3090 Federal Register / Vol. 80, No. 13 / Wednesday, January 21, 2015 / Proposed Rules 

ENVIRONMENTAL PROTECTION 

AGENCY 

40 CFR Part 63 

[EPA–HQ–OAR–2002–0058; FRL–9919–28– 

OAR] 

RIN 2060–AS09 

National Emission Standards for 

Hazardous Air Pollutants for Major 

Sources: Industrial, Commercial, and 

Institutional Boilers and Process 

Heaters 

AGENCY: Environmental Protection 

Agency. 

ACTION: Proposed rule. 

SUMMARY: On January 31, 2013, the 

Environmental Protection Agency (EPA) 

finalized amendments to the national 

emission standards for the control of 

hazardous air pollutants (HAP) from 

new and existing industrial, 

commercial, and institutional boilers 

and process heaters at major sources of 

HAP. Subsequently, the EPA received 

10 petitions for reconsideration of the 

final rule. The EPA is announcing 

reconsideration of and requesting public 

comment on three issues raised in the 

petitions for reconsideration, as detailed 

in the SUPPLEMENTARY INFORMATION

section of this notice. The EPA is 

seeking comment only on these three 

issues. The EPA will not respond to any 

comments addressing any other issues 

or any other provisions of the final rule. 

Additionally, the EPA is proposing 

amendments and technical corrections 

to the final rule to clarify definitions, 

references, applicability and compliance 

issues raised by stakeholders subject to 

the final rule. Also, we propose to delete 

rule provisions for an affirmative 

defense for malfunction in light of a 

recent court decision on the issue. 

DATES: Comments. Comments must be 

received on or before March 9, 2015, or 

30 days after date of public hearing if 

later. 

Public Hearing. If anyone contacts us 

requesting to speak at a public hearing 

by January 26, 2015, a public hearing 

will be held on February 5, 2015. If you 

are interested in attending the public 

hearing, contact Ms. Pamela Garrett at 

(919) 541–7966 or by email at 

garrett.pamela@epa.gov to verify that a 

hearing will be held. 

ADDRESSES: Submit your comments, 

identified by Docket ID No. EPA–HQ– 

OAR–2002–0058, by one of the 

following methods: 

• Federal eRulemaking Portal: http:// 

www.regulations.gov: Follow the on-line 

instructions for submitting comments. 

• Email: A-and-R-Docket@epa.gov. 

Include docket ID No. EPA–HQ–OAR– 

2002–0058 in the subject line of the 

message. 

• Fax: (202) 566–9744, Attention 

Docket ID No. EPA–HQ–OAR–2002– 

0058. 

• Mail: Environmental Protection 

Agency, EPA Docket Center (EPA/DC), 

Mail Code 28221T, Attention Docket ID 

No. OAR–2002–0058, 1200 

Pennsylvania Avenue NW., Washington, 

DC 20460. The EPA requests a separate 

copy also be sent to the contact person 

identified below (see FOR FURTHER

INFORMATION CONTACT). 

• Hand/Courier Delivery: EPA Docket 

Center, Room 3334, EPA WJC West 

Building, 1301 Constitution Avenue 

NW., Washington, DC 20004, Attention 

Docket ID No. EPA–HQ–OAR–2002– 

0058. 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–2002– 

0058. The EPA’s policy is that all 

comments received will be included in 

the public docket without change and 

may be made available on-line 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. 

Public Hearing: If anyone contacts the 

EPA requesting a public hearing by 

January 26, 2015, the public hearing 

will be held on February 5, 2015 at the 

EPA’s campus at 109 T.W. Alexander 

Drive, Research Triangle Park, North 

Carolina. The hearing will begin at 

10:00 a.m. (Eastern Standard Time) and 

conclude at 5:00 p.m. (Eastern Standard 

Time). There will be a lunch break from 

12:00 p.m. to 1:00 p.m. Please contact 

Ms. Pamela Garrett at 919–541–7966 or 

at garrett.pamela@epa.gov to register to 

speak at the hearing or to inquire as to 

whether or not a hearing will be held. 

The last day to pre-register in advance 

to speak at the hearing will be February 

2, 2015. Additionally, requests to speak 

will be taken the day of the hearing at 

the hearing registration desk, although 

preferences on speaking times may not 

be able to be fulfilled. If you require the 

service of a translator or special 

accommodations such as audio 

description, please let us know at the 

time of registration. If you require an 

accommodation, we ask that you preregister for the hearing, as we may not 

be able to arrange such accommodations 

without advance notice. The hearing 

will provide interested parties the 

opportunity to present data, views or 

arguments concerning the proposed 

action. The EPA will make every effort 

to accommodate all speakers who arrive 

and register. Because the hearing is 

being held at a U.S. government facility, 

individuals planning to attend the 

hearing should be prepared to show 

valid picture identification to the 

security staff in order to gain access to 

the meeting room. Please note that the 

REAL ID Act, passed by Congress in 

2005, established new requirements for 

entering federal facilities. If your 

driver’s license is issued by Alaska, 

American Samoa, Arizona, Kentucky, 

Louisiana, Maine, Massachusetts, 

Minnesota, Montana, New York, 

Oklahoma or the state of Washington, 

you must present an additional form of 

identification to enter the federal 

building. Acceptable alternative forms 

of identification include: Federal 

employee badges, passports, enhanced 

driver’s licenses and military 

identification cards. In addition, you 

will need to obtain a property pass for 

any personal belongings you bring with 

you. Upon leaving the building, you 

will be required to return this property 

pass to the security desk. No large signs 

will be allowed in the building, cameras 

may only be used outside of the 

building and demonstrations will not be 

allowed on federal property for security 

reasons. The EPA may ask clarifying 

questions during the oral presentations, 

but will not respond to the 

presentations at that time. Written 

statements and supporting information 

submitted during the comment period 

will be considered with the same weight 


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Federal Register / Vol. 80, No. 13 / Wednesday, January 21, 2015 / Proposed Rules 3091 

as oral comments and supporting 

information presented at the public 

hearing. A hearing will not be held 

unless requested. 

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/DC), Room 

3334, EPA WJC West Building, 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 Air 

Docket is (202) 566–1742. 

FOR FURTHER INFORMATION CONTACT: Mr. 

Jim Eddinger, Energy Strategies Group, 

Sector Policies and Programs Division 

(D243–01), Environmental Protection 

Agency, Research Triangle Park, North 

Carolina 27711; telephone number: 

(919) 541–5426; facsimile 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 the preamble. 

I. General Information 

A. What is the source of authority for the 

reconsideration action? 

B. What entities are potentially affected by 

the reconsideration action? 

C. What should I consider as I prepare my 

comments for the EPA? 

II. Background 

III. Discussion of the Issues under 

Reconsideration 

A. Startup and Shutdown Provisions 

B. CO Limits Based on a Minimum CO 

Level of 130 ppm 

C. Use of PM CPMS Including 

Consequences of Exceeding the 

Operating Parameter 

IV. Technical Corrections and Clarifications 

V. Affirmative Defense for Violation of 

Emission Standards During Malfunction 

VI. Solicitation of Public Comment and 

Participation 

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 (PRA) 

C. Regulatory Flexibility Act (RFA) 

D. Unfunded Mandates Reform Act 

(UMRA) 

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. What is the source of authority for 

the reconsideration action? 

The statutory authority for this action 

is provided by sections 112 and 

307(d)(7)(B) of the Clean Air Act as 

amended (42 U.S.C. 7412 and 

7607(d)(7)(B)). 

B. What entities are potentially affected 

by the reconsideration action? 

Categories and entities potentially 

regulated by this action include: 

Category NAICS Code 1 Examples of potentially regulated entities 

Any industry using a boiler or process 

heater as defined in the final rule.

211 Extractors of crude petroleum and natural gas. 

321 Manufacturers of lumber and wood products. 

322 Pulp and paper mills. 

325 Chemical manufacturers. 

324 Petroleum refineries, and manufacturers of coal products. 

316, 326, 339 Manufacturers of rubber and miscellaneous plastic products. 

331 Steel works, blast furnaces. 

332 Electroplating, plating, polishing, anodizing, and coloring. 

336 Manufacturers of motor vehicle parts and accessories. 

221 Electric, gas, and sanitary services. 

622 Health services. 

611 Educational services. 

1 North American Industry Classification System. 

This table is not intended to be 

exhaustive, but rather provides a guide 

for readers regarding entities likely to be 

affected by this action. To determine 

whether your boiler or process heater is 

regulated by this action, you should 

examine the applicability criteria in 40 

CFR 63.7485. If you have any questions 

regarding the applicability of this action 

to a particular entity, consult either the 

air permitting authority for the entity or 

your EPA regional representative, as 

listed in 40 CFR 63.13 of subpart A 

(General Provisions). 

C. What should I consider as I prepare 

my comments for the EPA? 

Submitting CBI. Do not submit this 

information to the EPA through 

regulations.gov or email. 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. Information so marked 

will not be disclosed except in 

accordance with procedures set forth in 

40 CFR part 2. Send or deliver 

information identified as CBI to only the 

following address: Mr. Jim Eddinger, 

c/o OAQPS Document Control Officer 

(Mail Drop C404–02), U.S. EPA, 

Research Triangle Park, NC 27711, 

Attention Docket ID No. EPA–HQ– 

OAR–2002–0058. 

Docket. The docket number for this 

notice is Docket ID No. EPA–HQ–OAR– 

2002–0058. 

World Wide Web (WWW). In addition 

to being available in the docket, an 

electronic copy of this notice will be 

posted on the WWW through the 


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1The EPA is still reviewing the other issues 

raised in the petitions for reconsideration and is not 

taking any action at this time with respect to those 

issues. 

Technology Transfer Network Web site 

(TTN Web). Following signature, the 

EPA will post a copy of this notice at 

http://www.epa.gov/ttn/atw/boiler/

boilerpg.html. The TTN provides 

information and technology exchange in 

various areas of air pollution control. 

II. Background 

On March 21, 2011, the EPA 

promulgated national emissions 

standards for hazardous air pollutants 

(NESHAP) for the Major Source Boilers 

and Process Heaters source category. 

The EPA received a number of petitions 

for reconsideration on that action, and 

granted reconsideration on certain 

issues raised in the petitions. On 

January 31, 2013, the EPA promulgated 

amendments to the NESHAP for new 

and existing industrial, commercial, and 

institutional boilers and process heaters 

located at major sources (78 FR 7138). 

Following promulgation of the January 

31, 2013, final rule, the EPA received 10 

petitions for reconsideration pursuant to 

section 307(d)(7)(B) of the Clean Air Act 

(CAA). The EPA received petitions 

dated March 28, 2013, from New Hope 

Power Company and the Sugar Cane 

Growers Cooperative of Florida. The 

EPA received a petition dated March 29, 

2013, from the Eastman Chemical 

Company. The EPA received petitions 

dated April 1, 2013, from Earthjustice, 

on behalf of Sierra Club, Clean Air 

Council, Partnership for Policy Integrity, 

Louisiana Environmental Action 

Network, and Environmental Integrity 

Project; American Forest and Paper 

Association on behalf of American 

Wood Council, National Association of 

Manufacturers, Biomass Power 

Association, Corn Refiners Association, 

National Oilseed Processors 

Association, Rubber Manufacturers 

Association, Southeastern Lumber 

Manufacturers Association, and U.S. 

Chamber of Commerce; the Florida 

Sugar Industry; Council of Industrial 

Boiler Owners, American Municipal 

Power, Inc., and American Chemistry 

Council; American Petroleum Institute; 

and the Utility Air Regulatory Group 

which also submitted a supplemental 

petition on July 3, 2013. Finally, the 

EPA received a petition dated July 2, 

2013, from the Natural Environmental 

Development Association’s Clean Air 

Project and the Council of Industrial 

Boiler Owners. The petitions are 

available for review in the rulemaking 

docket (see Docket ID No. EPA–HQ– 

OAR–2002–0058). 

On August 5, 2013, the EPA issued 

letters to the petitioners granting 

reconsideration on three specific issues 

raised in the petitions for 

reconsideration and indicating that the 

agency would issue a Federal Register 

notice regarding the reconsideration 

process.1 This action requests comment 

on the three issues for which the EPA 

granted reconsideration and proposes 

certain revisions to the definitions of 

startup and shutdown and the work 

practices that apply during startup and 

shutdown periods. Additionally, the 

letters indicated that the EPA intends to 

make certain clarifying changes and 

corrections to the final rule, some of 

which were also raised in the petitions 

for reconsideration. This action 

proposes revisions to the regulatory text 

that would make those clarifications 

and corrections. 

III. Discussion of the Issues Under 

Reconsideration 

The EPA took final action on its 

proposed amendments to the March 

2011 NESHAP on January 31, 2013, (78 

FR 7138) to address certain issues raised 

in the petitions for reconsideration of 

the 2011 NESHAP. 

The January 31, 2013, amendments 

revised, among other things, the 

definitions of ‘‘startup’’ and 

‘‘shutdown’’ as well as the work 

practice requirements for the startup 

and shutdown periods. The 

amendments also established a carbon 

monoxide (CO) threshold level as an 

appropriate minimum maximum 

achievable control technology (MACT) 

floor level that adequately assures 

sources will be controlling organic HAP 

emissions to MACT levels. The 

amendments also replaced the 

requirement for certain units to install 

and operate a continuous emission 

monitoring system (CEMS) measuring 

particulate matter (PM) emissions with 

a requirement to install and operate a 

PM continuous parameter monitoring 

system (CPMS) which established 

reporting requirements for deviations 

and established conditions under which 

PM CPMS deviations would constitute a 

presumptive violation of the NESHAP. 

The EPA received petitions for 

reconsideration of certain aspects of 

these requirements, and granted 

reconsideration of the following three 

issues on August 5, 2013, to provide an 

additional opportunity for public 

comment: 

• Definition of startup and shutdown 

periods and the work practices that 

apply during such periods; 

• Revised CO limits based on a 

minimum CO level of 130 parts per 

million (ppm); and 

• The use of PM CPMS, including the 

consequences of exceeding the 

operating parameter. 

The reconsideration petitions stated 

that the public lacked sufficient 

opportunity to comment on these 

provisions. Although these provisions 

were established after consideration of 

public comments received on the 

proposed rule, the EPA is granting 

reconsideration on these issues in order 

to allow an additional opportunity for 

comment. These issues are discussed in 

more detail in the following sections. 

For the startup and shutdown 

provisions, the EPA is proposing certain 

revisions to the definitions of startup 

and shutdown and to the work practice 

standard that applies during the startup 

and shutdown periods. The proposed 

revision to the definition of startup is 

the addition of an alternate definition of 

startup. The revision to the work 

practice standard that applies during the 

startup period is the addition of an 

alternate work practice provision 

regarding the engaging of control 

devices that applies during startup 

periods. The EPA is not proposing 

revisions to the CO limits or the use of 

PM CPMS, but will consider any input 

that we receive in this additional public 

comment opportunity. 

Additionally, the EPA is proposing 

certain clarifying changes and 

corrections to the final rule, some of 

which were also raised in the petitions 

for reconsideration. Specifically, these 

are: (1) Clarify issues related to the 

applicability of the major source boiler 

rule to natural gas-fired electric utility 

steam generating units (EGUs); (2) 

clarify the compliance date for coal- or 

oil-fired EGUs that become subject to 

the major source boiler rule; (3) correct 

a conversion error in the MACT floor 

calculation for existing hybrid 

suspension grate boilers; (4) clarify 

certain recordkeeping requirements, 

including, for example, those related to 

records for periods of startup and 

shutdown for boilers and process 

heaters in the Gas 1 subcategory. The 

EPA also proposes to clarify and correct 

certain inadvertent inconsistencies in 

the final rule regulatory text, such as 

removal of unnecessary references to 

statistical equations, inclusion of 

averaging time for operating load limits 

in Table 8 to the final rule, and 

correction of the compliance date for 

new sources to reflect the effective date 

of the final rule. 

A. Startup and Shutdown Provisions 

The EPA received petitions asserting 

that the public lacked an opportunity to 

comment on the startup and shutdown 

provisions amended in the January 


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2013, final rule. Specifically, petitioners 

asserted that the definitions of ‘‘startup’’ 

and ‘‘shutdown’’ in the amended final 

rule failed to address restarts of process 

heaters and that the provisions for work 

practice standards did not adequately 

address fuels considered ‘‘clean’’ and 

operational limitations for certain 

pollution control devices. 

In response to petitions for 

reconsideration received on the March 

2011 NESHAP, the EPA proposed 

definitions of ‘‘startup’’ and 

‘‘shutdown’’ in December 2011 that 

were based on load specifications. The 

EPA received comments on the 

proposed definitions stating that load 

specifications within the definitions 

were inconsistent with either safe or 

normal (proper) operation of the various 

types of boilers and process heaters 

encountered within the source category. 

As the basis for defining periods of 

startup and shutdown, a number of 

commenters suggested that the EPA 

instead use the achievement of various 

steady-state conditions. The definitions 

in the January 2013 final rule addressed 

these comments by defining startup and 

shutdown based on the time during 

which fuel is fired in a boiler or process 

heater for the purpose of supplying 

steam or heat for heating and/or 

producing electricity or for any other 

purpose. As explained in the preamble 

to the January 2013 final rule, the EPA 

believes these definitions are 

appropriate because boilers and process 

heaters function to provide steam or 

heat; therefore, boilers and process 

heaters should be considered to be 

operating normally at all times steam or 

heat of the proper pressure, temperature 

and flow rate is being supplied to a 

common header system or energy 

user(s) for use as either process steam or 

for the cogeneration of electricity. 

The EPA also proposed work 

practices for startup and shutdown 

periods in the December 2011 notice, 

which generally required employing 

good combustion practices. In the 

January 2013 final rule, the EPA revised 

the proposed work practice standards 

after consideration of comments 

received. Among other things, the 

revised final work practice standards 

required sources to combust clean fuels 

during startup and shutdown periods 

and required sources to engage air 

pollution control devices (APCDs) when 

coal, biomass or heavy oil are fired in 

the boiler or process heater. (See 78 FR 

7198–99.) 

We are granting reconsideration on 

the definitions of startup and shutdown 

and the work practices that apply 

during these periods that are in the 

January 2013 final rule and are also 

proposing certain revisions to these 

aspects of the startup and shutdown 

provisions that are in the January 2013 

final rule. We are also proposing an 

alternate definition of startup and an 

alternate work practice provision 

regarding the engaging of pollution 

control devices. 

1. Definitions 

We are soliciting comment on the 

definition of startup and shutdown that 

were promulgated in the January 2013 

final rule, with the clarifying revisions 

explained below. We are proposing to 

revise the definitions of startup and 

shutdown in this reconsideration notice 

as set forth in 40 CFR 63.7575. 

Petitioners asserted that the final rule’s 

definitions of startup and shutdown 

were not sufficiently clear. We are 

proposing to revise the definitions as 

explained below. 

a. Definition of Startup Period. In 

addition to soliciting public comment 

on the definition of startup contained in 

the January 2013 final rule, the EPA is 

proposing to add an alternate definition 

to the definition of startup that is in the 

January 2013 final rule. We are 

proposing to allow sources to use either 

definition of startup when complying 

with the startup requirements. As 

explained in more detail below, under 

the alternate definition, startup would 

end four hours after the unit begins 

supplying useful thermal energy. 

Specifically, the EPA is proposing the 

alternate definition to clarify that, in 

terms of the first-ever firing of fuel, 

startup begins when fuel is fired for the 

purpose of supplying useful thermal 

energy (such as steam or heat) for 

heating, process, cooling, and/or 

producing electricity and to clarify that 

startup ends 4 hours after when the 

boiler or process heater makes useful 

thermal energy. The proposed 

clarification regarding the end of startup 

would apply to first-ever startups as 

well as startups occurring after 

shutdown events. With regard to when 

startup begins after a shutdown event, 

the alternate definition is the same as 

the definition in the January 31, 2013, 

final rule. That is, startup begins with 

the firing of fuel in a boiler for any 

purpose after a shutdown event. 

In this alternate definition, we are 

proposing the clarification regarding the 

first-ever firing of fuel to address 

implementation issues regarding ‘‘prestartup’’ activities that are done as part 

of installing a new boiler or process 

heater. Under the January 2013 

definition of ‘‘startup,’’ a new boiler or 

process heater would be considered to 

have started up, and be subject to the 

rule, when it first fires fuel ‘‘for any 

purpose.’’ However, a newly installed 

unit needs to be tested to ensure that it 

was properly installed and will operate 

as it was designed and that all 

associated components were also 

properly installed and will operate as 

designed. The EPA did not intend for 

the startup period to begin when newly 

installed units first fire fuel for testing 

or other pre-startup purposes because 

such firing of fuel does not represent 

normal operation of the unit. 

The EPA is also proposing in the 

alternate definition to replace the term 

‘‘steam and heat’’ in the January 2013 

definition of startup with the term 

‘‘useful thermal energy.’’ This proposed 

revision would apply to first-ever 

startups as well as startups after 

shutdown events and is intended to 

address the issue raised by petitioners 

that the language in the January 2013 

definition regarding the end of the 

startup period is ambiguous since once 

fuel is fired some steam or heat is 

generated but not in useful or 

controllable quantities. The petitioners 

comment that it takes time for steam 

and process fluid to be heated to 

adequate temperatures and pressures for 

beneficial use and that steam or heat 

should not be construed to be supplied 

until it is of adequate temperature and 

pressure. The EPA agrees with 

petitioners that the startup period 

should not end until such time as fuel 

is fired resulting in steam or heat that 

is useful thermal energy because it takes 

time for steam and process fluids to be 

heated to adequate temperatures and 

pressures for beneficial use. We believe 

the appropriate criteria for ending 

startup in the definition should be when 

useful steam is supplied. This proposed 

change doesn’t alter EPA’s 

determination that it is not technically 

feasible to require stack testing, in 

particular, to complete the multiple 

required test runs during periods of 

startup and shutdown due to physical 

limitations and the short duration of 

startup and shutdown periods. 

In order to clarify the term ‘‘useful 

thermal energy,’’ we are proposing a 

definition for ‘‘useful thermal energy’’ 

as follows: 

Useful thermal energy means energy 

(i.e., steam, hot water, or process heat) 

that meets the minimum operating 

temperature and/or pressure required by 

any energy use system that uses energy 

provided by the affected boiler or 

process heater. 

The EPA received several petitions for 

reconsideration of the definition of 

startup in the January 2013 final rule. 

The petitioners commented that this 

definition does not account for a wide 

range of boilers that operationally are 


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2 It is important to remember that the hour at 

which startup ends is the hour at which reporting 

for the purpose of determining compliance begins. 

Therefore, sources must collect and report operating 

limit data following the end of startup. These data 

are used in calculating whether a source is in 

compliance with the 30-day average operating 

limits. 

still in startup mode even after some 

steam or heat is supplied to the plant. 

Specifically, the petitioners commented 

that what constitutes ‘‘startup’’ for all 

boilers varies widely. For example, 

petitioners claimed that some boilers 

begin to supply steam or heat for some 

purposes onsite before they have 

achieved necessary temperature or load 

to engage emission controls. 

The petitioners commented that 

according to the final rule, a boiler 

supplying even a small amount of steam 

would no longer be in startup and 

would be required at that point in time 

to engage emission controls. However, 

petitioners noted that according to 

equipment specifications and 

established safe boiler operations, a 

boiler operator should not engage 

emission controls until specific 

parameters are met. 

The petitioners expressed that, above 

all, the boiler/process heater operator’s 

primary concern during startup is 

safety. The startup procedures must 

ensure that the equipment is brought up 

to normal operating conditions in a safe 

manner, and startup ends when the 

boiler/process heater and its controls are 

fully functional. The end of startup 

occurs when safe, stable operating 

conditions are reached, after emissions 

controls are properly operating. The 

startup provisions should not include 

requirements that could affect safe 

operating practices. 

The EPA agrees with the petitioners 

that the startup period should not end 

until such time that all control devices 

have reached stable conditions. The 

EPA has very limited information 

specifically for industrial boilers on the 

hours needed for controls to reach stable 

conditions after the start of supplying 

useful thermal energy. However, the 

EPA does have information for EGUs on 

the hours to stable control operation 

after the start of electricity generation. 

Using hour-by-hour emissions and 

operation data for EGUs reported to the 

agency under the Acid Rain Program, 

we found that controls used on the best 

performing 12 percent EGUs reach 

stable operation within 4 hours after the 

start of electricity generation. See 

technical support document titled 

‘‘Assessment of Startup Period at CoalFired Electric Generating Units— 

Revised’’ in the docket. Since the types 

of controls used on EGUs are similar to 

those used on industrial boilers and the 

start of electricity generation is similar 

to the start of supplying useful thermal 

energy, we believe that the controls on 

the best performing industrial boilers 

would also reach stable operation 

within 4 hours after the start of 

supplying useful thermal energy and 

have included this timeframe in the 

proposed alternate definition.2 This 

conclusion is supported by the very 

limited information (13 units) the EPA 

does have on industrial boilers and by 

information submitted by the Council of 

Industrial Boiler Owners obtained from 

an informal survey of its members on 

the time needed to reach stable 

conditions during startup. We welcome 

comment and additional information on 

this point during the public comment 

period. 

b. Definition of Shutdown. In today’s 

action, the EPA is proposing to revise 

the definition of shutdown in the 

January 2013 final rule. The EPA is 

proposing to clarify that shutdown 

begins when the boiler or process heater 

no longer makes useful thermal energy 

and ends when the boiler or process 

heater no longer makes useful thermal 

energy and no fuel is fired in the boiler 

or process heater. Specifically, the EPA 

is proposing to revise the regulatory text 

to replace the term ‘‘steam and heat’’ 

with the term ‘‘useful thermal energy’’ 

to address the same issue as raised by 

petitioners regarding the language in the 

definition of ‘‘startup’’ described above. 

The EPA did not intend for the 

shutdown period to begin until such 

time as fuel is no longer fired for the 

purpose of creating useful thermal 

energy. 

The EPA received several petitions for 

reconsideration of the definition of 

shutdown in the January 2013 final rule. 

The petitioners expressed concerns that 

the definition is problematic for units 

firing solid fuels on a grate or in a 

fluidized bed combustor where the 

residual material in the unit keeps 

burning after fuel feed to the unit is 

stopped. In this case, petitioners 

explained that fuel is still burning 

(‘‘being fired’’) in the unit despite the 

fact that load reduction is occurring, 

additional fuel is not being fed, and the 

shutdown process has clearly begun. 

For this reason, petitioners recommend 

that the shutdown definition be revised 

to state that shutdown begins either 

when none of the steam and heat from 

the boiler or process heater is supplied 

for heating and/or producing electricity 

or when fuel is no longer being fed to 

the boiler or process heater and that 

shutdown ends when there is both no 

steam or heat being supplied and no 

fuel being combusted in the boiler or 

process heater. 

The EPA agrees with the petitioners’ 

concerns and intended that the 

shutdown period would begin when 

fuel is no longer being fired for the 

purpose of creating useful thermal 

energy. The proposed revisions would 

address the concern raised by the 

petitioner. The proposed revision is 

appropriate because as the petitioners 

commented, for certain types of boilers 

where the fuel is combusted on a grate 

or bed, fuel firing may be considered to 

continue even after fuel feed to the unit 

is stopped. 

2. Work Practice Standards 

In today’s action, the EPA is 

proposing to revise the work practice 

standards in the January 2013 final rule 

that apply during periods of startup and 

shutdown. Specifically, the EPA is 

proposing revisions to the list of ‘‘clean 

fuel’’ in the January 2013 final rule and 

is proposing an alternate work practice 

requirement for periods of startup and 

shutdown. Sources would have the 

choice of complying with the work 

practice requirement contained in the 

January 2013 final rule or the alternate 

work practice requirement proposed in 

today’s action. Additionally, EPA is 

proposing a process through which 

sources can seek an extension of the 

time period by which the alternate work 

practice provision requires PM controls 

to be engaged, based on documented 

safety considerations. Finally, EPA is 

proposing certain recordkeeping and 

monitoring requirements that would 

apply to sources that choose to comply 

with the alternate work practice. These 

proposed provisions are described in 

more detail below. 

a. Clean Fuel Requirement. The 

January 2013 final rule requires sources 

to startup on ‘‘clean fuel.’’ The 

definition of ‘‘clean fuel’’ includes 

several fuels but does not include coal 

or biomass or other solid fuels that 

many sources use during boiler startup. 

In the December 2011 proposed rule, we 

solicited comment on ‘‘whether other 

work practices should be required 

during startup and shutdown, including 

requirements to operate using specific 

fuels to reduce emissions during such 

periods.’’ 

