80532 Federal Register / Vol. 76, No. 247 / Friday, December 23, 2011 / Proposed Rules 

ENVIRONMENTAL PROTECTION 

AGENCY 

40 CFR Part 63 

[EPA–HQ–OAR–2006–0790; FRL–9503–3] 

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 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 February 21, 2012. 

Public Hearing. If anyone contacts the 

EPA requesting to speak at a public 

hearing by January 3, 2012, a public 

hearing will be held on January 9, 2012. 

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. 

• Email: 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–OAR–2006– 

0790. 

• 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–HQ–OAR–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–OAR–2006– 

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 email. The www.regulations.gov Web 

site is an ‘‘anonymous access’’ system, 

which means the EPA will not know 

your identity or contact information 

unless you provide it in the body of 

your comment. If you send an email 

comment directly to the EPA without 

going through www.regulations.gov, 

your email address will be 

automatically captured and included as 

part of the comment that is placed in the 

public docket and made available on the 

Internet. If you submit an electronic 

comment, the EPA recommends that 

you include your name and other 

contact information in the body of your 

comment and with any disk or CD–ROM 

you submit. If the EPA cannot read your 

comment due to technical difficulties 

and cannot contact you for clarification, 

the EPA may not be able to consider 

your comment. Electronic files should 

avoid the use of special characters, any 

form of encryption, and be free 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. 

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; email 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 OilFired 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. 

C. Timing of Subsequent Performance 

Tests 

D. Demonstrating Initial Compliance 


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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: 

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 Health care and social assistance. 

22111 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 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 Email. 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– 

OAR–2006–0790. 

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 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– 

HQ–OAR–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 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, 


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the EPA identified 30 HAP that pose the 

greatest potential health threat in urban 

areas, and these HAP are referred to as 

the ‘‘30 urban HAP.’’ Section 112(c)(3) 

of the CAA requires the EPA to list 

sufficient categories or subcategories of 

area sources to ensure that area sources 

representing 90 percent of the emissions 

of the 30 urban HAP are subject to 

regulation. Under CAA section 

112(d)(5), the EPA may elect to 

promulgate standards or requirements 

for area sources ‘‘which provide for the 

use of generally available control 

technologies (‘‘GACT’’) or management 

practices by such sources to reduce 

emissions of hazardous air pollutants.’’ 

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-p-dioxin. 

As noted in the preamble to the final 

rule, (76 FR 15556, March 21, 2011), we 

listed area source industrial boilers and 

commercial/institutional boilers 

combusting coal under CAA section 

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

contribution of mercury and POM, and 

under CAA section 112(c)(3) for their 

contribution of arsenic, beryllium, 

cadmium, lead, chromium, manganese, 

nickel, ethylene dioxide, and PCBs, as 

well as mercury and POM. We 

promulgated final standards for coalfired 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 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. 

Additional information concerning 

issues and concerns presented by 

commenters can be found in Docket No. 

EPA–HQ–OAR–2006–0790 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. 

• 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 tuneup every five years, instead of on a 

biennial basis as is required for nonseasonal boilers. 

Agriculture industry representatives, 

specifically those from the sugar 

industry, noted that many boilers 


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operate only 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 tuneup, 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 

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 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 two years (by 

March 21, 2013) in which to 

demonstrate initial compliance, instead 

of one year to demonstrate initial 

compliance. 

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 tuneup, 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 two years to complete the 

initial compliance demonstration of the 

tune-up requirements applicable to 

existing boilers. Even though existing 

boilers that are subject to emission 

limits have three years to demonstrate 

initial compliance, we believe the 

proposed change to the tune-up initial 

compliance period is appropriate 

because compliance with the tune-up 

requirement does not involve the 

installation of control equipment. 

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. 

We are specifically requesting 

comment on whether the initial 

compliance period for the tune-up 

requirement should be extended to three 

years. 

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 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 


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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 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. 

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, 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 

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 small units. 

Specifically, petitioners requested that 

small oil-fired 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, tuneups 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 process. Thus, new 

units would be required to complete the 

applicable biennial (> 5MMBtu/h) or 

five-year (≤ 5MMBtu/h) tune-up 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 


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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 

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 oilfired area source boilers on generally 

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 coal-fired, 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. 

