80598 Federal Register / Vol. 76, No. 247 / Friday, December 23, 2011 / Proposed Rules 

ENVIRONMENTAL PROTECTION 

AGENCY 

40 CFR Part 63 

[EPA–HQ–OAR–2002–0058; FRL–9503–6] 

RIN 2060–AR13 

National Emission Standards for 

Hazardous Air Pollutants for Major 

Sources: Industrial, Commercial, and 

Institutional Boilers and Process 

Heaters 

AGENCY: Environmental Protection 

Agency (EPA). 

ACTION: Proposed rule; Reconsideration 

of final rule. 

SUMMARY: On March 21, 2011, the EPA 

promulgated national emission 

standards for the control of hazardous 

air pollutants from new and existing 

industrial, commercial, and institutional 

boilers and process heaters at major 

sources of hazardous air pollutants. On 

that same day, the EPA also published 

a notice announcing its intent to 

reconsider certain provisions of the final 

rule. The EPA subsequently issued a 

notice on May 18, 2011, to postpone the 

effective dates of the final rule until 

judicial review has been completed, or 

the agency finalizes its reconsideration 

of the standard, whichever is earlier. In 

the action to postpone the effective 

dates of the rule, the EPA also requested 

the public to submit data and 

information to assist the EPA in its 

reconsideration. Following these 

actions, the Administrator received 

several petitions for reconsideration. In 

response to the March 21, 2011, notice 

announcing its intent to initiate 

reconsideration and the petitions 

submitted, the EPA is reconsidering and 

requesting comment on several 

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. 

DATES: Comments. Comments must be 

received on or before February 21, 2012. 

Public Hearing. We will hold a public 

hearing concerning the proposed items 

for reconsideration. Persons interested 

in presenting oral testimony at the 

hearing should contact Ms. Teresa 

Clemons at (919) 541–7689 or at 

clemons.teresa@epa.gov by January 3, 

2012. If no one requests to speak at the 

public hearing by January 3, 2012, then 

the public hearing will be cancelled. We 

will specify the date and time of the 

public hearings on http://www.epa.gov/ 

ttn/atw/boiler/boilerpg.html. 

ADDRESSES: Submit your comments, 

identified by Docket ID No. EPA–HQ– 

OAR–2002–0058, by one of the 

following methods: 

• http://www.regulations.gov: Follow 

the instructions for submitting 

comments. 

• Email: Comments may be sent by 

email to a-and-r-Docket@epa.gov, 

Attention Docket ID No. EPA–HQ– 

OAR–2002–0058. 

• Fax: Fax your comments to: (202) 

566–9744, Attention Docket ID No. 

EPA–HQ–OAR–2002–0058. 

• Mail: Send your comments to: EPA 

Docket Center (EPA/DC), Environmental 

Protection Agency, Mailcode: 2822T, 

1200 Pennsylvania Ave. NW., 

Washington, DC 20460, Docket ID No. 

EPA–HQ–OAR–2002–0058. Please 

include a total of two copies. In 

addition, please mail a copy of your 

comments on the information collection 

provisions to the Office of Information 

and Regulatory Affairs, OMB, Attn: Desk 

Officer for EPA, 725 17th St. NW., 

Washington, DC 20503. 

• Hand Delivery: In person or by 

courier, deliver comments to: EPA 

Docket Center (2822T), EPA West, Room 

3334, 1301 Constitution Ave. NW., 

Washington, DC 20460. Such deliveries 

are only accepted during the Docket’s 

normal hours of operation (8:30 a.m. to 

4:30 p.m., Monday through Friday, 

excluding legal holidays), 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 online at http:// 

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 http:// 

www.regulations.gov or email. The 

http://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 http:// 

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, EPA 

recommends that you include your 

name and other contact information in 

the body of your comment and with any 

disk or CD–ROM you submit. If the EPA 

cannot read your comment due to 

technical difficulties and cannot contact 

you for clarification, the EPA may not 

be able to consider your comment. 

Electronic files should avoid the use of 

special characters, any form of 

encryption, and be free of any defects or 

viruses. For additional information 

about EPA’s public docket, visit the EPA 

Docket Center homepage at http:// 

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

Docket: All documents in the docket 

are listed in the http:// 

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 http:// 

www.regulations.gov or in hard copy at 

the EPA Docket Center, EPA West 

Building, Room 3334, 1301 Constitution 

Ave. NW., Washington, DC. The Public 

Reading Room is open from 8:30 a.m. to 

4:30 p.m., Monday through Friday, 

excluding legal holidays. The telephone 

number for the Public Reading Room is 

(202) 566–1744, and the telephone 

number for the Docket Center is (202) 

566–1742. 

FOR FURTHER INFORMATION CONTACT: Mr. 

Brian Shrager, Energy Strategies Group, 

Sector Policies and Programs Division, 

(D243–01), Office of Air Quality 

Planning and Standards, U.S. 

Environmental Protection Agency, 

Research Triangle Park, North Carolina 

27711; Telephone number: (919) 541– 

7689; Fax number: (919) 541–5450; 

Email address: shrager.brian@epa.gov. 

SUPPLEMENTARY INFORMATION: 

Organization of this Document. The 

following outline is provided to aid in 

locating information in this preamble. 

I. General Information 

A. Does this notice of reconsideration 

apply to me? 

B. What should I consider as I prepare my 

comments to the EPA? 

C. How do I obtain a copy of this document 

and other related information? 

II. Background Information 

III. Summary of This Proposed Rule 

A. What is the source category regulated by 

this proposed rule? 

B. What is the affected source? 

C. What are the pollutants regulated by this 

proposed rule? 

D. What emission limits and work practice 

standards must I meet? 

E. What are the requirements during 

periods of startup, shutdown and 

malfunction? 


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Federal Register / Vol. 76, No. 247 / Friday, December 23, 2011 / Proposed Rules 80599 

F. What are the testing and initial 

compliance requirements? 

G. What are the continuous compliance 

requirements? 

H. What are the notification, recordkeeping 

and reporting requirements? 

I. How should emissions test results be 

submitted to EPA? 

J. What are the proposed compliance dates? 

IV. Actions We Are Taking 

V. Discussion of Issues for Reconsideration 

A. Surrogates and Selected Regulated 

Pollutants 

B. Output-Based Standards 

C. Subcategories 

D. Monitoring 

E. Emission Limits 

F. MACT Floor Methodology 

G. Tune-up Work Practices 

H. Energy Assessment 

I. Affirmative Defense Provisions During 

Malfunctions 

J. Work Practices During Startup and 

Shutdown 

K. Applicability 

L. Compliance 

M. Other Issues Open for Comment 

VI. Technical Corrections and Clarifications 

VII. Impacts of This Proposed Rule 

A. What are the air impacts? 

B. What are the water and solid waste 

impacts? 

C. What are the energy impacts? 

D. What are the cost impacts? 

E. What are the economic impacts? 

F. What are the benefits of this proposed 

rule? 

G. What are the secondary air impacts? 

VIII. Relationship of this Proposed Action to 

Section 112(c)(6) of the Clean Air Act 

IX. Statutory and Executive Order Reviews 

A. Executive Order 12866: Regulatory 

Planning and Review and Executive 

Order 13563: Improving Regulation and 

Regulatory Review 

B. Paperwork Reduction Act 

C. Regulatory Flexibility Act 

D. Unfunded Mandates Reform Act 

E. Executive Order 13132: Federalism 

F. Executive Order 13175: Consultation 

and Coordination With Indian Tribal 

Governments 

G. Executive Order 13045: Protection of 

Children From Environmental Health 

Risks and Safety Risks 

H. Executive Order 13211: Actions 

Concerning Regulations That 

Significantly Affect Energy Supply, 

Distribution, or Use 

I. National Technology Transfer and 

Advancement Act 

J. Executive Order 12898: Federal Actions 

To Address Environmental Justice in 

Minority Populations and Low-Income 

Populations 

I. General Information 

A. Does this notice of reconsideration 

apply to me? 

The regulated categories and entities 

potentially affected by this action 

include: 

Category NAICS 

code 1

Examples of potentially 

regulated entities 

Any industry using a boiler or process heater as defined in 

the proposed 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 

regulated by this reconsideration action. 

To determine whether your facility may 

be affected by this reconsideration 

action, you should examine the 

applicability criteria in 40 CFR 63.7485 

of subpart DDDDD (National Emission 

Standards for Hazardous Air Pollutants 

(NESHAP) for Industrial, Commercial, 

and Institutional Boilers and Process 

Heaters). If you have any questions 

regarding the applicability of the 

proposed rule 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). 

B. What should I consider as I prepare 

my comments to the EPA? 

Submitting CBI. Do not submit 

information that you consider to be CBI 

electronically through http:// 

www.regulations.gov or email. Send or 

deliver information identified as CBI to 

only the following address: Mr. Robert 

Morales, c/o OAQPS Document Control 

Officer (Room C404–02), U.S. 

Environmental Protection Agency, 

Research Triangle Park, North Carolina 

27711, Attn: Docket ID No. EPA–HQ– 

OAR–2002–0058. 

Clearly mark the part or all of the 

information that you claim to be CBI. 

For CBI information in a disk or CD– 

ROM that you mail to the EPA, mark the 

outside of the disk or CD–ROM as CBI 

and then identify electronically within 

the disk or CD–ROM the specific 

information that is claimed as CBI. In 

addition to one complete version of the 

comment that includes information 

claimed as CBI, a copy of the comment 

that does not contain the information 

claimed as CBI must be submitted for 

inclusion in the public docket. If you 

submit a disk or CD–ROM that does not 

contain CBI, mark the outside of the 

disk or CD–ROM clearly that it does not 

contain CBI. Information marked as CBI 

will not be disclosed except in 

accordance with procedures set forth in 

40 CFR part 2. 

If you have any questions about CBI 

or the procedures for claiming CBI, 

please consult the person identified in 

the FOR FURTHER INFORMATION CONTACT

section. 

C. How do I obtain a copy of this 

document and other related 

information? 