In a petition for reconsideration, the 

petitioners claimed that the list of clean 

fuels, as written, is too narrow. They 

requested that the EPA expand the list 

to include all gaseous fuels meeting the 

‘‘other gas 1’’ classification as well as 

biodiesel, as distillate oil is sometimes 

a biodiesel blend. They also requested 

that fuels that meet the total selected 

metals (TSM), hydrogen chloride (HCl), 


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and mercury emission limits using fuel 

analysis should be added to the list of 

clean fuels. Dry biomass (less than 20- 

percent moisture content) should also 

be added to the list of clean fuels 

because they claim it will burn cleaner 

than other solid fuels. Specifically, they 

claim that it is a clean fuel for startup 

because it exhibits low HCl, mercury 

and CO emissions due to its chloride, 

mercury, and moisture content, and PM 

emissions would likely be below the dry 

biomass subcategory PM limit. 

Therefore, the petition states that it is a 

reasonable work practice for solid fuel 

boilers to burn only dry biomass as 

clean fuel during startup. In addition, 

the petition recommends that permitting 

authorities should have the flexibility to 

approve other clean fuels that EPA may 

not have considered (e.g., other 

renewable fuels). 

We are proposing two changes to the 

list of clean fuels for starting up a boiler 

or process heater. We agree that the list 

should include all gaseous fuels meeting 

the ‘‘other gas 1’’ classification. Also, we 

agree that any fuels that meet the 

applicable TSM, HCl and mercury 

emission limits using fuel analysis 

should be added to the list of clean fuels 

because their mercury, HCl and metals 

emissions would be in compliance with 

the applicable emission limits without 

the use of control devices. Sources 

would demonstrate compliance either 

through fuel analysis for the relevant 

parameters or stack testing. The EPA 

does not believe it is necessary to revise 

the regulatory text of the ‘‘clean fuel’’ 

definition to specifically include 

biodiesel on the list since the definition 

of ‘‘distillate oil’’ in the rule includes 

biodiesel. 

b. Engaging Pollution Control Devices. 

The January 2013 final rule required 

boilers and process heaters when they 

start firing coal/solid fossil fuel, 

biomass/bio-based solids, heavy liquid 

fuel or gas 2 (other) gases to engage 

applicable pollution control devices 

except for limestone injection in 

fluidized bed combustion (FBC) boilers, 

dry scrubbers, fabric filters, selective 

non-catalytic reduction (SNCR) and 

selective catalytic reduction (SCR), 

which must start as expeditiously as 

possible. The EPA received several 

petitions for reconsideration of this 

aspect of the work practice standard. 

The petitioners expressed concerns 

that the requirement for engaging 

applicable control devices does not 

accommodate potential safety problems 

relative to electrostatic precipitator 

(ESP) operation. Comments and 

recommended manufacturer operating 

procedures provided to the EPA during 

the comment period for the December 

2011 proposal explained the potential 

hazards associated with ESP 

energization when unburned fuel may 

be present with oxygen levels high 

enough that the mixture can be in the 

flammable range. The petitioners 

referenced these comments and 

requested that the EPA needs to 

reconsider this safety issue and revise 

the requirements to include ESP 

energization with the other controls that 

are to be started as expeditiously as 

possible rather than when solid fuel 

firing is first started. In addition, they 

claim that the ESP cannot practically be 

engaged until a certain flue gas 

temperature is reached. Specifically, 

they claim that premature starting of 

this equipment will lead to short-term 

stability problems that could result in 

unsafe actions and longer term 

degradation of ESP performance due to 

fouling, increased chances of wire 

damage, or increased corrosion within 

the chambers. They also state that 

vendors providing this equipment 

incorporate these safety and operational 

concerns into their standard operating 

procedures. For example, they claim 

that some ESPs have oxygen sensors and 

alarms that shut down the ESP at high 

flue gas oxygen levels to avoid a fire in 

the unit. The oxygen level is typically 

high during startup, so the ESP may not 

engage due to these safety controls until 

more stable operating conditions are 

reached. Therefore, the petitioners 

request that ESPs be included in the list 

of air pollution controls that must be 

started as expeditiously as possible. 

Considering the petitioners’ 

comments, the EPA is proposing an 

alternate work practice requirement for 

operating air pollution control devices 

during periods of startup as follows. 

Boilers and process heaters owners 

and operators shall, when firing coal/

solid fossil fuel, biomass/bio-based 

solids, heavy liquid fuel or gas 2 (other) 

gases, vent emissions to the main 

stack(s) and engage all of the applicable 

control devices so as to comply with the 

emission limits within 4 hours of start 

of supplying useful thermal energy. 

Owners and operators must effect PM 

control within one hour of first firing 

coal/solid fossil fuel, biomass/bio-based 

solids, heavy liquid fuel or gas 2 (other) 

gases. Owners and operators must start 

all applicable control devices as 

expeditiously as possible, but, in any 

case, when necessary to comply with 

other standards applicable to the source 

by a permit limit or a rule other than 

this subpart that require operation of the 

control devices. 

The EPA believes that the control 

technology operation related 

requirements we are proposing are 

practicable and broadly applicable. 

Owners and operators of boilers and 

process heaters have options to 

minimize any potential for detrimental 

impacts on hardware and any safety 

concerns, such as using clean fuels until 

appropriate flue gas conditions have 

been reached and then switching to the 

primary fuel. In addition, we are 

proposing in the alternate work practice 

requirement that owners and operators 

of boilers and process heaters, if they 

have an applicable emission limit, must 

develop and implement a written 

startup and shutdown plan (SSP) 

according to the requirements in Table 

3 to this subpart and that the SSP must 

be maintained onsite and available upon 

request for public inspection. Also in 

the alternate work practice requirement, 

we are proposing to allow a source to 

request a unit-specific case-by-case 

extension to the 1-hour period for 

engaging the PM controls. However, the 

EPA will only consider extensions for 

units that can provide evidence of a 

documented manufacturer-identified 

safety issue and can provide proof that 

the PM control device is adequately 

designed and sized to meet the filterable 

PM emission limit. In its request for the 

case-by-case determination, the owner/

operator must provide, among other 

materials, documentation that: (1) The 

unit is using clean fuels to the 

maximum extent possible to alleviate or 

prevent the safety issue prior to the 

combustion of coal/solid fossil fuel, 

biomass/bio-based solids, heavy liquid 

fuel or gas 2 (other) gases in the unit, (2) 

the source has explicitly followed the 

manufacturer’s procedures to alleviate 

or prevent the safety issue, (3) details 

the manufacturer’s statement of 

concern, and (4) provides evidence that 

the PM control device is adequately 

designed and sized to meet the PM 

emission limit. 

In order to clarify that the work 

practice does not supersede any other 

standard or requirements to which the 

affected source is subject, the EPA is 

including in the proposed alternate 

work practice provision a requirement 

that requires control devices to operate 

when necessary to comply with other 

standards (e.g., new source performance 

standards, state regulations) applicable 

to the source that require operation of 

the control device. 

In addition, to ensure compliance 

with the proposed definition of startup 

and the work practice standard that 

applies during startup periods, we are 

proposing that certain events and 

parameters be monitored and recorded 

during the startup periods. These events 

include the time when firing (i.e., 

feeding) starts for coal/solid fossil fuel, 


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biomass/bio-based solids, heavy liquid 

fuel or gas 2 (other) gases; the time 

when useful thermal energy is first 

supplied; and the time when the PM 

controls are engaged. The parameters to 

be monitored and recorded include the 

hourly steam temperature, hourly steam 

pressure, hourly flue gas temperature, 

and all hourly average CMS data (e.g., 

CEMS, PM CPMS, continuous opacity 

monitoring systems (COMS), ESP total 

secondary electric power input, 

scrubber pressure drop, scrubber liquid 

flow rate) collected during each startup 

period to confirm that the control 

devices are engaged. 

We request comments on (1) the 

startup and shutdown provisions 

(definitions and work practices) in the 

January 2013 final rule, (2) the proposed 

alternate definition for ‘‘startup’’ and 

the proposed alternate work practice 

(item 5.c.(2) of Table 3 of proposed rule) 

for the startup period, and (3) the 

recordkeeping requirements being 

proposed for the startup periods. 

B. CO Limits Based on a Minimum CO 

Level of 130 ppm 

In the January 2013 final rule, EPA 

established a CO emission limit for 

certain subcategories at a level of 130 

ppm, based on an analysis of CO levels 

and associated organic HAP emissions 

reductions. See 78 FR 7144. The EPA 

received a petition for reconsideration 

of these CO limits in the January 2013 

final rule. The petitioner claimed that 

these limits do not satisfy the statutory 

requirement that the MACT standard for 

existing sources is no less stringent than 

the average emission limitation 

achieved by the best performing twelve 

percent of units in the subcategory and 

that EPA’s rationale for adopting these 

limits is unrelated to this statutory 

MACT requirement. 

The EPA revised these particular CO 

limits in the January 2013 final rule in 

part based on comments received during 

the comment period for the December 

2011 proposed rule stating that a CO 

emission standard no lower than 100 

ppm, corrected to 7-percent oxygen, is 

adequate to assure complete control of 

organic HAP. 

As explained in the preamble to the 

January 2013 final rule, formaldehyde 

was selected as the basis of the organic 

HAP comparison because it was the 

most prevalent organic HAP in our 

emission database and a large number 

(over 300) of paired test runs existed for 

CO and formaldehyde. The linear 

relationship between CO and 

formaldehyde emissions exhibits a high 

correlation for CO levels above 150 

ppm, supporting the selection of CO as 

a surrogate for organic HAP emissions. 

In assessing the correlation between CO 

and formaldehyde, a trend can be seen 

that formaldehyde levels are lowest 

when CO emissions are in the range of 

150 to 300 ppm. At levels lower than 

150 ppm, the mean levels of 

formaldehyde appear to increase. Based 

on this analysis, we promulgated a 

minimum MACT floor level for CO of 

130 ppm, at 3-percent oxygen, (which is 

equivalent to 100 ppm corrected to 7- 

percent oxygen) which we believe is 

protective of human health and the 

environment. 

The EPA does not believe the 

petitioners have provided sufficient 

justification that the revised CO limits 

in the January 2013 final rule do not 

satisfy the CAA’s statutory floor 

requirements, and the EPA continues to 

believe that these standards do in fact 

satisfy the CAA’s floor requirements. 

CAA section 112(d)(3) states that 

emission standards for existing sources 

shall not be less stringent, and may be 

more stringent than ‘‘the average 

emission limitation achieved by the best 

performing sources (for which the 

Administrator has emission 

information).’’ If ‘‘lowest emitting’’ is 

used as the measure for determining 

‘‘best performing’’ sources, then the 130 

ppm standard does satisfy the CAA’s 

floor requirements. When the available 

formaldehyde emission information is 

ranked and the best performing 12 

percent identified, the mathematical 

average of the best performing units’ 

corresponding CO emission levels is 240 

ppm which is in the range, previously 

indicated, that formaldehyde emission 

levels are lowest. 

However, in consideration of the fact 

that the public lacked the opportunity to 

comment on the CO emission limits 

established at the level of 130 ppm, 

corrected to 3-percent oxygen, the EPA 

has granted reconsideration on the CO 

emission limits established at the level 

of 130 ppm, corrected to 3-percent 

oxygen, to provide an additional 

opportunity for public comment on 

those limits. The EPA is not soliciting 

comment on any other CO limits, or on 

other issues relating to establishment of 

CO limits, including the question of 

whether EPA should establish work 

practice standards for CO instead of 

numeric limits. 

If, after evaluating all comments and 

data received on this issue, the EPA 

determines that amendments to the CO 

emission limits established at the level 

of 130 ppm, corrected to 3-percent 

oxygen, may be appropriate, we will 

propose such amendments in a future 

regulatory action. 

C. Use of PM CPMS Including 

Consequences of Exceeding the 

Operating Parameter 

The January 2013 amended final rule 

requires units combusting solid fossil 

fuel or heavy liquid with heat input 

capacities of 250 million British thermal 

units per hour (MMBtu/hr) or greater to 

install, maintain, and operate PM 

CPMS. The provisions regarding PM 

CPMS in the January 2013 final rule are 

consistent with regulations for 

similarly-sized commercial and 

industrial solid waste incinerator units, 

Portland cement kilns, and EGUs 

subject to the Mercury and Air Toxics 

Standards (MATS) Rule. 

The March 21, 2011, final rule 

required boilers with a heat input rate 

greater than 250 MMBtu/hr from solid 

fuel and/or residual oil to install and 

operate a PM CEMS to demonstrate 

compliance with the applicable PM 

emission limit. In petitions for 

reconsideration to the March 2011 final 

rule, petitioners objected to this 

requirement, claiming that the EPA had 

failed to consider the ability of PM 

CEMS to meet the required Performance 

Specification 11 (PS 11) criteria, or to 

accurately measure PM, at the levels of 

the proposed standards. In the 

December 2011 Reconsideration 

proposal, the EPA acknowledged 

petitioners’ concerns regarding 

application of PM CEMS technology to 

various types of boilers, and concluded 

that for coal- and oil-fired boilers PM 

CEMS would best be employed as 

parametric monitors (i.e., as a PM 

CPMS). Specifically, rather than 

correlate the PM CEMS to the EPA 

reference method using PS 11, the EPA 

proposed that sources establish a sitespecific enforceable operating limit in 

terms of the PM CPMS output during 

the initial and periodic performance 

tests, and meet that operating limit on 

a 30-day rolling average basis. However, 

commenters objected to the EPA’s 

proposal to impose an enforceable sitespecific operating limit based on output 

during a short-term stack test which 

would not capture the variability in PM 

CPMS output that may occur during 

operations consistent with the PM limit. 

In the January 2013 final rule, the 

EPA finalized the requirement for use of 

a PM CPMS, but added provisions 

allowing sources a certain number of 

exceedances of the operating parameter 

limit before an exceedance would be 

presumed to be a violation, and 

allowing certain low emitting sources to 

‘‘scale’’ their site-specific operating 

limit to 75 percent of the emission 

standard. Specifically, under the 

January 2013 final rule, boilers opting to 


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use PM CPMS will establish an 

operating limit as the average parameter 

value (in terms of raw output from a PM 

CEMS) obtained during the performance 

test and, if the boiler did not exceed 75 

percent of the emission limit during the 

performance test, the boiler may linearly 

scale the average parameter value up to 

75 percent of the limit to obtain a new 

scaled parameter. Compliance with the 

parameter limit is determined on a 30- 

boiler-operating-day rolling average 

basis. For any exceedance of the 30- 

boiler-operating-day PM CPMS value, 

the owner or operator must (1) inspect 

the control device within 48 hours and, 

if a cause is identified, take corrective 

action as soon as possible, and (2) 

conduct a new performance test to 

verify or reestablish the operating limit 

within 30 calendar days. Additional 

exceedances that occur between the 

original exceedance and the 

performance test do not trigger another 

test. Up to four performance tests may 

be triggered in a 12-month rolling 

period without additional 

consequences. However, each additional 

performance test that is triggered would 

constitute a separate presumptive 

violation. 

The EPA received a petition for 

reconsideration on the use of PM CPMS. 

Specifically, the petitioner stated that 

while the option has the advantage of 

avoiding the testing issues associated 

with PS 11 correlations of PM CEMS, 

absent that correlation the parameter is 

nothing more than an indicator that PM 

may be increasing or decreasing. 

Therefore, while it is useful as a tool to 

identify the need for investigation and 

corrective action, the petitioner does not 

believe it is an appropriate tool to 

establish a violation as long as the 

requirement for corrective action is met. 

The petitioner claimed that any 

affected boiler that tests at its normal 

operating condition to establish a PM 

CPMS operating limit could be testing at 

a level well below the applicable 

emission limit. For such a boiler, the 

petitioner does not believe there is any 

basis to assume that an exceedance (or 

even multiple exceedances) of a 30- 

boiler-operating-day rolling average 

parameter limit indicates that the 

emission limit was exceeded, or that 

controls were not operated properly. 

Rather, the petitioner claims, it simply 

means that emissions on average 

probably were above the level of 

emissions during the last successful 

performance test. Unless the source has 

collected data to determine what PM 

CPMS parameter level is equivalent to a 

violation of the emission standard, the 

petitioner states that there is no basis to 

suggest that any parameter exceedance 

is a violation. The petitioner also argued 

that if a source that has invested in a PM 

CPMS is conducting appropriate 

investigations and corrective action in 

response to parameter exceedances, 

there is no basis to label the source a 

violator as a result of its fourth 

successful performance test in a 12- 

month period. 

In its petition for reconsideration, the 

petitioner also expressed concerns about 

the scaling procedure that the EPA 

added to that rule in an attempt to 

address the fact that ‘‘actual stack 

emissions of PM could still be well 

below the limit.’’ The petitioner 

expressed appreciation of the EPA’s 

attempt to address that issue for 

industrial boilers by also allowing 

scaling of the as-tested parameter value. 

However, the petitioner claims that 

EPA’s use of 75 percent of the emission 

level as the upper point is arbitrary and 

still puts sources that are operating with 

significant compliance margin at risk of 

a violation. For a scaled limit to justify 

a violation, the petitioner believes that 

the EPA must establish not only the 

consistency of the uncorrelated 

measurements over time, but allow 

scaling up to 100 percent of the 

emission limit. Only at that point would 

there be a reasonable basis to conclude 

that a performance test might have 

failed. 

In sum, the petitioner claimed that for 

PM CPMS to be useful as an alternative 

to stack testing for compliance with the 

alternate TSM standards or PM CEMS, 

the EPA must (1) allow scaling up to 

100 percent of the emission limit, and 

(2) remove its definition of a violation 

in favor of a pure investigation and 

corrective action approach. 

The EPA is not proposing to revise the 

PM CPMS provisions in the January 31, 

2013, final rule. The basis for the 

inclusion of the definition of a violation 

is that the site-specific CPMS limit 

could represent an emissions level 

higher than the proposed numerical 

emissions limit since the PM CPMS 

operating limit corresponds to the 

highest of the three runs collected 

during the Method 5 performance test. 

Second, the PM CPMS operating limit 

reflects a 30-day average that should 

represent an actual emissions level 

lower than the three test run numerical 

emissions limit since variability is 

mitigated over time. Consequently, we 

believe that there should be few if any 

deviations from the 30-day parametric 

limit and there is a reasonable basis for 

presuming that deviations that lead to 

multiple performance tests to represent 

poor control device performance and to 

be a violation of the standard. We 

continue to believe that there should be 

few if any deviations from the 30-day 

parametric limit and that there is a 

reasonable basis for presuming that 

deviations that lead to multiple 

performance tests represent poor control 

device performance and therefore 

constitute a presumptive violation of the 

standard, particularly since that 

presumption can be rebutted. Therefore, 

we continue to believe that PM CPMS 

deviations leading to more than four 

required performance tests in a 12- 

month process operating period should 

be presumed a violation of this 

standard, subject to the source’s ability 

to rebut that presumption with 

information about process and control 

device operations in addition to the 

Method 5 performance test results. 

Therefore, the EPA is not proposing to 

revise that PM CPMS provision in the 

January 2013 final rule. 

Based on an extensive analysis (see S. 

Johnson’s memo ‘‘Establishing an 

Operating Limit for PM CPMS’’, 

November 2012, docket ID number 

EPA–HQ–OAR–2011–0817–0840), we 

also continue to believe a scaling factor 

of 75 percent of the emission limit as a 

benchmark is appropriate and are not 

proposing to revise that provision of the 

January 2013 final rule. We recognized 

that non-linear instruments provide 

increased uncertainty in estimating PM 

concentrations above the performance 

test data point and, after considering 

several options, we determined that the 

75-percent scaling cap was appropriate 

for protecting the emission standard in 

this regard. This option provided 

flexibility for low emitting and welloperated sources, and was determined 

to be a reasonable compromise between 

flexibility for the regulated source and 

assurance that the emission standard is 

met. Seventy-five percent of the 

emission limit is an already-established 

threshold in the Standards of 

Performance for New Stationary Sources 

and Emission Guidelines for Existing 

Sources: Commercial and Industrial 

Solid Waste Incineration Unit (76 FR 

15757) to determine the frequency of 

subsequent compliance testing. In that 

rule, owners or operators of sources 

were able to reduce their performance 

test frequency when emissions were 

equivalent with or below 75 percent of 

the limits. Otherwise, performance 

testing was to occur at the normal 

frequency prescribed in the rule. We 

believe this threshold can be used in 

conjunction within a PM CPMS scaling 

factor, as results above 75 percent of the 

equivalent emissions limit would be 

ineligible for scaling factor use and 

could lead to increased performance 

testing and potentially to a presumptive 


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violation, while results equivalent with 

or below 75 percent of the emissions 

limit would be eligible for scaling factor 

use and provide greater operational 

flexibility for sources demonstrating 

compliance at lower emission rates. 

For these reasons, the EPA is not 

proposing to revise the requirements in 

40 CFR 63.7440(a)(18) for demonstrating 

continuous PM emission compliance 

using a PM CPMS. However, the EPA is 

soliciting additional comment on these 

requirements in today’s action. The EPA 

welcomes comments on these 

provisions, including whether the 

provisions are necessary or appropriate. 

If a commenter suggests revisions to the 

provisions, the commenter should 

provide detailed information supporting 

any such revision. 

IV. Technical Corrections and 

Clarifications 

We are proposing several technical 

corrections. These amendments are 

being proposed to correct inadvertent 

errors that were promulgated in the final 

rule and to make the rule language 

consistent with provisions addressed 

through this reconsideration. We are 

soliciting comment only on whether the 

proposed changes provide the intended 

accuracy, clarity and consistency. These 

proposed changes are described in Table 

1 of this preamble. We request comment 

on all of these proposed changes. 

TABLE 1—MISCELLANEOUS PROPOSED TECHNICAL CORRECTIONS TO 40 CFR PART 63, SUBPART DDDDD 

Section of subpart DDDDD Description of proposed correction 

40 CFR 63.7491(a) .............. Revise the language in this paragraph to clarify that natural gas-fired EGUs as defined in subpart UUUUU are not 

subject to the rule if firing at least 90 percent natural gas. 

40 CFR 63.7491(j) ............... Revise this paragraph to include the words ‘‘and process heaters’’ to clarify that it also applies to process heaters. 

40 CFR 63.7491(l) ............... Revise this paragraph to include the words ‘‘and process heaters’’ to clarify that it also applies to process heaters. 

40 CFR 63.7491(n) .............. Insert paragraph (n) which was in amended final rule but inadvertently had the wrong amendatory instruction to 

be included in the CFR. 

40 CFR 63.7495(a) .............. Revise this paragraph to correctly include the effective date (April 1, 2013) instead of the publication date (January 31, 2013) of the amendments. 

40 CFR 63.7495(e) .............. Revise this paragraph to add the language which was in amended final rule but inadvertently had the wrong 

amendatory instruction to be included in the CFR. 

40 CFR 63.7495(f) ............... Revise this paragraph to correctly list the date (January 31, 2016) after which existing EGUs that become subject 

to the rule must be in compliance. 

40 CFR 63.7495(h) and (i) ... Insert these paragraphs to clarify when existing and new affected units that switch subcategories due to fuel 

switch or physical change must be in compliance with the provisions of the new subcategory. 

40 CFR 63.7500(a) .............. Revise this paragraph to delete the comma after ‘‘paragraphs (b).’’ 

40 CFR 63.7500(a)(1)(ii) ...... Revise this paragraph by adding the words ‘‘on or’’ to include May 20, 2011. 

40 CFR 63.7500(a)(1)(iii) ..... Revise this paragraph by adding the words ‘‘on or’’ to include December 23, 2011 and to correctly include the effective date (April 1, 2013) instead of the publication date (January 31, 2013) of the amendments. 

40 CFR 63.7500(f) ............... Revise this paragraph to clarify that only items 5 and 6 of Table 3 apply during periods of startup and shutdown. 

40 CFR 63.7505(a) .............. Revise this paragraph by adding the words ‘‘emission and operating’’ to clarify the limits that apply at all times. 

40 CFR 63.7505(c) .............. Revise this paragraph by adding the word ‘‘stack’’ to clarify that the performance testing referred to is performance stack testing. 

40 CFR 63.7510(a)(2)(ii) ...... Revise this paragraph to clarify our intent on fuel type for the analysis requirements for gaseous fuels. 

40 CFR 63.7510(a) .............. Revise this paragraph by adding the word ‘‘stack’’ to clarify that the performance tests referred to are performance stack test. 

40 CFR 63.7510(c) .............. Revise this paragraph to correct the reference to tables 1 and 2, not 12. 

40 CFR 63.7510(e) .............. Revise this paragraph to remove reference to paragraph (j) for the one-time energy assessment because paragraph (j) only repeat the compliance date as indicated in paragraph (e) and to pluralize the word ‘‘demonstration.’’ 

40 CFR 63.7510(g) .............. Revise this paragraph to correct the references to 40 CFR 63.7515(d), not 40 CFR 63.7540(a) to clarify the appropriate schedule for conducting periodic tune-ups. 

40 CFR 63.7510(i) ............... Revise this paragraph to correctly list the initial compliance date (January 31, 2016). 

40 CFR 63.7510(k) .............. Add this paragraph to clarify the appropriate schedule for conducting performance tests after a switch in subcategory. 

40 CFR 63.7515(d) .............. Revise this paragraph to clarify that the first annual, biennial, or 5-year tune-up must be no later than 13 months, 

25 months, or 61 months, respectively, either after April 1, 2013, or the initial startup of the new or reconstructed affected source, whichever is later. 

40 CFR 63.7515(h) .............. Revise this paragraph to clarify that ‘‘performance tests’’ refers to both stack tests and fuel analyses. 

40 CFR 63.7521(a) .............. Revise this paragraph to clarify that gaseous and liquid fuels are not exempt from the sampling requirements in 

Table 6 of the rule. 

40 CFR 63.7521(c)(1)(ii) ...... Revise this paragraph to remove the requirement to collect monthly samples at 10-day intervals because it is inconsistent with the requirement for monthly fuel analysis in 40 CFR 63.7515(e). 

40 CFR 63.7521(f) ............... Revise this paragraph to clarify that the two methods listed in Table 6 for determining the mercury concentration 

for other gas 1 fuels are alternatives. 

40 CFR 63.7521(g) .............. Revise this paragraph to remove the requirement to submit for review and approval a site-specific fuel analysis 

plan for other gas 1 fuels because paragraph (g)(1) requires the plan to be submitted for review and approval 

only if an alternative analytical method other than those required by Table 6 is intended to be used. 

40 CFR 63.7521(h) .............. Revise this paragraph to remove the reference to sampling procedures listed in Table 6 because there are no 

sampling procedures listed in Table 6 for gaseous fuel. 

40 CFR 63.7522(c) .............. Revise this paragraph by changing wording from ‘‘January 31, 2013’’ (publication date of the amendments) to 

‘‘April 1, 2013’’ (the effective date of the amendments. 

40 CFR 63.7522(d) .............. Revise this paragraph by changing wording from ‘‘operating’’ to ‘‘subject to numeric emission limits’’ to clarify that 

the numeric emission limits do not apply during startup and shutdown periods. 

40 CFR 63.7522(j)(1) ........... Revise Equation 6 to delete ‘‘nanograms per dry standard cubic meter (ng/dscm)’’ from both EN and Eli since 

there are not numeric emission limits for dioxin. 


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Federal Register / Vol. 80, No. 13 / Wednesday, January 21, 2015 / Proposed Rules 3099 

TABLE 1—MISCELLANEOUS PROPOSED TECHNICAL CORRECTIONS TO 40 CFR PART 63, SUBPART DDDDD—Continued 

Section of subpart DDDDD Description of proposed correction 

40 CFR 63.7525(a) .............. Revise the paragraph to clarify that the procedures for installing oxygen analyzer system or CO CEMS do not include paragraph (a)(7) because (a)(7) does not require the installation of an oxygen trim system. 

40 CFR 63.7525(a), (a)(1), 

(a)(2), (a)(3), and (a)(5).

Revise these paragraphs to clarify that carbon dioxide may be used as an alternative to using oxygen in correcting the measured CO CEMS data without petitioning for an alternative monitoring procedure. 

40 CFR 63.7525(a)(7) .......... Revise this paragraph to clarify the oxygen set point for a source not required to conduct a CO performance test. 

40 CFR 63.7525(b) and 

(b)(1).

Remove the word ‘‘certify’’ because there is no certification procedure for PM CPMS. 

40 CFR 63.7525(b)(1)(iii) ..... Revise this paragraph to clarify that the 0.5 milligram per actual cubic meter is the detection limit. 

40 CFR 63.7525(g)(3) .......... Revise this paragraph to clarify that the pH monitor is to be calibrated each day and not performance evaluated 

which is covered in 40 CFR 63.7525(g)(4). 

40 CFR 63.7525(m) ............. Revise this paragraph to clarify that 40 CFR 63.7525(m) is only applicable if the source elects to use an SO2

CEMS to demonstrate compliance with the HCl emission limit and to clarify that the SO2 CEMS can be certified 

according to either part 60 or part 75. 

40 CFR 63.7530 ................... Revise equations 7, 8, and 9 to clarify that for ‘‘Qi’’ the highest content of chlorine, mercury, and TSM is used 

only for initial compliance and the actual fraction is used for continuous compliance demonstration. 