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 oilfired boilers equal to or greater than 10 

million British thermal units (Btu) per 

hour heat input capacity would have 

been subject to a MACT-based 

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 

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. 

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 off-site. 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 


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80538 Federal Register / Vol. 76, No. 247 / Friday, December 23, 2011 / Proposed Rules 

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.] 

of the 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 

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 oilfired 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 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 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. 

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 proposed changes 

are summarized in Table 1 of this 

preamble and described in more detail 

in the paragraphs that follow. 


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Federal Register / Vol. 76, No. 247 / Friday, December 23, 2011 / Proposed Rules 80539 

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. 

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.’’ 

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 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).’’ 

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), 


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80540 Federal Register / Vol. 76, No. 247 / Friday, December 23, 2011 / Proposed Rules 

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 re-numbered 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 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 redesignated 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 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 tuneup 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 oil-fired 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 tuneup. We are also proposing to 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. 

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 which 

would otherwise meet neither the 

definition of a biomass-fired 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 onsite 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 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 


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recognizing that the assessment may 

require intermittent activity spread over 

several days, instead of uninterrupted 

activity for a one-day or three-day 

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, 

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 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 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 coalfired boilers was 0.0000048 (4.8 × 10¥6) 

pounds (lb) mercury 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 × 

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 

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 


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80542 Federal Register / Vol. 76, No. 247 / Friday, December 23, 2011 / Proposed Rules 

3Small 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. 

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 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: 

• 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 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 coal-fired 

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. 

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 

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 


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allows an agency to ‘‘consider a series 

of closely related rules as one rule for 

the purposes of sections’’ 603 (initial 

regulatory flexibility analysis) and 604 

(final regulatory flexibility analysis) in 

order to avoid ‘‘duplicative action.’’ 5 

U.S.C. 605(c). This proposed rule is 

closely related to the 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 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 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 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. 

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 

control measures on sources regulated 

by the rules, and, therefore, will not 

cause emissions increases from these 

sources. 

List of Subjects in 40 CFR Part 63 

Environmental protection, 

Administrative practice and procedure, 

Air pollution control, Hazardous 

substances. 


sroberts on DSK5SPTVN1PROD with PROPOSALS
80544 Federal Register / Vol. 76, No. 247 / Friday, December 23, 2011 / Proposed Rules 

Dated: December 2, 2011. 

Lisa P. Jackson, 

Administrator. 

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 text 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. 

(k) An electric utility steam generating 

unit as defined in this subpart. 

3. Section 63.11196 is amended by 

revising paragraph (a)(1) to read as 

follows: 

§ 63.11196 What are my compliance 

dates? 

(a) * * * 

(1) If the existing affected boiler is 

subject to a work practice or 

management practice standard of a 

tuneup, you must achieve compliance 

with the work practice or management 

standard no later than March 21, 2013. 

* * * * * 

4. Section 63.11210 is amended by 

revising paragraph (d), by redesignating 

paragraph (e) as paragraph (f) and 

adding a new paragraphs (e) and (g) 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 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. 

* * * * * 

(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 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 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 

removing paragraphs (c), (d), and (f). 

The revisions 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: 

§ 63.11221 Is there a minimum amount of 

monitoring data I must obtain? 

(a) You must monitor and collect data 

according to this section and the sitespecific monitoring plan required by 

§ 63.11205(c). 

(b) You must operate the monitoring 

system and collect data at all required 

intervals at all times the affected source 

is operating and compliance is required, 

except for periods of monitoring system 

malfunctions or out-of-control periods 

(see § 63.8(c)(7) of this part), repairs 

associated with monitoring system 

malfunctions or out-of-control periods, 

and required monitoring system quality 

assurance or quality control activities 


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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 outof-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 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) introductory text, 

(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 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 tuneup 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 with a heat 

input capacity of equal to or less than 

5 million Btu per hour, the first fiveyear 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 biomassfired 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) 

introductory text, and (c)(2) 

introductory text, 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 § 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 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 


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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 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) through (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 

five-year tune-up according to 

§ 63.11223(a) and not subject to 

emission limits or operating limits, you 

may prepare only a biennial or five-year 

compliance report as specified in 

paragraphs (b)(1) and (2) of this section. 