Docket. The docket number for this 

action and the proposed rule (40 CFR 

part 63, subpart DDDDD) 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 action is 

available on the WWW through the 

Technology Transfer Network (TTN) 

Web site. Following signature, a copy of 

this notice will be posted on the TTN’s 

policy and guidance page for newly 

proposed or promulgated rules at 

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

provides information and technology 

exchange in various areas of air 

pollution control. 


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II. Background Information 

On March 21, 2011, the EPA issued 

final standards for new and existing 

industrial, commercial, and institutional 

boilers and process heaters, pursuant to 

its authority under section 112 of the 

Clean Air Act (CAA). On the same day 

as this final rule was issued, EPA also 

stated in a separate notice that it 

planned to initiate a reconsideration of 

several provisions of the final rule. This 

reconsideration notice identified several 

provisions of the final rule where 

additional public comment was 

appropriate, including: 

• Revisions to the proposed 

subcategories. 

• Establishing a fuel specification 

through which gas-fired boilers that use 

a fuel other than natural gas or refinery 

gas may be considered Gas 1 units. 

• Establishing a work practice 

standard for limited use units. 

• Providing an affirmative defense for 

malfunction events. 

This notice also identified several 

issues of central relevance to the 

rulemaking where reconsideration was 

appropriate under CAA section 307(d), 

including: 

• Revisions to the proposed 

monitoring requirements for carbon 

monoxide for major source boilers. 

• Revisions to the proposed dioxin 

emission limit and testing requirement 

for major source boilers. 

• Establishing a full-load stack test 

requirement for carbon monoxide 

coupled with continuous oxygen 

(oxygen trim) monitoring. 

On May 18, 2011, the EPA issued a 

notice to postpone the effective dates of 

the March 21, 2011, final rule. This 

notice also requested that the public 

submit additional data and information 

to the EPA by July 15, 2011, for review 

and consideration in the reconsideration 

proceedings. Following promulgation of 

the final rule, the EPA received 

petitions for reconsideration from the 

following organizations (‘‘Petitioners’’): 

Alliance for Industrial Efficiency (AIE), 

U.S. Clean Heat Power Association 

(USCHPA), Alyeska Pipeline, American 

Chemistry Council (ACC), American 

Home Furnishings Alliance (AHFA), 

American Iron and Steel Institute (AISI), 

American Coke and Coal Chemicals 

Institute (ACCCI), American Municipal 

Power Inc. (AMP), American Petroleum 

Institute (API), National Petrochemical 

and Refiners Association (NPRA), Auto 

Industry Forum (AIF), Citizens Energy 

Group (CEG), Council of Industrial 

Boiler Owners (CIBO), CraftMaster 

Manufacturing Inc. (CMI), District 

Energy St. Paul, Florida Sugar Industry 

(FSI), Great Plains Synfuels (GPSP), 

Hovensa L.L.C., Tesoro Hawaii Corp., 

Industry Coalition (AF&PA et. al.), 

JELD–WEN Inc., Michigan State 

University (MSU), Penn State University 

(PSU), Purdue University, Renovar 

Energy Corp., Rochester Public Utilities 

(RPU), Sierra Club, Southeastern 

Lumber Manufacturers Association, 

State of Washington Department of 

Ecology, The Business Council for 

Sustainable Energy (BCSE), Utility Air 

Regulatory Group (UARG), United 

States Sugar Corporation (U.S. Sugar), 

Waste Management Inc. (WM), and 

Wisconsin Electric Power Company. 

Copies of these petitions are provided in 

the docket (see Docket ID No. EPA–HQ– 

OAR–2002–0058). Petitioners, pursuant 

to CAA section 307(d)(7)(B), requested 

that the EPA reconsider numerous 

provisions in the rules. In this action, 

the EPA is proposing multiple changes 

to the final rule in response to the 

reconsideration requests and the issues 

that the EPA previously identified as 

reconsideration issues. The EPA also is 

soliciting comment on several 

provisions of the final rule for which we 

are not proposing changes, because the 

public did not previously have an 

opportunity to comment on those 

provisions. The issues upon which the 

EPA is soliciting comment are discussed 

in section V of this preamble. 

III. Summary of This Proposed Rule 

This section summarizes the 

requirements of this action. Some of the 

requirements are currently found in the 

final boilers rule and are not being 

proposed to be revised. Section IV 

below provides a summary of the 

significant changes the EPA is 

proposing to make in its reconsideration 

of the final rule, and on which EPA is 

soliciting public comment. 

A. What is the source category regulated 

by this proposed rule? 

This proposed rule regulates 

industrial, commercial, and institutional 

boilers and process heaters located at 

major sources of hazardous air 

pollutants (HAP). Waste heat boilers 

and process heaters and boilers and 

process heaters that combust solid 

waste, except for specific exceptions to 

the definition of a solid waste 

incineration unit outlined in section 

129(g)(1), are not subject to this 

proposed rule. 

B. What is the affected source? 

This proposed rule affects industrial, 

commercial, and institutional boilers 

and process heaters. A process heater is 

defined as a unit in which the 

combustion gases do not directly come 

into contact with process material or 

gases in the combustion chamber (e.g., 

indirect fired). A boiler is defined as an 

enclosed device using controlled flame 

combustion and having the primary 

purpose of recovering thermal energy in 

the form of steam or hot water. 

C. What are the pollutants regulated by 

this proposed rule? 

This proposed rule regulates 

hydrogen chloride (HCl) (as a surrogate 

for acid gas HAP), total selected metals 

(TSM) or particulate matter (PM) (as a 

surrogate for non-mercury HAP metals), 

carbon monoxide (CO) (as a surrogate 

for non-dioxin/furan organic HAP), 

mercury (Hg), and dioxin/furan 

emissions from boilers and process 

heaters. 

D. What emission limits and work 

practice standards must I meet? 

You must meet the emission limits 

presented in Table 1 of this preamble for 

each subcategory of units listed in the 

table. This proposed rule includes 17 

subcategories, which are based on unit 

design. New and existing units in 3 of 

the subcategories would be subject to 

work practices standards in lieu of 

emission limits for all pollutants. 

Numeric emission limits are being 

proposed for new and existing sources 

in each of 14 subcategories, which are 

shown in Table 1 of this preamble. 

HCl and Hg are ‘‘fuel-based 

pollutants’’ that directly result from 

contaminants in the fuels that are 

combusted. For those pollutants, if your 

new or existing unit combusts at least 

10 percent solid fuel on an annual basis, 

your unit is subject to emission limits 

that are based on data from all of the 

solid fuel-fired combustor designs. If 

your new or existing unit combusts 

liquid fuel (except as noted in this 

proposed rule) and less than 10 percent 

solid fuel and your facility is located in 

the continental United States, your unit 

is subject to the liquid fuel emission 

limits for the fuel-based pollutants. If 

your facility is located outside the lower 

contiguous 48 states and Alaska 

(referred to as a non-continental unit for 

the remainder of this preamble and in 

this proposed rule), and your new or 

existing unit combusts liquid fuel 

(except as noted in this rule) and less 

than 10 percent solid fuel, your unit is 

subject to the non-continental liquid 

fuel emission limits for the fuel-based 

pollutants. Finally, for the fuel-based 

pollutants, if your unit combusts 

gaseous fuel that does not qualify as a 

‘‘Gas 1’’ fuel, your unit is subject to the 

Gas 2 emission limits in Table 1 of this 

preamble. If your unit is a metal process 

furnace, limited-use unit, or Gas 1 unit 

(that is, it combusts only natural gas, 


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1Heat input means heat derived from combustion 

of fuel in a boiler or process heater and does not 

include the heat derived from preheated 

combustion air, recirculated flue gases or exhaust 

gases from other sources (such as stationary gas 

turbines, internal combustion engines, and kilns). 

refinery gas, or other clean gas that 

meets the fuel specification, with 

limited exceptions for gas curtailments 

and emergencies), your unit is subject to 

a work practice standard that requires 

an annual tune-up in lieu of emission 

limits. 

For the combustion-based pollutants, 

PM (a surrogate for metallic HAP) and 

CO (a surrogate for non-dioxin organic 

HAP), your unit is subject to the 

emission limits for the design-based 

subcategories shown in Table 1 of this 

preamble. We also are proposing, as 

alternatives to the PM limits, total 

selected metals emission limits for 

subcategories of units that combust 

solid fuels or Gas 2 fuels. If your new 

or existing boiler or process heater 

burns at least 10 percent biomass on an 

annual average heat input 1 basis, the 

unit is in one of the biomass 

subcategories. If your new or existing 

boiler or process heater burns at least 10 

percent coal, on an annual average heat 

input basis, and less than 10 percent 

biomass, on an annual average heat 

input basis, the unit is in one of the coal 

subcategories. If your facility is located 

in the lower contiguous 48 states or 

Alaska and your new or existing boiler 

or process heater burns light liquid fuel 

(i.e., distillate oil, biodiesel, or vegetable 

oil) and less than 10 percent coal and 

less than 10 percent biomass, on an 

annual average heat input basis, your 

unit is in the light liquid subcategory. If 

your facility is located in the lower 

contiguous 48 states or Alaska and your 

new or existing boiler or process heater 

burns heavy liquid fuel (other liquids 

that are not defined as light liquids) and 

less than 10 percent coal and less than 

10 percent biomass, on an annual 

average heat input basis, your unit is in 

the heavy liquid subcategory. If your 

non-continental new or existing boiler 

or process heater burns liquid fuel and 

less than 10 percent coal and less than 

10 percent biomass, on an annual 

average heat input basis, your unit is in 

the non-continental liquid subcategory. 

Finally, for combustion-based 

pollutants, if your unit combusts 

gaseous fuel that does not qualify as a 

‘‘Gas 1’’ fuel, your unit is subject to the 

Gas 2 emission limits in Table 1. If your 

unit combusts only natural gas, refinery 

gas, or equivalent fuel (other gas that 

qualifies as Gas 1 fuel), with limited 

exceptions for gas curtailment and 

emergencies, your unit is subject to a 

work practice standard that requires an 

annual tune-up in lieu of emission 

limits. 