40 CFR 63.7530(a) .............. Revise this paragraph to clarify which fuels are exempt from analysis by cross-referencing 40 CFR 63.7510(a)(2), 

instead of only 40 CFR 63.7510(a)(2) (i). 

40 CFR 63.7530(b) .............. Revise this paragraph by adding the word ‘‘stack’’ to clarify that the performance testing referred to is performance stack testing. 

40 CFR 63.7530(b)(4)(iii) to 

(viii).

Revise the numbering of these paragraphs to correct sequence. 

40 CFR 63.7530(c)(3) .......... Revise the reference to Equation 11 to be Equation 15, to accommodate the change in numbering of equations. 

40 CFR 63.7530(c)(4) .......... Revise the reference to Equation 11 to be Equation 15, to accommodate the change in numbering of equations. 

40 CFR 63.7530(c)(5) .......... Revise the reference to Equation 11 to be Equation 15, to accommodate the change in numbering of equations. 

40 CFR 63.7530(d) .............. Amend this paragraph to clarify that the requirement to include a signed statement that the tune-up was conducted is applicable to all existing units. 

40 CFR 63.7530(e) .............. Amend this paragraph to clarify that the energy assessment is also considered to have been completed if the 

maximum number of on-site technical hours specified in the definition of energy assessment applicable to the 

facility has been expended. 

40 CFR 63.7530(h) .............. Revise this paragraph to clarify that both items 5 and 6 of Table 3 apply during periods of startup and shutdown. 

40 CFR 63.7530(i)(3) ........... Revise this paragraph to read ‘‘maximum’’ instead of ‘‘minimum’’ to be consistent with item 10 of Table 4 to subpart DDDDD. 

40 CFR 63.7533(e) .............. Revise this paragraph by changing wording from ‘‘operating’’ to ‘‘subject to numeric emission limits’’ to clarify that 

the numeric emission limits do not apply during startup and shutdown periods. 

40 CFR 63.7535(c) .............. Amend this paragraph to clarify that data recorded during periods of startup and shutdown may not be used to 

report emissions or operating levels. 

40 CFR 63.7535(d) .............. Amend this paragraph to clarify that data recorded during periods of startup and shutdown may not be used to 

report emissions or operating levels and that the report for reporting periods when the monitoring system is out 

of control is the facility’s ‘‘semi-annual’’ report. 

40 CFR 63.7540(a)(2) .......... Revise the reference to 40 CFR 63.7550(c) to 40 CFR 63.7555(d). 

40 CFR 63.7540(a)(3) and 

(a)(3)(iii).

Revise the reference to Equation 12 to Equation 16, to accommodate the change in numbering of equations. 

40 CFR 63.7540(a)(5) and 

(a)(5)(iii).

Revise the reference to Equation 13 to Equation 17, to accommodate the change in numbering of equations. 

40 CFR 63.7540(a)(8)(ii) ...... Revise this paragraph by changing wording from ‘‘operating’’ to ‘‘subject to numeric emission limits’’ to clarify that 

the numeric emission limits do not apply during startup and shutdown periods. 

40 CFR 63.7540(a)(10) ........ Amend this paragraph to clarify that the tune-up must be conducted while burning the type of fuel that provided 

the majority of the heat input over the 12 months prior to the tune-up. 

40 CFR 63.7540(a)(10)(vi) ... Revise paragraph to remove the word ‘‘annual’’ because not all facilities will necessarily be subject to an annual 

tune-up requirement. 

40 CFR 63.7540(a)(17) and 

(a)(17)(iii).

Revise the reference to Equation 14 to Equation 18, to accommodate the change in numbering of equations. 

40 CFR 63.7540(a)(19)(iii) ... Revise the reference from paragraph (i) to paragraph (v). 

40 CFR 63.7540(d) .............. Revise the reference to item 5 of Table 3 to items 5 and 6 of Table 3 to accommodate the splitting of the work 

practice for startup and shutdown into two separate items in Table 3. 

40 CFR 63.7545(e)(8)(i) ....... Revise this paragraph by changing the wording from ‘‘complies with’’ to ‘‘completed’’ to add clarity. 

40 CFR 63.7545(h) .............. Revise this paragraph to clarify the paragraph also applies to process heaters. 

40 CFR 63.7550(b) .............. Revise this paragraph to clarify that units subject only to both the energy assessment and tune-up requirements 

may submit only an annual, biennial, or 5-year compliance report. 

40 CFR 63.7550(b)(1), 

(b)(2), (b)(3), and (b)(4).

Revise these paragraphs to add the word ‘‘semi-annual’’ to clarify that the compliance report initially discussed in 

each paragraph is the semi-annual report required for units subject to emission limits. 

40 CFR 63.7550(b)(1) .......... Revise this paragraph to change the reporting period end dates to be consistent with the dates in 40 CFR 

63.7550(b)(3). 

40 CFR 63.7550 (c)(1) ......... Revise this paragraph to remove the word ‘‘a,’’ to change the wording from ‘‘they’’ to ‘‘you’’ and to add reference 

to 40 CFR 63.7550(c)(5)(xvii). 

40 CFR 63.7550 (c)(2) and 

(c)(3).

Revise these paragraphs to add reference to 40 CFR 63.7550(c)(5)(xvii). 

40 CFR 63.7550 (c)(3) ......... Revise this paragraph to add reference to 40 CFR 63.7550(c)(5)(viii). 

40 CFR 63.7550 (c)(2), 

(c)(3) and (c)(4).

Revise these paragraphs to change the wording from ‘‘a facility is’’ to ‘‘you are’’ and ‘‘they’’ to ‘‘you.’’ 

40 CFR 63.7550 (c)(4) ......... Revise the paragraph to include reference to paragraph (c)(5)(xii). 


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3100 Federal Register / Vol. 80, No. 13 / Wednesday, January 21, 2015 / Proposed Rules 

TABLE 1—MISCELLANEOUS PROPOSED TECHNICAL CORRECTIONS TO 40 CFR PART 63, SUBPART DDDDD—Continued 

Section of subpart DDDDD Description of proposed correction 

40 CFR 63.7550(c)(5)(viii) ... Revise the reference to Equation 12 to Equation 16, the reference to Equation 13 to Equation 17, and the reference to Equation 14 to Equation 18, to accommodate the change in numbering of equations. 

40 CFR 63.7550(d) .............. Revise this paragraph to clarify that deviations from the work practice standards for periods of startup and shutdown must also be included in the compliance report. 

40 CFR 63.7550(h) .............. Revise the paragraph to update electronic reporting requirements. 

40 CFR 63.7555(a)(3) .......... Redesignating paragraph 63.7550(d)(3) as new paragraph 63.7550(a)(3) because limited use units are not subject to emission limits. 

40 CFR 63.7555(d)(4) .......... Change the reference to Equation 12 to Equation 16, to accommodate the change in numbering of equations. 

40 CFR 63.7555(d)(5) .......... Change the reference to Equation 13 to Equation 17, to accommodate the change in numbering of equations. 

40 CFR 63.7555(d)(9) .......... Change the reference to Equation 14 to Equation 18, to accommodate the change in numbering of equations. 

40 CFR 63.7555(i) and (j) .... Delete paragraphs because paragraphs (i) and (j) are identical to paragraphs (d)(10) and (d)(11) to be consistent 

with the intent of the amendments to limit these reporting requirements to units subject to emission limits. 

40 CFR 63.7575 ................... Revise the definition of ‘‘Coal’’ to clarify that coal derived liquids are considered to be a liquid fuel type. 

Add new definition of ‘‘Fossil fuel’’ to clarify what is meant by ‘‘fossil fuel’’ in the definition of ‘‘Electric utility steam

generating unit.’’ 

Revise the definition of ‘‘Limited-use boiler or process heater’’ to remove the word ‘‘average’’ to eliminate confusion regarding its use in the definition and maintain consistent terminology within the subpart. 

Revise the definition of ‘‘Load fraction’’ to clarify how load fraction is determined for a boiler or process heater cofiring natural gas. 

Revise the definition of ‘‘Oxygen trim system’’ to include draft controller and to clarify that it is a system that 

maintains the desired excess air level over the operating load range. 

Revise the definition of ‘‘Steam output’’ to clarify how steam output is determined for multi-function units and units 

supplying steam to a common header. 

Revise the definition of ‘‘Temporary boiler’’ to clarify that the definition is also applicable to process heaters. 

Table 1 to subpart DDDDD .. Revise the subcategory ‘‘Stokers designed to burn coal/solid fossil fuel’’ to clarify that the subcategory includes 

‘‘other combustors’’ consistent with the stokers designed to burn biomass subcategories. 

Add footnote ‘‘d’’ to clarify that carbon dioxide may be used as an alternative to using oxygen in correcting the 

measured CO CEMS data without petitioning for an alternative monitoring procedure. 

Table 2 to subpart DDDDD .. Revise the subcategory ‘‘Stokers designed to burn coal/solid fossil fuel’’ to clarify that the subcategory includes 

‘‘other combustors’’ consistent with the stokers designed to burn biomass subcategories. 

Revise the CO emission limit for hybrid suspension grate units to account for a conversion error in the emission 

database that inadvertently resulted in a source incorrectly being a best performing unit. 

Revise items 14.b and 16.b to add the reference to footnote ‘‘a.’’ 

Add footnote ‘‘c’’ to clarify that carbon dioxide may be used as an alternative to using oxygen in correcting the 

measured CO CEMS data without petitioning for an alternative monitoring procedure. 

Table 3 to subpart DDDDD .. Revise item 4 to clarify that ‘‘operates’’ does not require the energy management program to be implemented in 

perpetuity and that an energy management program developed according to ENERGY STAR guidelines would 

also satisfy the requirement. 

Revise item 4e to read ‘‘program’’ instead of ‘‘practices’’ to be consistent with the definition of ‘‘Energy management program’’ in § 63.7575. 

Table 4 to subpart DDDDD .. Revise certain items in the table to clarify the applicability of the parameter operating limits also apply to process 

heaters. 

Revise item 4 to clarify that item 4.a. is applicable to dry ESP and item 4.b. is applicable to wet ESP systems. 

Table 5 to subpart DDDDD .. Revise the heading of the third column to clarify that the requirement to use a specified method may not be appropriate in all cases. 

Add the missing footnote ‘‘a Incorporated by reference, see 40 CFR 63.14’’ 

Table 6 to subpart DDDDD .. Revise items 1, 2, and 4 to remove reference to the equations cited in 40 CFR 63.7530 for demonstrating only 

initial compliance. 

Revise items 1.c, 2.c, and 4.c to remove the listed method for liquid samples to be consistent with 40 CFR 

63.7521(a). 

Revise item 3 to clarify that the two methods listed are alternatives. 

Revise the title to item 4 to remove ‘‘for solid fuels’’ to clarify that item 4. is applicable to also liquid fuel types. 

Table 7 to subpart DDDDD .. Revise item 1.a.i.(1) to clarify that TSM performance test are also included. 

Revise items 2.a.i. and 2.a.i.(1) to remove ‘‘pressure drop’’ to be consistent with 40 CFR 63.7530(b). 

Revise items 2.b.i.(1)(c) and 3.a.i.(1)(c) to clarify that ‘‘load fraction’’ is as defined in 40 CFR 63.7575. 

Revise item 2.c.i(1)(b) to read ‘‘highest’’ instead of ‘‘lowest’’ to be consistent with item 10 of Table 4 to subpart 

DDDDD. 

Revise item 4 to read ‘‘Carbon monoxide for which compliance is demonstrated by a performance test’’ to clarify 

that this operating limit is not applicable for source complying with the CO CEMS based limits. 

Table 8 to subpart DDDDD .. Revise item 3 to change the reference to 40 CFR 63.7540(a)(9) to 40 CFR 63.7540(a)(7). 

Revise item 9.a to change the reference to 40 CFR 63.7525(a)(2) to 40 CFR 63.7525(a)(7). 

Revise item 11.c to read ‘‘highest’’ instead of ‘‘minimum’’ to be consistent with item 10 of Table 4 to subpart 

DDDDD. 

Revise the operating load compliance provisions (item 10) to be consistent with 40 CFR 63.7525(d). 

Table 9 to subpart DDDDD .. Revise Table 9 to subpart DDDDD to clarify that it is deviations from the work practice standards for periods of 

startup and shutdown that are to be included. 

Table 11 to subpart DDDDD Revise Table 11 to subpart DDDDD to be consistent with the final amended rule because of incorrect amendatory instructions. 

Table 12 to subpart DDDDD Revise Table 12 to subpart DDDDD to be consistent with the final amended rule because of incorrect amendatory instructions. 


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Federal Register / Vol. 80, No. 13 / Wednesday, January 21, 2015 / Proposed Rules 3101 

V. Affirmative Defense for Violation of 

Emission Standards During 

Malfunction 

In several prior CAA section 112 and 

CAA section 129 rules, including this 

rule, the EPA had included an 

affirmative defense to civil penalties for 

violations caused by malfunctions in an 

effort to create a system that 

incorporates some flexibility, 

recognizing that there is a tension, 

inherent in many types of air regulation, 

to ensure adequate compliance while 

simultaneously recognizing that despite 

the most diligent of efforts, emission 

standards may be violated under 

circumstances entirely beyond the 

control of the source. Although the EPA 

recognized that its case-by-case 

enforcement discretion provides 

sufficient flexibility in these 

circumstances, it included the 

affirmative defense to provide a more 

formalized approach and more 

regulatory clarity. See Weyerhaeuser Co. 

v. Costle, 590 F.2d 1011, 1057–58 (D.C. 

Cir. 1978) (holding that an informal 

case-by-case enforcement discretion 

approach is adequate); but see Marathon 

Oil Co. v. EPA, 564 F.2d 1253, 1272–73 

(9th Cir. 1977) (requiring a more 

formalized approach to consideration of 

‘‘upsets beyond the control of the permit 

holder.’’). Under the EPA’s regulatory 

affirmative defense provisions, if a 

source could demonstrate in a judicial 

or administrative proceeding that it had 

met the requirements of the affirmative 

defense in the regulation, civil penalties 

would not be assessed. Recently, the 

United States Court of Appeals for the 

District of Columbia Circuit vacated an 

affirmative defense in one of the EPA’s 

CAA section 112 regulations. NRDC v. 

EPA, 749 F.3d 1055 (D.C. Cir., 2014) 

(vacating affirmative defense provisions 

in CAA section 112 rule establishing 

emission standards for Portland cement 

kilns). The court found that the EPA 

lacked authority to establish an 

affirmative defense for private civil suits 

and held that under the CAA, the 

authority to determine civil penalty 

amounts in such cases lies exclusively 

with the courts, not the EPA. 

Specifically, the court found: ‘‘As the 

language of the statute makes clear, the 

courts determine, on a case-by-case 

basis, whether civil penalties are 

‘appropriate.’ ’’ See NRDC, 2014 U.S. 

App. LEXIS 7281 at *21 (‘‘[U]nder this 

statute, deciding whether penalties are 

‘appropriate’ . . . is a job for the courts, 

not EPA.’’). In light of NRDC, the EPA 

is proposing to remove the regulatory 

affirmative defense provision in the 

current rule. 

In the event that a source fails to 

comply with the applicable CAA section 

112 standards as a result of a 

malfunction event, the EPA would 

determine an appropriate response 

based on, among other things, the good 

faith efforts of the source to minimize 

emissions during malfunction periods, 

including preventative and corrective 

actions, as well as root cause analyses 

to ascertain and rectify excess 

emissions. The EPA would also 

consider whether the source’s failure to 

comply with the CAA section 112 

standard was, in fact, ‘‘sudden, 

infrequent, not reasonably preventable’’ 

and was not instead ‘‘caused in part by 

poor maintenance or careless 

operation.’’ 40 CFR 63.2 (definition of 

malfunction). 

Further, to the extent the EPA files an 

enforcement action against a source for 

violation of an emission standard, the 

source can raise any and all defenses in 

that enforcement action and the federal 

district court will determine what, if 

any, relief is appropriate. The same is 

true for citizen enforcement actions. Cf. 

NRDC at 1064 (arguments that violation 

was caused by unavoidable technology 

failure can be made to the courts in 

future civil cases when the issue arises). 

Similarly, the presiding officer in an 

administrative proceeding can consider 

any defense raised and determine 

whether administrative penalties are 

appropriate. 

VI. Solicitation of Public Comment and 

Participation 

The EPA seeks full public 

participation in arriving at its final 

decisions. At this time, the EPA is only 

proposing alternatives to the final rule’s 

definitions of startup and shutdown, the 

work practices that apply during those 

periods, and recordkeeping 

requirements for startup periods. The 

EPA is not proposing any other specific 

revisions to the reconsideration issues. 

However, the EPA requests public 

comment on the three issues under 

reconsideration. 

Additionally, the EPA is making 

certain clarifying changes and 

corrections to the final rule. We are 

soliciting comments on whether the 

proposed changes provide the intended 

accuracy, clarity and consistency. The 

EPA is also proposing to amend the 

final rule by removing the affirmative 

defense provision. We request comment 

on all of these proposed changes. 

The EPA is seeking comment only on 

the specific three issues, the clarifying 

changes and corrections, and the 

amendments described in this notice. 

The EPA will not respond to any 

comments addressing any other issues 

or any other provisions of the final rule 

or any other rule. 

VII. Statutory and Executive Order 

Reviews 

Additional information about these 

statutes and Executive Orders can be 

found at http://www2.epa.gov/lawsregulations/laws-and-executive-orders. 

A. Executive Order 12866: Regulatory 

Planning and Review and Executive 

Order 13563: Improving Regulation and 

Regulatory Review 

This action is not a significant 

regulatory action and was therefore not 

submitted to the Office of Management 

and Budget (OMB) for review. 

B. Paperwork Reduction Act (PRA) 

This action does not impose any new 

information collection burden under 

PRA. With this action, the EPA is 

seeking additional comments on three 

aspects of the final amended NESHAP 

for industrial, commercial, and 

institutional boilers and process heaters 

located at major sources of HAP with 

proposing only minor changes to the 

rule to correct and clarify 

implementation issues raised by 

stakeholders. However, the Office of 

Management and Budget (OMB) has 

previously approved the information 

collection requirements contained in the 

existing regulations under the 

provisions of the Paperwork Reduction 

Act, 44 U.S.C. 3501 et seq. and has 

assigned OMB control number 2060– 

0551. The OMB control numbers for the 

EPA’s regulations in 40 CFR are listed 

in 40 CFR part 9. 

C. Regulatory Flexibility Act (RFA) 

I certify that this action will not have 

a significant economic impact on a 

substantial number of small entities 

under the RFA. This action will not 

impose any requirements on small 

entities. This action seeks comment on 

three aspects of the final NESHAP for 

industrial, commercial, and institutional 

boilers and process heaters located at 

major sources of HAP as well as 

proposing minor changes to the rule to 

correct and clarify implementation 

issues raised by stakeholders. 

We continue to be interested in the 

potential impacts of the proposed rule 

on small entities and welcome 

comments on issues related to such 

impacts. 

D. Unfunded Mandates Reform Act 

(UMRA) 

This action does not contain any 

unfunded mandates as described in 

UMRA, 2 U.S.C. 1531–1538. The action 

imposes no enforceable duty on any 


asabaliauskas on DSK5VPTVN1PROD with PROPOSALS
3102 Federal Register / Vol. 80, No. 13 / Wednesday, January 21, 2015 / Proposed Rules 

state, local or tribal governments or the 

private sector. 

This action seeks comment on three 

aspects of the final NESHAP for 

industrial, commercial, and institutional 

boilers and process heaters located at 

major sources of HAP with proposing 

minor changes to the rule to correct and 

clarify implementation issues raised by 

stakeholders. 

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. This action seeks 

comment on three aspects of the final 

NESHAP for industrial, commercial, 

and institutional boilers and process 

heaters located at major sources of HAP 

without proposing any changes to the 

rule. Thus, Executive Order 13132 does 

not apply to this action. 

In the spirit of Executive Order 13132, 

and consistent with EPA policy to 

promote communications between 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 action does not have tribal 

implications, as specified in Executive 

Order 13175. This action will not have 

substantial direct effects on tribal 

governments, on the relationship 

between the federal government and 

Indian tribes, or on the distribution of 

power and responsibilities between the 

federal government and Indian tribes, as 

specified in Executive Order 13175. 

Thus, Executive Order 13175 does not 

apply to this action. 

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 as applying to those regulatory 

actions that concern environmental 

health or safety risks that the EPA has 

reason to believe may 

disproportionately affect children, per 

the definition of ‘‘covered regulatory 

action’’ in section 2–202 of the 

Executive Order. This action is not 

subject to Executive Order 13045 

because it does not concern an 

environmental health risk or safety risk. 

H. Executive Order 13211: Actions 

Concerning Regulations That 

Significantly Affect Energy Supply, 

Distribution, or Use 

This action is not a ‘‘significant 

energy action’’ because it is not likely to 

have a significant adverse effect on the 

supply, distribution or use of energy. 

I. National Technology Transfer and 

Advancement Act 

Section 12(d) of the National 

Technology Transfer and Advancement 

Act (NTTAA) of 1995 (Pub. L. 104–113, 

Section 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. The VCS 

are technical standards (e.g., materials 

specifications, test methods, sampling 

procedures and business practices) that 

are developed or adopted by VCS 

bodies. The NTTAA directs the EPA to 

provide Congress, through OMB, 

explanations when the agency does not 

use available and applicable VCS. 

This action does not involve 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 does not affect the level of 

protection provided to human health or 

the environment. This action seeks 

comment on three aspects of the final 

NESHAP for industrial, commercial, 

and institutional boilers and process 

heaters located at major sources of HAP 

with proposing minor changes to the 

rule to correct and clarify 

implementation issues raised by 

stakeholders. 

List of Subjects in 40 CFR Part 63 

Environmental Protect, 

Administrative practice and procedure, 

Air pollution control, Hazardous 

substances, Intergovernmental relations, 

Reporting and recordkeeping 

requirements. 

Dated: December 1, 2014. 

Gina McCarthy, 

Administrator. 

For the reasons cited in the preamble, 

title 40, chapter I, part 63 of the Code 

of Federal Regulations is proposed to be 

amended as follows: 

PART 63— NATIONAL EMISSION 

STANDARDS FOR HAZARDOUS AIR 

POLLUTANTS FOR SOURCE 

CATEGORIES 

■ 1. The authority for part 63 continues 

to read as follows: 

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

Subpart DDDDD—[Amended] 

■ 2. Section 63.7491 is amended by: 

■ a. Revising paragraphs (a), (j) and (l). 

■ b. Adding paragraph (n). 

The revisions and addition read as 

follows: 

§ 63.7491 Are any boilers or process 

heaters not subject to this subpart? 

* * * * * 

(a) An electric utility steam generating 

unit (EGU) covered by subpart UUUUU 

of this part or a natural gas-fired EGU as 

defined in subpart UUUUU of this part 

firing at least 90 percent natural gas on 

an annual heat input basis. 

* * * * * 

(j) Temporary boilers and process 

heaters as defined in this subpart. 

* * * * * 

(l) Any boiler or process heater 

specifically listed as an affected source 

in any standard(s) established under 

section 129 of the Clean Air Act. 

* * * * * 

(n) Residential boilers as defined in 

this subpart. 

■ 3. Section 63.7495 is amended by: 

■ a. Revising paragraphs (a) and (e). 

■ b. Adding paragraphs (h) and (i). 

The revisions and additions read as 

follows: 

§ 63.7495 When do I have to comply with 

this subpart? 

(a) If you have a new or reconstructed 

boiler or process heater, you must 

comply with this subpart by April 1, 

2013, or upon startup of your boiler or 

process heater, whichever is later. 

* * * * * 

(e) If you own or operate an 

industrial, commercial, or institutional 


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boiler or process heater and would be 

subject to this subpart except for the 

exemption in § 63.7491(l) for 

commercial and industrial solid waste 

incineration units covered by part 60, 

subpart CCCC or subpart DDDD, and 

you cease combusting solid waste, you 

must be in compliance with this subpart 

and are no longer subject to part 60, 

subparts CCCC or DDDD beginning on 

the effective date of the switch as 

identified under the provisions of 

§ 60.2145(a)(2) and (3) or § 60.2710(a)(2) 

and (3). 

* * * * * 

(h) If you own or operate an existing 

industrial, commercial, or institutional 

boiler or process heater and have switch 

fuels or made a physical change to the 

boiler or process heater that resulted in 

the applicability of a different 

subcategory after January 31, 2016, you 

must be in compliance with the 

applicable existing source provisions of 

this subpart on the effective date of the 

fuel switch or physical change. 

(i) If you own or operate a new 

industrial, commercial, or institutional 

boiler or process heater and have switch 

fuels or made a physical change to the 

boiler or process heater that resulted in 

the applicability of a different 

subcategory, you must be in compliance 

with the applicable new source 

provisions of this subpart on the 

effective date of the fuel switch or 

physical change. 

* * * * * 

■ 4. Section 63.7500 is amended by 

revising paragraphs (a)(1) and (f) to read 

as follows: 

§ 63.7500 What emission limitations, work 

practice standards, and operating limits 

must I meet? 

(a) * * * 

(1) You must meet each emission 

limit and work practice standard in 

Tables 1 through 3, and 11 through 13 

to this subpart that applies to your 

boiler or process heater, for each boiler 

or process heater at your source, except 

as provided under § 63.7522. The 

output-based emission limits, in units of 

pounds per million Btu of steam output, 

in Tables 1 or 2 to this subpart are an 

alternative applicable only to boilers 

and process heaters that generate either 

steam, cogenerate steam with electricity, 

or both. The output-based emission 

limits, in units of pounds per megawatthour, in Tables 1 or 2 to this subpart are 

an alternative applicable only to boilers 

that generate only electricity. Boilers 

that perform multiple functions 

(cogeneration and electricity generation) 

or supply steam to common heaters 

would calculate a total steam energy 

output using equation 21 of § 63.7575 to 

demonstrate compliance with the 

output-based emission limits, in units of 

pounds per million Btu of steam output, 

in Tables 1 or 2 to this subpart. If you 

operate a new boiler or process heater, 

you can choose to comply with 

alternative limits as discussed in 

paragraphs (a)(1)(i) through (a)(1)(iii) of 

this section, but on or after January 31, 

2016, you must comply with the 

emission limits in Table 1 to this 

subpart. 

(i) If your boiler or process heater 

commenced construction or 

reconstruction after June 4, 2010 and 

before May 20, 2011, you may comply 

with the emission limits in Table 1 or 

11 to this subpart until January 31, 

2016. 

(ii) If your boiler or process heater 

commenced construction or 

reconstruction on or after May 20, 2011 

and before December 23, 2011, you may 

comply with the emission limits in 

Table 1 or 12 to this subpart until 

January 31, 2016. 

(iii) If your boiler or process heater 

commenced construction or 

reconstruction on or after December 23, 

2011 and before April 1, 2013, you may 

comply with the emission limits in 

Table 1 or 13 to this subpart until 

January 31, 2016. 

* * * * * 

(f) These standards apply at all times 

the affected unit is operating, except 

during periods of startup and shutdown 

during which time you must comply 

only with items 5 and 6 of Table 3 to 

this subpart. 

* * * * * 

§ 63.7501 [Removed] 

■ 5. Section 63.7501 is removed. 

■ 6. Section 63.7505 is amended by 

revising paragraphs (a) and (c) and 

adding paragraph (e) to read as follows: 

§ 63.7505 What are my general 

requirements for complying with this 

subpart? 

(a) You must be in compliance with 

the emission limits, work practice 

standards, and operating limits in this 

subpart. These emission and operating 

limits apply to you at all times the 

affected unit is operating except for the 

periods noted in § 63.7500(f). 

* * * * * 

(c) You must demonstrate compliance 

with all applicable emission limits 

using performance stack testing, fuel 

analysis, or continuous monitoring 

systems (CMS), including a continuous 

emission monitoring system (CEMS), 

continuous opacity monitoring system 

(COMS), continuous parameter 

monitoring system (CPMS), or 

particulate matter continuous parameter 

monitoring system (PM CPMS), where 

applicable. You may demonstrate 

compliance with the applicable 

emission limit for hydrogen chloride 

(HCl), mercury, or total selected metals 

(TSM) using fuel analysis if the 

emission rate calculated according to 

§ 63.7530(c) is less than the applicable 

emission limit. (For gaseous fuels, you 

may not use fuel analyses to comply 

with the TSM alternative standard or 

the HCl standard.) Otherwise, you must 

demonstrate compliance for HCl, 

mercury, or TSM using performance 

stack testing, if subject to an applicable 

emission limit listed in Tables 1, 2, or 

11 through 13 to this subpart. 

* * * * * 

(e) If you have an applicable emission 

limit, you must develop a site-specific 

monitoring plan for work practice 

monitoring during startup periods 

according to the requirements in Table 

3 to this subpart. The site-specific 

monitoring plan for startup periods 

must be maintained onsite and available 

upon request for public inspection. 

