work Practice Standards, Emission Reduction 

Measures, and Management Practices

K. Requirements for Establishing Operating Limits 

L. Demonstrating Continuous Compliance.

VI. What are the impacts associated with the amendments?

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

I. General Information

A. Does this notice of reconsideration apply to me?

The regulated categories and entities potentially affected 

by this action include:
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Industry 

Category

NAICS 

Code1

Examples of Regulated Entities

Any area 

source 

facility 

using a 

boiler as 

defined in 

the final

rule

321 Wood product manufacturing.

11 Agriculture, greenhouses.

311 Food manufacturing.

327 Nonmetallic mineral product

manufacturing.

424 Wholesale trade, nondurable

goods.

531 Real estate.

611 Educational services.

813 Religious, civic, professional,

and similar organizations.

92 Public administration.

722 Food services and drinking

places.

62

22111

Health care and social assistance.

Electric power generation

1 North American Industry Classification System.

This table is not intended to be exhaustive, but rather 

provides a guide for readers regarding entities likely to be 

regulated by this reconsideration action. To determine whether 

your facility may be affected by this reconsideration action, 

you should examine the applicability criteria in 40 CFR 63.11193

of subpart JJJJJJ (National Emission Standards for Hazardous Air 

Pollutants for Industrial, Commercial, and Institutional Boilers 

Area Sources). If you have any questions regarding the 

applicability of the final rule to a particular entity, consult 
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either the air permit authority for the entity or your EPA 

regional representative, as listed in 40 CFR 63.13.

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

Submitting CBI. Do not submit information that you 

consider to be CBI electronically through 

http://www.regulations.gov or E-mail. Send or deliver 

information identified as CBI to only the following address: Mr. 

James Eddinger, c/o OAQPS Document Control Officer (Room C404-

02), U.S. Environmental Protection Agency, Research Triangle 

Park, North Carolina 27711, Attn: Docket ID No. EPA-HQ-OAR2006-0790. 

Clearly mark the part or all of the information that you 

claim to be CBI. For CBI information in a disk or CD-ROM that 

you mail to the EPA, mark the outside of the disk or CD-ROM as 

CBI and then identify electronically within the disk or CD-ROM 

the specific information that is claimed as CBI. In addition to 

one complete version of the comment that includes information 

claimed as CBI, a copy of the comment that does not contain the 

information claimed as CBI must be submitted for inclusion in 

the public docket. If you submit a disk or CD-ROM that does not 

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

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

disclosed except in accordance with procedures set forth in 40 
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CFR part 2.

If you have any questions about CBI or the procedures for 

claiming CBI, please consult the person identified in the FOR 

FURTHER INFORMATION CONTACT section.

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

information?

Docket. The docket number for this action and the final 

rule (40 CFR part 63, subpart JJJJJJ) is Docket ID No. EPA-HQOAR-2006-0790. 

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

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

the WWW through the Technology Transfer Network (TTN) web site. 

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

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

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

information and technology exchange in various areas of air 

pollution control. 

II. Background Information

Section 112(d) of the Clean Air Act (CAA) requires the EPA 

to establish national emission standards for hazardous air 

pollutants (NESHAP) for both major and area sources of hazardous 

air pollutants (HAP) that are listed for regulation under CAA 

section 112(c). A major source is any stationary source that 
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emits or has the potential to emit 10 tons per year (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), we 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 
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practices by such sources to reduce emissions of hazardous air 

pollutants.”

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

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

that the EPA list categories and subcategories of sources

assuring that sources accounting for not less than 90 percent of 

the aggregate emissions of each of seven specified HAP are 

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

which require the application of the more stringent MACT. The 

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

Alkylated lead compounds, polycyclic organic matter (POM) as 7-

polynuclear aromatic hydrocarbons (PAH), hexachlorobenzene, 

mercury, polychlorinated biphenyls (PCBs), 2,3,7,8-

tetrachlorodibenzofurans, and 2,3,7,8-tetrachlorodibenzo-pdioxin.

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

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

commercial/institutional boilers combusting coal under CAA 

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

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

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

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

mercury and POM. We promulgated final standards for coal-fired 
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area source boilers to reflect the application of MACT for

mercury and POM, and to reflect GACT for the urban HAP other 

than mercury and POM. 

We listed industrial and commercial/institutional boilers 

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

contribution of mercury, 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). In that notice, we announced that we would 

identify specific elements of this rule for which we believe 

further public comment is appropriate. We also announced that we 

would develop proposals to modify certain provisions after more 

fully evaluating the data and comments received in response to 

the original proposed area source rule published on June 4, 2010 

(75 FR 31896). Finally, we recognized that certain issues of

central relevance to these rules arose after the period for 

public comment or may have been impracticable to comment upon. 

Therefore, we concluded that reconsideration was appropriate

under section 307(d)(7)(B) of the CAA. Although we took final
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action and promulgated the area source boiler rule, and believe 

that the final rule reflects reasonable approaches consistent 

with the requirements of the CAA, some of the issues identified 

in the comments raised difficult technical issues that we 

believe may benefit from additional public involvement.

In the March 21, 2011 notice, we identified the following 

issues affecting area source boilers as being appropriate and 

consistent with the requirements of the Act, but for which we 

believe reconsideration and additional opportunity for public 

review and comment should be obtained:

 Establishment of standards for biomass and oil-fired area 

source boilers based on generally available control

technology.

 Providing an affirmative defense for malfunction events for 

area source boilers.

The following additional issues concern actions taken in 

the final rule for which we believe reconsideration under 

section 307(d) and, potentially, further revisions may be 

warranted because they involve issues of central relevance that 

arose after the period for public comment or may have been

impracticable to comment upon:

 Setting PM standards under generally available control 

technology for oil-fired area source boilers.

 Certain findings regarding the applicability of Title V 

permitting requirements for area source boilers.
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Additional information concerning issues and concerns 

presented by commenters can be found in Docket No. EPA-HQ-OAR2006-0790 for the final area source boiler rule under

reconsideration in today’s notice.

III. Actions We Are Taking

In this notice, we are requesting comment on the four 

issues listed in section II of this preamble, which were 

identified in the March 21, 2011 notice, and we are also 

convening reconsideration of, and requesting comment on, certain

issues raised by Petitioners in their petitions for 

reconsideration. Section IV of this preamble summarizes these

issues and discusses our proposed responses to each issue. 

We are also proposing technical corrections to correct 

inaccuracies and inadvertent oversights promulgated in the final 

rule. We are also proposing several amendments to clarify some 

applicability and implementation issues raised by stakeholders 

subject to the final rule. Section V of this preamble describes 

these corrections and amendments and provides the rationale for 

these corrections and amendments. These proposed changes, if 

finalized, would for example:

 Clarify certain regulatory requirements, such as whether 

compliance is based on a value calculated as a block 

average from recorded data.
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 Provide greater flexibility to certain facilities for which 

the current compliance requirements are impractical, such 

as increasing the time between tune-ups for seasonally 

operated boilers.

 Correct certain rule drafting or printing errors, such as 

correcting cross references among rule sections, removing 

paragraphs that are no longer relevant, or correcting the 

placement of text in a table.

We are seeking public comment only on the issues 

specifically identified in this notice. We will not respond to 

any comments addressing other aspects of the final rule or any 

other related rulemakings.

IV. Discussion of Issues for Reconsideration 

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

our proposed responses to the issues identified in the petitions

for reconsideration. We solicit comment on all proposed 

responses and revisions discussed in the following sections.

A. Subcategory for Seasonally Operated Boilers

We are proposing to create a new subcategory for seasonally 

operated boilers. For these seasonally operated boilers, we are 

proposing to amend 40 CFR 63.11223 to specify, after an initial 

tune up by the compliance date, they would be required to 

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

basis as is required for non-seasonal boilers.

Agriculture industry representatives, specifically those 

from the sugar industry, noted that many boilers operate only 
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seasonally, and these boilers are generally not equipped to 

measure carbon monoxide and oxygen. As a result, stack testing 

must be performed to measure carbon monoxide and oxygen as a 

component of the tune-up, as required by 40 CFR 63.11223(b)(5). 

The petitioners requested that the EPA reconsider the frequency 

of tune-ups for seasonal boilers. Specifically, the petitioners 

requested a reduction in the required frequency of subsequent 

tune-ups to the lesser of every 24 months of operation or every 

six to eight years. The petitioners commented that the final 

rule is more burdensome on industries with short seasonal 

operations than non-seasonal industries. The seasonal nature 

means that each boiler must undergo tune-ups every six or eight 

months of operation. This, the petitioners commented, is far 

more frequent than envisioned by the final rule.

We agree with the industry representatives on this issue 

and are proposing to address the issue by creating a subcategory 

for seasonal boilers and amending 40 CFR 63.11223 to specify 

that seasonal boilers would be required to complete the initial

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

years after the initial tune-up.

Seasonally operated boilers would be defined as follows:

Seasonal boiler means a boiler that undergoes a shutdown 

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

consecutive days) due to seasonal market conditions. This 
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definition only applies to boilers that would otherwise be 

included in the biomass subcategory or the oil subcategory.

B. Exemption for Temporary Boilers

We are proposing to amend 40 CFR 63.11195 (Are any boilers 

not subject to this subpart?) by adding temporary boilers to the 

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

major source rule for boilers, the EPA excluded temporary 

boilers from the source category (see 40 CFR 63.7491(j), and 76 

FR 15665 (March 21, 2011)), and is now proposing to do the same 

in the area source rule. Owners and operators of regulated 

sources have pointed out that temporary boilers are small (less 

than 10 MMBtu/hr heat input) and are generally owned and 

operated by contractors, rather than the facility. As a result, 

they are not included in the facility’s operating permits 

because state and federal CAA operating permit programs have 

historically classified such units as insignificant sources. The 

owners and operators also noted that compliance with the work 

practice requirements applicable to these small boilers would be 

complicated because they are typically located on site for less 

than a year, but would be subject to biennial management 

practice requirements. 

We agree that the source category identified in subpart 

JJJJJJ should specifically exclude these temporary boilers 
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because they have been considered insignificant sources, and 

were not included in the EPA’s analysis of the source category. 

Therefore, we are proposing to amend 40 CFR 63.11195 by adding 

temporary boilers to the list of boilers not subject to subpart 

JJJJJJ.

Temporary boilers would be defined in 40 CFR 63.11237 as:

“* * * 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 for 

more than 12 consecutive months. Any temporary boiler that 

replaces a temporary boiler at a location and performs the 

same or similar function will be included in calculating 

the consecutive time period.

(3) The equipment is located at a seasonal facility and 

operates during the full annual operating period of the 

seasonal facility, remains at the facility for at least 2 

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

each year.

(4) The equipment is moved from one location to another

within the facility in an attempt to circumvent the 

residence time requirements of this definition.

C. Initial Compliance Schedule for Existing Boilers

We are proposing to amend 40 CFR 63.11196 to specify that 

all existing boilers subject to the tune-up requirement would 

have three years (by March 21, 2014) in which to demonstrate 

initial compliance, instead of one year to demonstrate initial 

compliance.
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Industry representatives, specifically those with large 

numbers of affected boilers or seasonal boilers, note that many 

boilers are not equipped to measure carbon monoxide and oxygen. 