TABLE 1—EMISSION LIMITS FOR BOILERS AND PROCESS HEATERS

[lb/MMBtu heat input basis unless noted; alternative output based limits are not shown in the summary table below] 

Subcategory 

Filterable Particulate Matter (Filterable PM) (or total 

selected metals) (lb 

per MMBtu of heat 

input) a

Hydrogen 

chloride (HCl) 

(lb per MMBtu 

of heat input) a

Mercury (Hg) 

(lb per MMBtu 

of heat input) a

Carbon monoxide(CO) 

(ppm @3% 

oxygen) a

Alternate CO 

CEMS limit, 

(ppm @3% 

oxygen) b

Existing—Solid fuel ...................................................... NA 0.022 3.1E–06 NA NA 

Existing—Coal Stoker .................................................. 0.028 (8.3E–05) NA NA 220 34 

Existing—Coal Fluidized Bed ...................................... 0.088 (1.7E–05) NA NA 56 59 

Existing—Coal-Burning Pulverized Coal ..................... 0.044 (5.9E–05) NA NA 41 28 

Existing—Biomass Wet Stoker/Sloped Grate/Other .... 0.029 (5.7E–05) NA NA 790 410 

Existing—Biomass Kiln-Dried Stoker/Sloped Grate/ 

Other ......................................................................... 0.32 (0.004) NA NA 250 ND 

Existing—Biomass Fluidized Bed ................................ 0.11 (0.0012) NA NA 370 180 

Existing—Biomass Suspension Burner ....................... 0.051 (0.0011) NA NA 58 1,400 

Existing—Biomass Dutch Ovens/Pile Burners ............ 0.036 (2.4E–04) NA NA 810 440 

Existing—Biomass Fuel Cells ...................................... 0.033 (4.9E–05) NA NA 1,500 ND 

Existing—Biomass Hybrid Suspension Grate ............. 0.44 (4.9E–04) NA NA 3,900 730 

Existing—Liquid ........................................................... NA 0.0012 2.6E–05 NA NA 

Existing—Heavy Liquid ................................................ c 0.062 NA NA 10 18 

Existing—Light Liquid .................................................. c 0.0034 NA NA 7 d 60 

Existing—non-Continental Liquid ................................. c 0.0080 NA NA 18 e 91 

Existing—Gas 2 (Other Process Gases) ..................... 0.0067 (2.4E–04) 0.0017 7.9E–06 4 ND 

New—Solid Fuel .......................................................... NA 0.022 8.6E–07 NA NA 

New—Coal Stoker ....................................................... 0.028 (2.2E–05) NA NA 19 34 

New—Coal Fluidized Bed ............................................ 0.0011 (1.7E–05) NA NA 17 59 

New—Coal-Burning Pulverized Coal ........................... 0.0013 (2.8E–05) NA NA 9 28 

New—Biomass Wet Stoker/Sloped Grate/Other ......... 0.029 (2.6E–05) NA NA 590 410 

New—Biomass Kiln-Dried Stoker/Sloped Grate/Other 0.32 (0.0040) NA NA 250 ND 

New—Biomass Fluidized Bed ..................................... 0.0098 (4.2E–05) NA NA 230 180 

New—Biomass Suspension Burner ............................. 0.051 (0.0011) NA NA 58 1,400 

New—Biomass Dutch Ovens/Pile Burners .................. 0.036 (4.1E–05) NA NA 810 440 

New—Biomass Fuel Cells ........................................... 0.011 (4.9E–05) NA NA 210 ND 

New—Biomass Hybrid Suspension Grate ................... 0.026 (4.9E–04) NA NA 1,500 730 

New—Liquid ................................................................. NA 0.0012 4.9E–07 NA NA 

New—Heavy Liquid ..................................................... c 0.013 NA NA 10 18 

New—Light Liquid ........................................................ c 0.0011 NA NA 3 d 60 

New—Non-Continental Liquid ...................................... c 0.0080 NA NA 18 e 91 

New—Gas 2 (Other Process Gases) .......................... 0.0067 (2.4E–04) 0.0017 7.9E–06 4 ND 

NA—Not applicable; ND—No data available. 

a 3-run average, unless otherwise noted. 

b 10-day rolling average, unless otherwise noted. 

cTotal selected metals alternative limits are not available to units in any of the liquid subcategories. 

d 1-day block average. 


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e 3-hour rolling average. 

The emission limits in Table 1 apply 

only to new and existing boilers and 

process heaters that have a designed 

heat input capacity of 10 million British 

thermal units per hour (MMBtu/hr) or 

greater. We also are providing optional 

output-based standards in this proposed 

rule. Pursuant to CAA section 112(h), 

the final rule requires a work practice 

standard for the following particular 

classes of boilers and process heaters: 

new and existing units that have a 

designed heat input capacity of less 

than 10 MMBtu/hr, new and existing 

units in the Gas 1 (natural gas/refinery 

gas) subcategory and in the metal 

process furnaces subcategory, and new 

and existing limited-use units. The work 

practice standard for these boilers and 

process heaters requires the 

implementation of a tune-up program. 

We also are proposing a work practice 

standard for dioxin/furan emissions 

from all subcategories. Finally, the final 

rule includes a beyond-the-floor 

standard for all existing major source 

facilities having affected boilers or 

process heaters that would require the 

performance of a one-time energy 

assessment, as described in section IV of 

this preamble, of the affected boilers 

and facility to identify any cost-effective 

energy conservation measures. 

E. What are the requirements during 

periods of startup, shutdown, and 

malfunction? 

We are not proposing to change the 

malfunction provisions in this rule. See 

76 FR 15613. We are proposing revised 

work practice standards for periods of 

startup and shutdown. The final rule 

required that an owner/operator must 

‘‘Minimize the unit’s startup and 

shutdown periods following the 

manufacturer’s recommended 

procedures. If manufacturer’s 

recommended procedures are not 

available, you must follow 

recommended procedures for a unit of 

similar design for which manufacturer’s 

recommended procedures are 

available.’’ 

While we are maintaining a work 

practice approach for startup and 

shutdown, we are proposing to change 

the work practice standards to better 

reflect the maximum achievable control 

technology. First, we are proposing 

definitions of startup and shutdown. We 

are proposing to define startup as the 

period between the state of no 

combustion in the unit to the period 

where the unit first achieves 25 percent 

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

to define shutdown as the period that 

begins when a unit last operates at 25 

percent load and ending with a state of 

no fuel combustion in the unit. For 

periods of startup and shutdown, we are 

proposing the following work practice 

standard: you must employ good 

combustion practices and demonstrate 

that good combustion practices are 

maintained by monitoring O2

concentrations and optimizing those 

concentrations as specified by the boiler 

manufacturer; you must ensure that 

boiler operators are trained in startup 

and shutdown procedures, including 

maintenance and cleaning, safety, 

control device startup, and procedures 

to minimize emissions; and you must 

maintain records during periods of 

startup and shutdown and include in 

your compliance reports the O2

conditions/data for each startup event, 

length of startup/shutdown and reason 

for the startup/shutdown (i.e., normal/ 

routine, problem/malfunction, outage). 

You must comply with all applicable 

emissions limits at all times except for 

startup and shutdown periods, during 

which times you must comply with 

these work practices. 

F. What are the testing and initial 

compliance requirements? 

We are requiring that the owner or 

operator of a new or existing boiler or 

process heater conduct performance 

tests to demonstrate compliance with all 

applicable emission limits. An owner or 

operator of any affected unit would be 

required to conduct the following 

compliance tests as applicable: 

(1) Conduct initial and annual stack 

tests to determine compliance with the 

PM emission limits using EPA Method 

5 or 17 or conduct initial and annual 

stack tests to determine compliance 

with the TSM emission limits using 

EPA Method 29 for those subcategories 

with alternate TSM limits. 

(2) Conduct initial and annual stack 

tests to determine compliance with the 

Hg emission limits using EPA Method 

29, 30B, or ASTM–D6784–02 (Ontario 

Hydro Method). 

(3) Conduct initial and annual stack 

tests to determine compliance with the 

HCl emission limits using EPA Method 

26A or EPA Method 26 (if no entrained 

water droplets are in the sample). 

(4) Use EPA Method 19 to convert 

measured concentration values to 

pound per million Btu values. 

(5) Conduct initial and annual tests to 

determine compliance with the CO 

emission limits using EPA Method 10 or 

install, operate, and maintain CO 

continuous emission monitoring 

systems (CEMS) to determine 

compliance with the alternate CO 

CEMS-based emission limits. 

As part of the initial compliance 

demonstration, we are requiring that 

you monitor specified operating 

parameters during the initial 

performance tests that you would 

conduct to demonstrate compliance 

with the PM or TSM (as appropriate), 

Hg, HCl, and CO emission limits. You 

must calculate the average hourly 

parameter values measured during each 

test run over the three-run performance 

test. The lowest or highest hourly 

parameter average measured during the 

three test runs (depending on the 

parameter measured) for each applicable 

parameter would establish the sitespecific operating limit. The applicable 

operating parameters for which 

operating limits would be required to be 

established are based on the emissions 

limits applicable to your unit as well as 

the types of add-on controls on the unit. 

The following is a summary of the 

operating limits that we are requiring to 

be established for the various types of 

the following units: 

(1) For boilers and process heaters 

with wet PM scrubbers, you must 

measure pressure drop across the 

scrubber and liquid flow rate of the 

scrubber during the performance test, 

and calculate the average hourly values 

during each test run. The lowest hourly 

average determined during the three test 

runs establishes your minimum sitespecific pressure drop and liquid flow 

rate operating levels. 

(2) If you are complying with an HCl 

emission limit using a wet acid gas 

scrubber, you must measure pH and 

liquid flow rate of the scrubber sorbent 

during the performance test, calculate 

the average hourly values during each 

test run of the performance test for HCl 

and determine the lowest hourly 

average of the pH and liquid flow rate 

for each test run for the performance 

test. This establishes your minimum pH 

and liquid flow rate operating limits. 