* * * * * 

■ 7. Section 63.7510 is amended by: 

■ a. Revising paragraphs (a) 

introductory text, (a)(2)(ii), (c), (e), (g), 

and (i) . 

■ b. Adding paragraph (k). 

The revisions and addition read as 

follows: 

§ 63.7510 What are my initial compliance 

requirements and by what date must I 

conduct them? 

(a) For each boiler or process heater 

that is required or that you elect to 

demonstrate compliance with any of the 

applicable emission limits in Tables 1 or 

2 or 11 through 13 of this subpart 

through performance (stack) testing, 

your initial compliance requirements 

include all the following: 

* * * * * 

(2) * * * 

(ii) When natural gas, refinery gas, or 

other Gas 1 fuels are co-fired with other 

fuels, you are not required to conduct a 

fuel analysis of those Gas 1 fuels 

according to § 63.7521 and Table 6 to 

this subpart. If gaseous fuels other than 

natural gas, refinery gas, or other Gas 1 

fuels are co-fired with other fuels and 

those non-Gas 1 gaseous fuels are 

subject to another subpart of this part, 

part 60, part 61, or part 65, you are not 

required to conduct a fuel analysis of 

those non-Gas 1 fuels according to 

§ 63.7521 and Table 6 to this subpart. 

* * * * * 

(c) If your boiler or process heater is 

subject to a carbon monoxide (CO) limit, 

your initial compliance demonstration 

for CO is to conduct a performance test 


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for CO according to Table 5 to this 

subpart or conduct a performance 

evaluation of your continuous CO 

monitor, if applicable, according to 

§ 63.7525(a). Boilers and process heaters 

that use a CO CEMS to comply with the 

applicable alternative CO CEMS 

emission standard listed in Tables 1, 2, 

or 11 through 13 to this subpart, as 

specified in § 63.7525(a), are exempt 

from the initial CO performance testing 

and oxygen concentration operating 

limit requirements specified in 

paragraph (a) of this section. 

* * * * * 

(e) For existing affected sources (as 

defined in § 63.7490), you must 

complete the initial compliance 

demonstrations, as specified in 

paragraphs (a) through (d) of this 

section, no later than 180 days after the 

compliance date that is specified for 

your source in § 63.7495 and according 

to the applicable provisions in 

§ 63.7(a)(2) as cited in Table 10 to this 

subpart, except as specified in 

paragraph (j) of this section. You must 

complete an initial tune-up by following 

the procedures described in 

§ 63.7540(a)(10)(i) through (vi) no later 

than the compliance date specified in 

§ 63.7495, except as specified in 

paragraph (j) of this section. You must 

complete the one-time energy 

assessment specified in Table 3 to this 

subpart no later than the compliance 

date specified in § 63.7495. 

* * * * * 

(g) For new or reconstructed affected 

sources (as defined in § 63.7490), you 

must demonstrate initial compliance 

with the applicable work practice 

standards in Table 3 to this subpart 

within the applicable annual, biennial, 

or 5-year schedule as specified in 

§ 63.7515(d) following the initial 

compliance date specified in 

§ 63.7495(a). Thereafter, you are 

required to complete the applicable 

annual, biennial, or 5-year tune-up as 

specified in § 63.7515(d). 

* * * * * 

(i) For an existing EGU that becomes 

subject after January 31, 2016, you must 

demonstrate compliance within 180 

days after becoming an affected source. 

* * * * * 

(k) For affected sources, as defined in 

§ 63.7490, that switch subcategory 

consistent with § 63.7545(h) after the 

initial compliance date, you must 

demonstrate compliance within 60 days 

of the effective date of the switch, 

unless you had previously conducted 

your compliance demonstration for this 

subcategory within the previous 12 

months. 

■ 8. Section 63.7515 is amended by 

revising paragraphs (d) and (h) to read 

as follows: 

§ 63.7515 When must I conduct 

subsequent performance tests, fuel 

analyses, or tune-ups? 

* * * * * 

(d) If you are required to meet an 

applicable tune-up work practice 

standard, you must conduct an annual, 

biennial, or 5-year performance tune-up 

according to § 63.7540(a)(10), (11), or 

(12), respectively. Each annual tune-up 

specified in § 63.7540(a)(10) must be no 

more than 13 months after the previous 

tune-up. Each biennial tune-up 

specified in § 63.7540(a)(11) must be 

conducted no more than 25 months after 

the previous tune-up. Each 5-year tuneup specified in § 63.7540(a)(12) must be 

conducted no more than 61 months after 

the previous tune-up. For a new or 

reconstructed affected source (as 

defined in § 63.7490), the first annual, 

biennial, or 5-year tune-up must be no 

later than 13 months, 25 months, or 61 

months, respectively, after April 1, 2013 

or the initial startup of the new or 

reconstructed affected source, 

whichever is later. 

* * * * * 

(h) If your affected boiler or process 

heater is in the unit designed to burn 

light liquid subcategory and you 

combust ultra-low sulfur liquid fuel, 

you do not need to conduct further 

performance tests (stack tests or fuel 

analyses) if the pollutants measured 

during the initial compliance 

performance tests meet the emission 

limits in Tables 1 or 2 of this subpart 

providing you demonstrate ongoing 

compliance with the emissions limits by 

monitoring and recording the type of 

fuel combusted on a monthly basis. If 

you intend to use a fuel other than ultralow sulfur liquid fuel, natural gas, 

refinery gas, or other gas 1 fuel, you 

must conduct new performance tests 

within 60 days of burning the new fuel 

type. 

* * * * * 

■ 9. Section 63.7521 is amended by: 

■ a. Revising paragraph (a). 

■ b. Revising paragraph (c)(1). 

■ c. Revising paragraph (f) introductory 

text. 

■ d. Revising paragraph (g) introductory 

text. 

■ e. Revising paragraph (h). 

The revisions read as follows: 

§ 63.7521 What fuel analyses, fuel 

specification, and procedures must I use? 

(a) For solid and liquid fuels, you 

must conduct fuel analyses for chloride 

and mercury according to the 

procedures in paragraphs (b) through (e) 

of this section and Table 6 to this 

subpart, as applicable. For solid fuels 

and liquid fuels, you must also conduct 

fuel analyses for TSM if you are opting 

to comply with the TSM alternative 

standard. For gas 2 (other) fuels, you 

must conduct fuel analyses for mercury 

according to the procedures in 

paragraphs (b) through (e) of this section 

and Table 6 to this subpart, as 

applicable. (For gaseous fuels, you may 

not use fuel analyses to comply with the 

TSM alternative standard or the HCl 

standard.) For purposes of complying 

with this section, a fuel gas system that 

consists of multiple gaseous fuels 

collected and mixed with each other is 

considered a single fuel type and 

sampling and analysis is only required 

on the combined fuel gas system that 

will feed the boiler or process heater. 

Sampling and analysis of the individual 

gaseous streams prior to combining is 

not required. You are not required to 

conduct fuel analyses for fuels used for 

only startup, unit shutdown, and 

transient flame stability purposes. You 

are required to conduct fuel analyses 

only for fuels and units that are subject 

to emission limits for mercury, HCl, or 

TSM in Tables 1 and 2 or 11 through 13 

to this subpart. Gaseous and liquid fuels 

are exempt from the sampling 

requirements in paragraphs (c) and (d) 

of this section. 

* * * * * 

(c) * * * 

(1) If sampling from a belt (or screw) 

feeder, collect fuel samples according to 

paragraphs (c)(1)(i) and (ii) of this 

section. 

(i) Stop the belt and withdraw a 6- 

inch wide sample from the full crosssection of the stopped belt to obtain a 

minimum two pounds of sample. You 

must collect all the material (fines and 

coarse) in the full cross-section. You 

must transfer the sample to a clean 

plastic bag. 

(ii) Each composite sample will 

consist of a minimum of three samples 

collected at approximately equal onehour intervals during the testing period 

for sampling during performance stack 

testing. 

* * * * * 

(f) To demonstrate that a gaseous fuel 

other than natural gas or refinery gas 

qualifies as an other gas 1 fuel, as 

defined in § 63.7575, you must conduct 

a fuel specification analyses for mercury 

according to the procedures in 

paragraphs (g) through (i) of this section 

and Table 6 to this subpart, as 

applicable, except as specified in 

paragraph (f)(1) through (4) of this 

section, or as an alternative where fuel 

specification analysis is not practical, 


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you must measure mercury 

concentration in the exhaust gas when 

firing only the gaseous fuel to be 

demonstrated as an other gas 1 fuel in 

the boiler or process heater according to 

the procedures in Table 6 to this 

subpart. 

* * * * * 

(g) You must develop a site-specific 

fuel analysis plan for other gas 1 fuels 

according to the following procedures 

and requirements in paragraphs (g)(1) 

and (2) of this section. 

* * * * * 

(h) You must obtain a single fuel 

sample for each fuel type for fuel 

specification of gaseous fuels. 

* * * * * 

■ 10. Section 63.7522 is amended by 

revising paragraphs (c), (d), (i), and (j)(1) 

to read as follows: 

§ 63.7522 Can I use emissions averaging 

to comply with this subpart? 

* * * * * 

(c) For each existing boiler or process 

heater in the averaging group, the 

emission rate achieved during the initial 

compliance test for the HAP being 

averaged must not exceed the emission 

level that was being achieved on April 

1, 2013 or the control technology 

employed during the initial compliance 

test must not be less effective for the 

HAP being averaged than the control 

technology employed on April 1, 2013. 

(d) The averaged emissions rate from 

the existing boilers and process heaters 

participating in the emissions averaging 

option must not exceed 90 percent of 

the limits in Table 2 to this subpart at 

all times the affected units are subject to 

numeric emission limits following the 

compliance date specified in § 63.7495. 

* * * * * 

(i) For a group of two or more existing 

units in the same subcategory, each of 

which vents through a common 

emissions control system to a common 

stack, that does not receive emissions 

from units in other subcategories or 

categories, you may treat such averaging 

group as a single existing unit for 

purposes of this subpart and comply 

with the requirements of this subpart as 

if the group were a single unit. 

(j) * * * 

(1) Conduct performance tests 

according to procedures specified in 

§ 63.7520 in the common stack if 

affected units from other subcategories 

vent to the common stack. The emission 

limits that the group must comply with 

are determined by the use of Equation 

6 of this section. 

Where: 

En = HAP emission limit, pounds per million 

British thermal units (lb/MMBtu) or 

parts per million (ppm). 

ELi = Appropriate emission limit from Table 

2 to this subpart for unit i, in units of lb/ 

MMBtu or ppm. 

Hi = Heat input from unit i, MMBtu. 

* * * * * 

■ 11. Section 63.7525 is amended by: 

■ a. Revising paragraphs (a) 

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

introductory text, (a)(3), (a)(5), and 

(a)(7). 

■ b. Revising paragraphs (b) 

introductory text and (b)(1). 

■ c. Revising paragraph (g)(3). 

■ d. Revising paragraphs (m) 

introductory text and (m)(2). 

The revisions to read as follows: 

§ 63.7525 What are my monitoring, 

installation, operation, and maintenance 

requirements? 

(a) If your boiler or process heater is 

subject to a CO emission limit in Tables 

1, 2, or 11 through 13 to this subpart, 

you must install, operate, and maintain 

an oxygen analyzer system, as defined 

in § 63.7575, or install, certify, operate 

and maintain continuous emission 

monitoring systems for CO and oxygen 

(or carbon dioxide (CO2)) according to 

the procedures in paragraphs (a)(1) 

through (6) of this section. 

(1) Install the CO CEMS and oxygen 

(or CO2) analyzer by the compliance 

date specified in § 63.7495. The CO and 

oxygen (or CO2) levels shall be 

monitored at the same location at the 

outlet of the boiler or process heater. 

(2) To demonstrate compliance with 

the applicable alternative CO CEMS 

emission standard listed in Tables 1, 2, 

or 11 through 13 to this subpart, you 

must install, certify, operate, and 

maintain a CO CEMS and an oxygen 

analyzer according to the applicable 

procedures under Performance 

Specification 4, 4A, or 4B at 40 CFR part 

60, appendix B; part 75 of this chapter 

(if an CO2 analyzer is used); the sitespecific monitoring plan developed 

according to § 63.7505(d); and the 

requirements in § 63.7540(a)(8) and 

paragraph (a) of this section. Any boiler 

or process heater that has a CO CEMS 

that is compliant with Performance 

Specification 4, 4A, or 4B at 40 CFR part 

60, appendix B, a site-specific 

monitoring plan developed according to 

§ 63.7505(d), and the requirements in 

§ 63.7540(a)(8) and paragraph (a) of this 

section must use the CO CEMS to 

comply with the applicable alternative 

CO CEMS emission standard listed in 

Tables 1, 2, or 11 through 13 to this 

subpart. 

* * * * * 

(3) Complete a minimum of one cycle 

of CO and oxygen (or CO2) CEMS 

operation (sampling, analyzing, and 

data recording) for each successive 15- 

minute period. Collect CO and oxygen 

(or CO2) data concurrently. Collect at 

least four CO and oxygen (or CO2) CEMS 

data values representing the four 15- 

minute periods in an hour, or at least 

two 15-minute data values during an 

hour when CEMS calibration, quality 

assurance, or maintenance activities are 

being performed. 

* * * * * 

(5) Calculate one-hour arithmetic 

averages, corrected to 3 percent oxygen 

(or corrected to an CO2 percentage 

determined to be equivalent to 3 percent 

oxygen) from each hour of CO CEMS 

data in parts per million CO 

concentration. The one-hour arithmetic 

averages required shall be used to 

calculate the 30-day or 10-day rolling 

average emissions. Use Equation 19–19 

in section 12.4.1 of Method 19 of 40 

CFR part 60, appendix A–7 for 

calculating the average CO 

concentration from the hourly values. 

* * * * * 

(7) Operate an oxygen trim system 

with the oxygen level set no lower than 

the lowest hourly average oxygen 

concentration measured during the most 

recent CO performance test as the 

operating limit for oxygen according to 

Table 7 to this subpart, or if the facility 

is not required to conduct a 

performance test, set the oxygen level to 

the oxygen concentration measured 

during the most recent tune-up to 

optimize CO to manufacturer’s 

specification. 

(b) If your boiler or process heater is 

in the unit designed to burn coal/solid 

fossil fuel subcategory or the unit 

designed to burn heavy liquid 


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subcategory and has an average annual 

heat input rate greater than 250 MMBtu 

per hour from solid fossil fuel and/or 

heavy liquid, and you demonstrate 

compliance with the PM limit instead of 

the alternative TSM limit, you must 

install, maintain, and operate a PM 

CPMS monitoring emissions discharged 

to the atmosphere and record the output 

of the system as specified in paragraphs 

(b)(1) through (4) of this section. As an 

alternative to use of a PM CPMS to 

demonstrate compliance with the PM 

limit, you may choose to use a PM 

CEMS. If you choose to use a PM CEMS 

to demonstrate compliance with the PM 

limit instead of the alternative TSM 

limit, you must install, certify, maintain, 

and operate a PM CEMS monitoring 

emissions discharged to the atmosphere 

and record the output of the system as 

specified in paragraph (b)(5) through (8) 

of this section. For other boilers or 

process heaters, you may elect to use a 

PM CPMS or PM CEMS operated in 

accordance with this section in lieu of 

using other CMS for monitoring PM 

compliance (e.g., bag leak detectors, ESP 

secondary power, PM scrubber 

pressure). Owners of boilers and process 

heaters who elect to comply with the 

alternative TSM limit are not required to 

install a PM CPMS. 

(1) Install, operate, and maintain your 

PM CPMS according to the procedures 

in your approved site-specific 

monitoring plan developed in 

accordance with § 63.7505(d), the 

requirements in § 63.7540(a)(9), and 

paragraphs (b)(1)(i) through (iii) of this 

section. 

(i) The operating principle of the PM 

CPMS must be based on in-stack or 

extractive light scatter, light 

scintillation, beta attenuation, or mass 

accumulation detection of PM in the 

exhaust gas or representative exhaust 

gas sample. The reportable 

measurement output from the PM CPMS 

must be expressed as milliamps. 

(ii) The PM CPMS must have a cycle 

time (i.e., period required to complete 

sampling, measurement, and reporting 

for each measurement) no longer than 

60 minutes. 

(iii) The PM CPMS must have a 

documented detection limit of 0.5 

milligram per actual cubic meter, or 

less. 

* * * * * 

(g) * * * 

(3) Calibrate the pH monitoring 

system in accordance with your 

monitoring plan at least once each 

process operating day. 

* * * * * 

(m) If your unit is subject to a HCl 

emission limit in Tables 1, 2, or 11 

through 13 of this subpart and you have 

an acid gas wet scrubber or dry sorbent 

injection control technology and you 

elect to use an SO2 CEMS to 

demonstrate continuous compliance 

with the HCl emission limit, you must 

install the monitor at the outlet of the 

boiler or process heater, downstream of 

all emission control devices, and you 

must install, certify, operate, and 

maintain the CEMS according to either 

part 60 or part 75 of this chapter. 

(1) * * * 

(2) For on-going quality assurance 

(QA), the SO2 CEMS must meet either 

the applicable daily and quarterly 

requirements in Procedure 1 of 

appendix F of part 60 or the applicable 

daily, quarterly, and semiannual or 

annual requirements in sections 2.1 

through 2.3 of appendix B to part 75 of 

this chapter, with the following 

addition: You must perform the 

linearity checks required in section 2.2 

of appendix B to part 75 of this chapter 

if the SO2 CEMS has a span value of 30 

ppm or less. 

* * * * * 

■ 12. Section 63.7530 is amended by: 

■ a. Revising paragraphs (a). 

■ b. Revising paragraph (b) introductory 

text. 

■ c. Revising paragraphs (b)(1)(iii), 

(b)(2)(iii), and (b)(3)(iii). 

■ d. Revising paragraph (b)(4)(ii)(F). 

■ e. Redesignating paragraphs (b)(4)(iii) 

through (b)(4)(viii) as (b)(4)(iv) through 

(b)(4)(ix) and adding new paragraph 

(b)(4)(iii). 

■ f. Revising paragraphs (c)(3), (c)(4), 

and (c)(5). 

■ g. Revising paragraph (d). 

■ h. Revising paragraph (e). 

■ i. Revising paragraph (h). 

■ j. Revising paragraph (i)(3). 

The revisions and addition read as 

follows: 

§ 63.7530 How do I demonstrate initial 

compliance with the emission limitations, 

fuel specifications and work practice 

standards? 

(a) You must demonstrate initial 

compliance with each emission limit 

that applies to you by conducting initial 

performance tests and fuel analyses and 

establishing operating limits, as 

applicable, according to § 63.7520, 

paragraphs (b) and (c) of this section, 

and Tables 5 and 7 to this subpart. The 

requirement to conduct a fuel analysis 

is not applicable for units that burn a 

single type of fuel, as specified by 

§ 63.7510(a)(2). If applicable, you must 

also install, operate, and maintain all 

applicable CMS (including CEMS, 

COMS, and CPMS) according to 

§ 63.7525. 

(b) If you demonstrate compliance 

through performance stack testing, you 

must establish each site-specific 

operating limit in Table 4 to this subpart 

that applies to you according to the 

requirements in § 63.7520, Table 7 to 

this subpart, and paragraph (b)(4) of this 

section, as applicable. You must also 

conduct fuel analyses according to 

§ 63.7521 and establish maximum fuel 

pollutant input levels according to 

paragraphs (b)(1) through (3) of this 

section, as applicable, and as specified 

in § 63.7510(a)(2). (Note that 

§ 63.7510(a)(2) exempts certain fuels 

from the fuel analysis requirements.) 

However, if you switch fuel(s) and 

cannot show that the new fuel(s) does 

(do) not increase the chlorine, mercury, 

or TSM input into the unit through the 

results of fuel analysis, then you must 

repeat the performance test to 

demonstrate compliance while burning 

the new fuel(s). 

(1) * * * 

(iii) You must establish a maximum 

chlorine input level using Equation 7 of 

this section. 

Where: 

Clinput = Maximum amount of chlorine 

entering the boiler or process heater 

through fuels burned in units of pounds 

per million Btu. 

Ci = Arithmetic average concentration of 

chlorine in fuel type, i, analyzed 

according to § 63.7521, in units of 

pounds per million Btu. 

Qi = Fraction of total heat input from fuel 

type, i, based on the fuel mixture that 

has the highest content of chlorine 

during the initial compliance test. If you 

do not burn multiple fuel types during 

the performance testing, it is not 

necessary to determine the value of this 

term. Insert a value of ‘‘1’’ for Qi. For 

continuous compliance demonstration, 

the actual fraction of the fuel burned 

during the month would be used. 

n = Number of different fuel types burned in 

your boiler or process heater for the 


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mixture that has the highest content of 

chlorine. 

(2) * * * 

(iii) You must establish a maximum 

mercury input level using Equation 8 of 

this section. 

Where: 

Mercuryinput = Maximum amount of 

mercury entering the boiler or process 

heater through fuels burned in units of 

pounds per million Btu. 

HGi = Arithmetic average concentration of 

mercury in fuel type, i, analyzed 

according to § 63.7521, in units of 

pounds per million Btu. 

Qi = Fraction of total heat input from fuel 

type, i, based on the fuel mixture that 

has the highest mercury content during 

the initial compliance test. If you do not 

burn multiple fuel types during the 

performance test, it is not necessary to 

determine the value of this term. Insert 

a value of ‘‘1’’ for Qi. For continuous 

compliance demonstration, the actual 

fraction of the fuel burned during the 

month would be used. 

n = Number of different fuel types burned in 

your boiler or process heater for the 

mixture that has the highest content of 

mercury. 

(3) * * * 

(iii) You must establish a maximum 

TSM input level using Equation 9 of this 

section. 

Where: 

TSMinput = Maximum amount of TSM 

entering the boiler or process heater 

through fuels burned in units of pounds 

per million Btu. 

TSMi = Arithmetic average concentration of 

TSM in fuel type, i, analyzed according 

to § 63.7521, in units of pounds per 

million Btu. 

Qi = Fraction of total heat input from fuel 

type, i, based on the fuel mixture that 

has the highest content of TSM during 

the initial compliance test. If you do not 

burn multiple fuel types during the 

performance testing, it is not necessary 

to determine the value of this term. 

Insert a value of ‘‘1’’ for Qi. For 

continuous compliance demonstration, 

the actual fraction of the fuel burned 

during the month would be used. 

n = Number of different fuel types burned in 

your boiler or process heater for the 

mixture that has the highest content of 

TSM. 

(4) * * * 

(ii) * * * 

(F) For PM performance test reports 

used to set a PM CPMS operating limit, 

the electronic submission of the test 

report must also include the make and 

model of the PM CPMS instrument, 

serial number of the instrument, 

analytical principle of the instrument 

(e.g. beta attenuation), span of the 

instruments primary analytical range, 

milliamp value equivalent to the 

instrument zero output, technique by 

which this zero value was determined, 

and the average milliamp signals 

corresponding to each PM compliance 

test run. 

(iii) For a particulate wet scrubber, 

you must establish the minimum 

pressure drop and liquid flow rate as 

defined in § 63.7575, as your operating 

limits during the three-run performance 

test during which you demonstrate 

compliance with your applicable limit. 

If you use a wet scrubber and you 

conduct separate performance tests for 

PM and TSM emissions, you must 

establish one set of minimum scrubber 

liquid flow rate and pressure drop 

operating limits. The minimum scrubber 

effluent pH operating limit must be 

established during the HCl performance 

test. If you conduct multiple 

performance tests, you must set the 

minimum liquid flow rate and pressure 

drop operating limits at the higher of the 

minimum values established during the 

performance tests. 

* * * * * 

(c) * * * 

(3) To demonstrate compliance with 

the applicable emission limit for HCl, 

the HCl emission rate that you calculate 

for your boiler or process heater using 

Equation 16 of this section must not 

exceed the applicable emission limit for 

HCl. 

Where: 

HCl = HCl emission rate from the boiler or 

process heater in units of pounds per 

million Btu. 

Ci90 = 90th percentile confidence level 

concentration of chlorine in fuel type, i, 

in units of pounds per million Btu as 

calculated according to Equation 15 of 

this section. 

Qi = Fraction of total heat input from fuel 

type, i, based on the fuel mixture that 

has the highest content of chlorine. If 

you do not burn multiple fuel types, it 

is not necessary to determine the value 

of this term. Insert a value of ‘‘1’’ for Qi. 

n = Number of different fuel types burned in 

your boiler or process heater for the 

mixture that has the highest content of 

chlorine. 

1.028 = Molecular weight ratio of HCl to 

chlorine. 

(4) To demonstrate compliance with 

the applicable emission limit for 

mercury, the mercury emission rate that 

you calculate for your boiler or process 

heater using Equation 17 of this section 

must not exceed the applicable emission 

limit for mercury. 


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Where: 

Mercury = Mercury emission rate from the 

boiler or process heater in units of 

pounds per million Btu. 

Hgi90 = 90th percentile confidence level 

concentration of mercury in fuel, i, in 

units of pounds per million Btu as 

calculated according to Equation 15 of 

this section. 

Qi = Fraction of total heat input from fuel 

type, i, based on the fuel mixture that 

has the highest mercury content. If you 

do not burn multiple fuel types, it is not 

necessary to determine the value of this 

term. Insert a value of ‘‘1’’ for Qi. 

n = Number of different fuel types burned in 

your boiler or process heater for the 

mixture that has the highest mercury 

content. 

(5) To demonstrate compliance with 

the applicable emission limit for TSM 

for solid or liquid fuels, the TSM 

emission rate that you calculate for your 

boiler or process heater from solid fuels 

using Equation 18 of this section must 

not exceed the applicable emission limit 

for TSM. 

Where: 

Metals = TSM emission rate from the boiler 

or process heater in units of pounds per 

million Btu. 

TSMi90 = 90th percentile confidence level 

concentration of TSM in fuel, i, in units 

of pounds per million Btu as calculated 

according to Equation 15 of this section. 

Qi = Fraction of total heat input from fuel 

type, i, based on the fuel mixture that 

has the highest TSM content. If you do 

not burn multiple fuel types, it is not 

necessary to determine the value of this 

term. Insert a value of ‘‘1’’ for Qi. 

n = Number of different fuel types burned in 

your boiler or process heater for the 

mixture that has the highest TSM 

content. 

(d) If you own or operate an existing 

unit, you must submit a signed 

statement in the Notification of 

Compliance Status report that indicates 

that you conducted a tune-up of the 

unit. 

(e) You must include with the 

Notification of Compliance Status a 

signed certification that the energy 

assessment was completed according to 

Table 3 to this subpart and that the 

assessment is an accurate depiction of 

your facility at the time of the 

assessment or that the maximum 

number of on-site technical hours 

specified in the definition of energy 

assessment applicable to the facility has 

been expended. 

* * * * * 

(h) If you own or operate a unit 

subject to emission limits in Tables 1 or 

2 or 11 through 13 to this subpart, you 

must meet the work practice standard 

according to Table 3 of this subpart. 

During startup and shutdown, you must 

only follow the work practice standards 

according to items 5 and 6 of Table 3 of 

this subpart. 

(i) * * * 

(3) You establish a unit-specific 

maximum SO2 operating limit by 

collecting the maximum hourly SO2

emission rate on the SO2 CEMS during 

the paired 3-run test for HCl. The 

maximum SO2 operating limit is equal 

to the highest hourly average SO2

concentration measured during the most 

recent HCl performance test. 

■ 13. Section 63.7533 is amended by 

revising paragraph (e). 

§ 63.7533 Can I use efficiency credits 

earned from implementation of energy 

conservation measures to comply with this 

subpart? 

* * * * * 

(e) The emissions rate as calculated 

using Equation 20 of this section from 

each existing boiler participating in the 

efficiency credit option must be in 

compliance with the limits in Table 2 to 

this subpart at all times the affected unit 

is subject to numeric emission limits, 

following the compliance date specified 

in § 63.7495. 

* * * * * 

■ 14. Section 63.7535 is amended by 

revising paragraphs (c) and (d). 

§ 63.7535 Is there a minimum amount of 

monitoring data I must obtain? 

* * * * * 

(c) You may not use data recorded 

during periods of startup and shutdown, 

monitoring system malfunctions or outof-control periods, repairs associated 

with monitoring system malfunctions or 

out-of-control periods, or required 

monitoring system quality assurance or 

control activities in data averages and 

calculations used to report emissions or 

operating levels. You must record and 

make available upon request results of 

CMS performance audits and dates and 

duration of periods when the CMS is 

out of control to completion of the 

corrective actions necessary to return 

the CMS to operation consistent with 

your site-specific monitoring plan. You 

must use all the data collected during 

all other periods in assessing 

compliance and the operation of the 

control device and associated control 

system. 