* * * * * 

(2) Statement by a responsible official, 

with the official’s name, title, phone 

number, email address, and signature, 

certifying the truth, accuracy and 

completeness of the notification and a 

statement of whether the source has 

complied with all the relevant standards 

and other requirements of this subpart. 

Your notification must include the 

following certification(s) of compliance, 

as applicable, and signed by a 

responsible official: 

(i) ‘‘This facility complies with the 

requirements in § 63.11223 to conduct a 

biennial or 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. 

* * * * * 

(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 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 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 removing the definition for 

‘‘Minimum voltage or amperage.’’ 

The additions and revisions read as 

follows: 

§ 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 


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

(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 fuel-fired 

combustion unit of more than 25 

megawatts that serves a generator that 

produces electricity for sale. A fossil 

fuel-fired unit that cogenerates steam 

and electricity and supplies more than 

one-third of its potential electric output 

capacity and more than 25 megawatts 

electrical output to any utility power 

distribution system for sale is 

considered an electric utility steam 

generating unit. To be ‘‘capable of 

combusting’’ fossil fuels, an EGU would 

need to have these fuels allowed in their 

operating permits and have the 

appropriate fuel handling facilities onsite or otherwise available (e.g., coal 

handling equipment, including coal 

storage area, belts and conveyers, 

pulverizers, etc.; oil storage facilities). In 

addition, fossil fuel-fired EGU means 

any EGU that fired fossil fuel for more 

than 10.0 percent of the average annual 

heat input in any 3 consecutive calendar 

years or for more than 15.0 percent of 

the annual heat input during any one 

calendar year after (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 

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 on-site 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. 

* * * * * 

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.. 

* * * * * 

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 


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natural gas established for curtailment 

purposes does not constitute a reason 

that is under the control of a facility for 

the purposes of this definition. An 

increase in the cost or unit price of 

natural gas due to normal market 

fluctuations not during periods of 

supplier delivery restriction does not 

constitute a period of natural gas 

curtailment or supply interruption. Onsite gaseous fuel system emergencies or 

equipment failures may qualify as 

periods of supply interruption when the 

emergency or failure is beyond the 

control of the facility. 

Process heater means an enclosed 

device using controlled flame, and the 

unit’s primary purpose is to transfer 

heat indirectly to a process material 

(liquid, gas, or solid; 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 steam generation and 

major energy using systems, including, 

but not limited to: 

(i) Boiler combustion management. 

(ii) Boiler thermal energy recovery, 

including 

(A) Conventional feed water 

economizer. 

(B)Conventional combustion air 

preheater, and 

(C)Condensing economizer. 

(iii) Boiler blowdown thermal energy 

recovery. 

(iv) Primary energy resource selection, 

including 

(A) Fuel (primary energy source) 

switching, and 

(B) Applied steam energy versus 

direct-fired energy versus electricity. 

(v) Insulation issues. 

(vi) Steam trap and steam leak 

management. 

(vii) Condensate recovery. 

(viii) Steam end-use management. 

(2) Capabilities and knowledge 

includes, but is not limited to: 

(i) Background, experience, and 

recognized abilities to perform the 

assessment activities, data analysis, and 

report preparation. 

(ii) Familiarity with operating and 

maintenance practices for steam or 

process heating systems. 

(iii) Additional potential steam 

system improvement opportunities 

including improving steam turbine 

operations and reducing steam demand. 

(iv) Additional process heating system 

opportunities including effective 

utilization of waste heat and use of 

proper process heating methods. 

(v) Boiler-steam turbine cogeneration 

systems. 

(vi) Industry specific steam end-use 

systems. 

Residential boiler means a boiler used 

in a dwelling containing four or fewer 

family units to provide heat and/or hot 

water. This definition includes boilers 

used primarily to provide heat and/or 

hot water for a dwelling containing four 

or fewer families located at an 

institutional facility (e.g., university 

campus, military base, church grounds) 

or commercial/industrial facility (e.g., 

farm). 