(3) For boilers and process heaters 

with sorbent injection, you must 

measure the sorbent injection rate for 

each acid gas sorbent used during the 

performance tests for HCl and for 

activated carbon for Hg and calculate 

the hourly average for each sorbent 

injection rate during each test run. The 

lowest hourly average measured during 

the performance tests becomes your sitespecific minimum sorbent injection rate 

operating limit. If different acid gas 

sorbents and/or injection rates are used 

during the HCl test, the lowest hourly 


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average value for each sorbent becomes 

your site-specific operating limit. When 

your unit operates at lower loads, 

multiply your sorbent injection rate by 

the load fraction (operating heat input 

divided by the average heat input 

during your last compliance test for the 

appropriate pollutant) to determine the 

required injection rate operating limit 

value. 

(4) For boilers and process heaters 

with fabric filters not subject to PM 

Continuous Parametric Monitoring 

System (PM CPMS) or continuous 

compliance with an opacity limit (i.e., 

continuous opacity monitoring systems 

(COMS)), you must operate the fabric 

filter such that the bag leak detection 

system alarm does not sound more than 

5 percent of the operating time during 

any 6-month period unless a PM CPMS 

is installed to monitor PM control. For 

the purposes of the rule, we define a PM 

CPMS as a continuous parametric 

monitoring device based on a detection 

principle of light scatter, light 

scintillation, beta attenuation, or mass 

accumulation detection of PM in the 

exhaust gas or representative exhaust 

gas sample, installed and operated on 

the effluent stack or duct downstream of 

any particulate control device(s), and 

programmed to provide a continuous 

electronic signal representative of 

ongoing particulate matter control 

device performance. 

(5) For boilers and process heaters 

with electrostatic precipitators (ESP) not 

subject to PM CPMS or continuous 

compliance with an opacity limit (i.e., 

COMS), you must measure the 

secondary voltage and secondary 

current of the ESP collection fields 

during the Hg and PM performance test. 

You then calculate the average total 

secondary electric power value from 

these parameters for each test run. The 

lowest hourly average total secondary 

electric power measured during the 

three test runs establishes your sitespecific minimum operating limit for 

the ESP on a 12-hour block average 

basis. 

(6) For boilers and process heaters 

that choose to demonstrate compliance 

with the Hg emission limit by fuel 

analysis, you must measure the Hg 

content of the inlet fuel that was burned 

during the Hg performance test. This 

value is your maximum fuel Hg content 

operating limit. 

(7) For boilers and process heaters 

that choose to demonstrate compliance 

with the HCl emission limit by fuel 

analysis, you must measure the chlorine 

content of the inlet fuel that was burned 

during the HCl performance test. This 

value is your maximum fuel chlorine 

content operating limit. 

(8) For boilers and process heaters 

that choose to demonstrate compliance 

with the total selected metals emission 

limit on the basis of fuel analysis, you 

are required to measure the total 

selected metals content of the inlet fuel 

that was burned during the total 

selected metals performance test. This 

value is your maximum fuel total 

selected metals content operating limit. 

(9) For boilers and process heaters 

that are subject to a CO emission limit, 

you must record the oxygen 

concentration representative of your 

boiler operation (e.g., oxygen trim) 

during the initial performance test. 

These operating limits do not apply to 

owners or operators of boilers or process 

heaters having a heat input capacity of 

less than 10 MMBtu/hr or boilers or 

process heaters of any size which 

combust natural gas or other clean gas, 

metal process furnaces, or limited-use 

units. Instead, if requested, owners or 

operators of such boilers and process 

heaters shall submit to the delegated 

authority or the EPA, as appropriate, 

documentation that a tune-up meeting 

the requirements of this final rule was 

conducted. In order to comply with the 

work practice standard, a tune-up 

procedure must include the following 

actions: 

(1) Inspect the burner and clean or 

replace any components of the burner as 

necessary, 

(2) Inspect the flame pattern and make 

any adjustments to the burner necessary 

to optimize the flame pattern consistent 

with the manufacturer’s specifications, 

(3) Inspect the system controlling the 

air-to-fuel ratio and ensure that the 

system is correctly calibrated and 

functioning properly, 

(4) Optimize total emissions of CO 

consistent with the manufacturer’s 

specifications, 

(5) Measure the concentration in the 

effluent stream of CO in parts per 

million by volume dry (ppmvd), before 

and after any adjustments related to the 

tune-up are made, 

(6) Submit to the delegated authority 

or the EPA an annual report containing 

the concentrations of CO in the effluent 

stream in ppmvd and oxygen in percent 

dry basis, both measured before and 

after the adjustments of the unit; a 

description of any corrective actions 

taken as a part of the combustion 

adjustment; and the type and amount of 

fuel used over the 12 months prior to 

the adjustment. 

Further, all owners or operators of 

major source facilities having boilers 

and process heaters subject to this final 

rule are required to submit to the 

delegated authority or the EPA, as 

appropriate, documentation that an 

energy assessment was performed by a 

qualified energy assessor and 

documentation of the cost-effective 

energy conservation measures 

indentified by the energy assessment. 

G. What are the continuous compliance 

requirements? 

To demonstrate continuous 

compliance with the emission 

limitations, we are requiring the 

following: 

(1) For units combusting coal or 

residual fuel oil (i.e., No. 4, 5 or 6 fuel 

oil) with average annual heat input rate 

of less than 250 MMBtu/hr (from the 

combustion of those fuels) or any units 

in the biomass subcategories and all 

biomass units that do not use a wet 

scrubber, opacity levels must be 

maintained to less than 10 percent 

(daily average) for existing and new 

units with applicable emission limits. If 

the unit is controlled with a fabric filter, 

instead of being subject to continuous 

opacity monitoring, the fabric filter 

must be continuously operated such 

that the bag leak detection system alarm 

does not sound more than 5 percent of 

the operating time during any 6-month 

period (unless a PM CPMS is used). 

(2) For units combusting coal or 

residual oil with heat input capacities of 

250 MMBtu/hr or greater from the 

combustion of those fuels, the EPA is 

proposing the collection of data using a 

PM CPMS at all times that the unit is 

subject to numeric emission limits, with 

the exception of periods of PM CPMS 

repair, malfunction, scheduled 

maintenance, or QA/QC related 

activities. The operating unit will 

prepare, and submit for approval, a sitespecific monitoring plan that addresses 

the PM CPMS design, data collection, 

and the QA/QC elements outlined in 

63.8(d), including the performance 

criteria and design specifications for the 

monitoring system equipment, the 

sample interface location, frequency of 

quality control checks, frequency of 

system performance evaluations, 

ongoing operation and maintenance 

procedures as well as ongoing reporting 

and recordkeeping procedures. An 

annual deviation report must be 

submitted detailing data collected 

during periods of boiler startup, 

shutdown or malfunction and PM CPMS 

malfunction, repair, or other QA/QC 

related activity. Records of these data 

must be available on site for inspection, 

including corrective actions necessary 

to return the PM CPMS to operation 

consistent with the site specific 

monitoring plan. The operating unit will 

use output data collected from the 

CPMS (milliamps, milligrams per actual 

cubic meter, or other instrument output) 


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during all other operating hours where 

numeric emission limits apply to assess 

compliance with the operating limit. An 

arithmetic average of the measurement 

output values collected during each 

hour will be calculated, and for each 

operating day the arithmetic average of 

all hourly measurement output values 

will be calculated for the previous 30 

operating days. You must transmit four 

reports per year for each PM CPMS to 

the EPA’s WebFIRE database by using 

the Compliance and Emissions Data 

Reporting Interface, or CEDRI, that is 

accessed through the EPA’s Central Data 

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

Complete reports must be submitted 

within 60 days after March 31st, June 

30th, September 30th, and December 

31st. Complete reports contain daily PM 

CPMS rolling 30-day average values for 

the periods that end with each of the 4 

previously mentioned dates. 

(3) For boilers and process heaters 

with wet PM scrubbers, you must 

monitor pressure drop and liquid flow 

rate of the scrubber and maintain the 30- 

day rolling averages at or above the 

operating limits established during the 

performance test to demonstrate 

continuous compliance with the PM 

emission limits. 

(4) For boilers and process heaters 

with wet acid gas scrubbers, you must 

monitor the pH and liquid flow rate of 

the scrubber and maintain the 30-day 

rolling average at or above the operating 

limits established during the most 

recent performance test to demonstrate 

continuous compliance with the HCl 

emission limits. 

(5) For boilers and process heaters 

with dry scrubbers, you must 

continuously monitor the sorbent 

injection rate and maintain the hourly 

average at or above the operating limits, 

which include an adjustment for load, 

established during the performance 

tests. When your unit operates at lower 

loads, multiply your sorbent injection 

rate by the load fraction (operating load 

divided by the load during your last 

compliance test for the appropriate 

pollutant) to determine the required 

parameter value. 

(6) For boilers and process heaters not 

required to install a CPMS and having 

an ESP installed, you must monitor the 

voltage and current of the ESP 

collection plates and maintain the 30- 

day rolling average total secondary 

electric power at or above the operating 

limits established during the Hg, PM, or 

TSM performance test. 

(7) For units that choose to comply 

with either the Hg emission limit, the 

HCl emission limit, or TSM emission 

limit (solid fuel units only) based on 

fuel analysis rather than on performance 

testing, you must maintain monthly fuel 

records that demonstrate that you 

burned no new fuels or fuels from a new 

supplier such that the Hg content, 

chlorine content, or TSM content of the 

inlet fuel was maintained at or below 

your maximum fuel Hg content 

operating limit, your chlorine content 

operating limit, or your TSM content 

operating limit set during the 

performance tests. If you plan to burn a 

new fuel, a fuel from a new mixture, or 

a new supplier’s fuel that differs from 

what was burned during the initial 

performance tests, then you must 

recalculate the maximum Hg input, 

maximum chlorine input, and/or 

maximum TSM input anticipated from 

the new fuels based on supplier data or 

own fuel analysis, using the 

methodology specified in Table 6 of this 

final rule. If the results of recalculating 

the inputs exceed the average content 

levels established during the initial test, 

then you must conduct a new 

performance test(s) to demonstrate 

continuous compliance with the 

applicable emission limit. 

(8) For all boilers and process heaters, 

except those that are exempt from the 

incinerator standards under section 129 

because they are qualifying facilities 

burning a homogeneous waste stream, 

you must maintain records of fuel use 

that demonstrate that your fuel was not 

solid waste. 