(d) Except for periods of monitoring 

system malfunctions, repairs associated 

with monitoring system malfunctions, 

and required monitoring system quality 

assurance or quality control activities 

(including, as applicable, system 

accuracy audits, calibration checks, and 

required zero and span adjustments), 

failure to collect required data is a 

deviation of the monitoring 

requirements. In calculating monitoring 

results, do not use any data collected 

during periods of startup and shutdown, 

when the monitoring system is out of 

control as specified in your site-specific 

monitoring plan, while conducting 

repairs associated with periods when 

the monitoring system is out of control, 

or while conducting required 

monitoring system quality assurance or 

quality control activities. You must 

calculate monitoring results using all 

other monitoring data collected while 

the process is operating. You must 

report all periods when the monitoring 

system is out of control in your semiannual report. 

■ 15. Section 63.7540 is amended by: 

■ a. Revising paragraph (a)(2) 

introductory text. 

■ b. Revising paragraph (a)(3). 

■ c. Revising paragraph (a)(5). 

■ d. Revising paragraph (a)(8)(ii). 

■ e. Revising paragraph (a)(10) 

introductory text. 

■ f. Revising paragraph (a)(10)(vi) 

introductory text. 

■ g. Revising paragraph (a)(17). 

■ h. Revising paragraph (a)(19)(iii). 

■ i. Revising paragraph (d). 


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The revisions read as follows: 

§ 63.7540 How do I demonstrate 

continuous compliance with the emission 

limitations, fuel specifications and work 

practice standards? 

(a) * * * 

(2) As specified in § 63.7550(d), you 

must keep records of the type and 

amount of all fuels burned in each 

boiler or process heater during the 

reporting period to demonstrate that all 

fuel types and mixtures of fuels burned 

would result in either of the following: 

* * * * * 

(3) If you demonstrate compliance 

with an applicable HCl emission limit 

through fuel analysis for a solid or 

liquid fuel and you plan to burn a new 

type of solid or liquid fuel, you must 

recalculate the HCl emission rate using 

Equation 16 of § 63.7530 according to 

paragraphs (a)(3)(i) through (iii) of this 

section. You are not required to conduct 

fuel analyses for the fuels described in 

§ 63.7510(a)(2)(i) through (iii). You may 

exclude the fuels described in 

§ 63.7510(a)(2)(i) through (iii) when 

recalculating the HCl emission rate. 

(i) You must determine the chlorine 

concentration for any new fuel type in 

units of pounds per million Btu, based 

on supplier data or your own fuel 

analysis, according to the provisions in 

your site-specific fuel analysis plan 

developed according to § 63.7521(b). 

(ii) You must determine the new 

mixture of fuels that will have the 

highest content of chlorine. 

(iii) Recalculate the HCl emission rate 

from your boiler or process heater under 

these new conditions using Equation 16 

of § 63.7530. The recalculated HCl 

emission rate must be less than the 

applicable emission limit. 

* * * * * 

(5) If you demonstrate compliance 

with an applicable mercury emission 

limit through fuel analysis, and you 

plan to burn a new type of fuel, you 

must recalculate the mercury emission 

rate using Equation 17 of § 63.7530 

according to the procedures specified in 

paragraphs (a)(5)(i) through (iii) of this 

section. You are not required to conduct 

fuel analyses for the fuels described in 

§ 63.7510(a)(2)(i) through (iii). You may 

exclude the fuels described in 

§ 63.7510(a)(2)(i) through (iii) when 

recalculating the mercury emission rate. 

(i) You must determine the mercury 

concentration for any new fuel type in 

units of pounds per million Btu, based 

on supplier data or your own fuel 

analysis, according to the provisions in 

your site-specific fuel analysis plan 

developed according to § 63.7521(b). 

(ii) You must determine the new 

mixture of fuels that will have the 

highest content of mercury. 

(iii) Recalculate the mercury emission 

rate from your boiler or process heater 

under these new conditions using 

Equation 17 of § 63.7530. The 

recalculated mercury emission rate must 

be less than the applicable emission 

limit. 

* * * * * 

(8) * * * 

(ii) Maintain a CO emission level 

below or at your applicable alternative 

CO CEMS-based standard in Tables 1 or 

2 or 11 through 13 to this subpart at all 

times the affected unit is subject to 

numeric emission limits. 

* * * * * 

(10) If your boiler or process heater 

has a heat input capacity of 10 million 

Btu per hour or greater, you must 

conduct an annual tune-up of the boiler 

or process heater to demonstrate 

continuous compliance as specified in 

paragraphs (a)(10)(i) through (vi) of this 

section. You must conduct the tune-up 

while burning the type of fuel (or fuels 

in case of units that routinely burn a 

mixture) that provided the majority of 

the heat input to the boiler or process 

heater over the 12 months prior to the 

tune-up. This frequency does not apply 

to limited-use boilers and process 

heaters, as defined in § 63.7575, or units 

with continuous oxygen trim systems 

that maintain an optimum air to fuel 

ratio. 

* * * * * 

(vi) Maintain on-site and submit, if 

requested by the Administrator, a report 

containing the information in 

paragraphs (a)(10)(vi)(A) through (C) of 

this section, 

* * * * * 

(17) If you demonstrate compliance 

with an applicable TSM emission limit 

through fuel analysis for solid or liquid 

fuels, and you plan to burn a new type 

of fuel, you must recalculate the TSM 

emission rate using Equation 18 of 

§ 63.7530 according to the procedures 

specified in paragraphs (a)(5)(i) through 

(iii) of this section. You are not required 

to conduct fuel analyses for the fuels 

described in § 63.7510(a)(2)(i) through 

(iii). You may exclude the fuels 

described in § 63.7510(a)(2)(i) through 

(iii) when recalculating the TSM 

emission rate. 

(i) You must determine the TSM 

concentration for any new fuel type in 

units of pounds per million Btu, based 

on supplier data or your own fuel 

analysis, according to the provisions in 

your site-specific fuel analysis plan 

developed according to § 63.7521(b). 

(ii) You must determine the new 

mixture of fuels that will have the 

highest content of TSM. 

(iii) Recalculate the TSM emission 

rate from your boiler or process heater 

under these new conditions using 

Equation 18 of § 63.7530. The 

recalculated TSM emission rate must be 

less than the applicable emission limit. 

* * * * * 

(19) * * * 

* * * * * 

(iii) Collect PM CEMS hourly average 

output data for all boiler operating 

hours except as indicated in paragraph 

(v) of this section. 

* * * * * 

(d) For startup and shutdown, you 

must meet the work practice standards 

according to items 5 and 6 of Table 3 of 

this subpart. 

* * * * * 

■ 16. Section 63.7545 is amended by 

revising paragraphs (e)(8)(i) and (h) 

introductory text. 

§ 63.7545 What notifications must I submit 

and when? 

* * * * * 

(e) * * * 

(8) * * * 

(i) ‘‘This facility completed the 

required initial tune-up according to the 

procedures in § 63.7540(a)(10)(i) 

through (vi).’’ 

* * * * * 

(h) If you have switched fuels or made 

a physical change to the boiler or 

process heater and the fuel switch or 

physical change resulted in the 

applicability of a different subcategory, 

you must provide notice of the date 

upon which you switched fuels or made 

the physical change within 30 days of 

the switch/change. The notification 

must identify: 

* * * * * 

■ 17. Section 63.7550 is amended by 

revising paragraphs (b), (c), (d) 

introductory text, (d)(1), and (h) to read 

as follows: 

§ 63.7550 What reports must I submit and 

when? 

* * * * * 

(b) Unless the EPA Administrator has 

approved a different schedule for 

submission of reports under § 63.10(a), 

you must submit each report, according 

to paragraph (h) of this section, by the 

date in Table 9 to this subpart and 

according to the requirements in 

paragraphs (b)(1) through (4) of this 

section. For units that are subject only 

to the energy assessment requirement 

and a requirement to conduct an annual, 

biennial, or 5-year tune-up according to 

§ 63.7540(a)(10), (11), or (12), 


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respectively, and not subject to emission 

limits or Table 4 operating limits, you 

may submit only an annual, biennial, or 

5-year compliance report, as applicable, 

as specified in paragraphs (b)(1) through 

(4) of this section, instead of a semiannual compliance report. 

(1) The first semi-annual compliance 

report must cover the period beginning 

on the compliance date that is specified 

for each boiler or process heater in 

§ 63.7495 and ending on June 30 or 

December 31, whichever date is the first 

date that occurs at least 180 days (or 1, 

2, or 5 years, as applicable, if submitting 

an annual, biennial, or 5-year 

compliance report) after the compliance 

date that is specified for your source in 

§ 63.7495. 

(2) The first semi-annual compliance 

report must be postmarked or submitted 

no later than July 31 or January 31, 

whichever date is the first date 

following the end of the first calendar 

half after the compliance date that is 

specified for each boiler or process 

heater in § 63.7495. The first annual, 

biennial, or 5-year compliance report 

must be postmarked or submitted no 

later than January 31. 

(3) Each subsequent semi-annual 

compliance report must cover the 

semiannual reporting period from 

January 1 through June 30 or the 

semiannual reporting period from July 1 

through December 31. Annual, biennial, 

and 5-year compliance reports must 

cover the applicable 1-, 2-, or 5-year 

periods from January 1 to December 31. 

(4) Each subsequent semi-annual 

compliance report must be postmarked 

or submitted no later than July 31 or 

January 31, whichever date is the first 

date following the end of the 

semiannual reporting period. Annual, 

biennial, and 5-year compliance reports 

must be postmarked or submitted no 

later than January 31. 

(c) A compliance report must contain 

the following information depending on 

how the facility chooses to comply with 

the limits set in this rule. 

(1) If the facility is subject to the 

requirements of a tune up you must 

submit a compliance report with the 

information in paragraphs (c)(5)(i) 

through (iii), (xiv) and (xvii) of this 

section, and paragraph (c)(5)(iv) of this 

section for limited-use boiler or process 

heater. 

(2) If you are complying with the fuel 

analysis you must submit a compliance 

report with the information in 

paragraphs (c)(5)(i) through (iii), (vi), 

(x), (xi), (xiii), (xv), (xvii), (xviii) and 

paragraph (d) of this section. 

(3) If you are complying with the 

applicable emissions limit with 

performance testing you must submit a 

compliance report with the information 

in (c)(5)(i) through (iii), (vi), (vii), (viii), 

(ix), (xi), (xiii), (xv), (xvii), (xviii) and 

paragraph (d) of this section. 

(4) If you are complying with an 

emissions limit using a CMS the 

compliance report must contain the 

information required in paragraphs 

(c)(5)(i) through (iii), (v), (vi), (xi) 

through (xiii), (xv) through (xviii), and 

paragraph (e) of this section. 

(5)(i) Company and Facility name and 

address. 

(ii) Process unit information, 

emissions limitations, and operating 

parameter limitations. 

(iii) Date of report and beginning and 

ending dates of the reporting period. 

(iv) The total operating time during 

the reporting period. 

(v) If you use a CMS, including CEMS, 

COMS, or CPMS, you must include the 

monitoring equipment manufacturer(s) 

and model numbers and the date of the 

last CMS certification or audit. 

(vi) The total fuel use by each 

individual boiler or process heater 

subject to an emission limit within the 

reporting period, including, but not 

limited to, a description of the fuel, 

whether the fuel has received a nonwaste determination by the EPA or your 

basis for concluding that the fuel is not 

a waste, and the total fuel usage amount 

with units of measure. 

(vii) If you are conducting 

performance tests once every 3 years 

consistent with § 63.7515(b) or (c), the 

date of the last 2 performance tests and 

a statement as to whether there have 

been any operational changes since the 

last performance test that could increase 

emissions. 

(viii) A statement indicating that you 

burned no new types of fuel in an 

individual boiler or process heater 

subject to an emission limit. Or, if you 

did burn a new type of fuel and are 

subject to a HCl emission limit, you 

must submit the calculation of chlorine 

input, using Equation 7 of § 63.7530, 

that demonstrates that your source is 

still within its maximum chlorine input 

level established during the previous 

performance testing (for sources that 

demonstrate compliance through 

performance testing) or you must submit 

the calculation of HCl emission rate 

using Equation 16 of § 63.7530 that 

demonstrates that your source is still 

meeting the emission limit for HCl 

emissions (for boilers or process heaters 

that demonstrate compliance through 

fuel analysis). If you burned a new type 

of fuel and are subject to a mercury 

emission limit, you must submit the 

calculation of mercury input, using 

Equation 8 of § 63.7530, that 

demonstrates that your source is still 

within its maximum mercury input 

level established during the previous 

performance testing (for sources that 

demonstrate compliance through 

performance testing), or you must 

submit the calculation of mercury 

emission rate using Equation 17 of 

§ 63.7530 that demonstrates that your 

source is still meeting the emission limit 

for mercury emissions (for boilers or 

process heaters that demonstrate 

compliance through fuel analysis). If 

you burned a new type of fuel and are 

subject to a TSM emission limit, you 

must submit the calculation of TSM 

input, using Equation 9 of § 63.7530, 

that demonstrates that your source is 

still within its maximum TSM input 

level established during the previous 

performance testing (for sources that 

demonstrate compliance through 

performance testing), or you must 

submit the calculation of TSM emission 

rate, using Equation 18 of § 63.7530, that 

demonstrates that your source is still 

meeting the emission limit for TSM 

emissions (for boilers or process heaters 

that demonstrate compliance through 

fuel analysis). 

(ix) If you wish to burn a new type of 

fuel in an individual boiler or process 

heater subject to an emission limit and 

you cannot demonstrate compliance 

with the maximum chlorine input 

operating limit using Equation 7 of 

§ 63.7530 or the maximum mercury 

input operating limit using Equation 8 

of § 63.7530, or the maximum TSM 

input operating limit using Equation 9 

of § 63.7530 you must include in the 

compliance report a statement 

indicating the intent to conduct a new 

performance test within 60 days of 

starting to burn the new fuel. 

(x) A summary of any monthly fuel 

analyses conducted to demonstrate 

compliance according to §§ 63.7521 and 

63.7530 for individual boilers or process 

heaters subject to emission limits, and 

any fuel specification analyses 

conducted according to §§ 63.7521(f) 

and 63.7530(g). 

(xi) If there are no deviations from any 

emission limits or operating limits in 

this subpart that apply to you, a 

statement that there were no deviations 

from the emission limits or operating 

limits during the reporting period. 

(xii) If there were no deviations from 

the monitoring requirements including 

no periods during which the CMSs, 

including CEMS, COMS, and CPMS, 

were out of control as specified in 

§ 63.8(c)(7), a statement that there were 

no deviations and no periods during 

which the CMS were out of control 

during the reporting period. 

(xiii) If a malfunction occurred during 

the reporting period, the report must 


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include the number, duration, and a 

brief description for each type of 

malfunction which occurred during the 

reporting period and which caused or 

may have caused any applicable 

emission limitation to be exceeded. The 

report must also include a description of 

actions taken by you during a 

malfunction of a boiler, process heater, 

or associated air pollution control 

device or CMS to minimize emissions in 

accordance with § 63.7500(a)(3), 

including actions taken to correct the 

malfunction. 

(xiv) Include the date of the most 

recent tune-up for each unit subject to 

only the requirement to conduct an 

annual, biennial, or 5-year tune-up 

according to § 63.7540(a)(10), (11), or 

(12) respectively. Include the date of the 

most recent burner inspection if it was 

not done annually, biennially, or on a 5- 

year period and was delayed until the 

next scheduled or unscheduled unit 

shutdown. 

(xv) If you plan to demonstrate 

compliance by emission averaging, 

certify the emission level achieved or 

the control technology employed is no 

less stringent than the level or control 

technology contained in the notification 

of compliance status in 

§ 63.7545(e)(5)(i). 

(xvi) For each reporting period, the 

compliance reports must include all of 

the calculated 30 day rolling average 

values based on the daily CEMS (CO 

and mercury) and CPMS (PM CPMS 

output, scrubber pH, scrubber liquid 

flow rate, scrubber pressure drop) data. 

(xvii) Statement by a responsible 

official with that official’s name, title, 

and signature, certifying the truth, 

accuracy, and completeness of the 

content of the report. 

(xviii) For each instance of startup or 

shutdown include the information 

required to be monitored, collected, or 

recorded according to the requirements 

of § 63.7555(d). 

* * * * * 

(d) For each deviation from an 

emission limit or operating limit in this 

subpart that occurs at an individual 

boiler or process heater where you are 

not using a CMS to comply with that 

emission limit or operating limit, or 

from the work practice standards for 

periods if startup and shutdown, the 

compliance report must additionally 

contain the information required in 

paragraphs (d)(1) through (3) of this 

section. 

(1) A description of the deviation and 

which emission limit, operating limit, or 

work practice standard from which you 

deviated. 

* * * * * 

(h) You must submit the reports 

according to the procedures specified in 

paragraphs (h)(1) through (3) of this 

section. 

(1) Within 60 days after the date of 

completing each performance test 

(defined in § 63.2) required by this 

subpart, you must submit the results of 

the performance test, including any 

associated fuel analyses, following the 

procedure specified in either paragraph 

(h)(1)(i) or (h)(1)(ii) of this section. 

(i) For data collected using test 

methods supported by the EPA’s 

Electronic Reporting Tool (ERT) as 

listed on the EPA’s ERT Web site 

(http://www.epa.gov/ttn/chief/ert/

index.html) at the time of the test, you 

must submit the results of the 

performance test to the EPA via the 

Compliance and Emissions Data 

Reporting Interface (CEDRI). (CEDRI can 

be accessed through the EPA’s Central 

Data Exchange (CDX) (www.epa.gov/

cdx).) Performance test data must be 

submitted in a file format generated 

through use of the EPA’s ERT. Instead 

of submitting performance test data in a 

file format generated through the use of 

the EPA’s ERT, you may submit an 

alternate electronic file format 

consistent with the extensible markup 

language (XML) schema listed on the 

EPA’s ERT Web site, once the XML 

schema is available. If you claim that 

some of the performance test 

information being submitted is 

confidential business information (CBI), 

you must submit a complete file 

generated through the use of the EPA’s 

ERT (or an alternate electronic file 

consistent with the XML schema listed 

on the EPA’s ERT Web site once the 

XML schema is available), including 

information claimed to be CBI, on a 

compact disc, flash drive or other 

commonly used electronic storage 

media to the EPA. The electronic media 

must be clearly marked as CBI and 

mailed to U.S. EPA/OAPQS/CORE CBI 

Office, Attention: Group Leader, 

Measurement Policy Group, MD C404– 

02, 4930 Old Page Rd., Durham, NC 

27703. The same ERT or alternate file 

with the CBI omitted must be submitted 

to the EPA via the EPA’s CDX as 

described earlier in this paragraph. 

(ii) For data collected using test 

methods that are not supported by the 

EPA’s ERT as listed on the EPA’s ERT 

Web site, you must submit the results of 

the performance test to the 

Administrator at the appropriate 

address listed in § 63.13. 

(2) Within 60 days after the date of 

completing each CEMS performance 

evaluation (as defined in 63.2), you 

must submit the results of the 

performance evaluation following the 

procedure specified in either paragraph 

(h)(2)(i) or (h)(2)(ii) of this section. 

(i) For performance evaluations of 

continuous monitoring systems 

measuring relative accuracy test audit 

(RATA) pollutants that are supported by 

the EPA’s ERT as listed on the EPA’s 

ERT Web site at the time of the test, you 

must submit the results of the 

performance evaluation to the EPA via 

the CEDRI. (CEDRI can be accessed 

through the EPA’s CDX.) Performance 

evaluation data must be submitted in a 

file format generated through the use of 

the EPA’s ERT. Instead of submitting 

performance evaluation data in a file 

format generated through the use of the 

EPA’s ERT, you may submit an alternate 

electronic file format consistent with the 

XML schema listed on the EPA’s ERT 

Web site, once the XML schema is 

available. If you claim that some of the 

performance evaluation information 

being submitted is CBI, you must submit 

a complete file generated through the 

use of the EPA’s ERT (or an alternate 

electronic file consistent with the XML 

schema listed on the EPA’s ERT Web 

site once the XML schema is available), 

including information claimed to be 

CBI, on a compact disc, flash drive or 

other commonly used electronic storage 

media to the EPA. The electronic media 

must be clearly marked as CBI and 

mailed to U.S. EPA/OAPQS/CORE CBI 

Office, Attention: Group Leader, 

Measurement Policy Group, MD C404– 

02, 4930 Old Page Rd., Durham, NC 

27703. The same ERT or alternate file 

with the CBI omitted must be submitted 

to the EPA via the EPA’s CDX as 

described earlier in this paragraph. 

(ii) For any performance evaluations 

of continuous monitoring systems 

measuring RATA pollutants that are not 

supported by the EPA’s ERT as listed on 

the ERT Web site, you must submit the 

results of the performance evaluation to 

the Administrator at the appropriate 

address listed in § 63.13. 

(3) You must submit all reports 

required by Table 9 of this subpart 

electronically to the EPA via the CEDRI. 

(CEDRI can be accessed through the 

EPA’s CDX.) You must use the 

appropriate electronic report in CEDRI 

for this subpart. Instead of using the 

electronic report in CEDRI for this 

subpart, you may submit an alternate 

electronic file consistent with the XML 

schema listed on the CEDRI Web site 

(http://www.epa.gov/ttn/chief/cedri/

index.html), once the XML schema is 

available. If the reporting form specific 

to this subpart is not available in CEDRI 

at the time that the report is due, you 

must submit the report to the 

Administrator at the appropriate 

address listed in § 63.13. You must 


asabaliauskas on DSK5VPTVN1PROD with PROPOSALS
3112 Federal Register / Vol. 80, No. 13 / Wednesday, January 21, 2015 / Proposed Rules 

begin submitting reports via CEDRI no 

later than 90 days after the form 

becomes available in CEDRI. 

■ 18. Section 63.7555 is amended by: 

■ a. Adding paragraph (a)(3). 

■ b. Removing paragraph (d)(3). 

■ c. Redesignating paragraphs (d)(4) 

through (d)(11) as paragraphs (d)(3) 

through (d)(10). 

■ d. Revising newly designated 

paragraphs (d)(3), (d)(4), and (d)(8). 

■ e. Adding new paragraphs (d)(11) and 

(12). 

■ f. Removing paragraphs (i) and (j). 

The revisions and additions read as 

follows: 

§ 63.7555 What records must I keep? 

(a) * * * 

(3) For units in the limited use 

subcategory, you must keep a copy of 

the federally enforceable permit that 

limits the annual capacity factor to less 

than or equal to 10 percent and fuel use 

records for the days the boiler or process 

heater was operating. 

* * * * * 

(d) * * * 

(3) A copy of all calculations and 

supporting documentation of maximum 

chlorine fuel input, using Equation 7 of 

§ 63.7530, that were done to 

demonstrate continuous compliance 

with the HCl emission limit, for sources 

that demonstrate compliance through 

performance testing. For sources that 

demonstrate compliance through fuel 

analysis, a copy of all calculations and 

supporting documentation of HCl 

emission rates, using Equation 16 of 

§ 63.7530, that were done to 

demonstrate compliance with the HCl 

emission limit. Supporting 

documentation should include results of 

any fuel analyses and basis for the 

estimates of maximum chlorine fuel 

input or HCl emission rates. You can 

use the results from one fuel analysis for 

multiple boilers and process heaters 

provided they are all burning the same 

fuel type. However, you must calculate 

chlorine fuel input, or HCl emission 

rate, for each boiler and process heater. 

(4) A copy of all calculations and 

supporting documentation of maximum 

mercury fuel input, using Equation 8 of 

§ 63.7530, that were done to 

demonstrate continuous compliance 

with the mercury emission limit for 

sources that demonstrate compliance 

through performance testing. For 

sources that demonstrate compliance 

through fuel analysis, a copy of all 

calculations and supporting 

documentation of mercury emission 

rates, using Equation 17 of § 63.7530, 

that were done to demonstrate 

compliance with the mercury emission 

limit. Supporting documentation should 

include results of any fuel analyses and 

basis for the estimates of maximum 

mercury fuel input or mercury emission 

rates. You can use the results from one 

fuel analysis for multiple boilers and 

process heaters provided they are all 

burning the same fuel type. However, 

you must calculate mercury fuel input, 

or mercury emission rates, for each 

boiler and process heater. 

* * * * * 

(8) A copy of all calculations and 

supporting documentation of maximum 

TSM fuel input, using Equation 9 of 

§ 63.7530, that were done to 

demonstrate continuous compliance 

with the TSM emission limit for sources 

that demonstrate compliance through 

performance testing. For sources that 

demonstrate compliance through fuel 

analysis, a copy of all calculations and 

supporting documentation of TSM 

emission rates, using Equation 18 of 

§ 63.7530, that were done to 

demonstrate compliance with the TSM 

emission limit. Supporting 

documentation should include results of 

any fuel analyses and basis for the 

estimates of maximum TSM fuel input 

or TSM emission rates. You can use the 

results from one fuel analysis for 

multiple boilers and process heaters 

provided they are all burning the same 

fuel type. However, you must calculate 

TSM fuel input, or TSM emission rates, 

for each boiler and process heater. 

* * * * * 

(11) For each startup period, you must 

maintain records of the time that clean 

fuel combustion begins; the time when 

firing (i.e., feeding) start for coal/solid 

fossil fuel, biomass/bio-based solids, 

heavy liquid fuel, or gas 2 (other) gases; 

the time when useful thermal energy is 

first supplied; and the time when the 

PM controls are engaged. 

(12) For each startup period, you must 

maintain records of the hourly steam 

temperature, hourly steam pressure, 

hourly steam flow, hourly flue gas 

temperature, and all hourly average 

CMS data (e.g., CEMS, PM CPMS, 

COMS, ESP total secondary electric 

power input, scrubber pressure drop, 

scrubber liquid flow rate) collected 

during each startup period to confirm 

that the control devices are engaged. In 

addition, if compliance with the PM 

emission limit is demonstrated using a 

PM control device, you must maintain 

records as specified in paragraphs 

(d)(12)(i) through (iii) of this section. 

(i) For a boiler or process heater with 

an electrostatic precipitator, record the 

number of fields in service, as well as 

each field’s secondary voltage and 

secondary current during each hour of 

startup. 

(ii) For a boiler or process heater with 

a fabric filter, record the number of 

compartments in service, as well as the 

differential pressure across the baghouse 

during each hour of startup. 

(iii) For a boiler or process heater with 

a wet scrubber needed for filterable PM 

control, record the scrubber liquid to 

fuel ratio and the differential pressure of 

the liquid during each hour of startup. 

* * * * * 

■ 19. Section 63.7575 is amended by: 

■ a. Revising the definitions for ‘‘Coal,’’ 

‘‘Limited-use boiler or process heater,’’ 

‘‘Load fraction,’’ ‘‘Oxygen trim system,’’ 

‘‘Shutdown,’’ ‘‘Startup,’’ ‘‘Steam 

output,’’ and ‘‘Temporary boiler.’’ 

■ b. Adding in alphabetical order 

definitions for ‘‘Fossil fuel’’ and ‘‘Useful 

thermal energy.’’ 

■ c. Removing the definition for 

‘‘Affirmative defense.’’ 

The revisions read as follows: 

§ 63.7575 What definitions apply to this 

subpart? 

* * * * * 

Coal means all solid fuels classifiable 

as anthracite, bituminous, subbituminous, or lignite by ASTM D388 

(incorporated by reference, see § 63.14), 

coal refuse, and petroleum coke. For the 

purposes of this subpart, this definition 

of ‘‘coal’’ includes synthetic fuels 

derived from coal, including but not 

limited to, solvent-refined coal, coal-oil 

mixtures, and coal-water mixtures. Coal 

derived gases and liquids are excluded 

from this definition. 

* * * * * 

Fossil fuel means natural gas, oil, 

coal, and any form of solid, liquid, or 

gaseous fuel derived from such material. 

* * * * * 

Limited-use boiler or process heater 

means any boiler or process heater that 

burns any amount of solid, liquid, or 

gaseous fuels and has a federally 

enforceable annual capacity factor of no 

more than 10 percent. 

* * * * * 

Load fraction means the actual heat 

input of a boiler or process heater 

divided by heat input during the 

performance test that established the 

minimum sorbent injection rate or 

minimum activated carbon injection 

rate, expressed as a fraction (e.g., for 50 

percent load the load fraction is 0.5). 

For boilers and process heaters that cofire natural gas or refinery gas with a 

solid or liquid fuel, the load fraction is 

determined by the actual heat input of 

the solid or liquid fuel divided by heat 

input of the solid or liquid fuel fired 

during the performance test (e.g., if the 

performance test was conducted at 100 

percent solid fuel firing, for 100 percent 


asabaliauskas on DSK5VPTVN1PROD with PROPOSALS
Federal Register / Vol. 80, No. 13 / Wednesday, January 21, 2015 / Proposed Rules 3113 

load firing 50 percent solid fuel and 50 

percent natural gas the load fraction is 

0.5). 

* * * * * 

Oxygen trim system means a system of 

monitors that is used to maintain excess 

air at the desired level in a combustion 

device over its operating load range. A 

typical system consists of a flue gas 

oxygen and/or CO monitor that 

automatically provides a feedback signal 

to the combustion air controller or draft 

controller. 