As a result, stack testing must be performed to measure carbon 

monoxide and oxygen as a component of the tune-up, as required 

by 40 CFR 63.11223(b)(5). The industry members have noted that 

they cannot schedule and complete the testing needed to comply 

with the tune-up requirements during the one year initial 

compliance period, as specified in the final rule. The industry 

members also noted that the three-year initial compliance date 

originally provided in the proposed rule would have allowed for 

the staggering of the tune-ups over three years, while the final 

rule requires initial tune-ups be completed in one year. 

Finally, industry members and other stakeholders did not have an 

adequate opportunity to comment on the one-year compliance 

period for the tune-up requirement. 

We agree with the industry representatives on this issue 

and are proposing to address the issue by allowing three years 

to complete all of the initial compliance demonstration 

requirements applicable to existing boilers. Existing boilers 

that are subject to emission limits and the energy assessment 

requirement already have three years to demonstrate initial 

compliance, and the proposed change to the tune-up requirement 
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would be consistent with those requirements for demonstrating 

initial compliance. Providing the amended compliance schedule 

would eliminate the potential need to approve alternative 

compliance schedules for facilities with multiple boilers or 

seasonal boilers that could not comply with the one-year 

compliance requirement.

If the Agency has not taken final action on the initial 

compliance date for tune-ups prior to the date (March 21, 2012) 

for initial compliance, we could stay the effectiveness of the 

rule for 90 days, as allowed under CAA section 307(d)(7)(B), so 

that the Agency could complete reconsideration. 

D. Definition of Natural Gas Curtailment

We are proposing to amend the definition of “period of 

natural gas curtailment or supply interruption” 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 proposing to amend 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. Finally, we are proposing to revise the 
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term and the definition so that it includes the curtailment of 

any gaseous fuel, and is not limited to just natural gas. 

The definition would be 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 facility is halted for reasons beyond the 

control of the facility. The act of entering into a 

contractual agreement with a supplier of natural gas 

established for curtailment purposes does not constitute a 

reason that is under the control 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 may qualify as periods of 

supply interruption when the emergency or failure is beyond 

the control of the facility.

E. Monitoring Carbon Monoxide Emissions

We are proposing to amend the monitoring requirements in 40 

CFR 63.11224(a) to allow sources subject to a carbon monoxide 

emission limit the option to install, operate and maintain a 

carbon monoxide and oxygen continuous emission monitoring system 

(CEMS). The CEMS would be installed, operated, and maintained 

according to Performance Specifications 3 and 4A at 40 CFR part 

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

plan that each facility is already required to develop according 

to the final rule published on March 21, 2011. The CEMS would 
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also be required to complete a performance evaluation, also 

according to Performance Specifications 3 and 4A. 

The rule currently requires sources subject to a carbon 

monoxide emission limit to demonstrate compliance by measuring

carbon monoxide emissions while also monitoring the oxygen 

content of the exhaust, and then demonstrating continuous 

compliance by monitoring and complying with an oxygen content 

operating limit that is established during the performance test. 

Under the proposed amendments, sources would have the 

option to demonstrate continuous compliance by either monitoring

both carbon monoxide and oxygen to demonstrate compliance with 

the carbon monoxide emission limit, corrected to 3 percent 

oxygen, or by complying with an operating limit for oxygen 

content established during the performance test. 

Several facilities have indicated that they already have 

carbon monoxide CEMS, and should be able to rely on the data 

from those CEMS to demonstrate compliance, rather than from a 

performance test and from compliance with the operating limit. 

They noted that these proposed amendments would also resolve any 

compliance questions that may arise if their oxygen monitor 

showed a deviation from the operating limit, but the CEMS still 

showed compliance with the carbon monoxide emission limit. 
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We are proposing to amend the oxygen monitoring 

requirements to allow for the use of continuous oxygen trim 

analyzer systems. These systems would be defined as 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 provide a feedback signal to the combustion air 

controller. Owners and operators would be required to operate 

the oxygen trim system with the oxygen level set at the minimum 

percent oxygen by volume that is established as the operating 

limit for oxygen during the carbon monoxide performance test. We 

are also removing 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.

F. Averaging Times

The EPA has determined the 30 day rolling average for 

parameter monitoring and compliance with operating limits is 

appropriate for this rule. The operating limits established 

through performance testing in this rule represent short term 

process and control operating conditions representative of 

compliance. Concerns of variability outside the operators 

control such as fuel content, seasonal factors, load cycling, 
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and infrequent hours of needed operation prompted us to look at 

longer averaging periods on which to base operating compliance 

determination. We are aware from studies of emissions over long 

averaging periods that long term (e.g., 30 day) average 

emissions for a operating in compliance will have a variability 

of about half of that represented by the results of short term 

testing. Given that short term tests are representative of 

distinct points along a continuum of that inherent operational

variability, we believe it appropriate to provide a means for 

the source operator to account for that variability by applying 

a long term average for establishing compliance. We expect more 

problematic control system variability (e.g. ESP transformer 

failure or scrubber venturi fan failure) to result in deviations 

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

for a shorter term average.

G. Affirmative Defense Language

The EPA finalized affirmative defense provisions for 

malfunctions and, as part of this reconsideration proposal, we 

are soliciting comments on the affirmative defense provisions 

that were included in the final rule.

H. Tune-up Work Practices

1. Requirements for Small Units. Petitioners requested that the 

EPA reconsider the tune-up work practices for a subset of very 
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small units. Specifically, petitioners requested that small oilfired boilers (petitioners defined “small” at various levels 

between 2 MMBtu/hr and 10 MMBtu/hr) be exempted from the rule. 

While the EPA disagrees that small units should be exempt from 

the rule, the EPA agrees that for the smallest units, a 

decreased tune-up frequency is appropriate. The large number of 

small oil-fired units that can be located at an individual 

facility, particularly an institution, provides logistical 

issues with completion of tune-ups on a biennial basis. We are 

proposing to require an initial tune-up by March 21, 2014, the 

compliance date for this rule, and to change the requirement for 

subsequent tune-ups only for oil-fired boilers equal to or less 

than 5 MMBtu/hr to a tune-up once every 5 years.

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

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

respect to the compliance dates for existing and new sources. 

All emission standards must be met by the compliance date, even 

if compliance demonstrations are sometimes allowed after the 

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

tune-ups must, therefore, be completed by the compliance date 

for existing sources. For new units, we are proposing to remove 

the requirement for the initial tune-up. The EPA anticipates 

that new units will typically be tuned during the startup 
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process. Thus, new units would be required to complete the 

applicable biennial (> 5MMBtu/h) or five-year (≤ 5MMBtu/h) tuneup no later than 25 months or 61 months, respectively, after the 

initial startup of the new or reconstructed affected boiler.

I. Using the Upper Prediction Limit (UPL) for Setting Carbon 

Monoxide Emission Limits

We are proposing to amend the final carbon monoxide 

emission limit for coal-fired boilers to reflect a revised 

analysis that uses the original 99 percent confidence level in 

determining the UPL. In the final rule, the EPA selected the use 

of a 99.9 percent confidence interval for calculating the MACT 

floor for CO emissions. A petitioner requested reconsideration 

of this selection given the fact that the EPA used a 99 percent 

confidence interval for all of the other emission limits in the 

final rule. The petitioner pointed out that if the data are 

highly variable, the 99 percent confidence interval should 

adequately reflect the variability of emissions as well as for 

the data sets for other pollutants. In the development of the 

final rule, the 99.9 percent confidence interval was selected in 

part because the standards covered periods of startup and 

shutdown, while the data did not reflect CO emissions during 

those periods. While the EPA finalized work practice standards 

for startup and shutdown periods, the selection of the 
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confidence interval was not revisited due to time constraints. 

The EPA is now proposing to use a 99 percent confidence interval 

in order to maintain a consistent methodology with the 

development of the MACT floors for other pollutants, and because 

optional CO CEMS-based limits are being proposed that would 

allow sources additional flexibility in meeting the requirements 

of the rule.

In the revised analysis, we have also removed the data from 

a boiler for which only two test runs were completed in 

measuring carbon monoxide emissions. The required number of test 

runs for accurately measuring emissions and demonstrating 

compliance is three test runs. Therefore, we determined that the 

datum from this unit was not representative and we excluded it 

from the data set upon which we performed the revised analysis.

Based on the results of the revised analysis, we are 

proposing to amend the carbon monoxide emission limit for new 

and existing coal-fired boilers from 400 parts per million (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.

J. Establishing GACT Emission Limits for Biomass and Oil-Fired 

Boilers

We are taking comment on basing the final standards for

biomass- and oil-fired area source boilers on generally 
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available control technology (GACT) instead of based on maximum 

achievable control technology (MACT) as were the proposed 

standards.

We stated in the preamble (75 FR 31904) to the proposed 

rule, that both industrial boilers and institutional/commercial 

boilers were on the list of CAA section 112(c)(6) source 

categories for mercury and POM. Section 112(c)(6) requires MACT 

standards for each of the pollutants needed to achieve 

regulation of 90 percent of the emissions of the relevant 

pollutant. In contrast, CAA section 112(c)(3) allows the EPA to 

establish standards under GACT instead of MACT for urban HAP. At 

proposal, we believed that we had to regulate POM from coalfired, biomass-fired, and oil-fired area source boilers and 

mercury from coal-fired area source boilers in order to meet the 

requirement in section 112(c)(6). As such, we proposed MACTbased limits for POM for all subcategories and mercury for the 

coal subcategory. However, based on the information we received

after proposal in developing standards for various other source 

categories, such as major source boilers, gold mines, commercial 

and industrial solid waste incinerators, and other categories, 

we determined only coal-fired area source boilers were necessary 

to meet the 90 percent requirement set forth in section 

112(c)(6) for POM and mercury in the final rule.
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In the proposed rule published on June 4, 2010 (75 FR 

31896) for the biomass and oil subcategories, all new biomass 

and oil-fired boilers would have been subject to numerical 

emission limits for both PM (GACT-based) and CO (MACT-based) as 

surrogates for other HAP. Existing biomass and oil-fired boilers 

equal to or greater than 10 million British thermal units (Btu)

per hour heat input capacity would have been subject to a MACTbased numerical emission limits for CO, and would have needed a 

one-time energy assessment. Existing boilers with heat input 

capacity less than 10 million Btu per hour would have been 

required to have a MACT-based work practice standard, as allowed 

under CAA section 112(h), of a biennial tune-up in lieu of being 

subject to a numerical CO limit. 

The final standards for area source biomass- and oil-fired 

boilers published on March 21, 2011, required these boilers to 

meet the following emission limitations:

 New boilers with heat input capacity greater than 10 

million Btu per hour that are biomass-fired or oil-fired 

must meet a GACT-based numerical emission limits for PM.

 New boilers with heat input capacity greater than 10 

million Btu per hour that are biomass-fired or oil-fired 

must comply with work practice standards to minimize the 

boiler’s startup and shutdown periods following the 

manufacturer’s recommendations, or the manufacturer’s 

recommendations for a unit of similar design. 