(9) For boilers and process heaters, 

you must install, calibrate and operate 

an oxygen trim system in order to 

ensure efficient combustion and 

compliance with the CO standards. 

(10) For boilers and process heaters 

that demonstrate compliance using a 

performance test you must maintain an 

operating load no greater than 110 

percent of the operating load established 

during the performance test. 

If an owner or operator would like to 

use a control device other than the ones 

specified in this section to comply with 

this final rule, the owner or operator 

should follow the requirements in 40 

CFR 63.8(f), which presents the 

procedure for submitting a request to 

the Administrator to use alternative 

monitoring. 

H. What are the notification, 

recordkeeping and reporting 

requirements? 

All new and existing sources are 

required to comply with certain 

requirements of the General Provisions 

(40 CFR part 63, subpart A), which are 

identified in Table 10 of this final rule. 

The General Provisions include specific 

requirements for notifications, 

recordkeeping, and reporting. 

Each owner or operator is required to 

submit a notification of compliance 

status report, as required by § 63.9(h) of 

the General Provisions. This final rule 

requires the owner or operator to 

include certifications of compliance 

with rule requirements in the 

notification of compliance status report. 

This proposed rule would require 

records to demonstrate compliance with 

each emission limit, operating limit and 

work practice standard, as specified in 

the General Provisions. Owners or 

operators of sources with units with 

heat input capacity of less than 10 

MMBtu/hr, units combusting natural gas 

or other clean gas, metal process 

furnaces and limited use units must 

keep records of the dates and the results 

of each required boiler tune-up. 

Records of either continuously 

monitored parameter data for a control 

device if a device is used to control the 

emissions or continuous monitoring 

systems (CMS) data are required. 

You are required to keep the 

following records: 

(1) All reports and notifications 

submitted to comply with the rule. 

(2) Continuous monitoring data as 

required in the rule. 

(3) Each instance in which you did 

not meet each emission limit and each 

operating limit (i.e., deviations from the 

rule). 

(4) Daily hours of operation by each 

source. 

(5) Total fuel use by each affected 

source electing to comply with an 

emission limit based on fuel analysis for 

each 30-day period along with a 

description of the fuel, the total fuel 

usage amounts and units of measure, 

and information on the supplier and 

original source of the fuel. 

(6) Calculations and supporting 

information of chlorine fuel input, as 

required in the rule, for each affected 

source with an applicable HCl emission 

limit. 

(7) Calculations and supporting 

information of Hg fuel input, as required 

in the rule, for each affected source with 

an applicable Hg emission limit. 

(8) A paragraph that discusses 

calculations and supporting information 

of TSM fuel input, as required in the 

rule, for each affected source with an 

applicable total selected metals 

emission limit. 

(9) A signed statement, as required in 

the rule, indicating that you burned no 

new fuel type and no new fuel mixture 

or that the recalculation of chlorine 

input demonstrated that the new fuel or 

new mixture still meets chlorine fuel 

input levels, for each affected source 

with an applicable HCl emission limit. 


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(10) A signed statement, as required 

in the rule, indicating that you burned 

no new fuels and no new fuel mixture 

or that the recalculation of Hg fuel input 

demonstrated that the new fuel or new 

fuel mixture still meets the Hg fuel 

input levels, for each affected source 

with an applicable Hg emission limit. 

(11) A signed statement, as required 

in the rule, indicating that you burned 

no new fuels and no new fuel mixture 

or that the recalculation of total selected 

metals fuel input demonstrated that the 

new fuel or new fuel mixture still meets 

the total selected metals fuel input 

levels, for each affected source with an 

applicable total selected metals 

emission limit. 

(12) A copy of the results of all 

performance tests, fuel analyses, opacity 

observations, performance evaluations, 

or other compliance demonstrations 

conducted to demonstrate initial or 

continuous compliance with the rule. 

(13) A copy of your site-specific 

monitoring plan developed for the rule 

as specified in 63 CFR 63.8(e), if 

applicable. 

(14) A copy of your fuel analysis plan 

at least 60 days prior to demonstrating 

initial compliance. 

You also are required to submit the 

following reports and notifications: 

(1) Notifications required by the 

General Provisions. 

(2) Initial Notification no later than 

120 calendar days after you become 

subject to this subpart, even if you 

submitted an initial notification for the 

vacated standards that were 

promulgated in 2004. 

(3) Notification of Intent to conduct 

performance tests and/or compliance 

demonstration at least 60 calendar days 

before the performance test and/or 

compliance demonstration is scheduled 

to occur. 

(4) Notification of Compliance Status 

60 calendar days following completion 

of the performance test and/or 

compliance demonstration. 

(5) Compliance reports semi-annually. 

I. How should emissions test results be 

submitted to the EPA? 

The EPA must have performance test 

data to conduct effective reviews of 

CAA sections 112 standards, as well as 

for many other purposes including 

compliance determinations, emission 

factor development, and annual 

emission rate determinations. In 

conducting these required reviews, the 

EPA has found it ineffective and time 

consuming, for us, for regulatory 

agencies and for source owners and 

operators, to locate, collect, and submit 

performance test data because of varied 

locations for data storage and varied 

data storage methods. In recent years, 

however, stack testing firms have 

typically collected performance test data 

in electronic format, making it possible 

to move to an electronic data submittal 

system that would increase the ease and 

efficiency of data submittal and improve 

data accessibility. 

In this proposal, the EPA is presenting 

a step to improve the ease and efficiency 

of data submittal and increase data 

accessibility. Specifically, the EPA is 

proposing that owners and operators of 

industrial, commercial, and institutional 

boilers and process heaters submit 

electronic copies of required 

performance test reports to EPA’s 

WebFIRE database. The WebFIRE 

database was constructed to store 

performance test data for use in 

developing emission factors. A 

description of the WebFIRE database is 

available at http://cfpub.epa.gov/ 

oarweb/index.cfm?action=fire.main. 

Data entry would be through an 

electronic emissions test report 

structure called the Electronic Reporting 

Tool (ERT). The ERT would be able to 

transmit the electronic report through 

the EPA’s CDX network for storage in 

the WebFIRE database making submittal 

of data very straightforward and easy. A 

description of the ERT can be found at 

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

index.html. 

The proposal to submit performance 

test data electronically to the EPA 

would apply only to those performance 

tests conducted using test methods that 

will be supported by the ERT. The ERT 

contains a specific electronic data entry 

form for most of the commonly used 

EPA reference methods. A listing of the 

pollutants and test methods supported 

by the ERT is available at http:// 

www.epa.gov/ttn/chief/ert/index.html. 

We believe that industry would benefit 

from this proposed approach to 

electronic data submittal. With these 

data, the EPA would be able to develop 

improved emission factors, make fewer 

information requests, and promulgate 

better regulations. 

One major advantage of the proposed 

submittal of performance test data 

through the ERT is that it provides a 

standardized method to compile and 

store much of the documentation 

required to be reported by this rule. 

Another advantage is that the ERT 

clearly states what testing information 

would be required. Another important 

proposed benefit of submitting these 

data to the EPA at the time the source 

test is conducted is that it should 

substantially reduce the effort involved 

in data collection activities in the 

future. If the EPA has performance test 

data from these submittals, the EPA will 

likely need fewer or less substantial data 

collection requests in conjunction with 

prospective required residual risk 

assessments or technology reviews. This 

would reduce the burden on both 

affected facilities (in terms of reduced 

manpower to respond to data collection 

requests) and the EPA (in terms of 

preparing and distributing data 

collection requests and assessing the 

results). 

State, local, and tribal agencies could 

also benefit from more streamlined and 

accurate review of electronic data 

submitted to them. The ERT would 

allow for an electronic review process 

rather than a manual data assessment, 

making review and evaluation of the 

source provided data and calculations 

easier and more efficient. Finally, 

another benefit of the proposed data 

submittal to WebFIRE electronically is 

that these data would greatly improve 

the overall quality of existing and new 

emissions factors, by supplementing the 

pool of emissions test data for 

establishing emissions factors and by 

ensuring that the factors are more 

representative of current industry 

operational procedures. A common 

complaint from industry and regulators 

is that emission factors are outdated or 

do not represent a particular source 

category. With timely receipt and 

incorporation of data from most 

performance tests, the EPA would be 

able to ensure that emission factors, 

when updated, represent the most 

current range of operational practices. In 

summary, in addition to supporting 

regulation development, control strategy 

development and other air pollution 

control activities, having an electronic 

database populated with performance 

test data would save industry, state, 

local, tribal agencies and the EPA 

significant time, money, and effort 

while also improving the quality of 

emission inventories and, as a result, air 

quality regulations. 

J. What are the proposed compliance 

dates? 

The EPA is proposing to reset the 

compliance date for existing sources to 

the date 3 years after the date of 

publication of the final reconsideration 

rule. For new sources, the EPA is 

proposing to change the compliance 

date to 60 days after the date of 

publication of the final reconsideration 

rule or upon startup, whichever is later. 

We are not proposing to change the date 

that identifies whether a source is new 

or existing. This date, June 4, 2010, is 

the publication date of the original 

proposed rule. 


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IV. Actions We Are Taking 

In this notice, we are granting 

reconsideration of, and requesting 

comment on, issues presented in the 

March 21, 2011, reconsideration notice 

as well as a subset of other issues raised 

by petitioners in their petitions for 

reconsideration. Section V of this 

preamble summarizes these issues and 

discusses our proposed responses to 

each issue. 

We have revised the rule language to 

address provisions related to the 

reconsideration and are requesting 

comment on the revised rule text to 

clarify definitions, applicability, 

compliance and references to various 

sections of the rule. Finally, we are 

proposing technical corrections to 

certain applicability and compliance 

provisions in the final rule. 

We are seeking public comment only 

on the issues specifically identified in 

Section V of this action. We will not 

respond to any comments addressing 

other aspects of the final rule or any 

other related rulemakings. 