* * * * * 

Shutdown means the period in which 

cessation of operation of a boiler or 

process heater is initiated for any 

purpose. Shutdown begins when the 

boiler or process heater no longer makes 

useful thermal energy (such as heat or 

steam) for heating, cooling, or process 

purposes and/or generates electricity or 

when no fuel is being fed to the boiler 

or process heater, whichever is earlier. 

Shutdown ends when the boiler or 

process heater no longer makes useful 

thermal energy (such as steam or heat) 

for heating, cooling, or process purposes 

and/or generates electricity, and no fuel 

is being combusted in the boiler or 

process heater. 

* * * * * 

Startup means: 

(1) Either the first-ever firing of fuel 

in a boiler or process heater for the 

purpose of supplying steam or heat for 

heating and/or producing electricity, or 

for any other purpose, or the firing of 

fuel in a boiler after a shutdown event 

for any purpose. Startup ends when any 

of the steam or heat from the boiler or 

process heater is supplied for heating, 

and/or producing electricity, or for any 

other purpose, or 

(2) The period in which operation of 

a boiler or process heater is initiated for 

any purpose. Startup begins with either 

the first-ever firing of fuel in a boiler or 

process heater for the purpose of 

supplying useful thermal energy (such 

as steam or heat) for heating, cooling or 

process purposes, or producing 

electricity, or the firing of fuel in a 

boiler or process heater for any purpose 

after a shutdown event. Startup ends 

four hours after when the boiler or 

process heater makes useful thermal 

energy (such as heat or steam) for 

heating, cooling, or process purposes, or 

generates electricity, whichever is 

earlier. 

Steam output means: 

(1) For a boiler that produces steam 

for process or heating only (no power 

generation), the energy content in terms 

of MMBtu of the boiler steam output, 

(2) For a boiler that cogenerates 

process steam and electricity (also 

known as combined heat and power), 

the total energy output, which is the 

sum of the energy content of the steam 

exiting the turbine and sent to process 

in MMBtu and the energy of the 

electricity generated converted to 

MMBtu at a rate of 10,000 Btu per 

kilowatt-hour generated (10 MMBtu per 

megawatt-hour), and 

(3) For a boiler that generates only 

electricity, the alternate output-based 

emission limits would be the 

appropriate emission limit from Table 1 

or 2 of this subpart in units of pounds 

per million Btu heat input (lb per 

MWh). 

(4) For a boiler that performs multiple 

functions and produces steam to be 

used for any combination of (1), (2) and 

(3) that includes electricity generation 

(3), the total energy output, in terms of 

MMBtu of steam output, is the sum of 

the energy content of steam sent directly 

to the process and/or used for heating 

(S1), the energy content of turbine steam 

sent to process plus energy in electricity 

according to (2) above (S2), and the 

energy content of electricity generated 

by a electricity only turbine as (3) above 

(S3) and would be calculated using 

Equation 21 of this section. In the case 

of boilers supplying steam to one or 

more common heaters, S1, S2, and MW(3)

for each boiler would be calculated 

based on the its (steam energy) 

contribution (fraction of total stam 

energy) to the common heater. 

Where: 

SOM = Total steam output for multi-function 

boiler, MMBtu 

S1 = Energy content of steam sent directly to 

the process and/or used for heating, 

MMBtu 

S2 = Energy content of turbine steam sent to 

the process plus energy in electricity 

according to (2) above, MMBtu 

MW(3) = Electricity generated according to (3) 

above, MWh 

CFn = Conversion factor for the appropriate 

subcategory for converting electricity 

generated according to (3) above to 

equivalent steam energy, MMBtu/MWh 

CFn for emission limits for boilers in the unit 

designed to burn solid fuel subcategory 

= 10.8 

CFn PM and CO emission limits for boilers 

in one of the subcategories of units 

designed to burn coal = 11.7 

CFn PM and CO emission limits for boilers 

in one of the subcategories of units 

designed to burn biomass = 12.1 

CFn for emission limits for boilers in one of 

the subcategories of units designed to 

burn liquid fuel = 11.2 

CFn for emission limits for boilers in the unit 

designed to burn gas 2 (other) 

subcategory = 6.2 

* * * * * 

Temporary boiler means any gaseous 

or liquid fuel boiler or process heater 

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 or process heater is not a 

temporary boiler or process heater if any 

one of the following conditions exists: 

(1) The equipment is attached to a 

foundation. 

(2) The boiler or process heater or a 

replacement remains at a location 

within the facility and performs the 

same or similar function for more than 

12 consecutive months, unless the 

regulatory agency approves an 

extension. An extension may be granted 

by the regulating agency upon petition 

by the owner or operator of a unit 

specifying the basis for such a request. 

Any temporary boiler or process heater 

that replaces a temporary boiler or 

process heater 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 

but continues to perform the same or 

similar function and serve the same 

electricity, process heat, steam, and/or 

hot water system in an attempt to 

circumvent the residence time 

requirements of this definition. 

* * * * * 

Useful thermal energy means energy 

(i.e., steam, hot water, or process heat) 

that meets the minimum operating 

temperature and/or pressure required by 

any energy use system that uses energy 

provided by the affected boiler or 

process heater. 

* * * * * 

■ 20. Table 1 to subpart DDDDD of part 

63 is revised to read as follows: 


asabaliauskas on DSK5VPTVN1PROD with PROPOSALSEP21JA15.007</GPH>
3114 Federal Register / Vol. 80, No. 13 / Wednesday, January 21, 2015 / Proposed Rules 

TABLE 1 TO SUBPART DDDDD OF PART 63—EMISSION LIMITS FOR NEW OR RECONSTRUCTED BOILERS AND PROCESS

HEATERS

AS STATED IN § 63.7500, YOU MUST COMPLY WITH THE FOLLOWING APPLICABLE EMISSION LIMITS: 

[Units with heat input capacity of 10 million Btu per hour or greater] 

If your boiler or 

process heater is 

in this subcategory . . . 

For the following 

pollutants . . . 

The emissions must not exceed 

the following emission limits, except during startup and shutdown 

. . . 

Or the emissions must not exceed the following alternative 

output-based limits, except during startup and shutdown . . . 

Using this specified sampling volume or test run duration . . . 

1. Units in all subcategories designed to burn 

solid fuel..

a. HCl ............... 2.2E–02 lb per MMBtu of heat 

input.

2.5E–02 lb per MMBtu of steam 

output or 0.28 lb per MWh.

For M26A, collect a minimum of 

1 dscm per run; for M26 collect 

a minimum of 120 liters per 

run. 

b. Mercury ........ 8.0E–07 a lb per MMBtu of heat 

input.

8.7E–07 a lb per MMBtu of steam 

output or 1.1E–05 a lb per 

MWh.

For M29, collect a minimum of 4 

dscm per run; for M30A or 

M30B, collect a minimum sample as specified in the method; 

for ASTM D6784 b collect a 

minimum of 4 dscm. 

2. Units designed 

to burn coal/

solid fossil fuel.

a. Filterable PM 

(or TSM).

1.1E–03 lb per MMBtu of heat 

input; or (2.3E–05 lb per 

MMBtu of heat input).

1.1E–03 lb per MMBtu of steam 

output or 1.4E–02 lb per MWh; 

or (2.7E–05 lb per MMBtu of 

steam output or 2.9E–04 lb per 

MWh).

Collect a minimum of 3 dscm per 

run. 

3. Pulverized coal 

boilers designed to burn 

coal/solid fossil 

fuel.

a. Carbon monoxide (CO) (or 

CEMS).

130 ppm by volume on a dry 

basis corrected to 3 percent 

oxygen, 3-run average; or (320 

ppm by volume on a dry basis 

corrected to 3 percent oxygen d, 30-day rolling average).

0.11 lb per MMBtu of steam output or 1.4 lb per MWh; 3-run 

average.

1 hr minimum sampling time. 

4. Stokers/others 

designed to 

burn coal/solid 

fossil fuel.

a. CO (or 

CEMS).

130 ppm by volume on a dry 

basis corrected to 3 percent 

oxygen, 3-run average; or (340 

ppm by volume on a dry basis 

corrected to 3 percent oxygen d, 30-day rolling average).

0.12 lb per MMBtu of steam output or 1.4 lb per MWh; 3-run 

average.

1 hr minimum sampling time. 

5. Fluidized bed 

units designed 

to burn coal/

solid fossil fuel.

a. CO (or 

CEMS).

130 ppm by volume on a dry 

basis corrected to 3 percent 

oxygen, 3-run average; or (230 

ppm by volume on a dry basis 

corrected to 3 percent oxygen d, 30-day rolling average).

0.11 lb per MMBtu of steam output or 1.4 lb per MWh; 3-run 

average.

1 hr minimum sampling time. 

6. Fluidized bed 

units with an integrated heat 

exchanger designed to burn 

coal/solid fossil 

fuel.

a. CO (or 

CEMS).

140 ppm by volume on a dry 

basis corrected to 3 percent 

oxygen, 3-run average; or (150 

ppm by volume on a dry basis 

corrected to 3 percent oxygen d, 30-day rolling average).

1.2E–01 lb per MMBtu of steam 

output or 1.5 lb per MWh; 3- 

run average.

1 hr minimum sampling time. 

7. Stokers/sloped 

grate/others designed to burn 

wet biomass 

fuel.

a. CO (or 

CEMS).

620 ppm by volume on a dry 

basis corrected to 3 percent 

oxygen, 3-run average; or (390 

ppm by volume on a dry basis 

corrected to 3 percent oxygen d, 30-day rolling average).

5.8E–01 lb per MMBtu of steam 

output or 6.8 lb per MWh; 3- 

run average.

1 hr minimum sampling time. 

b. Filterable PM 

(or TSM).

3.0E–02 lb per MMBtu of heat 

input; or (2.6E–05 lb per 

MMBtu of heat input).

3.5E–02 lb per MMBtu of steam 

output or 4.2E–01 lb per MWh; 

or (2.7E–05 lb per MMBtu of 

steam output or 3.7E–04 lb per 

MWh).

Collect a minimum of 2 dscm per 

run. 

8. Stokers/sloped 

grate/others designed to burn 

kiln-dried biomass fuel.

a. CO ................ 460 ppm by volume on a dry 

basis corrected to 3 percent 

oxygen.

4.2E–01 lb per MMBtu of steam 

output or 5.1 lb per MWh.

1 hr minimum sampling time. 

b. Filterable PM 

(or TSM).

3.0E–02 lb per MMBtu of heat 

input; or (4.0E–03 lb per 

MMBtu of heat input).

3.5E–02 lb per MMBtu of steam 

output or 4.2E–01 lb per MWh; 

or (4.2E–03 lb per MMBtu of 

steam output or 5.6E–02 lb per 

MWh).

Collect a minimum of 2 dscm per 

run. 


asabaliauskas on DSK5VPTVN1PROD with PROPOSALS
Federal Register / Vol. 80, No. 13 / Wednesday, January 21, 2015 / Proposed Rules 3115 

TABLE 1 TO SUBPART DDDDD OF PART 63—EMISSION LIMITS FOR NEW OR RECONSTRUCTED BOILERS AND PROCESS

HEATERS—Continued 

AS STATED IN § 63.7500, YOU MUST COMPLY WITH THE FOLLOWING APPLICABLE EMISSION LIMITS: 

[Units with heat input capacity of 10 million Btu per hour or greater] 

If your boiler or 

process heater is 

in this subcategory . . . 

For the following 

pollutants . . . 

The emissions must not exceed 

the following emission limits, except during startup and shutdown 

. . . 

Or the emissions must not exceed the following alternative 

output-based limits, except during startup and shutdown . . . 

Using this specified sampling volume or test run duration . . . 

9. Fluidized bed 

units designed 

to burn biomass/bio-based 

solids.

a. CO (or 

CEMS).

230 ppm by volume on a dry 

basis corrected to 3 percent 

oxygen, 3-run average; or (310 

ppm by volume on a dry basis 

corrected to 3 percent oxygen d, 30-day rolling average).

2.2E–01 lb per MMBtu of steam 

output or 2.6 lb per MWh; 3- 

run average.

1 hr minimum sampling time. 

b. Filterable PM 

(or TSM).

9.8E–03 lb per MMBtu of heat 

input; or (8.3E–05 a lb per 

MMBtu of heat input).

1.2E–02 lb per MMBtu of steam 

output or 0.14 lb per MWh; or 

(1.1E–04 a lb per MMBtu of 

steam output or 1.2E–03 a lb 

per MWh).

Collect a minimum of 3 dscm per 

run. 

10. Suspension 

burners designed to burn 

biomass/biobased solids.

a. CO (or 

CEMS).

2,400 ppm by volume on a dry 

basis corrected to 3 percent 

oxygen, 3-run average; or 

(2,000 ppm by volume on a 

dry basis corrected to 3 percent oxygen d, 10-day rolling 

average).

1.9 lb per MMBtu of steam output or 27 lb per MWh; 3-run 

average.

1 hr minimum sampling time. 

b. Filterable PM 

(or TSM).

3.0E–02 lb per MMBtu of heat 

input; or (6.5E–03 lb per 

MMBtu of heat input).

3.1E–02 lb per MMBtu of steam 

output or 4.2E–01 lb per MWh; 

or (6.6E–03 lb per MMBtu of 

steam output or 9.1E–02 lb per 

MWh).

Collect a minimum of 2 dscm per 

run. 

11. Dutch Ovens/

Pile burners designed to burn 

biomass/biobased solids.

a. CO (or 

CEMS).

330 ppm by volume on a dry 

basis corrected to 3 percent 

oxygen, 3-run average; or (520 

ppm by volume on a dry basis 

corrected to 3 percent oxygen d, 10-day rolling average).

3.5E–01 lb per MMBtu of steam 

output or 3.6 lb per MWh; 3- 

run average.

1 hr minimum sampling time. 

b. Filterable PM 

(or TSM).

3.2E–03 lb per MMBtu of heat 

input; or (3.9E–05 lb per 

MMBtu of heat input).

4.3E–03 lb per MMBtu of steam 

output or 4.5E–02 lb per MWh; 

or (5.2E–05 lb per MMBtu of 

steam output or 5.5E–04 lb per 

MWh).

Collect a minimum of 3 dscm per 

run. 

12. Fuel cell units 

designed to 

burn biomass/

bio-based solids.

a. CO ................ 910 ppm by volume on a dry 

basis corrected to 3 percent 

oxygen.

1.1 lb per MMBtu of steam output or 1.0E+01 lb per MWh.1 hr minimum sampling time. 

b. Filterable PM 

(or TSM).

2.0E–02 lb per MMBtu of heat 

input; or (2.9E–05 a lb per 

MMBtu of heat input).

3.0E–02 lb per MMBtu of steam 

output or 2.8E–01 lb per MWh; 

or (5.1E–05 lb per MMBtu of 

steam output or 4.1E–04 lb per 

MWh).

Collect a minimum of 2 dscm per 

run. 

13. Hybrid suspension grate 

boiler designed 

to burn biomass/bio-based 

solids.

a. CO (or 

CEMS).

1,100 ppm by volume on a dry 

basis corrected to 3 percent 

oxygen, 3-run average; or (900 

ppm by volume on a dry basis 

corrected to 3 percent oxygen d, 30-day rolling average).

1.4 lb per MMBtu of steam output or 12 lb per MWh; 3-run 

average.

1 hr minimum sampling time. 

b. Filterable PM 

(or TSM).

2.6E–02 lb per MMBtu of heat 

input; or (4.4E–04 lb per 

MMBtu of heat input).

3.3E–02 lb per MMBtu of steam 

output or 3.7E–01 lb per MWh; 

or (5.5E–04 lb per MMBtu of 

steam output or 6.2E–03 lb per 

MWh).

Collect a minimum of 3 dscm per 

run. 

14. Units designed to burn 

liquid fuel.

a. HCl ............... 4.4E–04 lb per MMBtu of heat 

input.

4.8E–04 lb per MMBtu of steam 

output or 6.1E–03 lb per MWh.

For M26A: Collect a minimum of 

2 dscm per run; for M26, collect a minimum of 240 liters 

per run. 

b. Mercury ........ 4.8E–07 a lb per MMBtu of heat 

input.

5.3E–07 a lb per MMBtu of steam 

output or 6.7E–06 a lb per 

MWh.

For M29, collect a minimum of 4 

dscm per run; for M30A or 

M30B, collect a minimum sample as specified in the method; 

for ASTM D6784 b collect a 

minimum of 4 dscm. 


asabaliauskas on DSK5VPTVN1PROD with PROPOSALS
3116 Federal Register / Vol. 80, No. 13 / Wednesday, January 21, 2015 / Proposed Rules 

TABLE 1 TO SUBPART DDDDD OF PART 63—EMISSION LIMITS FOR NEW OR RECONSTRUCTED BOILERS AND PROCESS

HEATERS—Continued 

AS STATED IN § 63.7500, YOU MUST COMPLY WITH THE FOLLOWING APPLICABLE EMISSION LIMITS: 

[Units with heat input capacity of 10 million Btu per hour or greater] 

If your boiler or 

process heater is 

in this subcategory . . . 

For the following 

pollutants . . . 

The emissions must not exceed 

the following emission limits, except during startup and shutdown 

. . . 

Or the emissions must not exceed the following alternative 

output-based limits, except during startup and shutdown . . . 

Using this specified sampling volume or test run duration . . . 

15. Units designed to burn 

heavy liquid fuel.

a. CO ................ 130 ppm by volume on a dry 

basis corrected to 3 percent 

oxygen, 3-run average.

0.13 lb per MMBtu of steam output or 1.4 lb per MWh; 3-run 

average.

1 hr minimum sampling time. 

b. Filterable PM 

(or TSM).

1.3E–02 lb per MMBtu of heat 

input; or (7.5E–05 lb per 

MMBtu of heat input).

1.5E–02 lb per MMBtu of steam 

output or 1.8E–01 lb per MWh; 

or (8.2E–05 lb per MMBtu of 

steam output or 1.1E–03 lb per 

MWh).

Collect a minimum of 3 dscm per 

run. 

16. Units designed to burn 

light liquid fuel.

a. CO ................ 130 ppm by volume on a dry 

basis corrected to 3 percent 

oxygen.

0.13 lb per MMBtu of steam output or 1.4 lb per MWh.1 hr minimum sampling time. 

b. Filterable PM 

(or TSM).

1.1E–03 a lb per MMBtu of heat 

input; or (2.9E–05 lb per 

MMBtu of heat input).

1.2E–03 a lb per MMBtu of steam 

output or 1.6E–02 a lb per 

MWh; or (3.2E–05 lb per 

MMBtu of steam output or 

4.0E–04 lb per MWh).

Collect a minimum of 3 dscm per 

run. 

17. Units designed to burn 

liquid fuel that 

are non-continental units.

a. CO ................ 130 ppm by volume on a dry 

basis corrected to 3 percent 

oxygen, 3-run average based 

on stack test.

0.13 lb per MMBtu of steam output or 1.4 lb per MWh; 3-run 

average.

1 hr minimum sampling time. 

b. Filterable PM 

(or TSM).

2.3E–02 lb per MMBtu of heat 

input; or (8.6E–04 lb per 

MMBtu of heat input).

2.5E–02 lb per MMBtu of steam 

output or 3.2E–01 lb per MWh; 

or (9.4E–04 lb per MMBtu of 

steam output or 1.2E–02 lb per 

MWh).

Collect a minimum of 4 dscm per 

run. 

18. Units designed to burn 

gas 2 (other) 

gases.

a. CO ................ 130 ppm by volume on a dry 

basis corrected to 3 percent 

oxygen.

0.16 lb per MMBtu of steam output or 1.0 lb per MWh.1 hr minimum sampling time. 

b. HCl ............... 1.7E–03 lb per MMBtu of heat 

input.

2.9E–03 lb per MMBtu of steam 

output or 1.8E–02 lb per MWh.

For M26A, Collect a minimum of 

2 dscm per run; for M26, collect a minimum of 240 liters 

per run. 

c. Mercury ......... 7.9E–06 lb per MMBtu of heat 

input.

1.4E–05 lb per MMBtu of steam 

output or 8.3E–05 lb per MWh.

For M29, collect a minimum of 3 

dscm per run; for M30A or 

M30B, collect a minimum sample as specified in the method; 

for ASTM D6784 b, collect a 

minimum of 3 dscm. 

d. Filterable PM 

(or TSM).

6.7E–03 lb per MMBtu of heat 

input; or (2.1E–04 lb per 

MMBtu of heat input).

1.2E–02 lb per MMBtu of steam 

output or 7.0E–02 lb per MWh; 

or (3.5E–04 lb per MMBtu of 

steam output or 2.2E–03 lb per 

MWh).

Collect a minimum of 3 dscm per 

run. 

a If you are conducting stack tests to demonstrate compliance and your performance tests for this pollutant for at least 2 consecutive years 

show that your emissions are at or below this limit, you can skip testing according to § 63.7515 if all of the other provisions of § 63.7515 are met. 

For all other pollutants that do not contain a footnote ‘‘a’’, your performance tests for this pollutant for at least 2 consecutive years must show 

that your emissions are at or below 75 percent of this limit in order to qualify for skip testing. b Incorporated by reference, see § 63.14. 

c If your affected source is a new or reconstructed affected source that commenced construction or reconstruction after June 4, 2010, and before January 31, 2013, you may comply with the emission limits in Tables 11, 12 or 13 to this subpart until January 31, 2016. On and after January 31, 2016, you must comply with the emission limits in Table 1 to this subpart. dAn owner or operator may request that compliance with the carbon monoxide emission limit be determined using carbon dioxide measurements corrected to an equivalent of 3 percent oxygen. The relationship between oxygen and carbon dioxide levels for the affected facility shall 

be established during the initial compliance test. 

■ 21. Table 2 to subpart DDDDD of part 

63 is revised to read as follows: 


asabaliauskas on DSK5VPTVN1PROD with PROPOSALS
Federal Register / Vol. 80, No. 13 / Wednesday, January 21, 2015 / Proposed Rules 3117 

TABLE 2 TO SUBPART DDDDD OF PART 63—EMISSION LIMITS FOR EXISTING BOILERS AND PROCESS HEATERS

AS STATED IN § 63.7500, YOU MUST COMPLY WITH THE FOLLOWING APPLICABLE EMISSION LIMITS: 

[Units with heat input capacity of 10 million Btu per hour or greater] 

If your boiler or 

process heater is 

in this subcategory . . . 

For the following 

pollutants . . . 

The emissions must not exceed 

the following emission limits, except during startup and shutdown 

. . . 

The emissions must not exceed 

the following alternative outputbased limits, except during startup and shutdown . . . Using this specified sampling volume or test run duration . . . 

1. Units in all subcategories designed to burn 

solid fuel.

a. HCl ............... 2.2E–02 lb per MMBtu of heat 

input.

2.5E–02 lb per MMBtu of steam 

output or 0.27 lb per MWh.

For M26A, Collect a minimum of 

1 dscm per run; for M26, collect a minimum of 120 liters 

per run. 

b. Mercury ........ 5.7E–06 lb per MMBtu of heat 

input.

6.4E–06 lb per MMBtu of steam 

output or 7.3E–05 lb per MWh.

For M29, collect a minimum of 3 

dscm per run; for M30A or 

M30B, collect a minimum sample as specified in the method; 

for ASTM D6784 b collect a 

minimum of 3 dscm. 

2. Units design to 

burn coal/solid 

fossil fuel.

a. Filterable PM 

(or TSM).

4.0E–02 lb per MMBtu of heat 

input; or (5.3E–05 lb per 

MMBtu of heat input).

4.2E–02 lb per MMBtu of steam 

output or 4.9E–01 lb per MWh; 

or (5.6E–05 lb per MMBtu of 

steam output or 6.5E–04 lb per 

MWh).

Collect a minimum of 2 dscm per 

run. 

3. Pulverized coal 

boilers designed to burn 

coal/solid fossil 

fuel.

a. CO (or 

CEMS).

130 ppm by volume on a dry 

basis corrected to 3 percent 

oxygen, 3-run average; or (320 

ppm by volume on a dry basis 

corrected to 3 percent oxygen,c 30-day rolling average).

0.11 lb per MMBtu of steam output or 1.4 lb per MWh; 3-run 

average.

1 hr minimum sampling time. 

4. Stokers/others 

designed to 

burn coal/solid 

fossil fuel.

a. CO (or 

CEMS).

160 ppm by volume on a dry 

basis corrected to 3 percent 

oxygen, 3-run average; or (340 

ppm by volume on a dry basis 

corrected to 3 percent oxygen,c 30-day rolling average).

0.14 lb per MMBtu of steam output or 1.7 lb per MWh; 3-run 

average.

1 hr minimum sampling time. 

5. Fluidized bed 

units designed 

to burn coal/

solid fossil fuel.

a. CO (or 

CEMS).

130 ppm by volume on a dry 

basis corrected to 3 percent 

oxygen, 3-run average; or (230 

ppm by volume on a dry basis 

corrected to 3 percent oxygen,c 30-day rolling average).

0.12 lb per MMBtu of steam output or 1.4 lb per MWh; 3-run 

average.

1 hr minimum sampling time. 

6. Fluidized bed 

units with an integrated heat 

exchanger designed to burn 

coal/solid fossil 

fuel.

a. CO (or 

CEMS).

140 ppm by volume on a dry 

basis corrected to 3 percent 

oxygen, 3-run average; or (150 

ppm by volume on a dry basis 

corrected to 3 percent oxygen,c 30-day rolling average).

1.3E–01 lb per MMBtu of steam 

output or 1.5 lb per MWh; 3- 

run average.

1 hr minimum sampling time. 

7. Stokers/sloped 

grate/others designed to burn 

wet biomass 

fuel.

a. CO (or 

CEMS).

1,500 ppm by volume on a dry 

basis corrected to 3 percent 

oxygen, 3-run average; or (720 

ppm by volume on a dry basis 

corrected to 3 percent oxygen,c 30-day rolling average).

1.4 lb per MMBtu of steam output or 17 lb per MWh; 3-run 

average.

1 hr minimum sampling time. 

b. Filterable PM 

(or TSM).

3.7E–02 lb per MMBtu of heat 

input; or (2.4E–04 lb per 

MMBtu of heat input).

4.3E–02 lb per MMBtu of steam 

output or 5.2E–01 lb per MWh; 

or (2.8E–04 lb per MMBtu of 

steam output or 3.4E–04 lb per 

MWh).

Collect a minimum of 2 dscm per 

run. 

8. Stokers/sloped 

grate/others designed to burn 

kiln-dried biomass fuel.

a. CO ................ 460 ppm by volume on a dry 

basis corrected to 3 percent 

oxygen.

4.2E–01 lb per MMBtu of steam 

output or 5.1 lb per MWh.

1 hr minimum sampling time. 

b. Filterable PM 

(or TSM).

3.2E–01 lb per MMBtu of heat 

input; or (4.0E–03 lb per 

MMBtu of heat input).

3.7E–01 lb per MMBtu of steam 

output or 4.5 lb per MWh; or 

(4.6E–03 lb per MMBtu of 

steam output or 5.6E–02 lb per 

MWh).

Collect a minimum of 1 dscm per 

run. 


asabaliauskas on DSK5VPTVN1PROD with PROPOSALS
3118 Federal Register / Vol. 80, No. 13 / Wednesday, January 21, 2015 / Proposed Rules 

TABLE 2 TO SUBPART DDDDD OF PART 63—EMISSION LIMITS FOR EXISTING BOILERS AND PROCESS HEATERS— 

Continued 

AS STATED IN § 63.7500, YOU MUST COMPLY WITH THE FOLLOWING APPLICABLE EMISSION LIMITS: 

[Units with heat input capacity of 10 million Btu per hour or greater] 

If your boiler or 

process heater is 

in this subcategory . . . 

For the following 

pollutants . . . 

The emissions must not exceed 

the following emission limits, except during startup and shutdown 

. . . 

The emissions must not exceed 

the following alternative outputbased limits, except during startup and shutdown . . . Using this specified sampling volume or test run duration . . . 

9. Fluidized bed 

units designed 

to burn biomass/bio-based 

solid.

a. CO (or 

CEMS).

470 ppm by volume on a dry 

basis corrected to 3 percent 

oxygen, 3-run average; or (310 

ppm by volume on a dry basis 

corrected to 3 percent oxygen,c 30-day rolling average).

4.6E–01 lb per MMBtu of steam 

output or 5.2 lb per MWh; 3- 

run average.

1 hr minimum sampling time. 

b. Filterable PM 

(or TSM).

1.1E–01 lb per MMBtu of heat 

input; or (1.2E–03 lb per 

MMBtu of heat input).

1.4E–01 lb per MMBtu of steam 

output or 1.6 lb per MWh; or 

(1.5E–03 lb per MMBtu of 

steam output or 1.7E–02 lb per 

MWh).

Collect a minimum of 1 dscm per 

run. 