 Existing boilers with heat input capacity greater than 10 

million Btu per hour that are biomass-fired or oil-fired 
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must have a one-time energy assessment performed by a 

qualified energy assessor. 

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

biomass-fired or oil-fired must have a GACT-based tune-up 

biennially (every two years). 

The EPA’s rationale for the changes between proposal and 

promulgation for the biomass- and oil-fired boilers can be found 

in the preamble to the promulgated area source standards (76 FR 

15565-15567 and 15574-15575, March 21, 2011). As explained in 

the preamble to the final rule, rather than require a numeric 

MACT-based limit for CO as a surrogate for the individual 

organic urban HAP (including POM), new and existing biomass- and 

oil-fired boilers must meet GACT requirements consisting of 

management practice requirements. For the purposes of regulating 

PM from new boilers, we concluded that the GACT standards should 

consist of numeric emission limits for units with heat input 

capacities greater than 10 million Btu per hour or greater 

because these new units will be subject to the new source 

performance standard (NSPS) emission limits for PM, and the NSPS 

will require PM emissions testing. For units with capacity less 

than 10 million Btu per hour, GACT does not include a numerical 

emission limit because of technical limitations of testing PM 

emissions from boilers with small diameter stacks. 
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We are accepting comment on basing the final standards for 

these two subcategories of area source boilers on GACT, but we 

are not proposing any amendments to these standards at this 

time.

K. Energy Assessment

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

the energy assessment. Specifically, petitioners requested 

that the scope be clearly limited to only those energy use 

systems, located on-site, associated with the affected boilers 

and process heaters. The final definition for “Energy use 

system” was intended only to list examples of potential 

systems that may use the energy generated by affected boilers 

and process heaters. We did not intend that the energy 

assessment would include energy use systems using electricity 

purchased from an off-site source. We also did not intend that 

the energy assessment include energy use systems located offsite. We have revised the definition of “Energy assessment” to 

better clarify our intent. 

2. Compliance Date. Petitioners requested that the EPA clarify 

the due date of the energy assessment. All emission standards 

must be met by the compliance date (March 21, 2014), even if 

compliance demonstrations are sometimes allowed after the 

compliance date. In order to meet the requirements of the 
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rule, energy assessments must, therefore, be completed by the 

compliance date (March 21, 2014) for existing sources.

3. Maximum Duration Requirements. Petitioners requested that the 

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

assessment because the maximum times were not included in the 

proposal and stakeholders had no opportunity to comment. The 

concern raised by petitioners is that, as the final definition 

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

violation could occur if the energy assessment effort exceeds 

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

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

smaller fuel-use facilities, many of which are likely small 

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

concern was that if there was no time limit these small 

facilities would have no means to limit the time/effort of an 

outside energy assessor that is contracted to perform the 

energy assessment. We have revised the definition of “Energy 

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

technical hours and from three-day to 24 technical hours and 

to allow sources to perform longer assessments at their

discretion.

L. Setting PM Standards Under Generally Available Control 

Technology for Oil-Fired Area Source Boilers
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The EPA’s rationale for finalizing PM emissions limits, 

based on GACT, for new oil-fired area source boilers can be 

found in the preamble to the promulgated area source standards 

(76 FR 15574). We are not proposing any changes to the PM limits 

for new oil-fired area source boilers. We are only soliciting 

comments on the final PM limits for new oil-fired area source 

boilers.

M. Title V Permitting Requirements

In the proposed rule published on June 4, 2010 (75 FR 

31925), we proposed to exempt area sources from the requirement 

to obtain a title V permit, if they were not an area source as a 

result of installing a control device on a boiler after November 

15, 1990. In other words, this exemption would have only applied 

to “natural” area sources and would not have applied to 

“synthetic” area sources that would otherwise have been major 

sources but for the control device. In the final rule, in 

response to comments and after a full review of the record, we 

extended the exemption to all area sources, including major 

sources that became synthetic area sources by installing air 

pollution controls. We explained that we lacked sufficient 

information at that time to distinguish from other synthetic and 

natural area sources those sources which have applied controls 
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to boilers in order to become area sources.1 As a result, the 

rationale for exempting most area sources subject to this rule 

as explained in the proposal preamble (see 75 FR 31910 to 31913, 

June 4, 2010) was also relevant for those sources which we 

proposed to permit. 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.

After promulgation of the final boiler area source rule, we 

received a petition to reconsider the decision to not require 

title V permits for area source boilers in the final rule, and 

to reconsider the decision to extend the exemption to include 

synthetic area sources. The petition from Sierra Club is in the 

docket for today’s rule.2 The petition disputes our conclusion 

that title V permitting is unnecessarily burdensome; discusses 

the benefits of permitting, including compliance benefits;

contests our estimation of the costs of permitting; and 

challenges our determination to extend the proposed exemption 

from title V permitting to include synthetic area sources.

We are not proposing any changes to the title V exemption 

at this time. We invite comment on the rationale we expressed in 

 

1 In the preamble to the proposed area source NESHAP, we estimated that at 

least 48 synthetic area sources reduced their emissions to below the major 

source threshold by installing air pollution control devices. (75 FR 31911, 

June 4, 2010.)

2

[Citation to docket for the Earthjustice et al petition]
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the March 21, 2011 final rule as well as on the arguments 

outlined in the petition for reconsideration. Additionally, with 

respect to the issue of exempting synthetic area sources, we 

invite comment on our additional analysis of the petitioner’s 

issue, presented below. 

At proposal, we estimated that about 137,000 area source 

facilities are in the category, including schools, hospitals, 

and churches. See 75 FR 31912. We also estimated that at least 

48 synthetic area sources reduced their HAP emissions to below 

the major source threshold by installing air pollution controls. 

See 75 FR 31911. The total number of facilities that are likely 

to be synthetic area sources for HAP emissions is likely to be a 

small proportion (e.g., less than 1 percent) of the total 

population of area source facilities in the category. 

Those facilities that are synthetic minor sources for HAP 

may already have a title V permit for other reasons. For example 

they could still be major sources for criteria pollutants, or 

may be subject to NSPS. The title V exemption in subpart JJJJJJ 

does not affect the applicability of title V under those other 

programs and facilities required to obtain a title V permit 

under those other programs would still be required to have a 

permit.
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The presence of an exemption from title V permitting for 

synthetic area sources under subpart JJJJJJ would still mean 

that synthetic area sources would likely be subject to more 

stringent permitting and monitoring requirements than natural 

area sources. In order for a facility to be treated as a 

synthetic area source due to the installation of controls, the 

facility still has a legal duty to use the control equipment 

because the control equipment requirement must be Federally 

enforceable. The use of the control is not optional and must be 

continued.

Facilities that are synthetic minors because of add-on 

controls are similar in size and sophistication to those that 

are natural area sources and the added burden of obtaining and 

complying with a title V permit would be disproportionate to any 

added environmental benefit, after accounting for the relatively 

small size differences between synthetic minor and natural area 

source facilities. The uncontrolled emissions are generally on 

the same order of magnitude as the emissions of natural area 

sources, and the facilities and owners are comparable in size.

V. Technical Corrections and Clarifications

We are proposing several technical corrections. These 

amendments are being proposed to correct inaccuracies and 

oversights that were promulgated in the final rule. These 
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proposed changes are summarized in Table 1 of this preamble and 

described in more detail in the paragraphs that follow. 

Table 1. Miscellaneous Technical Corrections to 40 CFR Part 63, 

Subpart JJJJJJ

Section of subpart

JJJJJJ

Description of proposed correction

40 CFR 63.11195 Adding residential boilers and electric 

boilers to the list of boilers not 

subject to subpart JJJJJJ.

40 CFR 63.11195(c) Clarifying the language in this 

paragraph to provide an exemption 

stating “unless such units do not 

combust hazardous waste and combust 

comparable fuels.”

40 CFR 63.11210 Revising paragraph (d) and adding a new 

paragraph (e) to clarify the dates by 

which new and reconstructed affected 

boilers need to demonstrate initial 

compliance.

40 CFR 63.11210(g) Adding a new paragraph (g) to clarify 

the dates by which affected boilers 

that switch subcategories need to 

demonstrate compliance.

40 CFR 

63.11211(b)(2)

Removing the second sentence of that 

paragraph.

40 CFR 63.11220 Removing paragraphs (b) through (d) 

because they are not relevant, and 

renumber paragraph (e) as (b).

40 CFR 63.11221 Clarifying the monitoring data 

collection requirements and the meaning 

of a “deviation” with respect to 

collecting monitoring data.

40 CFR 63.11223(b) Clarifying the requirements for units 

that burn more than one type of fuel.

40 CFR 63.11223(c) Adding a new paragraph to allow for a 

triennial tune-up for seasonal boilers.
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40 CFR 63.11223(d) Including oil-fired and biomass-fired 

boilers in the requirement to minimize 

the time spent in startup and shutdown 

periods.

40 CFR 

63.11224(c)(1) and 

(c)(2)

Correcting a cross reference error.

40 CFR 63.11224(b) Clarifying the requirements for the 

annual and biennial compliance reports.

40 CFR 63.11224(c) Clarifying the record keeping 

requirements.

40 CFR 63.11225(b) Clarifying the requirements for 

compliance reports.

40 CFR 63.11225(d) Revising to allow for computer access 

of records.

40 CFR 63.11225(g) Revising to include physical changes to 

the boiler that may also result in the 

applicability of a different 

subcategory.

40 CFR 63.11237 Revising the definitions for “Annual 

heat input basis,” “Biomass 

subcategory,” “Boiler,” “Energy 

assessment,” “Gas-fired boiler,” “Hot 

water heater,” “Institutional boiler,” 

“Liquid fuel,” “Oil subcategory,” 

“Period of natural gas curtailment or 

supply interruption,” “Qualified Energy 

Assessor” and “Waste heat boiler.”

Adding definitions for “30-day rolling

average,” “Calendar year,” “Daily block 

average,” “Electric boiler,” “Electric 

utility steam generating unit (EGU),” 

“Minimum total secondary electric 

power,” “Oxygen analyzer system,” 

“Oxygen trim system,” “Process heater,” 

“Residential boiler,” “Seasonal 

boiler,” “Shutdown,” “Startup,” and 

“Temporary boiler.” 

Deleting the definition for “Minimum 

voltage or amperage.”
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Table 1 to subpart 

JJJJJJ

Amending the mercury emission limit for 

coal fired boilers. Clarifying that the 

particulate matter emission limits do 

not include condensable particulate 

matter.

Table 2 to subpart 

JJJJJJ

Allowing seasonal boilers to conduct a 

tune-up every five years.

Table 6 to subpart 

JJJJJJ

 Correcting a printing error in 

Item 1.a related to wet scrubbers.

 Clarifying the applicability of 

the operating limits for ESPs.

 Adding operating load limit 

requirements for units subject to 

emission limits and performance 

stack tests. 

Table 7 to subpart 

JJJJJJ

 Revising the 12-hour averages to 

30-day rolling averages. 

 Adding operating load limit 

requirements for units subject to 

emission limits and performance 

stack tests.