V. Discussion of Issues for 

Reconsideration 

This section of the preamble contains 

EPA’s basis for our responses to certain 

issues identified in the petitions for 

reconsideration and the changes to the 

rule that we are proposing. We solicit 

comment on all responses and revisions 

discussed in the following sections: 

A. Surrogates and Selected Regulated 

Pollutants 

1. Alternative Total Selected Metals 

Limit. Multiple petitioners requested 

that EPA include an emission limit for 

TSM as an alternative to the PM limits 

in the final rule, particularly for biomass 

units, as part of the reconsideration. 

After assessing the available data, the 

EPA determined that inclusion of these 

limits is appropriate for some 

subcategories, and the EPA is proposing 

TSM limits for each subcategory of units 

that combust solid fuels or Gas 2 fuels. 

Sources will have the option of meeting 

either the TSM limit or the alternative 

PM limit. The TSM measurement, 

which directly quantifies the HAP 

metals rather than relying on a 

surrogate, is a more direct measurement 

of HAP than PM and is, therefore, 

appropriate as a pollutant group for 

regulation with numeric emission 

limits. For this rule, TSM includes the 

following eight metals: Arsenic, 

beryllium, cadmium, chromium, lead, 

manganese, nickel, and selenium. The 

EPA selected these eight metals, rather 

than all of the HAP metals other than 

Hg, because more test data are available 

for these metals than for the other two 

HAP metals, cobalt and antimony. The 

use of 8 of 10 metals should have little 

or no impact on a facility’s selection of 

controls to meet the standards, and the 

controls that would be used to reduce 

emissions of the eight metals would be 

equally effective in reducing emissions 

of the other two metals. Therefore, TSM 

can serve as a surrogate for all metallic 

HAP except for Hg, which the final rule 

regulates separately. 

For the light liquid, heavy liquid and 

non-continental liquid units 

subcategories, we are not proposing 

alternative TSM emission limits. 

Instead, we are proposing that these 

units meet the filterable PM emission 

limits in all instances. We are not 

proposing the TSM alternative because 

of the limited emission test data for 

TSM and the large variability in the 

TSM data for these subcategories. Using 

the EPA’s maximum achievable control 

technology (MACT) floor methodology, 

the alternative TSM limits resulted in 

MACT floor values which do not appear 

to represent the actual performance of 

the best performing units. The EPA has 

sent follow-up inquiries to facilities to 

confirm these data, and is soliciting 

comment on whether alternative TSM 

limits are appropriate for the 

subcategories of units designed to 

combust liquid fuels. The EPA also is 

soliciting comment on whether an 

alternative approach to calculating the 

TSM MACT floors for these units is 

appropriate. If the EPA receives 

sufficient information that supports the 

alternative TSM standards for units 

designed to combust liquid fuels, we 

will consider adopting these limits in 

the final rule. 

2. Work Practice for Dioxin/Furan 

Emissions. Multiple petitioners 

requested that EPA reassess the 

potential for applying work practice 

standards for dioxins/furans in lieu of 

numeric emission limits. The EPA has 

re-assessed the dioxin/furan data sets 

and has determined that, similar to data 

for electric utilities for which work 

practice standards were proposed for 

dioxins/furans, the large majority of the 

emission measurements for all of the 

subcategories are below the level that 

can be accurately measured using EPA 

Method 23. While the EPA recognized 

this as an issue prior to issuing the final 

rule, sufficient time was not available to 

fully analyze the issue. For this 

proposal, the EPA conducted extensive 

analyses to determine the lowest level of 

emissions that can be accurately 

measured using EPA Method 23. The 

percentages of measurements (test runs) 

below the method detection level (a 

level at which the pollutant is known to 

be present but is not accurately 

quantified) is about 55 percent, which is 

10 percent lower than the percentage for 

electric utilities. However, in addition 

to the high percentage of measurements 

below the method detection level, a very 

high percentage of measurements are 

below the level that can be accurately 

measured (see section V.E.3 of this 

preamble) for each subcategory. Those 

percentage are as follows: Coal stoker— 

100 percent; coal fluidized bed—89 

percent; pulverized coal—85 percent; 

biomass stoker/other—100 percent; 

biomass fluidized bed—100 percent; 

biomass dutch oven/pile burner—80 

percent; biomass fuel cell—100 percent; 

heavy liquid—96 percent; light liquid— 

100 percent; gas 2 (other process 

gases)—100 percent; non-continental 

liquid—100 percent (based on No. 6 oil 

data). While data are not available for 

two of the biomass subcategories, there 

is no reason to believe that dioxin 

emissions for those subcategories would 

be different than for the other biomassbased subcategories. Based on the 

percentages of data below the method 

detection limit coupled with the 

percentage of data below the level that 

can be accurately quantified, the EPA 

concludes that emissions from 

industrial boilers and process heaters 

cannot practicably be measured, and the 

EPA is now proposing work practice 

standards in place of numeric emission 

limits for dioxin/furan. The work 

practice standards require an annual 

tune-up to ensure good combustion. 

Details on the assessment of the 

minimum level that can be accurately 

measured can be found in the docket 

memorandum entitled ‘‘Updated data 

and procedure for handling below 

detection level data in analyzing various 

pollutant emissions databases for MACT 

and RTR emissions limits.’’ We do not 

expect that the change from numeric 

emission limits to work practice 

standards will result in less public 

health protection because the levels of 

dioxin emitted from units in the source 

category are at or near current detection 

level capabilities, and we are not aware 

of any emissions controls that are 

demonstrated to reduce dioxin 

emissions from the low levels indicated 

by the available data for boilers and 

process heaters. 

B. Output-Based Standards 

1. Revisions to Boiler Efficiency 

Analysis 

Petitioners requested that the EPA 

reassess the calculation of boiler 

efficiency, which is the key calculation 

in the development of output-based 

standards, because the EPA’s 


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calculations often resulted in 

efficiencies that were unrealistically 

high, often above 100 percent, which is 

a physical impossibility. The petitioners 

attributed this to the fact that the EPA 

had disregarded feedwater temperature 

(industry average being 280 degrees F). 

The inclusion of feedwater temperature 

provides the correct assessment of boiler 

efficiency because it accounts for the 

heat energy that is supplied by steam 

from the boiler to heat the feedwater. 

The steam used to heat the feedwater is 

supplied by the boiler and was reported 

by facilities as part of the boiler ‘‘steam 

output,’’ but was not accounted for in 

the final rule efficiency calculations. 

Thus, the EPA has modified the 

development of the revised outputbased emission limits to include the 

heat (energy) associated with the 

feedwater. The revised boiler 

efficiencies of the best performing units 

for each subcategory were determined 

by the equation: 

Boiler Efficiency = (Steam output (Btu) 

¥ Feedwater Input (Btu))/(Fuel 

Input (Btu)) 

To calculate ‘‘feedwater input (Btu)’’, 

we used the industry average 

temperature of 280 degrees F and 

determined a heat content value of 

249.3 Btu/lb. Unit operators provided 

the ‘‘steam output (Btu)’’ for each best 

performing unit in response to the 

EPA’s information gathering efforts. For 

all best performing units reporting this 

steam energy output data, we calculated 

boiler efficiencies, as well as 

corresponding input-to-output 

conversion factors (CF). We averaged CF 

from the best performing units that have 

realistic boiler efficiencies averaged and 

assigned a subcategory-specific 

conversion factor. Finally, we applied 

the revised average CF to the proposed 

input-based emission limits to develop 

the revised alternate output-based 

limits. The resultant proposed outputbased limits provide a compliance 

option that achieves emission 

reductions equivalent to those achieved 

by the input-based limits and encourage 

energy efficiency. 

2. Other Changes to Output-Based 

Provisions 

a. Accommodating Emissions 

Averaging Provisions. In order to allow 

for emissions averaging for units that 

elect to comply with the output-based 

emission limits, the EPA is proposing to 

add additional equations to the rule to 

allow for emissions averaging as 

requested by petitioners. Averaging of 

output based limits was not included in 

the final rule due to time constraints, 

but there is no technical reason why 

averaging of output-based limits is 

inappropriate. The output-based limits 

are equivalent to the input-based limits 

and promote energy efficiency, and, 

therefore, EPA is proposing to allow 

averaging for units that elect to comply 

with the output-based standards. 

b. Output-Based Standards for Units 

that Generate Electricity. Petitioners 

pointed out that the final output-based 

standards were not designed to consider 

efficiency improvements from units that 

generate electricity only. In response to 

this concern, the EPA is proposing to 

add language to the definition of ‘‘Steam 

output’’ that addresses boilers that only 

produce electricity. The language 

provides fuel-specific conversion factors 

for electricity generating units that 

result in output-based standards in units 

of pounds per megawatt-hour. 

c. Clarification that output-based 

standards are alternative standards. 

Petitioners requested that the EPA 

clarify in the tables that the outputbased standards are alternative 

standards to the input-based standards. 

The EPA is proposing regulatory text to 

make this clarification. 

d. Legal Authority for Emission 

Credits. One petitioner questioned the 

legal authority of the emission credit 

system and stated that it should be 

removed from the final rule. However, 

the petitioner provided no support for 

its position, and the EPA continues to 

believe that the emission credit system 

is consistent with the CAA as 

promulgated. Therefore, no changes are 

being proposed. However, we are 

specifically requesting comment on: (1) 

The overall concept of the emission 

credit provision, (2) how to administer 

it consistently across the country, and 

(3) available guidelines to inform the 

delegated authority’s decision to 

approve the implementation plan. 

C. Subcategories 

In the final rule, the EPA added 

subcategories for hybrid suspension/ 

grate biomass units, limited-use units, 

solid fuel units, and non-continental 

liquid units. The EPA also added a fuel 

specification to the final rule that would 

allow units combusting gases not 

defined as ‘‘Gas 1’’ gases to qualify as 

Gas 1 units by demonstrating that the 

fuels combusted meet a fuel 

specification. Petitioners requested that 

EPA allow comment on these 

subcategory changes and the fuel 

specification, and EPA is now soliciting 

comments on these portions of the final 

rule, including the changes and 

particular issues described in sections [1 

through 7] below. Petitioners also 

requested additional subcategories, 

clarification of several subcategory 

definitions, and changes to some of the 

subcategory definitions. 