10. Suspension 

burners designed to burn 

biomass/biobased solid.

a. CO (or 

CEMS).

2,400 ppm by volume on a dry 

basis corrected to 3 percent 

oxygen, 3-run average; or 

(2,000 ppm by volume on a 

dry basis corrected to 3 percent oxygen,c 10-day rolling 

average).

1.9 lb per MMBtu of steam output or 27 lb per MWh; 3-run 

average.

1 hr minimum sampling time. 

b. Filterable PM 

(or TSM).

5.1E–02 lb per MMBtu of heat 

input; or (6.5E–03 lb per 

MMBtu of heat input).

5.2E–02 lb per MMBtu of steam 

output or 7.1E–01 lb per MWh; 

or (6.6E–03 lb per MMBtu of 

steam output or 9.1E–02 lb per 

MWh).

Collect a minimum of 2 dscm per 

run. 

11. Dutch Ovens/

Pile burners designed to burn 

biomass/biobased solid.

a. CO (or 

CEMS).

770 ppm by volume on a dry 

basis corrected to 3 percent 

oxygen, 3-run average; or (520 

ppm by volume on a dry basis 

corrected to 3 percent oxygen,c 10-day rolling average).

8.4E–01 lb per MMBtu of steam 

output or 8.4 lb per MWh; 3- 

run average.

1 hr minimum sampling time. 

b. Filterable PM 

(or TSM).

2.8E–01 lb per MMBtu of heat 

input; or (2.0E–03 lb per 

MMBtu of heat input).

3.9E–01 lb per MMBtu of steam 

output or 3.9 lb per MWh; or 

(2.8E–03 lb per MMBtu of 

steam output or 2.8E–02 lb per 

MWh).

Collect a minimum of 1 dscm per 

run. 

12. Fuel cell units 

designed to 

burn biomass/

bio-based solid.

a. CO ................ 1,100 ppm by volume on a dry 

basis corrected to 3 percent 

oxygen.

2.4 lb per MMBtu of steam output or 12 lb per MWh.1 hr minimum sampling time. 

b. Filterable PM 

(or TSM).

2.0E–02 lb per MMBtu of heat 

input; or (5.8E–03 lb per 

MMBtu of heat input).

5.5E–02 lb per MMBtu of steam 

output or 2.8E–01 lb per MWh; 

or (1.6E–02 lb per MMBtu of 

steam output or 8.1E–02 lb per 

MWh).

Collect a minimum of 2 dscm per 

run. 

13. Hybrid suspension grate 

units designed 

to burn biomass/bio-based 

solid.

a. CO (or 

CEMS).

3,500 ppm by volume on a dry 

basis corrected to 3 percent 

oxygen, 3-run average; or (900 

ppm by volume on a dry basis 

corrected to 3 percent oxygen,c 30-day rolling average).

3.5 lb per MMBtu of steam output or 39 lb per MWh; 3-run 

average.

1 hr minimum sampling time. 

b. Filterable PM 

(or TSM).

4.4E–01 lb per MMBtu of heat 

input; or (4.5E–04 lb per 

MMBtu of heat input).

5.5E–01 lb per MMBtu of steam 

output or 6.2 lb per MWh; or 

(5.7E–04 lb per MMBtu of 

steam output or 6.3E–03 lb per 

MWh).

Collect a minimum of 1 dscm per 

run. 

14. Units designed to burn 

liquid fuel.

a. HCl ............... 1.1E–03 lb per MMBtu of heat 

input.

1.4E–03 lb per MMBtu of steam 

output or 1.6E–02 lb per MWh.

For M26A, collect a minimum of 

2 dscm per run; for M26, collect a minimum of 240 liters 

per run. 

b. Mercury ........ 2.0E–06 a lb per MMBtu of heat 

input.

2.5E–06 a lb per MMBtu of steam 

output or 2.8E–05 lb per MWh.

For M29, collect a minimum of 3 

dscm per run; for M30A or 

M30B collect a minimum sample as specified in the method, 

for ASTM D6784, b collect a 

minimum of 2 dscm. 


asabaliauskas on DSK5VPTVN1PROD with PROPOSALS
Federal Register / Vol. 80, No. 13 / Wednesday, January 21, 2015 / Proposed Rules 3119 

TABLE 2 TO SUBPART DDDDD OF PART 63—EMISSION LIMITS FOR EXISTING BOILERS AND PROCESS HEATERS— 

Continued 

AS STATED IN § 63.7500, YOU MUST COMPLY WITH THE FOLLOWING APPLICABLE EMISSION LIMITS: 

[Units with heat input capacity of 10 million Btu per hour or greater] 

If your boiler or 

process heater is 

in this subcategory . . . 

For the following 

pollutants . . . 

The emissions must not exceed 

the following emission limits, except during startup and shutdown 

. . . 

The emissions must not exceed 

the following alternative outputbased limits, except during startup and shutdown . . . Using this specified sampling volume or test run duration . . . 

15. Units designed to burn 

heavy liquid fuel.

a. CO ................ 130 ppm by volume on a dry 

basis corrected to 3 percent 

oxygen, 3-run average.

0.13 lb per MMBtu of steam output or 1.4 lb per MWh; 3-run 

average.

1 hr minimum sampling time. 

b. Filterable PM 

(or TSM).

6.2E–02 lb per MMBtu of heat 

input; or (2.0E–04 lb per 

MMBtu of heat input).

7.5E–02 lb per MMBtu of steam 

output or 8.6E–01 lb per MWh; 

or (2.5E–04 lb per MMBtu of 

steam output or 2.8E–03 lb per 

MWh).

Collect a minimum of 1 dscm per 

run. 

16. Units designed to burn 

light liquid fuel.

a. CO ................ 130 ppm by volume on a dry 

basis corrected to 3 percent 

oxygen.

0.13 lb per MMBtu of steam output or 1.4 lb per MWh.1 hr minimum sampling time. 

b. Filterable PM 

(or TSM).

7.9E–03 a lb per MMBtu of heat 

input; or (6.2E–05 lb per 

MMBtu of heat input).

9.6E–03 a lb per MMBtu of steam 

output or 1.1E–01 a lb per 

MWh; or (7.5E–05 lb per 

MMBtu of steam output or 

8.6E–04 lb per MWh).

Collect a minimum of 3 dscm per 

run. 

17. Units designed to burn 

liquid fuel that 

are non-continental units.

a. CO ................ 130 ppm by volume on a dry 

basis corrected to 3 percent 

oxygen, 3-run average based 

on stack test.

0.13 lb per MMBtu of steam output or 1.4 lb per MWh; 3-run 

average.

1 hr minimum sampling time. 

b. Filterable PM 

(or TSM).

2.7E–01 lb per MMBtu of heat 

input; or (8.6E–04 lb per 

MMBtu of heat input).

3.3E–01 lb per MMBtu of steam 

output or 3.8 lb per MWh; or 

(1.1E–03 lb per MMBtu of 

steam output or 1.2E–02 lb per 

MWh).

Collect a minimum of 2 dscm per 

run. 

18. Units designed to burn 

gas 2 (other) 

gases.

a. CO ................ 130 ppm by volume on a dry 

basis corrected to 3 percent 

oxygen.

0.16 lb per MMBtu of steam output or 1.0 lb per MWh.1 hr minimum sampling time. 

b. HCl ............... 1.7E–03 lb per MMBtu of heat 

input.

2.9E–03 lb per MMBtu of steam 

output or 1.8E–02 lb per MWh.

For M26A, collect a minimum of 

2 dscm per run; for M26, collect a minimum of 240 liters 

per run. 

c. Mercury ......... 7.9E–06 lb per MMBtu of heat 

input.

1.4E–05 lb per MMBtu of steam 

output or 8.3E–05 lb per MWh.

For M29, collect a minimum of 3 

dscm per run; for M30A or 

M30B, collect a minimum sample as specified in the method; 

for ASTM D6784,b collect a 

minimum of 2 dscm. 

d. Filterable PM 

(or TSM).

6.7E–03 lb per MMBtu of heat 

input or (2.1E–04 lb per 

MMBtu of heat input).

1.2E–02 lb per MMBtu of steam 

output or 7.0E–02 lb per MWh; 

or (3.5E–04 lb per MMBtu of 

steam output or 2.2E–03 lb per 

MWh).

Collect a minimum of 3 dscm per 

run. 

a If you are conducting stack tests to demonstrate compliance and your performance tests for this pollutant for at least 2 consecutive years 

show that your emissions are at or below this limit, you can skip testing according to § 63.7515 if all of the other provisions of § 63.7515 are met. 

For all other pollutants that do not contain a footnote a, your performance tests for this pollutant for at least 2 consecutive years must show that 

your emissions are at or below 75 percent of this limit in order to qualify for skip testing. b Incorporated by reference, see § 63.14. 

cAn owner or operator may request that compliance with the carbon monoxide emission limit be determined using carbon dioxide measurements corrected to an equivalent of 3 percent oxygen. The relationship between oxygen and carbon dioxide levels for the affected facility shall 

be established during the initial compliance test. 

■ 22. Table 3 to subpart DDDDD of part 

63 is amended by revising the entry for 

‘‘4,’’ ‘‘5,’’ and ‘‘6’’ to read as follows: 


asabaliauskas on DSK5VPTVN1PROD with PROPOSALS
3120 Federal Register / Vol. 80, No. 13 / Wednesday, January 21, 2015 / Proposed Rules 

TABLE 3 TO SUBPART DDDDD OF PART 63—WORK PRACTICE STANDARDS

[As stated in § 63.7500, you must comply with the following applicable work practice standards:] 

If your unit is . . . You must meet the following . . . 

4. An existing boiler or process heater located at a 

major source facility, not 

including limited use units.

Must have a one-time energy assessment performed by a qualified energy assessor. An energy assessment 

completed on or after January 1, 2008, that meets or is amended to meet the energy assessment requirements 

in this table, satisfies the energy assessment requirement. A facility that operated under an energy management program developed according to the ENERGY STAR guidelines for energy management or compatible 

with ISO 50001 for at least one year between January 1, 2008 and the compliance date specified in § 63.7495 

that includes the affected units also satisfies the energy assessment requirement. The energy assessment 

must include the following with extent of the evaluation for items a. to e. appropriate for the on-site technical 

hours listed in § 63.7575: 

a. A visual inspection of the boiler or process heater system. 

b. An evaluation of operating characteristics of the boiler or process heater systems, specifications of energy 

using systems, operating and maintenance procedures, and unusual operating constraints. 

c. An inventory of major energy use systems consuming energy from affected boilers and process heaters and 

which are under the control of the boiler/process heater owner/operator. 

d. A review of available architectural and engineering plans, facility operation and maintenance procedures and 

logs, and fuel usage. 

e. A review of the facility’s energy management program and provide recommendations for improvements consistent with the definition of energy management program, if identified. 

f. A list of cost-effective energy conservation measures that are within the facility’s control. 

g. A list of the energy savings potential of the energy conservation measures identified. 

h. A comprehensive report detailing the ways to improve efficiency, the cost of specific improvements, benefits, 

and the time frame for recouping those investments. 

5. An existing or new boiler 

or process heater subject 

to emission limits in Table 

1 or 2 or 11 through 13 to 

this subpart during startup.

a. You must operate all CMS during startup. 

b. For startup of a boiler or process heater, you must use one or a combination of the following clean fuels: Natural gas, synthetic natural gas, propane, other Gas 1 fuels, distillate oil, syngas, ultra-low sulfur diesel, fuel oilsoaked rags, kerosene, hydrogen, paper, cardboard, refinery gas, liquefied petroleum gas, and any fuels meeting the appropriate HCl, mercury and TSM emission standards by fuel analysis. 

c. You have the option of complying using either of the following work practice standards. 

(1) If you start firing coal/solid fossil fuel, biomass/bio-based solids, heavy liquid fuel, or gas 2 (other) gases, you 

must vent emissions to the main stack(s) and engage all of the applicable control devices except limestone injection in fluidized bed combustion (FBC) boilers, dry scrubber, fabric filter, selective non-catalytic reduction 

(SNCR), and selective catalytic reduction (SCR). You must start your limestone injection in FBC boilers, dry 

scrubber, fabric filter, SNCR, and SCR systems as expeditiously as possible. Startup ends when steam or heat 

is supplied for any purpose, OR 

(2) If you choose to comply using definition (2) of ‘‘startup’’ in § 63.7575, once you start firing (i.e., feeding) coal/

solid fossil fuel, biomass/bio-based solids, heavy liquid fuel, or gas 2 (other) gases, you must vent emissions to 

the main stack(s) and engage all of the applicable control devices so as to comply with the emission limits 

within 4 hours of start of supplying useful thermal energy. You must effect PM control within one hour of first 

firing coal/solid fossil fuel, biomass/bio-based solids, heavy liquid fuel, or gas 2 (other) gases a. You must start 

all applicable control devices as expeditiously as possible, but, in any case, when necessary to comply with 

other standards applicable to the source by a permit limit or a rule other than this subpart that require operation 

of the control devices. 

d. You must comply with all applicable emission limits at all times except during startup and shutdown periods at 

which time you must meet this work practice. You must collect monitoring data during periods of startup, as 

specified in § 63.7535(b). You must keep records during periods of startup. You must provide reports concerning activities and periods of startup, as specified in § 63.7555. 

6. An existing or new boiler 

or process heater subject 

to emission limits in Tables 1 or 2 or 11 through 

13 to this subpart during 

shutdown.

You must operate all CMS during shutdown. While firing coal/solid fossil fuel, biomass/bio-based solids, heavy 

liquid fuel, or gas 2 (other) gases during shutdown, you must vent emissions to the main stack(s) and operate 

all applicable control devices, except limestone injection in FBC boilers, dry scrubber, fabric filter, SNCR, and 

SCR but, in any case, when necessary to comply with other standards applicable to the source that require operation of the control device. 

If, in addition to the fuel used prior to initiation of shutdown, another fuel must be used to support the shutdown 

process, that additional fuel must be one or a combination of the following clean fuels: Natural gas, synthetic 

natural gas, propane, other Gas 1 fuels, distillate oil, syngas, ultra-low sulfur diesel, refinery gas, and liquefied 

petroleum gas. 

You must comply with all applicable emissions limits at all times except for startup or shutdown periods conforming with this work practice. You must collect monitoring data during periods of shutdown, as specified in 

§ 63.7535(b). You must keep records during periods of shutdown. You must provide reports concerning activities and periods of shutdown, as specified in § 63.7555. 

aThe source may request a variance with the PM controls requirement. The source must provide evidence that (1) meeting the ‘‘fuel firing + 1 

hour’’ requirement violates manufacturer’s recommended operation and/or safety requirements, and (2) the PM control device is appropriately designed and sized to meet the filterable PM emission limit. 


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Federal Register / Vol. 80, No. 13 / Wednesday, January 21, 2015 / Proposed Rules 3121 

■ 23. Table 4 to subpart DDDDD of part 

63 is revised to read as follows: 

TABLE 4 TO SUBPART DDDDD OF PART 63—OPERATING LIMITS FOR BOILERS AND PROCESS HEATERS

[As stated in § 63.7500, you must comply with the applicable operating limits:] 

When complying with a Table 1, 2, 11, 12, or 

13 numerical emission limit using . . . You must meet these operating limits . . . 

1. Wet PM scrubber control on a boiler or process heater not using a PM CPMS.Maintain the 30-day rolling average pressure drop and the 30-day rolling average liquid flow 

rate at or above the lowest one-hour average pressure drop and the lowest one-hour average liquid flow rate, respectively, measured during the most recent performance test demonstrating compliance with the PM emission limitation according to § 63.7530(b) and Table 7 

to this subpart. 

2. Wet acid gas (HCl) scrubber control on a 

boiler or process heater not using a HCl 

CEMS.

Maintain the 30-day rolling average effluent pH at or above the lowest one-hour average pH 

and the 30-day rolling average liquid flow rate at or above the lowest one-hour average liquid flow rate measured during the most recent performance test demonstrating compliance 

with the HCl emission limitation according to § 63.7530(b) and Table 7 to this subpart. 

3. Fabric filter control on a boiler or process 

heater not using a PM CPMS.

a. Maintain opacity to less than or equal to 10 percent opacity (daily block average); or 

b. Install and operate a bag leak detection system according to § 63.7525 and operate the fabric filter such that the bag leak detection system alert is not activated more than 5 percent of 

the operating time during each 6-month period. 

4. Electrostatic precipitator control on a boiler or 

process heater not using a PM CPMS.

a. This option is for boilers and process heaters that operate dry control systems (i.e., an ESP 

without a wet scrubber). Existing and new boilers and process heaters must maintain opacity to less than or equal to 10 percent opacity (daily block average). 

b. This option is only for boilers and process heaters not subject to PM CPMS or continuous 

compliance with an opacity limit (i.e., dry ESP). Maintain the 30-day rolling average total 

secondary electric power input of the electrostatic precipitator at or above the operating limits established during the performance test according to § 63.7530(b) and Table 7 to this 

subpart. 

5. Dry scrubber or carbon injection control on a 

boiler or process heater not using a mercury 

CEMS.

Maintain the minimum sorbent or carbon injection rate as defined in § 63.7575 of this subpart. 

6. Any other add-on air pollution control type on 

a boiler or process heater not using a PM 

CPMS.

This option is for boilers and process heaters that operate dry control systems. Existing and 

new boilers and process heaters must maintain opacity to less than or equal to 10 percent 

opacity (daily block average). 

7. Fuel analysis ................................................... Maintain the fuel type or fuel mixture such that the applicable emission rates calculated according to § 63.7530(c)(1), (2) and/or (3) is less than the applicable emission limits. 

8. Performance testing ....................................... For boilers and process heaters that demonstrate compliance with a performance test, maintain the operating load of each unit such that it does not exceed 110 percent of the highest 

hourly average operating load recorded during the most recent performance test. 

9. Oxygen analyzer system ................................ For boilers and process heaters subject to a CO emission limit that demonstrate compliance 

with an O2 analyzer system as specified in § 63.7525(a), maintain the 30-day rolling average 

oxygen content at or above the lowest hourly average oxygen concentration measured during the most recent CO performance test, as specified in Table 8. This requirement does not 

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

the level specified in § 63.7525(a). 

10. SO2CEMS ..................................................... For boilers or process heaters subject to an HCl emission limit that demonstrate compliance 

with an SO2CEMS, maintain the 30-day rolling average SO2emission rate at or below the 

highest hourly average SO2concentration measured during the most recent HCl performance 

test, as specified in Table 8. 

■ 24. Table 5 to subpart DDDDD of part 

63 is amended by revising the heading 

to the third column and adding the 

footnote ‘‘a’’ to read as follows: 

TABLE 5 TO SUBPART DDDDD OF

PART 63—PERFORMANCE TESTING

REQUIREMENTS

[As stated in § 63.7520, you must comply with 

the following requirements for performance 

testing for existing, new or reconstructed affected sources:] 

To conduct a 

performance 

test for the 

following pollutant . . . 

You must 

. . . 

Using, as appropriate . . . 

* * * * * 

a Incorporated by reference, see § 63.14. 

■ 25. Table 6 to subpart DDDDD of part 

63 is revised to read as follows: 


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3122 Federal Register / Vol. 80, No. 13 / Wednesday, January 21, 2015 / Proposed Rules 

TABLE 6 TO SUBPART DDDDD OF PART 63—FUEL ANALYSIS REQUIREMENTS

[As stated in § 63.7521, you must comply with the following requirements for fuel analysis testing for existing, new or reconstructed affected 

sources. However, equivalent methods (as defined in § 63.7575) may be used in lieu of the prescribed methods at the discretion of the 

source owner or operator:] 

To conduct a fuel 

nalysis for the following 

pollutant . . . 

You must . . . Using . . . 

1. Mercury ................ a. Collect fuel samples .......................... Procedure in § 63.7521(c) or ASTM D5192 a, or ASTM D7430 a, or ASTM 

D6883 a, or ASTM D2234/D2234M a (for coal) or EPA 1631 or EPA 1631E or 

ASTM D6323 a (for solid), or EPA 821–R–01–013 (for liquid or solid), or 

ASTM D4177 a (for liquid), or ASTM D4057 a (for liquid), or equivalent. 

b. Composite fuel samples ................... Procedure in § 63.7521(d) or equivalent. 

c. Prepare composited fuel samples .... EPA SW–846–3050Ba (for solid samples), ASTM D2013/D2013M a (for coal), 

ASTM D5198 a (for biomass), or EPA 3050 a (for solid fuel), or EPA 821–R– 

01–013 a (for liquid or solid), or equivalent. 

d. Determine heat content of the fuel 

type.

ASTM D5865 a (for coal) or ASTM E711 a (for biomass), or ASTM D5864 a for 

liquids and other solids, or ASTM D240 a or equivalent. 

e. Determine moisture content of the 

fuel type.

ASTM D3173 a, ASTM E871 a, or ASTM D5864 a, or ASTM D240, or ASTM 

D95 a (for liquid fuels), or ASTM D4006 a (for liquid fuels), or ASTM D4177 a

(for liquid fuels) or ASTM D4057 a (for liquid fuels), or equivalent. 

f. Measure mercury concentration in 

fuel sample.

ASTM D6722 a (for coal), EPA SW–846–7471Ba (for solid samples), or EPA 

SW–846–7470Aa (for liquid samples), or equivalent. 

g. Convert concentration into units of 

pounds of mercury per MMBtu of 

heat content.

Equation 8 in § 63.7530. 

2. HCl ....................... a. Collect fuel samples .......................... Procedure in § 63.7521(c) or ASTM D5192 a, or ASTM D7430 a, or ASTM 

D6883 a, or ASTM D2234/D2234M a (for coal) or ASTM D6323 a (for coal or 

biomass), ASTM D4177 a (for liquid fuels) or ASTM D4057 a (for liquid fuels), 

or equivalent. 

b. Composite fuel samples ................... Procedure in § 63.7521(d) or equivalent. 

c. Prepare composited fuel samples .... EPA SW–846–3050Ba (for solid samples), ASTM D2013/D2013M a (for coal), 

or ASTM D5198 a (for biomass), or EPA 3050 a or equivalent. 

d. Determine heat content of the fuel 

type.

ASTM D5865 a (for coal) or ASTM E711 a (for biomass), ASTM D5864, ASTM 

D240 a or equivalent. 

e. Determine moisture content of the 

fuel type.

ASTM D3173 a or ASTM E871 a, or D5864 a, or ASTM D240 a, or ASTM D95 a

(for liquid fuels), or ASTM D4006 a (for liquid fuels), or ASTM D4177 a (for 

liquid fuels) or ASTM D4057 a (for liquid fuels) or equivalent. 

f. Measure chlorine concentration in 

fuel sample.

EPA SW–846–9250 a, ASTM D6721 a, ASTM D4208 a (for coal), or EPA SW– 

846–5050 a or ASTM E776 a (for solid fuel), or EPA SW–846–9056 a or SW– 

846–9076 a (for solids or liquids) or equivalent. 

g. Convert concentrations into units of 

pounds of HCl per MMBtu of heat 

content.

Equation 7 in § 63.7530. 

3. Mercury Fuel 

Specification for 

other gas 1 fuels.

a. Measure mercury concentration in 

the fuel sample and convert to units 

of micrograms per cubic meter, or.

Method 30B (M30B) at 40 CFR part 60, appendix A–8 of this chapter or ASTM 

D5954 a, ASTM D6350 a, ISO 6978–1:2003(E) a, or ISO 6978–2:2003(E) a, or 

EPA–1631 a or equivalent. 

b. Measure mercury concentration in 

the exhaust gas when firing only the 

other gas 1 fuel is fired in the boiler 

or process heater.

Method 29, 30A, or 30B (M29, M30A, or M30B) at 40 CFR part 60, appendix 

A–8 of this chapter or Method 101A or Method 102 at 40 CFR part 61, appendix B of this chapter, or ASTM Method D6784 a or equivalent. 

4. TSM ...................... a. Collect fuel samples .......................... Procedure in § 63.7521(c) or ASTM D5192 a, or ASTM D7430 a, or ASTM 

D6883 a, or ASTM D2234/D2234M a (for coal) or ASTM D6323 a (for coal or 

biomass), or ASTM D4177 a, (for liquid fuels)or ASTM D4057 a (for liquid 

fuels), or equivalent. 

b. Composite fuel samples ................... Procedure in § 63.7521(d) or equivalent. 

c. Prepare composited fuel samples .... EPA SW–846–3050Ba (for solid samples), ASTM D2013/D2013M a (for coal), 

ASTM D5198 a or TAPPI T266 a (for biomass), or EPA 3050 a or equivalent. 

d. Determine heat content of the fuel 

type.

ASTM D5865 a (for coal) or ASTM E711 a (for biomass), or ASTM D5864 a for 

liquids and other solids, or ASTM D240 a or equivalent. 

e. Determine moisture content of the 

fuel type.

ASTM D3173 a or ASTM E871 a, or D5864, or ASTM D240 a, or ASTM D95 a

(for liquid fuels), or ASTM D4006 a (for liquid fuels), or ASTM D4177 a (for 

liquid fuels) or ASTM D4057 a (for liquid fuels), or equivalent. 

f. Measure TSM concentration in fuel 

sample.

ASTM D3683 a, or ASTM D4606 a, or ASTM D6357 a or EPA 200.8 a or EPA 

SW–846–6020 a, or EPA SW–846–6020Aa, or EPA SW–846–6010C a, EPA 

7060 a or EPA 7060Aa (for arsenic only), or EPA SW–846–7740a (for selenium only). 

g. Convert concentrations into units of 

pounds of TSM per MMBtu of heat 

content.

Equation 9 in § 63.7530. 

a Incorporated by reference, see § 63.14. 


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■ 26. Table 7 to subpart DDDDD of part 

63 is revised to read as follows: 

TABLE 7 TO SUBPART DDDDD OF PART 63—ESTABLISHING OPERATING LIMITS

[As stated in § 63.7520, you must comply with the following requirements for establishing operating limits:] 

If you have an applicable emission 

limit for . . . 

And your operating limits are 

based on . . . 

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

1. PM, TSM, or 

mercury.

a. Wet scrubber 

operating parameters.

i. Establish a site-specific minimum scrubber pressure drop 

and minimum flow rate operating limit according to 

§ 63.7530(b).

(1) Data from the scrubber pressure drop and liquid flow rate 

monitors and the PM, TSM, or 

mercury performance test.

(a) You must collect scrubber 

pressure drop and liquid flow 

rate data every 15 minutes 

during the entire period of the 

performance tests. 

(b) Determine the lowest hourly 

average scrubber pressure 

drop and liquid flow rate by 

computing the hourly averages 

using all of the 15-minute readings taken during each performance test. 

b. Electrostatic 

precipitator 

operating parameters (option only for 

units that operate wet 

scrubbers).

i. Establish a site-specific minimum total secondary electric 

power input according to 

§ 63.7530(b).

(1) Data from the voltage and 

secondary amperage monitors 

during the PM or mercury performance test.

(a) You must collect secondary 

voltage and secondary amperage for each ESP cell and calculate total secondary electric 

power input data every 15 minutes during the entire period of 

the performance tests. 

(b) Determine the average total 

secondary electric power input 

by computing the hourly averages using all of the 15-minute 

readings taken during each 

performance test. 

2. HCl .................. a. Wet scrubber 

operating parameters.

i. Establish site-specific minimum 

effluent pH and flow rate operating limits according to 

§ 63.7530(b).

(1) Data from the pH and liquid 

flow-rate monitors and the HCl 

performance test.

(a) You must collect pH and liquid flow-rate data every 15 

minutes during the entire period of the performance tests. 

(b) Determine the hourly average 

pH and liquid flow rate by computing the hourly averages 

using all of the 15-minute readings taken during each performance test. 

b. Dry scrubber 

operating parameters.

i. Establish a site-specific minimum sorbent injection rate operating limit according to 

§ 63.7530(b). If different acid 

gas sorbents are used during 

the HCl performance test, the 

average value for each sorbent 

becomes the site-specific operating limit for that sorbent.

(1) Data from the sorbent injection rate monitors and HCl or 

mercury performance test.

(a) You must collect sorbent injection rate data every 15 minutes during the entire period of 

the performance tests. 

(b) Determine the hourly average 

sorbent injection rate by computing the hourly averages 

using all of the 15-minute readings taken during each performance test. 

(c) Determine the lowest hourly 

average of the three test run 

averages established during 

the performance test as your 

operating limit. When your unit 

operates at lower loads, multiply your sorbent injection rate 

by the load fraction, as defined 

in § 63.7575, to determine the 

required injection rate. 

c. Alternative 

Maximum SO2

emission rate.

i. Establish a site-specific maximum SO2 emission rate operating limit according to 

§ 63.7530(b).

(1) Data from SO2 CEMS and 

the HCl performance test.

(a) You must collect the SO2

emissions data according to 

§ 63.7525(m) during the most 

recent HCl performance tests. 