A. Electric and Residential Boilers

We are proposing to amend 40 CFR 63.11195 (Are any boilers 

not subject to this subpart?) by adding electric boilers and 

residential boilers to the list of boilers not subject to 

subpart JJJJJJ. Electric boilers would be added because they do 

not have any combustion emissions, except when gaseous or liquid 

fuels are combusted as an emergency back-up during electric 

power outages. An electric boiler would be defined in 40 CFR 

63.11237 as:

“* * * a boiler in which electric heating serves as the 

source of heat. Electric boilers that burn gaseous or 
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liquid fuel during periods of electrical power curtailment 

or failure are included in this definition.”

Residential boilers are the boilers used in single and 

multi-family residences (e.g., duplexes, townhouses) where each 

dwelling typically has its own heating and hot water system, 

rather than a shared central system as in an apartment building 

or dormitory. Owners and operators of regulated sources have 

pointed out that residential boilers are small and are not 

included in the facility’s operating permits because such units 

have historically been classified as insignificant sources under 

state and federal Clean Air Act operating permit programs. We 

agree that these residential boilers should be specifically 

excluded from the source category identified in subpart JJJJJJ 

because they are not part of either the industrial boiler source 

category or the commercial/institutional source category. The 

EPA did not intend to include these in the final rule for 

industrial, commercial, and institutional boilers. 

A residential boiler would be defined in 40 CFR 63.11237 

as:

“* * * a boiler used to provide heat and/or hot water 

used by the owner or occupant of a dwelling designed for 

and used for not more than four family units. This 

definition includes boilers used primarily to provide heat 

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

families located at an institutional facility (e.g., 

university campus, military base, church grounds) or 

commercial/industrial facility (e.g., farm).”
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B. Establishing Operating Limits for Wet Scrubbers

We are proposing to amend the operating limit provisions to

clarify the operating limits for electrostatic precipitators. We 

are amending 40 CFR 63.11211(b)(2) to remove the second sentence 

stating that the operating limits for electrostatic 

precipitators (ESP) do not apply to dry ESP systems operated 

without a wet scrubber. 

C. Timing of Subsequent Performance Tests

We are proposing to amend 40 CFR 63.11220 to correct a 

technical error. Paragraphs (b) through (d) of that section 

should have been removed from the final rule, and paragraph (a) 

should have been revised to remove the references to paragraphs 

(b) through (d), when the testing frequency in paragraph (a) was 

changed between proposal and promulgation from annual testing to 

triennial testing for all sources. Paragraph (e) will be renumbered to become paragraph (b).

D. Demonstrating Initial Compliance

We are proposing to amend 40 CFR 63.11210 to clarify the 

dates by which new and reconstructed boilers need to demonstrate 

initial compliance. We are proposing to amend 40 CFR 63.11210(d) 

to clarify that only boilers that are subject to emission limits 

for PM, mercury, or carbon monoxide in Table 1 to subpart JJJJJJ 
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have a 180-day period after the applicable compliance date to 

demonstrate initial compliance. We are adding a new paragraph 

(e) to clarify that units that are only subject to work practice 

standards, emission reduction measures, and management practices 

in Table 2 to subpart JJJJJJ, and not subject to emission limits 

in Table 1, must demonstrate initial compliance no later than 

the applicable compliance date. The existing paragraph (e) would 

be re-designated paragraph (f).

We are adding a new paragraph (g) to clarify that units 

that switch fuels that result in the applicability of a 

different subcategory must demonstrate initial compliance with 

the applicable standards of the new subcategory no later than

180 days after the date upon which the fuel switch is commenced 

as identified in the notification submitted according to 

§63.11225(g).

E. Demonstrating Compliance with the Work Practice and 

Management Practice Standards

We are proposing to amend 40 CFR 63.11223(b) to specify 

that you must conduct boiler tune-ups 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. We are also proposing 

to amend 40 CFR 63.11223(b)(6)(iii) to specify that the type and 

amount of fuel needs to be included in the biennial report only 
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if the unit was physically and legally capable of using more 

than one type of fuel during that period. We are also proposing 

to specify that for units sharing a fuel meter, you may estimate 

the fuel use by each unit. These changes are being proposed to 

accommodate units that burn more than one type of fuel.

We are also proposing to amend 40 CFR 63.11223 to include a 

new paragraph (c) to specify that, after an initial tune-up by 

the compliance date, seasonal boilers must complete a tune-up

every 5 years, rather than a biennial tune-up. 

We are renumbering paragraph (c) of 40 CFR 63.11223 to 

become paragraph (d) and amending that paragraph to include oilfired and biomass-fired boilers in the requirement to minimize 

the time spent in startup and shutdown periods so that this 

requirement matches the requirement specified in Table 2 to 

subpart JJJJJJ.

F. Monitoring Requirements

We are proposing to amend 40 CFR 63.11224(c)(1) and (c)(2) 

to correct a cross reference error. The references to (b)(1)(i) 

should be to (c)(1)(i) in those two paragraphs.

G. Notification, Recordkeeping, and Reporting Requirements

We are proposing to amend 40 CFR 63.11225(b) to clarify the 

requirements for submitting a biennial report for units that are 

only subject to a biennial tune-up. We are also proposing to 
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amend 40 CFR 63.11225(b)(2) to specify the information that must 

be included in the annual or biennial compliance report.

We are proposing to amend 40 CFR 63.11225(c)(2) to add 

additional record requirements. These would include a copy of 

the energy assessment and the days of operation for each boiler 

that meets the definition of a seasonal boiler. We are also 

proposing to amend 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 in Table 1 to subpart 

JJJJJJ, instead of for all boilers.

We are also proposing to revise 40 CFR 63.11225(d) to 

remove the reference to 40 CFR 63.10(b)(1) and the requirement 

that the most recent 2 years of records be maintained “on site.” 

We are proposing to add language that would allow for computer 

access or other means of immediate access of records stored in a 

centralized location.

We are proposing to revise 40 CFR 63.11225(g) to add any 

physical change that may result in the applicability of a 

different subcategory to the notification requirement. We are 

proposing this revision to address the situation when a physical 

modification is made to limit/reduce the heat input capacity 

such that there is a change in applicability. 
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We are also proposing to amend 40 CFR 63.11214(c) to remove 

the requirement for submitting, upon request, the energy 

assessment. Petitioners commented that this approach, submit 

upon request, is contrary to the approach taken in the final 

Boiler MACT [40 CFR 63.7530(e)]. We agree that we had previously 

stated our intent to recognize in the final Boiler Area Source 

rule the sensitivity of confidential business information (CBI) 

contained in energy assessments. Considering this, the 

petitioners requested that the EPA reconsider the text of 

63.11214(c) and clarify that energy assessment reports are not 

required to be submitted. We note that, even with this change, 

the Agency has the authority to obtain the energy assessment as 

authorized by CAA section 114, including the provisions for

protecting CBI. 

H. Definitions

We are proposing the following changes to the definitions 

in 40 CFR 63.11237:

Biomass subcategory: Proposing to revise the definition 

for “Biomass subcategory” to clarify that boilers burning any 

biomass are included in the definition unless they are included 

in the “Coal subcategory” definition. This change is being 

proposed to account for boilers burning less than 15 percent, on 

an annual heat input basis, in combination with gaseous fuels 
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which would otherwise meet neither the definition of a biomassfired boiler nor the definition of a gas-fired boiler.

Boiler: Proposing to revise the definition for “Boiler” to 

clarify that boilers may heat steam, hot water, or both, and to 

clarify that process heaters (for which a definition would be 

added) are excluded from the definition of boilers. 

Electric utility steam generating unit (EGU): Proposing to 

amend the rule to define “Electric utility steam generating unit 

(EGU)” so that fossil fuel-fired EGUs are not inadvertently

included in the boiler source category.

Energy assessment: Proposing to amend the definition of 

“Energy assessment” to correct a reference to Table 2 of subpart 

JJJJJJ, to remove the inclusion of process heaters, and to 

clarify that the energy assessment only needs to include an 

assessment of on-site energy usage. This latter change is made 

to account for the fact that some boilers provide steam and/or 

hot-water to off-site customers over whom they have no control.

We are also revising the definition of the energy 

assessment to change the time limit for the assessment from one 

or three days to eight or 24 technical labor hours, and to allow 

facilities to spend additional time on the assessment at their 

discretion. Facilities have indicated that it may be difficult 

to complete the energy assessments in the amount of time allowed 
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in the final rule, and they should have the option to spend more 

time to complete the assessment. By switching from days to 

technical labor hours, we are also recognizing that the 

assessment may require intermittent activity spread over several 

days, instead of uninterrupted activity for a one-day or threeday period.

Gas-fired boiler: Proposing to amend the definition of 

“Gas-fired boiler” to include startups as one of the conditions 

during which liquid fuel can be burned in units meeting this 

definition. We are also proposing to change from “gas supply 

emergencies” to “gas supply interruptions” because the term 

“interruption” more accurately and objectively describes the 

situations under which liquid fuels may be burned than 

“emergency.”

Hot water heater: Proposing to amend the definition of “Hot 

water heater” to clarify that hot water boilers are included in 

the definition. Hot water boilers having a heat input capacity 

of less than 1.6 million Btu per hour meet the criteria listed 

for hot water heaters. We are also proposing to amend the 

definition to clarify/simplify applicability determinations.

Institutional boiler: Proposing to revise this definition 

to better encompass and describe the range of facilities that 

would be considered “institutions” by adding nursing homes, 
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elementary and secondary schools, libraries, religious 

establishments, and governmental buildings to the examples in 

the definition. We are also adding language to clarify that 

“institutions” are not limited to just these examples.

Minimum voltage or amperage: Proposing to replace the term 

“Minimum voltage or amperage” with the term “Minimum total 

secondary electric power,” to better reflect the concept being 

described and the operating limit to which it applies. We are 

also proposing revising the definition of that term to clarify 

the meaning.

Oil subcategory: Proposing to change the terms in the 

definition from “gas supply emergencies” to “gas supply 

interruptions,” and adding “startups” as conditions under which 

liquid fuels can be burned in gas-fired units that are 

specifically excluded from meeting the definition of oil 

subcategory. We are also proposing to amend this definition to 

clarify that the 48-hour limit per calendar year applies only to 

periodic testing.

Period of natural gas curtailment or supply interruption: 

The rationale and description of the proposed amendments to this 

definition are described in Section IV.D of this preamble.

Process heater: Proposing to amend the rule to define 

“Process heater” so that process heaters are not inadvertently 
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included in the boiler source category. This definition would 

also clarify that units that heat a water mixture as a heat 

transfer fluid, without generating steam, are not considered

boilers. Although they are not specifically mentioned in the 

definition, the proposed definition would also be broad enough 

to include process heaters that utilize waste heat, as well as 

process heaters that rely directly on fuel combustion. A process 

heater would be defined as follows:

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; raw, 

intermediate or finished) 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, oil 

heating, or autoclaves.

Qualified energy assessor: Proposing to amend the 

definition to correct a paragraph numbering error in the 

definition.

Residential boiler and temporary boiler: Proposing to add 

definitions for “Residential boiler” and “Temporary boiler”

because we are proposing to add these two types of boilers to 

the list of boilers that are exempt from subpart JJJJJJ. The 

rationale for adding temporary boilers and the definition are 
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described in Section IV.B of this preamble, and the rationale 

for adding residential boilers and the definition are described 

in Section V.A of this preamble.