1. Solid Fuel. The EPA added a solid 

fuel subcategory to the final rule that 

replaced previously proposed separate 

subcategories for units designed to burn 

solid fossil-based fuels and units 

designed to burn solid bio-based fuels. 

The solid fuel subcategory applied to 

pollutants identified in the final rule as 

fuel-based pollutants (PM, HCl, and Hg). 

Standards for combustion-based 

pollutants (CO and dioxin/furan), 

however, were based on specific 

subcategories for the various types of 

combustion units, including the specific 

fuel types the units were designed to 

combust. The rationale for the change is 

presented in the preamble to the final 

rule and the EPA is, in this action, 

soliciting comments on the solid fuel 

subcategory. 

One significant change is also being 

proposed related to the solid fuel 

subcategory. Several petitioners 

provided information to support the 

position that PM should be considered 

a combustion-based pollutant rather 

than a fuel-based pollutant. After 

assessing the points raised by the 

petitioners, the EPA determined that PM 

emissions are influenced both by fuel 

type and unit design. Therefore, it is 

appropriate to treat PM as a combustionbased pollutant. Differences in PM 

particle size, applicability of airpollution controls to units combusting 

various fuels, and the lack of 

demonstration of certain control 

technologies on certain designs of 

boilers (e.g., fabric filters are not used 

on any hybrid suspension grate boilers) 

suggest that PM is more appropriately 

classified as a combustion-based 

pollutant. Therefore, the EPA is now 

proposing separate PM limits for each 

‘‘combustion-based’’ subcategory. 

Emission limits for HCl and Hg were 

developed for the same subcategories as 

presented in the March 21, 2011, final 

rule; the only changes associated with 

the HCl and Hg emission limits are due 

to new data, corrections to old data, and 

inventory changes. 

2. Units Designed to Combust Liquid 

Fuels. The EPA finalized a single 

subcategory covering liquid fuel-fired 

units (with limited exceptions such as 

non-continental liquid units and 

limited-used units). Petitioners 

requested that the EPA reconsider the 

liquid unit subcategories and include 

separate subcategories for units 

designed to combust light liquids and 

units designed to combust heavy 

liquids. Petitioners cited issues related 

to achievability of standards and the 

types of controls that are used on liquid 

units but did not cite design differences 


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that could be used to justify a 

subcategory. However, we identified 

several design differences, including the 

need for steam atomization or highpressure atomization of heavy liquids, 

the need for heated storage vessels for 

heavy liquids in some climates, and the 

lack of a demonstration that the new 

source PM limit based on combustion of 

light liquid fuels had been achieved by 

any unit combusting heavy liquid fuels. 

Therefore, the EPA is proposing 

separate subcategories for heavy liquidfired and light liquid-fired units for PM 

and CO, pollutants that are dependent 

on combustor design. Units designed to 

combust light and heavy liquids will 

continue to be grouped together in a 

liquid fuel subcategory for Hg and HCl, 

which are the fuel-based pollutants. 

Light liquids include distillate oil, 

biodiesel and vegetable oil. Heavy 

liquids include all other liquid fuels 

that are combusted in boilers, including 

byproduct liquid fuels generated at 

industrial facilities and residual oil. 

Units that combust any liquid fuels (and 

less than 10 percent coal/solid fossil 

fuel and less than 10 percent biomass/ 

bio-based solid fuel) where at least 10 

percent of the heat input from liquid 

fuels on an annual heat input basis 

comes from heavy liquids would be 

considered heavy liquid units. Units 

that combust any liquid fuels (and less 

than 10 percent coal/solid fossil fuel 

and less than 10 percent biomass/biobased solid fuel) that are not part of the 

unit designed to burn heavy liquid 

subcategory would be considered light 

liquid units. 

3. Non-Continental Liquid Units. The 

EPA finalized a subcategory for noncontinental liquid units. Stakeholders 

did not have the opportunity to 

comment on this subcategory. 

Therefore, the EPA is now soliciting 

comments on the non-continental liquid 

unit subcategory. The preamble to the 

final rule presents the rationale for the 

establishment of the subcategory. See 76 

FR 15635. The EPA also is proposing to 

revise several of the emission limits for 

non-continental liquid units due to the 

receipt of new emissions data for PM 

and CO from these units and the 

development of performance estimates 

based on the combustion of No. 6 fuel 

oil (rather than all types of liquid fuels). 

The rationale for estimating the 

performance of these units based on 

data from No. 6 oil units is presented 

below. Petitioners pointed out that noncontinental units do not combust 

distillate oil because of availability 

issues. While non-continental liquid 

units typically combust refinery gas, 

they combust residual oil when process 

requirements necessitate supplementing 

the available refinery gas. The 

petitioners requested that, in the 

absence of data from non-continental 

units, emission limits for noncontinental units be based on data from 

liquid units that combust residual oil. 

The EPA agrees that it would be 

appropriate to make this change for the 

combustion-based pollutants due to the 

design of these units and the unique 

constraints faced by these units. We 

now have data for both CO and PM from 

non-continental units, and there are no 

longer data gaps for these pollutants. We 

are thus able to establish numeric 

emission limits using data from within 

the subcategory. For fuel-based 

pollutants, Hg and HCl, the EPA 

determined that, based on the very 

limited data sets and the overlap of data 

for units designed to combust various 

liquid fuels, it is more appropriate to 

consider all liquid fuel-fired units 

together for the development of MACT 

emission limits. This is consistent with 

the treatment of Hg and HCl for solid 

fuel units. 

4. Liquid Units in Alaska. A petitioner 

requested that liquid units in Alaska be 

included in the non-continental liquid 

unit subcategory or in a separate, newly 

created subcategory for units in Alaska. 

The petitioner stated that units in 

Alaska face the same difficulties with 

respect to the available supply of 

natural gas or refinery gas as the noncontinental units. The commenter did 

not provide specific design differences 

from other types of liquid units. In 

addition, no test data are available for 

liquid-fired units in Alaska. Finally, 

while units in Alaska may face some 

unique constraints, the design of such 

units is different from the noncontinental units because the units are 

designed to combust different fuels (i.e. 

non-continental units combust No. 6 

fuel oil, which was not reported as a 

fuel for any unit in Alaska in the 

responses to the EPA’s information 

collection request). For these reasons, 

the EPA is not proposing a subcategory 

for liquid units in Alaska and is not 

including these units in the noncontinental subcategory. The EPA is, 

however, soliciting comment and 

supporting rationale on whether a 

subcategory for liquid units in Alaska is 

appropriate, and is requesting stack test 

data that could be used to establish 

MACT floors if such a subcategory is 

justified. 

5. Biomass. Petitioners requested 

additional biomass subcategories and 

clarifications to the final subcategories. 

Suggestions included separate 

subcategories (for all pollutants) for 

boilers that are designed to combust 

kiln-dried wood and for hybrid 

suspension grate boilers designed to 

combust bagasse, clarification of which 

subcategory covers pile burners, and 

separation of the dutch oven and 

suspension burner subcategories. In 

addition to soliciting comment on the 

proposed changes described below, the 

EPA is requesting comment on whether 

additional subcategories are 

appropriate, as well as data and 

rationale in support of any additional 

subcategories. 

a. Boilers Designed to Combust KilnDried Wood. With respect to a separate 

subcategory for boilers designed to 

combust kiln-dried wood, the EPA is 

proposing a separate subcategory for 

these units based on the design of the 

boilers and the unique nature of the 

facilities that combust this material. 

These facilities are carefully integrated 

to utilize their available resources onsite, and the boilers are designed and 

sized to efficiently combust biomass 

that has already undergone a drying 

process that enhances the fuel quality. 

Care is taken within the facility to 

maintain the fuel moisture content at 

levels far lower than virgin biomass 

materials, typically less than 2 percent 

moisture. The EPA is proposing 

emission limits for PM and CO for this 

subcategory of units that we are calling 

biomass dry stokers. For HCl and Hg, 

the final rule’s approach of regulating 

these pollutants under the ‘‘solid fuel 

subcategory’’ for all solid fuel units has 

not changed. 

b. Hybrid Suspension Grate Boilers 

Designed to Combust Bagasse. In the 

final rule, the EPA added a subcategory 

for hybrid suspension/grate boilers, 

which included boilers that are 

designed to combust very wet biomass 

fuels such as bagasse. The rationale for 

the establishment of the subcategory is 

presented in the preamble to the final 

rule. See 76 FR 15634–15635. 

Petitioners pointed out that in addition 

to their unique designs that provide fuel 

drying within the combustor, these 

units are highly integrated into the sugar 

production process and primarily 

combust specific materials that are 

generated on-site. Petitioners 

emphasized that the particle size profile 

from these units differs significantly 

from units designed to combust other 

types of fuels. As discussed in section 

V.C.1 of this preamble, the EPA is now 

considering PM to be a ‘‘combustion 

based’’ pollutant. Accordingly, the EPA 

is proposing emission limits for PM 

(along with an alternate TSM standard) 

and CO for these types of units. For HCl 

and Hg, the final rule’s approach of 

regulating these pollutants under the 


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‘‘solid fuel subcategory’’ for all solid 

fuel units has not changed. 

c. Clarification of Subcategories for 

Pile Burners, Dutch Ovens, and 

Suspension Boilers. The final rule did 

not address pile burners, and it 

established a single subcategory that 

covered dutch ovens and suspension 

boilers. Petitioners pointed out that 

dutch ovens and suspension boilers are 

inherently different types of boilers and 

requested EPA to create separate 

subcategories for those types of units. 

Petitioners also pointed out that pile 

burners are very similar to dutch ovens, 

and, as such, should be included in the 

dutch oven subcategory. The EPA 

evaluated these clarification requests 

and determined that the petitioners’ 

points regarding the design and other 

differences between dutch ovens and 

suspension boilers are valid. The EPA 

agrees that dutch ovens and pile burners 

should be included in the same 

subcategory and suspension burners 

should be a separate subcategory. 

Therefore, the EPA is proposing 

separate emission limits for the 

combustion-based pollutants for these 

subcategories. All of these types of units 

will remain in the solid fuel subcategory 

for the fuel-based pollutants. 