* * * * * 

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. 

* * * * * 

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 referred to as heat 

recovery steam generators. This 

definition includes both fired and 

unfired waste heat boilers. 

* * * * * 

14. Tables 1, 2, 3, 6, and 7 to subpart 

JJJJJJ are revised to read as follows: 

As stated in § 63.11201, you must 

comply with the following applicable 

emission limits: 

TABLE 1 TO SUBPART JJJJJJ OF PART 63—EMISSION LIMITS

If your boiler is in this subcategory * * * For the following 

pollutants * * * 

You must achieve less than or equal to the following emission limits, except 

during periods of startup and shutdown * * * 

1. New coal-fired 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). 


sroberts on DSK5SPTVN1PROD with PROPOSALS
Federal Register / Vol. 76, No. 247 / Friday, December 23, 2011 / Proposed Rules 80549 

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

If your boiler is in this subcategory * * * For the following 

pollutants * * * 

You must achieve less than or equal to the following emission limits, except 

during periods of startup and shutdown * * * 

3. New biomass-fired 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. 

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. 

As stated in § 63.11201, you must 

comply with the following applicable 

work practice standards, emission 

reduction measures, and management 

practices: 

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

MANAGEMENT PRACTICES

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

1. Existing or new coal, new biomass, and 

new oil (units with heat input capacity of 

10 million Btu per hour or greater).

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 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 oil-fired boilers with heat input 

capacity greater than 5 million Btu per 

hour, and all existing biomass-fired 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 oil-fired 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 input capacity of equal to or less than 5 million Btu 

per hour.

Conduct a tune-up of the boiler every five years as specified in § 63.11223. 

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. 

As stated in § 63.11201, you must 

comply with the applicable operating 

limits: 


sroberts on DSK5SPTVN1PROD with PROPOSALS
80550 Federal Register / Vol. 76, No. 247 / Friday, December 23, 2011 / Proposed Rules 

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

If you demonstrate compliance 

with applicable emission limits 

using * * * 

You must meet these operating limit * * * 

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. 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. 

* * * * * As stated in § 63.11211, you must 

comply with the following requirements 

for establishing operating limits: 

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

If you have an 

applicable 

emission limit 

for * * * 

And your operating limits 

are based on 

* * * 

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

1. Particulate 

matter or 

mercury.

a. Wet scrubber operating parameters.i. Establish a site-specific 

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. Electrostatic 

precipitator 

operating 

parameters.

i. Establish a site-specific 

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; 

....................... ............................................... ............................................... (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 site-specific 

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; 


sroberts on DSK5SPTVN1PROD with PROPOSALS
Federal Register / Vol. 76, No. 247 / Friday, December 23, 2011 / Proposed Rules 80551 

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

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. 

3. Carbon 

monoxide.

a. Oxygen ...... i. Establish a unit-specific 

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. 

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. 

As stated in § 63.11222, you must 

show continuous compliance with the 

emission limitations for affected sources 

according to the following: 

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

If you must meet the following 

operating limits * * * You must demonstrate continuous compliance by * * * 

1. Opacity ......................................... a. Collecting the opacity monitoring system data according to § 63.11224(e) and § 63.11221; and 

b. Reducing the opacity monitoring data to 6-minute averages; and 

c. Maintaining opacity to less than or equal to 10 percent (daily block average). 

2. Fabric Filter Bag Leak Detection 

Operation.

Installing and operating a bag leak detection system according to § 63.11224 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 Precipitator Total 

Secondary Electric Power Input.

a. Collecting the total secondary electric power input monitoring system data for the electrostatic precipitator according to §§ 63.11224 and 63.11220; 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. 


sroberts on DSK5SPTVN1PROD with PROPOSALS
80552 Federal Register / Vol. 76, No. 247 / Friday, December 23, 2011 / Proposed Rules 

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

If you must meet the following 

operating limits * * * You must demonstrate continuous compliance by * * * 

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. 

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). 

[FR Doc. 2011–31644 Filed 12–19–11; 8:45 am] 

BILLING CODE 6560–50–P 


sroberts on DSK5SPTVN1PROD with PROPOSALS