Seasonal boiler: Proposing to add a definition for 

“Seasonal boiler” because we are proposing to add a subcategory

for those types of boilers. The rationale for adding this 

subcategory and the proposed definition is described in Section 

IV.A of this preamble.

Startup and Shutdown: While we are maintaining a work 

practice/management practice approach for startup and shutdown, 

we are proposing definitions of startup and shutdown. We are 

proposing to define “startup” as the period between the state of 

no combustion in the boiler to the period where the boiler first 

achieves 25 percent load (i.e., a cold start). We are proposing 

to define “shutdown” as the period that begins when a boiler 

last operates at 25 percent load and ending with a state of no 

fuel combustion in the boiler.

I. Change to the Mercury Emission Limit for New Coal-Fired 

Boilers

We are proposing to amend the mercury emission limit for 

new and existing coal-fired boilers in Table 1 to subpart 

JJJJJJ. At promulgation, the mercury limit for new and existing 

coal-fired boilers was 0.0000048 (4.8 x 10-6) pounds (lb) mercury 
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per MMBtu. This limit was based on the best performer of seven 

units for which data were available. All of the mercury data 

emissions from this boiler were below the method detection 

limit. After promulgation, however, the EPA determined that the 

boiler on which the EPA based this limit is a utility boiler and 

thus is not part of the source category and should not have been

considered in setting the mercury emission limit for existing 

and new sources.

Examining the emissions data for the remaining six units, 

the top performing unit is now a unit from Massachusetts that 

achieved an emission level of 2.0 x 10-6 lb mercury per MMBtu. 

These emissions are above the method detection limit. Because 

this unit is from Massachusetts, the fuel variability factor 

(FVF) for eastern bituminous coal of 10.9 is still applicable. 

Using these data and the FVF of 10.9, the proposed mercury 

emission limit for new and existing coal-fired boilers is 

0.000022 lb mercury per MMBtu. 

J. Changes to the Work Practice Standards, Emission Reduction 

Measures, and Management Practices

We are proposing to amend Table 2 to subpart JJJJJJ

to add a provision that allows seasonal boilers, after an 

initial tune up by the compliance date, to conduct a tune-up

every 5 years instead of a biennial tune-up. As explained in 
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section IV.A of this preamble, we are proposing to create a new 

subcategory for seasonally operated boilers. Because these 

boilers are operated seasonally, it can be difficult to schedule 

and complete the testing needed to complete the tune-up 

requirements every other year (biennially) for periods when the 

boilers are operating, especially at facilities that have

multiple boilers. Therefore, we are proposing to allow 

seasonally operated boilers to conduct tune-ups every five years 

after the initial tune up by the compliance date, and include 

this requirement in Table 2 to subpart JJJJJJ. 

K. Requirements for Establishing Operating Limits

We are proposing several changes to Table 6 to subpart 

JJJJJJ:

We are proposing to revise the requirements for 

establishing the operating limits for wet scrubbers in Item 1.a

of Table 6 to correct a printing error related to how the 

recorded data are reduced to determine the operating limits. 

Operators are currently instructed to collect pressure drop and 

liquid flow-rate data every 15 minutes during the entire period 

of the performance stack tests. The instruction to determine the 

average pressure drop and liquid flow-rate for each individual 

test run in the three-run performance stack test was placed in 

the incorrect column of Table 6. It will be moved from the 
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second column (“And your operating limits are based on . . .”)

to the fifth column (“According to the following requirements”).

We are proposing to revise the requirements for 

establishing the operating limits for ESPs in Item 1.b of Table 

6 to clarify that they apply to all ESPs, and do not apply to 

only those that are operated on units with wet scrubbers.

We are proposing to revise Table 6 to include as Item 4 

provisions for establishing a unit-specific limit for maximum 

operating load. These provisions would apply to any unit subject 

to a pollutant emissions limit for which compliance is 

demonstrated by a performance (stack) test. Operating load data 

would include fuel feed rate data or steam generation rate data 

and would be collected at 15 minute intervals during each run of 

the performance test. The average rate would be determined for 

each run of the performance test and the average of the three 

test runs would be determined. The maximum operating limit would 

be 110 percent of the average of the three test runs.

L. Demonstrating Continuous Compliance

We are proposing several amendments to Table 7 to subpart 

JJJJJJ:

We are proposing to amend the continuous compliance 

requirements for the following operating limits to clarify that 

compliance is based on a 30-day rolling average:
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 Wet scrubber pressure drop and liquid flow rate in Item 

3.c.

 Dry scrubber sorbent or carbon injection rate in Item 4.c.

 ESP secondary amperage and voltage, or total power input in 

Item 5.c.

 Oxygen content in the combustion exhaust in Item 7.b.

We are proposing to amend the provisions for oxygen 

monitoring to reflect the amendments to add oxygen trim analyzer 

systems that were discussed in more detail in section IV.E of 

this preamble.

We are also proposing to add new requirements as Item 8 for 

establishing a unit-specific operating limit for unit operating 

load based on fuel feed rate or steam generation rate. This 

change coincides with the proposed amendment to Table 6 to 

subpart JJJJJJ to establish a unit-specific operating limit for 

maximum operating load for any pollutant for which compliance is 

demonstrated by a performance (stack) test.

VI. What are the impacts associated with the amendments?

The proposed amendments contained in this action are 

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

coverage of the final rule. The clarifications and corrections 

should make it easier for owners and operators and for local and 

State authorities to understand and implement the requirements. 

The amendments will not increase the costs for the final rule 
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but will result in a decrease in the burden on small facilities 

as a result of the reduction in the frequency of conducting 

tune-ups for seasonal boilers and small (equal to or less than 5 

MMBtu/hr) oil-fired boilers.

As discussed in section V, the mercury emission limits for 

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

source boilers was revised because of an error discovered in the 

analysis conducted for the final rule. This technical correction 

resulted in an increase in the emission limits for mercury. 

Concurrently, we revised our impacts analysis to be consistent 

with changes made to the major source boiler rule. The baseline 

emissions for area sources are calculated using the emission 

factors developed for the major source rule because of 

insufficient data for area sources. Since promulgation, the EPA 

has received and incorporated a significant amount of additional 

data and has corrected previous calculation errors that impacted 

the emission factors used to calculate baseline emissions 

resulting in a higher baseline emission for mercury from coalfired area source boilers. Consequently, the result of the 

increase in both baseline mercury emissions and mercury emission 

limits in this proposed rule is that the overall reduction in 

mercury emissions does not change significantly from the 

estimated reduction for the promulgated rule. 
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In summary, as compared to the control costs estimated in 

the March 2011 final rule, the proposed amendments will result 

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

in emission limits and the decrease in burden on small 

facilities.

VII. Statutory and Executive Order Reviews

A. Executive Order 12866: Regulatory Planning and Review and 

Executive Order 13563: Improving Regulation and Regulatory 

Review

Under Executive Order 12866 (58 FR 51735, October 4, 1993), 

this action is a “significant regulatory action” because it may 

raise novel legal or policy issues. Accordingly, the EPA 

submitted this action to the Office of Management and Budget 

(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 proposed rule does not impose any new information 

collection burden. However, 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 
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assigned OMB control number 2060-0688, EPA information 

collection request (ICR) number 2253.02, to the ICR. 

This action results in no changes to the information 

collection requirements of the final rule and will have no 

impact on the information collection estimate of project cost 

and hour burden made and approved by OMB. Therefore, the ICR has

not been revised. The OMB control numbers for the EPA’s 

regulations in 40 CFR are listed in 40 CFR part 9.

C. Regulatory Flexibility Act

The Regulatory Flexibility Act (RFA) generally requires an 

agency to prepare a regulatory flexibility analysis of any rule 

subject to notice and comment rulemaking requirements under the 

Administrative Procedure Act or any other statute unless the 

agency certifies that the rule will not have a significant 

economic impact on a substantial number of small entities.3 The 

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

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

(initial regulatory flexibility analysis) and 604 (final 

regulatory flexibility analysis) in order to avoid “duplicative 

 

3

Small entities include small businesses, small organizations, and small governmental jurisdictions. For purposes of 

assessing the impacts of this proposed rule on small entities, small entity is defined as: (1) a small business as 

defined by the Small Business Administration size standards for small businesses at 13 CFR 121.201 (less than 500, 

750, or 1,000 employees, depending on the specific NAICS Code under subcategory 325); (2) a small governmental 

jurisdiction that is a government of a city, county, town, school district or special district with a population of less 

than 50,000; and (3) a small organization that is any not-for-profit enterprise that is independently owned and 

operated and is not dominant in its field. 
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action.” 5 U.S.C. § 605(c). This proposed rule is closely 

related to the boiler area source rule, which EPA signed on 

February 21, 2011 and that took effect on May 20, 2011. The EPA 

prepared an initial regulatory flexibility analysis in 

connection with the boiler area source rule. Therefore, pursuant 

to § 605(c), the EPA is not required to complete an initial 

regulatory flexibility analysis for this rule.

The EPA has been concerned with potential small entity 

impacts since it began developing the boiler area source rule. 

The EPA conducted outreach to small entities and, pursuant to §

609 of RFA, convened a Small Business Advocacy Review Panel (the 

Panel) on January 22, 2009, to obtain advice and recommendations 

from small entity representatives. Pursuant to the RFA, the EPA 

used the Panel’s report and prepared both an initial regulatory 

flexibility analysis and a final regulatory flexibility analysis 

in connection with the closely related boiler area source rule. 

Convening an additional Panel and preparing an additional 

initial regulatory flexibility analysis would be procedurally

duplicative and is unnecessary given that the issues here are

within the scope of those considered by the Panel. Finally, we 

note that this rule, which proposes to amend the boiler area 

source rule, will not impose any additional regulatory 
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requirements beyond those imposed by the previously promulgated 

boiler area source rule. 

D. Unfunded Mandates Reform Act

This action contains no new Federal mandates under the 

provisions of Title II of the Unfunded Mandates Reform Act of 

1995 (UMRA), 2 U.S.C. 1531-1538 for State, local, or tribal 

governments or the private sector. This proposed rule imposes no 

new enforceable duty on any State, local, or tribal governments 

or the private sector. Therefore, this proposed rule 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 new regulatory 

requirements that might significantly or uniquely affect small 

governments. This rule proposes amendments to aid with 

compliance, but does not change the level of the standards in 

the rule. 

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 proposed rule will not impose new direct compliance 
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costs on State or local governments, and will not preempt State 

law. Thus, Executive Order 13132 does not apply to this action.

In the spirit of Executive Order 13132 and consistent with 

the EPA policy to promote communications between the EPA and 

State and local governments, the EPA specifically solicits 

comment on this proposed action from State and local officials.

F. Executive Order 13175: Consultation and Coordination with 

Indian Tribal Governments

This proposed rule 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 proposed rule.

The EPA specifically solicits additional comment on this 

proposed action from tribal officials.