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3124 Federal Register / Vol. 80, No. 13 / Wednesday, January 21, 2015 / Proposed Rules 

TABLE 7 TO SUBPART DDDDD OF PART 63—ESTABLISHING OPERATING LIMITS—Continued 

[As stated in § 63.7520, you must comply with the following requirements for establishing operating limits:] 

If you have an applicable emission 

limit for . . . 

And your operating limits are 

based on . . . 

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

(b) The maximum SO2 emission 

rate is equal to the highest 

hourly average SO2 emission 

rate measured during the most 

recent HCl performance tests. 

3. Mercury ........... a. Activated carbon injection.i. Establish a site-specific minimum activated carbon injection rate operating limit according to § 63.7530(b).(1) Data from the activated carbon rate monitors and mercury 

performance test.

(a) You must collect activated 

carbon injection rate data 

every 15 minutes during the 

entire period of the performance tests. 

(b) Determine the hourly average 

activated carbon injection rate 

by computing the hourly averages using all of the 15-minute 

readings taken during each 

performance test. 

(c) Determine the lowest hourly 

average established during the 

performance test as your operating limit. When your unit operates at lower loads, multiply 

your activated carbon injection 

rate by the load fraction, as 

defined in § 63.7575, to determine the required injection 

rate. 

4. Carbon monoxide for which 

compliance is 

demonstrated 

by a performance test.

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

minimum oxygen level according to § 63.7530(b).

(1) Data from the oxygen analyzer system specified in 

§ 63.7525(a).

(a) You must collect oxygen data 

every 15 minutes during the 

entire period of the performance tests. 

(b) Determine the hourly average 

oxygen concentration by computing the hourly averages 

using all of the 15-minute readings taken during each performance test. 

(c) Determine the lowest hourly 

average established during the 

performance test as your minimum operating limit. 

5. Any pollutant 

for which compliance is demonstrated by a 

performance 

test.

a. Boiler or process heater operating load.i. Establish a unit specific limit for 

maximum operating load according to § 63.7520(c).

(1) Data from the operating load 

monitors or from steam generation monitors.

(a) You must collect operating 

load 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. 

■ 27. Table 8 to subpart DDDDD of part 

63 is amended by revising the entry for 

‘‘3,’’ ‘‘9,’’ ‘‘10,’’ and ‘‘11’’ to read as 

follows: 


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Federal Register / Vol. 80, No. 13 / Wednesday, January 21, 2015 / Proposed Rules 3125 

TABLE 8 TO SUBPART DDDDD OF PART 63—DEMONSTRATING CONTINUOUS COMPLIANCE

[As stated in § 63.7540, you must show continuous compliance with the emission limitations for each boiler or process heater according to the 

following:] 

If you must meet the following operating limits 

or work practice standards . . . You must demonstrate continuous compliance by . . . 

*****

3. Fabric Filter Bag Leak Detection Operation ... Installing and operating a bag leak detection system according to § 63.7525 and operating the 

fabric filter such that the requirements in § 63.7540(a)(7) are met. 

* * * * * 

9. Oxygen content ............................................... a. Continuously monitor the oxygen content using an oxygen analyzer system according to 

§ 63.7525(a). This requirement does not apply to units that install an oxygen trim system 

since these units will set the trim system to the level specified in § 63.7525(a)(7). 

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

c. Maintain the 30-day rolling average oxygen content at or above the lowest hourly average 

oxygen level measured during the most recent CO performance test. 

10. Boiler or process heater operating load ....... a. Collecting operating load data or steam generation data every 15 minutes. 

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

b. Maintaining the 30-day rolling average operating load such that it does not exceed 110 percent of the highest hourly average operating load recorded during the most recent performance test according to § 63.7520(c). 

11. SO2emissions using SO2CEMS ................... a. Collecting the SO2CEMS output data according to § 63.7525; 

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

c. Maintaining the 30-day rolling average SO2CEMS emission rate to a level at or below the 

highest hourly SO2rate measured during the most recent HCl performance test according to 

§ 63.7530. 

■ 28. Table 9 to subpart DDDDD of part 

63 is revised to read as follows: 

TABLE 9 TO SUBPART DDDDD OF PART 63—REPORTING REQUIREMENTS

[As stated in § 63.7550, you must comply with the following requirements for reports:] 

You must submit 

a(n) The report must contain . . . You must submit the report . . . 

1. Compliance 

report.

a. Information required in § 63.7550(c)(1) through (5); and ............................................... Semiannually, annually, biennially, 

or every 5 years according to 

the requirements in 

§ 63.7550(b). 

b. If there are no deviations from any emission limitation (emission limit and operating 

limit) that applies to you and there are no deviations from the requirements for work 

practice standards for periods of startup and shutdown in Table 3 to this subpart that 

apply to you, a statement that there were no deviations from the emission limitations 

and work practice standards during the reporting period. If there were no periods during which the CMSs, including continuous emissions monitoring system, continuous 

opacity monitoring system, and operating parameter monitoring systems, were out-ofcontrol as specified in § 63.8(c)(7), a statement that there were no periods during 

which the CMSs were out-of-control during the reporting period; and.

c. If you have a deviation from any emission limitation (emission limit and operating 

limit) where you are not using a CMS to comply with that emission limit or operating 

limit, or a deviation from a work practice standard for periods of startup and shutdown, during the reporting period, the report must contain the information in 

§ 63.7550(d); and.

d. If there were periods during which the CMSs, including continuous emissions monitoring system, continuous opacity monitoring system, and operating parameter monitoring systems, were out-of-control as specified in § 63.8(c)(7), or otherwise not operating, the report must contain the information in § 63.7550(e).

* * * * * ■ 29. Table 11 to subpart DDDDD of part 

63 is revised to read as follows: 


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3126 Federal Register / Vol. 80, No. 13 / Wednesday, January 21, 2015 / Proposed Rules 

TABLE 11 TO SUBPART DDDDD OF PART 63—ALTERNATIVE EMISSION LIMITS FOR NEW OR RECONSTRUCTED BOILERS

AND PROCESS HEATERS THAT COMMENCED CONSTRUCTION OR RECONSTRUCTION AFTER JUNE 4, 2010, AND BEFORE MAY 20, 2011 

If your boiler or process heater is 

in this subcategory . . . For the following pollutants . . .

The emissions must not exceed 

the following emission limits, except during periods of startup and 

shutdown . . .

Using this specified sampling volume or test run duration . . .

1. Units in all subcategories designed to burn solid fuel.a. HCl ............................................ 0.022 lb per MMBtu of heat input For M26A, collect a minimum of 1 

dscm per run; for M26 collect a 

minimum of 120 liters per run. 

2. Units in all subcategories designed to burn solid fuel that 

combust at least 10 percent biomass/bio-based solids on an annual heat input basis and less 

than 10 percent coal/solid fossil 

fuels on an annual heat input 

basis.

a. Mercury ..................................... 8.0E–07 a lb per MMBtu of heat 

input.

For M29, collect a minimum of 4 

dscm per run; for M30A or 

M30B, collect a minimum sample as specified in the method; 

for ASTM D6784 b collect a 

minimum of 4 dscm. 

3. Units in all subcategories designed to burn solid fuel that 

combust at least 10 percent 

coal/solid fossil fuels on an annual heat input basis and less 

than 10 percent biomass/biobased solids on an annual heat 

input basis.

a. Mercury ..................................... 2.0E–06 lb per MMBtu of heat 

input.

For M29, collect a minimum of 4 

dscm per run; for M30A or 

M30B, collect a minimum sample as specified in the method; 

for ASTM D6784 b collect a 

minimum of 4 dscm. 

4. Units design to burn coal/solid 

fossil fuel.

a. Filterable PM (or TSM) ............. 1.1E–03 lb per MMBtu of heat 

input; or (2.3E–05 lb per MMBtu 

of heat input).

Collect a minimum of 3 dscm per 

run. 

5. Pulverized coal boilers designed 

to burn coal/solid fossil fuel.

a. Carbon monoxide (CO) (or 

CEMS).

130 ppm by volume on a dry 

basis corrected to 3 percent oxygen, 3-run average; or (320 

ppm by volume on a dry basis 

corrected to 3 percent oxygen c, 

30-day rolling average).

1 hr minimum sampling time. 

6. Stokers designed to burn coal/

solid fossil fuel.

a. CO (or CEMS) .......................... 130 ppm by volume on a dry 

basis corrected to 3 percent oxygen, 3-run average; or (340 

ppm by volume on a dry basis 

corrected to 3 percent oxygen c, 

10-day rolling average).

1 hr minimum sampling time. 

7. Fluidized bed units designed to 

burn coal/solid fossil fuel.

a. CO (or CEMS) .......................... 130 ppm by volume on a dry 

basis corrected to 3 percent oxygen, 3-run average; or (230 

ppm by volume on a dry basis 

corrected to 3 percent oxygen c, 

30-day rolling average).

1 hr minimum sampling time 

8. Fluidized bed units with an integrated heat exchanger designed 

to burn coal/solid fossil fuel.

a. CO (or CEMS) .......................... 140 ppm by volume on a dry 

basis corrected to 3 percent oxygen, 3-run average; or (150 

ppm by volume on a dry basis 

corrected to 3 percent oxygen c, 

30-day rolling average).

1 hr minimum sampling time. 

9. Stokers/sloped grate/others designed to burn wet biomass fuel.a. CO (or CEMS) .......................... 620 ppm by volume on a dry 

basis corrected to 3 percent oxygen, 3-run average; or (390 

ppm by volume on a dry basis 

corrected to 3 percent oxygen c, 

30-day rolling average).

1 hr minimum sampling time. 

b. Filterable PM (or TSM) ............. 3.0E–02 lb per MMBtu of heat 

input; or (2.6E–05 lb per MMBtu 

of heat input).

Collect a minimum of 2 dscm per 

run. 

10. Stokers/sloped grate/others designed to burn kiln-dried biomass fuel.a. CO ............................................ 560 ppm by volume on a dry 

basis corrected to 3 percent oxygen.

1 hr minimum sampling time. 

b. Filterable PM (or TSM) ............. 3.0E–02 lb per MMBtu of heat 

input; or (4.0E–03 lb per MMBtu 

of heat input).

Collect a minimum of 2 dscm per 

run. 


asabaliauskas on DSK5VPTVN1PROD with PROPOSALS
Federal Register / Vol. 80, No. 13 / Wednesday, January 21, 2015 / Proposed Rules 3127 

TABLE 11 TO SUBPART DDDDD OF PART 63—ALTERNATIVE EMISSION LIMITS FOR NEW OR RECONSTRUCTED BOILERS

AND PROCESS HEATERS THAT COMMENCED CONSTRUCTION OR RECONSTRUCTION AFTER JUNE 4, 2010, AND BEFORE MAY 20, 2011—Continued 

If your boiler or process heater is 

in this subcategory . . . For the following pollutants . . .

The emissions must not exceed 

the following emission limits, except during periods of startup and 

shutdown . . .

Using this specified sampling volume or test run duration . . .

11. Fluidized bed units designed to 

burn biomass/bio-based solids.

a. CO (or CEMS) .......................... 230 ppm by volume on a dry 

basis corrected to 3 percent oxygen, 3-run average; or (310 

ppm by volume on a dry basis 

corrected to 3 percent oxygen c, 

30-day rolling average).

1 hr minimum sampling time. 

b. Filterable PM (or TSM) ............. 9.8E–03 lb per MMBtu of heat 

input; or (8.3E–05 a lb per 

MMBtu of heat input).

Collect a minimum of 3 dscm per 

run. 

12. Suspension burners designed 

to burn biomass/bio-based solids.

a. CO (or CEMS) .......................... 2,400 ppm by volume on a dry 

basis corrected to 3 percent oxygen, 3-run average; or (2,000 

ppm by volume on a dry basis 

corrected to 3 percent oxygen c, 

10-day rolling average).

1 hr minimum sampling time. 

b. Filterable PM (or TSM) ............. 3.0E–02 lb per MMBtu of heat 

input; or (6.5E–03 lb per MMBtu 

of heat input).

Collect a minimum of 2 dscm per 

run. 

13. Dutch Ovens/Pile burners designed to burn biomass/biobased solids.a. CO (or CEMS) .......................... 1,010 ppm by volume on a dry 

basis corrected to 3 percent oxygen, 3-run average; or (520 

ppm by volume on a dry basis 

corrected to 3 percent oxygen c, 

10-day rolling average).

1 hr minimum sampling time. 

b. Filterable PM (or TSM) ............. 8.0E–03 lb per MMBtu of heat 

input; or (3.9E–05 lb per MMBtu 

of heat input).

Collect a minimum of 3 dscm per 

run. 

14. Fuel cell units designed to 

burn biomass/bio-based solids.

a. CO ............................................ 910 ppm by volume on a dry 

basis corrected to 3 percent oxygen.

1 hr minimum sampling time. 

b. Filterable PM (or TSM) ............. 2.0E–02 lb per MMBtu of heat 

input; or (2.9E–05 lb per MMBtu 

of heat input).

Collect a minimum of 2 dscm per 

run. 

15. Hybrid suspension grate boiler 

designed to burn biomass/biobased solids.

a. CO (or CEMS) .......................... 1,100 ppm by volume on a dry 

basis corrected to 3 percent oxygen, 3-run average; or (900 

ppm by volume on a dry basis 

corrected to 3 percent oxygen c, 

30-day rolling average).

1 hr minimum sampling time. 

b. Filterable PM (or TSM) ............. 2.6E–02 lb per MMBtu of heat 

input; or (4.4E–04 lb per MMBtu 

of heat input).

Collect a minimum of 3 dscm per 

run. 

16. Units designed to burn liquid 

fuel.

a. HCl ............................................ 4.4E–04 lb per MMBtu of heat 

input.

For M26A: Collect a minimum of 2 

dscm per run; for M26, collect a 

minimum of 240 liters per run. 

b. Mercury ..................................... 4.8E–07 a lb per MMBtu of heat 

input.

For M29, collect a minimum of 4 

dscm per run; for M30A or 

M30B, collect a minimum sample as specified in the method; 

for ASTM D6784 b collect a 

minimum of 4 dscm. 

17. Units designed to burn heavy 

liquid fuel.

a. CO ............................................ 130 ppm by volume on a dry 

basis corrected to 3 percent oxygen, 3-run average.

1 hr minimum sampling time. 

b. Filterable PM (or TSM) ............. 1.3E–02 lb per MMBtu of heat 

input; or (7.5E–05 lb per MMBtu 

of heat input).

Collect a minimum of 3 dscm per 

run. 

18. Units designed to burn light liquid fuel.a. CO ............................................ 130 ppm by volume on a dry 

basis corrected to 3 percent oxygen.

1 hr minimum sampling time. 

b. Filterable PM (or TSM) ............. 2.0E–03 a lb per MMBtu of heat 

input; or (2.9E–05 lb per MMBtu 

of heat input).

Collect a minimum of 3 dscm per 

run. 


asabaliauskas on DSK5VPTVN1PROD with PROPOSALS
3128 Federal Register / Vol. 80, No. 13 / Wednesday, January 21, 2015 / Proposed Rules 

TABLE 11 TO SUBPART DDDDD OF PART 63—ALTERNATIVE EMISSION LIMITS FOR NEW OR RECONSTRUCTED BOILERS

AND PROCESS HEATERS THAT COMMENCED CONSTRUCTION OR RECONSTRUCTION AFTER JUNE 4, 2010, AND BEFORE MAY 20, 2011—Continued 

If your boiler or process heater is 

in this subcategory . . . For the following pollutants . . .

The emissions must not exceed 

the following emission limits, except during periods of startup and 

shutdown . . .

Using this specified sampling volume or test run duration . . .

19. Units designed to burn liquid 

fuel that are non-continental 

units.

a. CO ............................................ 130 ppm by volume on a dry 

basis corrected to 3 percent oxygen, 3-run average based on 

stack test.

1 hr minimum sampling time. 

b. Filterable PM (or TSM) ............. 2.3E–02 lb per MMBtu of heat 

input; or (8.6E–04 lb per MMBtu 

of heat input).

Collect a minimum of 4 dscm per 

run. 

20. Units designed to burn gas 2 

(other) gases.

a. CO ............................................ 130 ppm by volume on a dry 

basis corrected to 3 percent oxygen.

1 hr minimum sampling time. 

b. HCl ............................................ 1.7E–03 lb per MMBtu of heat 

input.

For M26A, Collect a minimum of 2 

dscm per run; for M26, collect a 

minimum of 240 liters per run. 

c. Mercury ..................................... 7.9E–06 lb per MMBtu of heat 

input.

For M29, collect a minimum of 3 

dscm per run; for M30A or 

M30B, collect a minimum sample as specified in the method; 

for ASTM D6784 b collect a 

minimum of 3 dscm. 

d. Filterable PM (or TSM) ............. 6.7E–03 lb per MMBtu of heat 

input; or (2.1E–04 lb per MMBtu 

of heat input).

Collect a minimum of 3 dscm per 

run. 

a If you are conducting stack tests to demonstrate compliance and your performance tests for this pollutant for at least 2 consecutive years 

show that your emissions are at or below this limit, you can skip testing according to § 63.7515 if all of the other provision of § 63.7515 are met. 

For all other pollutants that do not contain a footnote ‘‘a’’, your performance tests for this pollutant for at least 2 consecutive years must show 

that your emissions are at or below 75 percent of this limit in order to qualify for skip testing. b Incorporated by reference, see § 63.14. 

cAn owner or operator may request that compliance with the carbon monoxide emission limit be determined using carbon dioxide measurements corrected to an equivalent of 3 percent oxygen. The relationship between oxygen and carbon dioxide levels for the affected facility shall 

be established during the initial compliance test. 

■ 29. Table 12 to subpart DDDDD of part 

63 is revised to read as follows: 

TABLE 12 TO SUBPART DDDDD OF PART 63—ALTERNATIVE EMISSION LIMITS FOR NEW OR RECONSTRUCTED BOILERS

AND PROCESS HEATERS THAT COMMENCED CONSTRUCTION OR RECONSTRUCTION AFTER MAY 20, 2011, AND BEFORE DECEMBER 23, 2011 

If your boiler or process heater is in this 

subcategory . . . 

For the following 

pollutants . . . 

The emissions must not exceed the 

following emission limits, except during 

periods of startup and shutdown . . . 

Using this specified sampling volume 

or test run duration . . . 

1. Units in all subcategories designed to 

burn solid fuel.

a. HCl .................... 0.022 lb per MMBtu of heat input ........ For M26A, collect a minimum of 1 

dscm per run; for M26 collect a minimum of 120 liters per run. 

b. Mercury ............. 3.5E–06 a lb per MMBtu of heat input .. For M29, collect a minimum of 3 dscm 

per run; for M30A or M30B, collect a 

minimum sample as specified in the 

method; for ASTM D6784 b collect a 

minimum of 3 dscm. 

2. Units design to burn coal/solid fossil 

fuel.

a. Filterable PM (or 

TSM).

1.1E–03 lb per MMBtu of heat input; or 

(2.3E–05 lb per MMBtu of heat 

input).

Collect a minimum of 3 dscm per run. 

3. Pulverized coal boilers designed to 

burn coal/solid fossil fuel.

a. Carbon monoxide (CO) (or 

CEMS) 

130 ppm by volume on a dry basis 

corrected to 3 percent oxygen, 3-run 

average; or (320 ppm by volume on 

a dry basis corrected to 3 percent 

oxygen c, 30-day rolling average) 

1 hr minimum sampling time. 

4. Stokers designed to burn coal/solid 

fossil fuel.

a. CO (or CEMS) .. 130 ppm by volume on a dry basis 

corrected to 3 percent oxygen, 3-run 

average; or (340 ppm by volume on 

a dry basis corrected to 3 percent 

oxygen c, 10-day rolling average) 

1 hr minimum sampling time. 


asabaliauskas on DSK5VPTVN1PROD with PROPOSALS
Federal Register / Vol. 80, No. 13 / Wednesday, January 21, 2015 / Proposed Rules 3129 

TABLE 12 TO SUBPART DDDDD OF PART 63—ALTERNATIVE EMISSION LIMITS FOR NEW OR RECONSTRUCTED BOILERS

AND PROCESS HEATERS THAT COMMENCED CONSTRUCTION OR RECONSTRUCTION AFTER MAY 20, 2011, AND BEFORE DECEMBER 23, 2011—Continued 

If your boiler or process heater is in this 

subcategory . . . 

For the following 

pollutants . . . 

The emissions must not exceed the 

following emission limits, except during 

periods of startup and shutdown . . . 

Using this specified sampling volume 

or test run duration . . . 

5. Fluidized bed units designed to burn 

coal/solid fossil fuel.

a. CO (or CEMS) .. 130 ppm by volume on a dry basis 

corrected to 3 percent oxygen, 3-run 

average; or (230 ppm by volume on 

a dry basis corrected to 3 percent 

oxygen c, 30-day rolling average) 

1 hr minimum sampling time. 

6. Fluidized bed units with an integrated 

heat exchanger designed to burn 

coal/solid fossil fuel.

a. CO (or CEMS) .. 140 ppm by volume on a dry basis 

corrected to 3 percent oxygen, 3-run 

average; or (150 ppm by volume on 

a dry basis corrected to 3 percent 

oxygen c, 30-day rolling average) 

1 hr minimum sampling time. 

7. Stokers/sloped grate/others designed 

to burn wet biomass fuel.

a. CO (or CEMS) .. 620 ppm by volume on a dry basis 

corrected to 3 percent oxygen, 3-run 

average; or (390 ppm by volume on 

a dry basis corrected to 3 percent 

oxygen c, 30-day rolling average) 

1 hr minimum sampling time. 

b. Filterable PM (or 

TSM).

3.0E–02 lb per MMBtu of heat input; or 

(2.6E–05 lb per MMBtu of heat 

input) 

Collect a minimum of 2 dscm per run. 

8. Stokers/sloped grate/others designed 

to burn kiln-dried biomass fuel.

a. CO .................... 460 ppm by volume on a dry basis 

corrected to 3 percent oxygen 

1 hr minimum sampling time. 

b. Filterable PM (or 

TSM).

3.0E–02 lb per MMBtu of heat input; or 

(4.0E–03 lb per MMBtu of heat 

input) 

Collect a minimum of 2 dscm per run. 

9. Fluidized bed units designed to burn 

biomass/bio-based solids.

a. CO (or CEMS) .. 260 ppm by volume on a dry basis 

corrected to 3 percent oxygen, 3-run 

average; or (310 ppm by volume on 

a dry basis corrected to 3 percent 

oxygen c, 30-day rolling average) 

1 hr minimum sampling time. 

b. Filterable PM (or 

TSM).

9.8E–03 lb per MMBtu of heat input; or 

(8.3E–05 a lb per MMBtu of heat 

input) 

Collect a minimum of 3 dscm per run. 

10. Suspension burners designed to 

burn biomass/bio-based solids.

a. CO (or CEMS) .. 2,400 ppm by volume on a dry basis 

corrected to 3 percent oxygen, 3-run 

average; or (2,000 ppm by volume 

on a dry basis corrected to 3 percent oxygen c, 10-day rolling average) 

1 hr minimum sampling time. 

b. Filterable PM (or 

TSM).

3.0E–02 lb per MMBtu of heat input; or 

(6.5E–03 lb per MMBtu of heat 

input) 

Collect a minimum of 2 dscm per run. 

11. Dutch Ovens/Pile burners designed 

to burn biomass/bio-based solids.

a. CO (or CEMS) .. 470 ppm by volume on a dry basis 

corrected to 3 percent oxygen, 3-run 

average; or (520 ppm by volume on 

a dry basis corrected to 3 percent 

oxygen c, 10-day rolling average) 

1 hr minimum sampling time. 

b. Filterable PM (or 

TSM).

3.2E–03 lb per MMBtu of heat input; or 

(3.9E–05 lb per MMBtu of heat 

input) 

Collect a minimum of 3 dscm per run. 

12. Fuel cell units designed to burn biomass/bio-based solids.a. CO .................... 910 ppm by volume on a dry basis 

corrected to 3 percent oxygen 

1 hr minimum sampling time. 

b. Filterable PM (or 

TSM).

2.0E–02 lb per MMBtu of heat input; or 

(2.9E–05 lb per MMBtu of heat 

input) 

Collect a minimum of 2 dscm per run. 

13. Hybrid suspension grate boiler designed to burn biomass/bio-based solids.a. CO (or CEMS) .. 1,500 ppm by volume on a dry basis 

corrected to 3 percent oxygen, 3-run 

average; or (900 ppm by volume on 

a dry basis corrected to 3 percent 

oxygen c, 30-day rolling average) 

1 hr minimum sampling time. 

b. Filterable PM (or 

TSM).

2.6E–02 lb per MMBtu of heat input; or 

(4.4E–04 lb per MMBtu of heat 

input) 

Collect a minimum of 3 dscm per run. 

14. Units designed to burn liquid fuel .... a. HCl .................... 4.4E–04 lb per MMBtu of heat input .... For M26A: Collect a minimum of 2 

dscm per run; for M26, collect a 

minimum of 240 liters per run. 


asabaliauskas on DSK5VPTVN1PROD with PROPOSALS
3130 Federal Register / Vol. 80, No. 13 / Wednesday, January 21, 2015 / Proposed Rules 

TABLE 12 TO SUBPART DDDDD OF PART 63—ALTERNATIVE EMISSION LIMITS FOR NEW OR RECONSTRUCTED BOILERS

AND PROCESS HEATERS THAT COMMENCED CONSTRUCTION OR RECONSTRUCTION AFTER MAY 20, 2011, AND BEFORE DECEMBER 23, 2011—Continued 

If your boiler or process heater is in this 

subcategory . . . 

For the following 

pollutants . . . 

The emissions must not exceed the 

following emission limits, except during 

periods of startup and shutdown . . . 

Using this specified sampling volume 

or test run duration . . . 

b. Mercury ............. 4.8E–07 a lb per MMBtu of heat input .. For M29, collect a minimum of 4 dscm 

per run; for M30A or M30B, collect a 

minimum sample as specified in the 

method; for ASTM D6784 b collect a 

minimum of 4 dscm. 

15. Units designed to burn heavy liquid 

fuel.

a. CO .................... 130 ppm by volume on a dry basis 

corrected to 3 percent oxygen, 3-run 

average 

1 hr minimum sampling time. 

b. Filterable PM (or 

TSM).

1.3E–02 lb per MMBtu of heat input; or 

(7.5E–05 lb per MMBtu of heat 

input) 

Collect a minimum of 2 dscm per run. 

16. Units designed to burn light liquid 

fuel.

a. CO .................... 130 ppm by volume on a dry basis 

corrected to 3 percent oxygen 

1 hr minimum sampling time. 

b. Filterable PM (or 

TSM).

1.3E–03 a lb per MMBtu of heat input; 

or (2.9E–05 lb per MMBtu of heat 

input) 

Collect a minimum of 3 dscm per run. 

17. Units designed to burn liquid fuel 

that are non-continental units 

a. CO .................... 130 ppm by volume on a dry basis 

corrected to 3 percent oxygen, 3-run 

average based on stack test 

1 hr minimum sampling time. 

b. Filterable PM (or 

TSM).

2.3E–02 lb per MMBtu of heat input; or 

(8.6E–04 lb per MMBtu of heat 

input) 

Collect a minimum of 4 dscm per run. 

18. Units designed to burn gas 2 (other) 

gases.

a. CO .................... 130 ppm by volume on a dry basis 

corrected to 3 percent oxygen 

1 hr minimum sampling time. 

b. HCl .................... 1.7E–03 lb per MMBtu of heat input .... For M26A, Collect a minimum of 2 

dscm per run; for M26, collect a 

minimum of 240 liters per run. 

c. Mercury ............. 7.9E–06 lb per MMBtu of heat input .... For M29, collect a minimum of 3 dscm 

per run; for M30A or M30B, collect a 

minimum sample as specified in the 

method; for ASTM D6784 b collect a 

minimum of 3 dscm. 

d. Filterable PM (or 

TSM).

6.7E–03 lb per MMBtu of heat input; or 

(2.1E–04 lb per MMBtu of heat 

input) 

Collect a minimum of 3 dscm per run. 

a If you are conducting stack tests to demonstrate compliance and your performance tests for this pollutant for at least 2 consecutive years 

show that your emissions are at or below this limit, you can skip testing according to § 63.7515 if all of the other provision of § 63.7515 are met. 

For all other pollutants that do not contain a footnote ‘‘a’’, your performance tests for this pollutant for at least 2 consecutive years must show 

that your emissions are at or below 75 percent of this limit in order to qualify for skip testing. b Incorporated by reference, see § 63.14. 

cAn owner or operator may request that compliance with the carbon monoxide emission limit be determined using carbon dioxide measurements corrected to an equivalent of 3 percent oxygen. The relationship between oxygen and carbon dioxide levels for the affected facility shall 

be established during the initial compliance test. 

[FR Doc. 2014–29569 Filed 1–20–15; 8:45 am] 

BILLING CODE 6560–50–P 


asabaliauskas on DSK5VPTVN1PROD with PROPOSALS