G. Executive Order 13045: Protection of Children from 

Environmental Health Risks and Safety Risks

The EPA interprets Executive Order 13045 (62 FR 19885, 

April 23, 1997) as applying to those regulatory actions that 

concern health or safety risks, such that the analysis required 
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under section 5-501 of the Executive Order has the potential to 

influence the regulation. This proposed rule 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. Further, this action 

does not change the level of standards already in place. 

I. National Technology Transfer and Advancement Act

Section 12(d) of the National Technology Transfer and 

Advancement Act (NTTAA) of 1995, Public Law No. 104-113, 12(d) 

(15 U.S.C. 272 note) directs the EPA to use voluntary consensus 

standards (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.
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This proposed rulemaking 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 proposed rule will not 

have disproportionately high and adverse human health or 

environmental effects on minority or low-income populations

because it would not change the level of environmental 

protection for any affected populations. 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. The amendments would not relax the 
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control measures on sources regulated by the rules, and, 

therefore, will not cause emissions increases from these 

sources.
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Review***

EO12866 NESHAP AS-Industrial Commercial Institutional Boiler RIN 

2060-AR14 Proposed Rule – Reconsideration 20111011

National Emission Standards for Hazardous Air Pollutants for Area 

Sources: Industrial, Commercial and Institutional Boilers

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List of Subjects in 40 CFR Part 63

Environmental protection, Administrative practice and procedure, 

Air pollution control, Hazardous substances.

Dated:

Lisa P. Jackson,

Administrator.
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For the reasons stated in the preamble, title 40, chapter I, 

part 63 of the Code of Federal Regulations is proposed to be 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 JJJJJJ-[AMENDED]

2. Section 63.11195 is amended by revising the introductory 

paragraph and paragraph (c) and by adding paragraphs (h), (i), (j), 

and (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.

* * * * *

(h) Temporary boilers as defined in this subpart.

(i) Residential boilers as defined in this subpart.

(j) Electric boilers as defined in this subpart.
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(k) An electric utility steam generating unit as defined in 

this subpart.

3. Section 63.11196 is amended by revising paragraph (a) to read 

as follows:

§63.11196 What are my compliance dates? 

(a) If you own or operate an existing affected source, you must 

achieve compliance with the applicable provisions in this subpart no 

later than March 21, 2014.

* * * * *

4. Section 63.11210 is amended by revising paragraph (d), by 

redesignating paragraph (e) as paragraph (f) and adding a new 

paragraph (e) to read as follows:

§ 63.11210 What are my initial compliance requirements and by what 

date must I conduct them?

* * * * *

(d) For new or reconstructed affected boilers that have 

applicable emission limits, you must demonstrate initial compliance 

no later than 180 calendar days after March 21, 2011 or within 180 

calendar days after startup of the source, whichever is later, 

according to § 63.7(a)(2)(ix).

(e) For new or reconstructed affected boilers that have only 

applicable work practice standards or management practices, 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). You are not required to complete an initial 
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performance tune-up for a new or reconstructed affected source, but 

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

tune-up as specified in § 63.11223(b), (c), and (d) no later than 25 

months or 61 months, respectively, after the initial startup of the 

new or reconstructed affected source.

(f) For affected boilers that ceased burning solid waste 

consistent with § 63.11196(d), you must demonstrate compliance within 

60 days of the effective date of the waste-to-fuel switch. If you 

have not conducted your compliance demonstration for this subpart 

within the previous 12 months, you must complete all compliance 

demonstrations before you commence or recommence combustion of solid 

waste.

(g) For affected boilers that switch fuels or make a physical 

modification to the boiler that result in the applicability of a 

different subcategory, you must demonstrate compliance within 180

days of the effective date of the fuel switch or physical 

modification consistent with §63.11225(g).

5. Section 63.11211 is amended by revising paragraph (b)(2) to 

read as follows:

§63.11211 How do I demonstrate initial compliance with the emission 

limits? 

* * * * *

(b) * * *

(2) For an electrostatic precipitator operated with a wet 

scrubber, you must establish the minimum secondary voltage and 
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secondary amperage (or total secondary electric power input), as 

defined in §63.11237, as your operating limits during the three-run 

performance stack test. 

* * * * *

6. Section 63.11212 is amended by revising paragraph (b) 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 

continuous emission monitoring system for carbon monoxide are exempt 

from the initial carbon monoxide performance testing in Table 4 to 

this subpart and the oxygen concentration operating limit requirement 

specified in Table 3 to this subpart.

* * * * *

7. 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 
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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.

* * * * *

8. Section 63.11220 is amended by revising paragraphs (a) and 

(b) and by deleting paragraphs (c), (d), and (f) to read as follows:

§63.11220 When must I conduct subsequent performance tests?

(a) If your boiler has a heat input capacity of 10 million Btu 

per hour or greater, you must conduct all applicable performance 

(stack) tests according to §63.11212 on a triennial basis. Triennial 

performance tests must be completed no more than 37 months after the 

previous performance test. 

(b) 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 monthly. 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.

9. Section 63.11221 is amended by revising the section heading, 

and paragraphs (a), (b) and (d) to read as follows:
Page 70 of 102

§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 site-specific monitoring plan required by §63.11205(c). 

(b) You must operate the monitoring system and collect data at 

all required intervals at all times the affected source is operating 

and compliance is required, except for periods of monitoring system 

malfunctions or out-of-control periods (see § 63.8(c)(7) of this 

part), repairs associated with monitoring system malfunctions or outof-control periods, and required monitoring system quality assurance 

or quality control activities including, as applicable, calibration 

checks and required zero and span adjustments. 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 effect 

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. 

* * * * *

(d) Except for periods of monitoring system malfunctions, 

repairs associated with monitoring system malfunctions, and required 

monitoring system quality assurance or quality control activities 

including, as applicable, calibration checks and required zero and 
Page 71 of 102

span adjustments, failure to collect required data is a deviation of 

the monitoring requirements.

10. Section 63.11223 is amended by revising paragraphs (a), (b) 

introductory text, (b)(5), (b)(6)(iii), and (c), and adding 

paragraphs (d) and (e) 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. 

(b) Except as specified in paragraphs (c) and (d) 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.

* * * * *

(5) Measure the concentrations in the effluent stream of carbon 

monoxide in parts per million, by volume, and oxygen in volume 

percent, before and after the adjustments are made (measurements may 
Page 72 of 102

be either on a dry or wet basis, as long as it is the same basis 

before and after the adjustments are made). You must conduct the 

tune-up 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. 

(6) Maintain onsite and submit, if requested by the 

Administrator, a report containing the information in paragraphs 

(b)(6)(i) through (iii) of this section.

* * * * *

(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.

* * * * *

(c) Seasonal boilers must complete a tune-up every five years 

as specified in paragraphs (b)(1) through (7) of this section. Each 

five-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 five-year tune-up must be no later than 61 months after the 

initial startup.

(d) Oil-fired boilers with a heat input capacity of equal to or 

less than 5 million Btu per hour must complete a tune-up every five 

years as specified in paragraphs (b)(1) through (7) of this section. 

Each five-year tune-up must be conducted no more than 61 months after 

the previous tune-up. For a new or reconstructed oil-fired boiler 
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with a heat input capacity of equal to or less than 5 million Btu per 

hour, the first five-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 until the next 

scheduled unit shutdown, but you must inspect each burner at least 

once every 72 months.

(e) If you own or operate an existing or new coal-fired boiler, 

a new biomass-fired boiler, or a new oil-fired boiler with a heat 

input capacity of 10 million Btu per hour or greater, you must 

minimize the boiler’s time spent during startup and shutdown 

following the manufacturer’s recommended procedures and 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.

11. Section 63.11224 is amended by revising paragraphs (a)

introductory text, (a)(1), (a)(2), (a)(5), (a)(6), (c)(1), and 

(c)(2), and adding paragraph (a)(7) to read as follows:

§63.11224 What are my monitoring, installation, operation, and 

maintenance requirements? 

(a) If your boiler is subject to a carbon monoxide emission 

limit in Table 1 to this subpart, you must either install, operate, 

and maintain a CEMS for CO and oxygen according to the procedures in 

paragraphs (a)(1) through (6) of this section, or install, operate, 

and maintain a continuous oxygen analyzer system as defined in 
Page 74 of 102

§63.11237 according to paragraphs (a)(7) and (d) of this section by 

the compliance date specified in §63.11196. The CEMS for CO and 

oxygen shall be monitored at the same location at the outlet of the 

boiler. Boilers that use a CEMS for CO are exempt from the initial CO 

performance testing and oxygen concentration operating limit 

requirements specified in §63.11211(a) of this subpart.

(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.

* * * * *

(5) You must calculate one-hour arithmetic averages, corrected 

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

million CO concentrations. The one-hour arithmetic averages required 

shall be used to calculate the boiler operating day daily arithmetic 

average emissions. Calculate a 10-day rolling average from the daily 

averages. Use Equation 19-19 in section 12.4.1 of Method 19 of 40 CFR 
Page 75 of 102

part 60, appendix A-7 for calculating the average carbon monoxide 

concentration from the hourly values.

(6) For purposes of calculating data averages, you must use all 

the data collected during all periods in assessing compliance, 

excluding data collected during periods when the monitoring system 

malfunctions or is out of control, during associated repairs, and 

during required quality assurance or control activities (including, 

as applicable, calibration checks and required zero and span 

adjustments). Monitoring failures that are caused in part by poor 

maintenance or careless operation are not malfunctions. Any period 

for which the monitoring system is out of control and data are not 

available for a required calculation constitutes a deviation from the 

monitoring requirements. Periods when data are unavailable because of 

required quality assurance or control activities (including, as 

applicable, calibration checks and required zero and span 

adjustments) do not constitute monitoring deviations.

(7) You must operate the oxygen analyzer system with the oxygen 

level set at the minimum percent oxygen by volume that is established 

as the operating limit for oxygen according to Table 4 to this 

subpart.

(c) * * *

* * * * *

(1) For each continuous monitoring system (CMS) required in 

this section, you must develop, and submit to the EPA Administrator 

for approval upon request, a site-specific monitoring plan that 
Page 76 of 102

addresses paragraphs (c)(1)(i) through (iii) of this section. You 

must submit this site-specific monitoring plan (if requested) at 

least 60 days before your initial performance evaluation of your CMS.

* * * * *

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

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

* * * * *

12. Section 63.11225 is amended by revising paragraphs (b) 

introductory text, (b)(2), (c)(2) introductory text, (c)(2)(ii), (d), 

and (g) and by adding (c)(2)(iii), (c)(2)(iv), and (c)(2)(v) to read 

as follows:

§63.11225 What are my notification, reporting, and recordkeeping, 

requirements?

* * * * *

(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 fiveyear tune-up according to § 63.11223(a) and not subject to emission 

limits or operating limits, you may prepare only a biennial or fiveyear compliance report as specified in paragraphs (b)(1) and (2) of 

this section.
Page 77 of 102

* * * * *

(2) Statement by a responsible official, with the official’s 

name, title, phone number, e-mail 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 five-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 

§63.11223(c) to minimize the boiler’s time spent during startup and 

shutdown following the manufacturer’s recommended procedures.”

* * * * *

(c) * * *

(2) You must keep records to document conformance with the work 

practices, emission reduction measures, and management practices 

required by § 63.11214 as specified in paragraphs (c)(2)(i) through 

(v) of this section.

* * * * *
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(ii) Records documenting the fuel type(s) used monthly by each 

boiler, including whether the fuel has received a non-waste 

determination by you or the EPA. If you combust non-hazardous 

secondary materials that have been determined not to be solid waste 

pursuant to §241.3(b)(1), you must keep a record which documents how 

the secondary material meets each of the legitimacy criteria. If you 

combust a fuel that has been processed from a discarded non-hazardous 

secondary material pursuant to §241.3(b)(4), you must keep records as 

to how the operations that produced the fuel satisfies the definition 

of processing in §241.2. If the fuel received a non-waste 

determination pursuant to the petition process submitted under 

§241.3(c), you must keep a record that documents how the fuel 

satisfies the requirements of the petition process.

(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) You must keep records of days of operation by each boiler 

that meets the definition of seasonal boiler.

* * * * *

(d) Your records must be in a form suitable and readily 

available for expeditious review. You must keep each record for 5 

years following the date of each recorded action. You must keep each 

record onsite or be accessible from a central location by computer or 
Page 79 of 102

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.

* * * * *

(g) If you intend to switch fuels or make a physical change to 

the boiler, and this fuel switch or change may result in the

applicability of a different subcategory or a switch out of subpart 

JJJJJJ due to a switch to 100 percent natural gas, you must provide 

30 days prior notice of the date upon which you will switch fuels.

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 will switch fuels or 

be physically modified, and the date of the notice.

(2) The currently applicable subcategory under this subpart.

(3) The date on which you became subject to the currently 

applicable standards.

(4) The date upon which you will commence the fuel switch or 

modification.

13. Section 63.11237 is amended as follows:

a. By adding new definitions in alphabetical order for “30-day 

rolling average,” “Calendar year,” “Daily block average,” “Electric 

boiler,” “Electric utility steam generating unit (EGU),” “Minimum 

total secondary electric power,” “Oxygen analyzer system,” “Oxygen 
Page 80 of 102

trim system,” “Process heater,” “Residential boiler,” “Seasonal 

boiler,” “Shutdown,” “Startup,” and “Temporary boiler.”

b. By revising the definitions for “Annual heat input basis,” 

“Biomass subcategory,” “Boiler,” “Energy assessment,” “Gas-fired 

boiler,” “Hot water heater,” “Institutional boiler,” “Oil 

subcategory,” “Period of natural gas curtailment or supply 

interruption,” “Qualified Energy Assessor,” and “Waste heat boiler.”

c. By deleting the definition for “Minimum voltage or amperage.”

§63.11237 What definitions apply to this subpart? 

* * * * *

30-day rolling average means the arithmetic mean of all valid 

data from 30 successive operating days that is calculated for each 

operating day using the data from that operating day and the previous 

29 operating days.

* * * * *

Annual heat input basis means the heat input for the calendar 

year preceding the compliance demonstration.

* * * * *

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 
Page 81 of 102

oxidizer feed rates are controlled. A device combusting solid waste, 

as defined in §241.3, is not a boiler unless the device is exempt 

from the definition of a solid waste incineration unit as provided in 

section 129(g)(1) of the Clean Air Act. Waste heat boilers and 

process heaters are excluded from this definition.

* * * * *

Calendar year means the period between January 1 and December 

31, inclusive, for a given year.

* * * * *

Daily block average means the arithmetic mean of all valid 

emission concentrations or parameter levels recorded when a unit is 

operating measured over the 24-hour period from 12 am (midnight) to 

12 am (midnight).

* * * * *

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 fuelfired 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 
Page 82 of 102

be “capable of combusting” fossil fuels, an EGU would need to have 

these fuels allowed in their operating permits and have the 

appropriate fuel handling facilities on-site or otherwise available 

(e.g., coal handling equipment, including coal storage area, belts 

and conveyers, pulverizers, etc.; oil storage facilities). In 

addition, fossil fuel-fired EGU means any EGU that fired fossil fuel 

for more than 10.0 percent of the average annual heat input in any 3 

consecutive calendar years or for more than 15.0 percent of the 

annual heat input during any one calendar year after (COMPLIANCE DATE 

OF THE FINAL EGU RULE].

* * * * *

Energy assessment means the following only as this term is used 

in Table 2 to this subpart:

(1) Energy assessment for facilities with affected boilers 

using less than 0.3 trillion Btu (TBtu) per year heat input will be 8 

technical labor hours in length maximum, but may be longer at the 

discretion of the owner or operator of the affected source. The 

boiler system and on-site energy use system accounting for at least 

50 percent of the affected boiler(s) energy output will be evaluated 

to identify energy savings opportunities, within the limit of 

performing an 8-hour energy assessment.

(2) Energy assessment for facilities with affected boilers 

using 0.3 to 1 TBtu/year will be 24 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 
Page 83 of 102

use system(s) accounting for at least 33 percent of the affected 

boiler(s) energy output will be evaluated to identify energy savings 

opportunities, within the limit of performing a 24-hour energy 

assessment.

(3) Energy assessment for facilities with affected boilers 

using greater than 1.0 TBtu/year, the boiler system(s) and any onsite energy use system(s) accounting for at least 20 percent of the 

affected boiler(s) energy output will be evaluated to identify energy 

savings opportunities.

* * * * *

Gas-fired boiler includes any boiler that burns gaseous fuels 

not combined with any solid fuels, 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.

* * * * *

Hot water heater means a closed vessel with a capacity of no 

more than 120 U.S. gallons in which water is heated by combustion of 

gaseous or liquid fuel and hot water is withdrawn for use external to 

the vessel. Hot water boilers (i.e., not generating steam) combusting 

gaseous or liquid fuel with a heat input capacity of less than 1.6 

million Btu per hour are included in this definition.

* * * * *
Page 84 of 102

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.

* * * * *

Liquid fuel includes, but is not limited to, distillate oil, 

residual oil, any form of liquid fuel derived from petroleum, on-spec 

used oil, liquid biofuels, biodiesel, and vegetable oil.

* * * * *

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 test demonstrating compliance with the 

applicable emission limits.

* * * * *

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..

* * * * *
Page 85 of 102

Oxygen analyzer system means all equipment required to determine 

the oxygen content of a gas stream and used to monitor oxygen in the 

boiler flue gas or firebox. This definition includes oxygen trim 

systems. The source owner or operator is responsible to install, 

calibrate, maintain, and operate the oxygen analyzer system in 

accordance with the manufacturer’s recommendations. 

Oxygen trim system means a system of monitors that is used to 

maintain excess air at the desired level in a combustion device. A 

typical system consists of a flue gas oxygen and/or carbon monoxide 

monitor that automatically provide a feedback signal to the 

combustion air controller. 

Period of gas curtailment or supply interruption means a period 

of time during which the supply of gaseous fuel to an affected 

facility is halted for reasons beyond the control of the facility. 

The act of entering into a contractual agreement with a supplier of 

natural gas established for curtailment purposes does not constitute 

a reason that is under the control 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 may qualify as periods of supply 

interruption when the emergency or failure is beyond the control of 

the facility.
Page 86 of 102

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; raw, intermediate or 

finished) 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 opportunity 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.
Page 87 of 102

(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.

Residential boiler means a boiler used to provide heat and/or 

hot water used by the owner or occupant of a dwelling designed for 

and used for not more than four family units. This definition 

includes boilers used primarily to provide heat and/or hot water for 

a dwelling containing four or fewer families located at an 

institutional facility (e.g., university campus, military base, 

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

* * * * *

Seasonal boiler means a boiler that undergoes a shutdown for a 

period of at least 7 consecutive months (or 210 consecutive days) due 

to seasonal market conditions.

Shutdown means the period that begins when the boiler last 

operates at 25 percent load and ending with a state of no fuel 

combustion in the boiler.
Page 88 of 102

* * * * *

Startup means the period between the state of no combustion in 

the boiler to the period where the boiler first achieves 25 percent 

load (i.e., a cold start).

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 for more 

than 12 consecutive months. Any temporary boiler that replaces a 

temporary boiler at a location and performs the same or similar 

function will be included in calculating the consecutive time period.

(3) The equipment is located at a seasonal facility and operates 

during the full annual operating period of the seasonal facility, 

remains at the facility for at least 2 years, and operates at that 

facility for at least 3 months each year.

(4) The equipment is moved from one location to another in an 

attempt to circumvent the residence time requirements of this 

definition.

* * * * *

Waste heat boiler means a device that recovers normally unused 

energy and converts it to usable heat. Waste heat boilers are also 
Page 89 of 102

referred to as heat recovery steam generators. This definition 

includes both fired and unfired waste heat boilers.

* * * * *

14. Tables 1, 2, 6 and 7 to subpart JJJJJJ are revised to read 

as follows:

Table 1 to Subpart JJJJJJ of Part 63 — Emission Limits

As stated in § 63.11201, you must comply with the following 

applicable emission limits:

If your boiler is 

in this 

subcategory...

For the 

following 

pollutants...

You must achieve less 

than or equal to the 

following emission 

limits, except during 

periods of startup and 

shutdown ...

1. New coal-fired 

boiler with 

heat input 

capacity of 

30 million 

Btu per hour 

or greater

a. Particulate 

Matter

(Filterable)

0.03 lb per MMBtu of 

heat input.

b. Mercury 0.000022 lb per MMBtu 

of heat input.

c. Carbon 

Monoxide

420 ppm by volume on a 

dry basis corrected to 

3 percent oxygen (3-run 

average or 10-day 

rolling average).

2. New coal-fired 

boiler with 

heat input 

capacity of 

between 10 

and 30 

million Btu 

per hour

a. Particulate 

Matter

(Filterable)

0.42 lb per MMBtu of 

heat input.

b. Mercury 0.000022 lb per MMBtu 

of heat input.

c. Carbon 

Monoxide

420 ppm by volume on a 

dry basis corrected to 

3 percent oxygen (3-run 

average or 10-day 

rolling average).

3. New biomassfired boiler a. Particulate 

Matter

0.03 lb per MMBtu of 

heat input.
Page 90 of 102

with heat 

input 

capacity of 

30 million 

Btu per hour 

or greater

(Filterable)

4. New biomass 

fired boiler 

with heat 

input 

capacity of 

between 10 

and 30 

million Btu 

per hour

a. Particulate 

Matter

(Filterable)

0.07 lb per MMBtu of 

heat input.

5. New oil-fired 

boiler with 

heat input 

capacity of 

10 million 

Btu per hour 

or greater

a. Particulate 

Matter

(Filterable)

0.03 lb per MMBtu of 

heat input.

6. Existing coal 

(units with heat 

input 

capacity of 

10 million 

Btu per hour 

or greater) 

a. Mercury 0.000022 lb per MMBtu 

of heat input.

b. Carbon 

Monoxide

420 ppm by volume on a 

dry basis corrected to 

3 percent oxygen.

Table 2 to Subpart JJJJJJ of Part 63 — Work Practice Standards, 

Emission Reduction Measures, and Management Practices

As stated in § 63.11201, you must comply with the following 

applicable work practice standards, emission reduction measures, and 

management practices:

If your boiler is in 

this subcategory...

You must meet the following...

1. Existing or new 

coal, new biomass, 

and new oil (units 

with heat input 

capacity of 10 

million Btu per hour 

Minimize the boiler’s startup and 

shutdown periods following the 

manufacturer’s recommended 

procedures. If manufacturer’s 

recommended procedures are not 

available, you must follow 
Page 91 of 102

or greater) recommended procedures for a unit 

of similar design for which 

manufacturer’s recommended 

procedures are available.

2. Existing coal 

(units with heat 

input capacity of 

less than 10 million 

Btu per hour) 

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 (units 

with heat input 

capacity of less 

than 10 million Btu 

per hour) 

Conduct a tune-up of the boiler 

biennially as specified in 

§63.11223.

4. Existing oilfired boilers with 

heat input capacity 

greater than 5

million Btu per 

hour, and all 

existing biomassfired boilers

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

million Btu per 

hour, and all new 

biomass-fired 

boilers

Conduct a tune-up of the boiler 

biennially as specified in 

§63.11223.

6. Existing seasonal 

boilers

Conduct an initial tune-up as 

specified in §63.11214, and 

conduct a tune-up of the boiler 

every five years as specified in 

§63.11223.

7. New seasonal 

boilers

Conduct a tune-up of the boiler every 

five years as specified in 

§63.11223.

8. Existing oilfired boiler with 

heat input capacity 

of equal to or less 

than 5 million Btu 

per hour

Conduct an initial tune-up as 

specified in §63.11214, and conduct a 

tune-up of the boiler every five 

years as specified in §63.11223.

9. New oil-fired 

boiler with heat 

Conduct a tune-up of the boiler every 

five years as specified in §63.11223.
Page 92 of 102

input capacity of 

equal to or less 

than 5 million Btu 

per hour

10. Existing coal, 

biomass, or oil 

(units with heat 

input capacity of 10 

million Btu per hour 

and greater) 

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. 

The energy assessment must include: 

(1) A visual inspection of the 

boiler system.

(2) An evaluation of operating 

characteristics of the facility, 

specifications of energy using 

systems, operating and maintenance 

procedures, and unusual operating 

constraints,

(3) Inventory of major systems 

consuming energy from affected 

boiler(s),

(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,

(7) A comprehensive report 

detailing the ways to improve 

efficiency, the cost of specific 

improvements, benefits, and the time 

frame for recouping those 

investments,

Table 3 to Subpart JJJJJJ of Part 63 — Operating Limits for Boilers 

with Emission Limits

As stated in §63.11201, you must comply with the applicable operating 

limits:
Page 93 of 102

If you demonstrate 

compliance with 

applicable emission 

limits using...

You must meet these operating 

limits...

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 secondary electric power 

input of the electrostatic 

precipitator at or above the 

lowest 1-hour average secondary 

electric power measured during the 

most recent performance test 

demonstrating compliance with the 

particulate matter emission 

limitations. 

3. Wet PM scrubber 

control

Maintain the 30-day rolling 

average pressure drop at or above 

the lowest 1-hour average pressure 

drop across the wet scrubber and 

the 30-day rolling average liquid 

flow-rate at or above the lowest 

1-hour average liquid flow rate 

measured during the most recent 

performance test demonstrating 

compliance with the PM emission 

limitation. 

4. Dry sorbent or 

carbon injection 

control

Maintain the 30-day rolling 

average sorbent or carbon 

injection rate at or above the 

lowest 2-hour average sorbent flow 

rate measured during the most 

recent performance test 

demonstrating compliance with the 

mercury emissions limitation. 
Page 94 of 102

When your boiler operates at lower 

loads, multiply your sorbent or 

carbon injection rate by the load 

fraction (e.g., actual heat input 

divided by the heat input during 

performance stack test, for 50 

percent load, multiply the 

injection rate operating limit by 

0.5).

5. Any other add-on air 

pollution control type.

This option is for boilers that 

operate dry control systems. 

Boilers must maintain opacity to 

less than or equal to 10 percent 

opacity (daily block average).

6. Fuel analysis Maintain the fuel type or fuel 

mixture (annual average) such that 

the mercury emission rates 

calculated according to 

§63.11211(b) is less than the 

applicable emission limits for 

mercury.

7. Performance stack 

testing

For boilers that demonstrate 

compliance with a performance 

stack test, maintain the operating 

load of each unit such that is 

does not exceed 110 percent of the 

average operating load recorded 

during the most recent performance 

stack test.

8. Continuous Oxygen 

Monitor 

Maintain the 30-day rolling 

average oxygen level at or above 

the lowest 1-hour average oxygen 

level measured during the most 

recent CO performance stack test.

* * * * *

Table 6 to Subpart JJJJJJ of Part 63 — Establishing Operating Limits

As stated in §63.11211, you must comply with the following 

requirements for establishing operating limits:
Page 95 of 102

If you have 

an 

applicable 

emission 

limit for 

. . .

And your 

operating 

limits are 

based on 

. . . You must... Using . . .

According to 

the following 

requirements

1. 

Particulate 

matter or 

mercury

a. Wet 

scrubber 

operating 

parameters

i. Establish 

a sitespecific 

minimum 

pressure 

drop and 

minimum flow 

rate 

operating 

limit 

according to 

§63.11211(b)

(1) Data from 

the pressure 

drop and 

liquid flow 

rate monitors 

and the 

particulate 

matter or 

mercury 

performance 

stack test

(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. 

Electrostat

ic 

precipitato

r operating 

parameters 

i. Establish 

a sitespecific 

minimum 

secondary 

electric 

power 

according to 

§63.11211(b)

(1) Data from 

the secondary 

electric 

power 

monitors 

during the 

particulate 

matter or 

mercury 

performance 

stack test

(a) You must 

collect 

secondary 

electric power 

input data 

every 15 

minutes during 

the entire 

period of the 

performance 

stack tests;
Page 96 of 102

If you have 

an 

applicable 

emission 

limit for 

. . .

And your 

operating 

limits are 

based on 

. . . You must... Using . . .

According to 

the following 

requirements

 (b) Determine 

the secondary 

electric power 

input 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 a. 

Activated 

carbon 

injection

i. Establish 

a sitespecific 

minimum 

activated 

carbon 

injection 

rate 

operating 

limit 

according to 

§63.11211(b)

(1) Data from 

the activated 

carbon rate 

monitors and 

mercury 

performance 

stack tests

(a) You must 

collect 

activated 

carbon 

injection rate 

data every 15 

minutes during 

the entire 

period of the 

performance 

stack tests;
Page 97 of 102

If you have 

an 

applicable 

emission 

limit for 

. . .

And your 

operating 

limits are 

based on 

. . . You must... Using . . .

According to 

the following 

requirements

(b) Determine 

the average 

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 

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.
Page 98 of 102

If you have 

an 

applicable 

emission 

limit for 

. . .

And your 

operating 

limits are 

based on 

. . . You must... Using . . .

According to 

the following 

requirements

3. Carbon 

monoxide

a. Oxygen i. Establish 

a unitspecific 

limit for 

minimum 

oxygen 

level.

(1) Data from 

the oxygen 

analyzer 

system 

specified in 

§63.11224(a).

(a) You must

collect oxygen 

data every 15 

minutes during 

the entire 

period of the 

performance 

stack tests;

(b) Determine 

the average 

hourly oxygen 

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.
Page 99 of 102

If you have 

an 

applicable 

emission 

limit for 

. . .

And your 

operating 

limits are 

based on 

. . . You must... Using . . .

According to 

the following 

requirements

4. Any 

pollutant 

for which

compliance 

is 

demonstrated

by a 

performance

test.

a. Boiler 

operating 

load.

i. Establish 

a unit 

specific

limit for 

maximum 

operating

load 

according to

§ 

63.11212(c).

(1) Data from 

the operating

load monitors 

(fuel feed 

monitors or

from 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.
Page 100 of 102

Table 7 to Subpart JJJJJJ of Part 63 — Demonstrating Continuous 

Compliance

As stated in §63.11222, you must show continuous compliance with 

the emission limitations for affected sources according to the 

following:

If you must meet the 

following operating 

limits . . .

You must demonstrate continuous compliance by 

. . .

1. Opacity a. Collecting the opacity monitoring system 

data according to §63.11224(e) and §63.11221; 

and

 b. Reducing the opacity monitoring data to 6-

minute averages; and

 c. Maintaining opacity to less than or equal 

to 10 percent (daily block average).

2. Fabric Filter Bag 

Leak Detection 

Operation

Installing and operating a bag leak detection 

system according to §63.11224 and operating 

the fabric filter such that the requirements 

in §63.11222(a)(4) are met.

3. Wet Scrubber 

Pressure Drop and 

Liquid Flow-rate

a. Collecting the pressure drop and liquid 

flow rate monitoring system data according to 

§§63.11224 and 63.11221; and

 b. Reducing the data to 30-day rolling

averages; and

 c. Maintaining the 30-day rolling average 

pressure drop and liquid flow-rate at or above 

the operating limits established during the 

performance test according to §63.1140.

4. Dry Scrubber Sorbent 

or Carbon Injection 

Rate

a. Collecting the sorbent or carbon injection 

rate monitoring system data for the dry 

scrubber according to §§63.11224 and 63.11220; 

and

 b. Reducing the data to 30-day rolling

averages; and

 c. Maintaining the 30-day rolling average 

sorbent or carbon injection rate at or above 

the minimum sorbent or carbon injection rate 

as defined in §63.11237.

5. Electrostatic a. Collecting the total secondary electric
Page 101 of 102

If you must meet the 

following operating 

limits . . .

You must demonstrate continuous compliance by 

. . .

Precipitator Total 

Secondary Electric

Power Input

power input monitoring system data for the 

electrostatic precipitator according to 

§§63.11224 and 63.11220; and

 b. Reducing the data to 30-day rolling

averages; and

 c. Maintaining the 30-day rolling average

total secondary electric power input at or 

above the operating limits established during 

the performance test according to §63.11214.

6. Fuel Pollutant 

Content

a. Only burning the fuel types and fuel 

mixtures used to demonstrate compliance with 

the applicable emission limit according to 

§63.11214 as applicable; and

 b. Keeping monthly records of fuel use 

according to §63.11222.

7. Oxygen content a. Continuously monitor the oxygen content in 

the combustion exhaust according to §63.11224.

b. Reducing the data to 30-day rolling

averages; and

c. Maintain the 30-day rolling average oxygen 

content at or above the operating limit 

established during the most recent carbon 

monoxide performance test.

8. Carbon monoxide 

emissions

a. Continuously monitor the carbon monoxide 

concentration in the combustion exhaust 

according to §63.11224(a).

b. Correcting the data to 3 percent oxygen, 

and reducing the data to one-hour and daily 

block averages;

c. Reducing the data from the daily averages 

to 10-day rolling averages;

d. Maintain the 10-day rolling average carbon 

monoxide concentration at or below the 

applicable emission limit in Tables 1 of this 

subpart. 

9. Boiler operating 

load 

a. Collecting operating load data (fuel feed 

rate or steam generation data) every 15 

minutes.
Page 102 of 102

If you must meet the 

following operating 

limits . . .

You must demonstrate continuous compliance by 

. . .

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).