6. Gaseous Fuel Specification. 

Multiple petitioners requested 

reconsideration of the fuel specification 

that the EPA finalized but did not 

propose. Petitioners correctly pointed 

out that the levels of the fuel 

specification were based only on natural 

gas and suggested that it would be 

appropriate to base the fuel 

specification on levels of contaminants 

in either natural gas or refinery gas. 

Petitioners further pointed out that a 

fuel specification for hydrogen sulfide 

(H2S) is not directly related to potential 

HAP emissions from boilers and process 

heaters and the H2S fuel specification 

should be eliminated from the rule. The 

EPA has reexamined the fuel 

specification and agrees that the key 

contaminant for demonstration of 

comparability from a HAP perspective is 

Hg and that the H2S fuel specification 

that was finalized does not provide a 

direct indication of potential HAP from 

combustion of gaseous fuel. 

Accordingly, the EPA is proposing a 

fuel specification based only on the Hg 

level in the gaseous fuel, and that level 

is the same level that the EPA included 

in the March 2011 final rule. The 

rationale for the Hg fuel specification is 

included in the preamble to the final 

rule. See 76 FR 15639. 

One petitioner stated that the 

inclusion of a fuel specification 

demonstrates that emissions can be 

measured from the units that combust 

the gaseous fuels, and therefore, the 

units cannot be regulated by a work 

practice standard. Regarding this point, 

the EPA recognizes that the 

contaminants in the fuel may be able to 

be measured, but the resulting 

emissions from combustion of the fuel 

are another matter entirely. For 

instance, a unit that combusts a fuel that 

meets the fuel specification for Hg will 

have demonstrated that its fuel contains 

an amount of Hg that is comparable to 

that found in natural gas. The emissions 

data for natural gas-fired units show the 

overwhelming majority of emissions to 

be below the level that can be accurately 

quantified by the available test methods. 

Therefore, the same is expected of units 

combusting gases with similar 

contaminant levels to natural gas. Thus, 

a work practice standard is the 

appropriate standard for these units. 

The EPA also is requesting comment on 

whether additional parameters should 

be included in the fuel specification. 

7. Work Practices for Limited-Use 

Units. The EPA added a subcategory for 

limited-use units in the final rule, and 

petitioners requested an opportunity to 

comment on the creation of the 

subcategory and the definition of the 

subcategory. Specifically, multiple 

petitioners requested that rather than 

defining the subcategory to include 

units that operate less than 10 percent 

of the hours in a year, the EPA define 

the subcategory to include units that 

operate with a capacity factor of 10 

percent or less. The petitioners believe 

that such a change would provide more 

flexibility, but petitioners did not 

provide support that such a subcategory 

would qualify for work practice 

standards under section 112 the CAA. 

Therefore, the EPA is not proposing a 

change to the final approach but is 

requesting comment on how a 

subcategory defined with a 10 percent 

capacity factor would qualify for work 

practice standards in lieu of emission 

limits. The EPA also is requesting 

comment on the limited-use subcategory 

as finalized, and the rationale for the 

creation of that subcategory can be 

found in the preamble to the final rule. 

See 76 FR 15634. 

D. Monitoring 

1. Oxygen monitoring. Petitioners 

requested reconsideration of the 

requirement for installation of oxygen 

monitoring systems on the outlet of the 

boiler combustion chamber for 

numerous technical reasons. Several 

parties expressed concern regarding this 

location as it is known to be highly 

stratified, making it very difficult to find 

a representative location and certify the 

instrumentation. In reviewing 

alternatives to this requirement we find 

that rather than requiring monitoring of 

oxygen levels in the stack that follows 

a combustion unit, a better way to 

ensure good combustion is by requiring 

the installation, calibration, monitoring 

and use of oxygen trim systems to 

optimize air to fuel ratio and 

combustion efficiency. We agree with 

petitioners that use of the data from 

such devices is not only an appropriate 

control for efficient combustion and a 

less burdensome alternative to 

monitoring stack oxygen concentration 

but also is a better system for many 

types of units that experience significant 

load swings and operate with high 

levels of excess air. Many units are 

already fitted with these controls, and 

this proposed change will reduce the 

monitoring burden for affected units. 

These systems will provide adequate 

combustion control to maintain 

compliance with the CO emission levels 

demonstrated during the performance 

test. We seek comment on the 

appropriateness of using these controls 

operated as, and for the purposes, 

described. 

2. PM CEMS. Petitioners requested 

reconsideration of the use of PM CEMS 

as compliance monitors for coal, 

biomass and residual oil units with heat 

input capacity greater than 250 MMBtu/ 

hr. Petitioners emphasized that PM 

CEMS are not demonstrated for biomass 

units and requested EPA to remove the 

requirement because of technical issues 

related to PM particle size and the 

inability of PM CEMS effectively 

measure PM from biomass units. 

Petitioners also stated that PM CEMS 

are not demonstrated at the low levels 

that are required by the rule. The EPA 

agrees that PM CEMS are not 

demonstrated for biomass units and that 

significant technical concerns exist 

regarding the technology’s ability to 

monitor emissions from biomass units. 

The technical concerns include the fact 

that PM CEMS are calibrated and 

certified to measure emissions from a 

single fuel type. A change in fuel would 

require a change in the calibration curve 

of the PM CEMS instrument. The 

unpredictable variety of biomass fuel 

constituents as well as biomass fuel 

moisture content make relying on a 

single calibration point problematic in 

terms of compliance assessment when 

these fuel components change. 

Furthermore, it is impracticable to 

replicate, during performance testing, 

all of the varying fuel conditions 

necessary for calibrating the monitor. 

For all of these reasons, it is impractical 

to appropriately apply PM CEMS to 

provide the accuracy necessary for 


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compliance assessment. Accordingly, 

we are proposing to remove the PM 

CEMS requirement for biomass units. 

Relative to application for other boiler 

units, several parties expressed concern 

over the state of readiness of current PM 

CEMS technology, certification 

methodology and the technical effort 

and cost required for the recertification 

necessary to handle changing fuel and 

control operating conditions. In our 

reevaluation of this technology we find 

that PM monitoring technology would 

best be employed as parametric 

monitors (PM CPMS) and used to 

determine compliance with operating 

limits rather than emissions limits. This 

approach reduces the burden of 

certification of the monitor, which can 

be a substantial annual cost, and 

maintains our goals of seeking 

continuous data monitoring of the 

source particulate mass emission rate as 

a 30-day rolling average. We seek 

comment on the use of these monitors 

as described in the rule. 

3. CEMS Alternative for Hg. 

Petitioners requested reconsideration of 

the absence of an option to use Hg 

CEMS for compliance demonstration 

and monitoring for units subject to Hg 

limits whose operators do not want to 

rely on periodic testing, fuel sampling 

analysis, and parameter monitoring. We 

have included options in the proposed 

rule for the use of Hg CEMS. We seek 

comment on the use of these monitors 

as described in the rule. 

4. Use of sulfur dioxide (SO2) CEMS 

for demonstrating continuous 

compliance with HCl emission limits. A 

petitioner requested that the EPA 

consider adding a provision to the rule 

to allow for the use of SO2 CEMS for 

demonstration of continuous 

compliance with the HCl emission 

limits for sources that are equipped with 

acid gas controls. While the EPA does 

not have enough information to propose 

specific requirements, we believe that a 

reasonable approach would be to allow 

for the use of SO2 CEMS provided that 

the source demonstrates a correlation 

between SO2 control and control of 

other acid gases emitted from each 

specific unit that chooses to use SO2

CEMS. Such a relationship is expected 

because the available add-on controls 

for acid gases would provide better 

control efficiencies for the acid gas HAP 

than for SO2, and, therefore, 

demonstration of SO2 control using 

CEMS would provide assurance that the 

acid gas HAP are being controlled. 

Therefore, the EPA is soliciting 

comment on the use of SO2 CEMS for 

demonstrating continuous compliance 

with the HCl emission limits with the 

condition noted above. 

5. Minimum Data Availability 

Provisions. Petitioners noted that the 

requirement to operate any CMS and 

collect data at all times is unrealistic 

and that the agency should include a 

reasonable minimum data availability 

limitation allowing for CMS downtime. 

We have not included any specific 

minimum data availability requirement 

for CEMS or other monitoring in the 

final rule. We disagree with petitioners 

that we are establishing unreasonable 

monitoring operating requirements with 

this rule. Instead, we believe that we are 

reiterating the source owner’s 

responsibility to operate and maintain 

the CMS in accordance with existing 

rules. For example, section 63.8(c) 

already requires that the source operate 

the CMS consistent with good air 

pollution control practices and that the 

CMS be in continuous operation in 

accordance with a written quality 

control program. The final rule clarified 

that continuous operation does not 

include periods when the process is not 

operating and the requirements 

delineated in the rule otherwise mirror 

other existing requirements in the 

MACT general provisions. We do agree 

with petitioners that a CMS must 

undergo periodic system inspections, 

preventive maintenance, and parts 

replacements in order to continue good 

operation. It is clear that these events 

are among normal scheduled quality 

control events that would be included 

in the site-specific quality control 

program that is required under section 

63.8(d)(2)(iii) to which the source owner 

is subject. We also agree that such 

periods are to be categorized as 

exceptions to CMS data collection that 

are already allowed in the rule. Given 

the existing regulatory requirements and 

the clarifications in this rule about how 

to apply those requirements, we believe 

the rule provides allowances sufficient 

for CMS operational flexibility and are 

therefore not proposing any revisions on 

this issue. 

6. Averaging Times. The EPA has 

determined that a 30-day rolling average 

for parameter monitoring and 

demonstration of continuous 

compliance with operating limits is 

appropriate for this rule. This would be 

a change from the final rule, which 

generally included 12-hour block 

averages that corresponded to the 

expected length of the longest duration 

3-run emission test that was required to 

demonstrate initial compliance with the 

emission limits. The operating limits 

established through performance testing 

in this rule represent short term process 

and control operating conditions 

representative of compliance. Concerns 

of variability outside the operators 

control such as fuel content, seasonal 

factors, load cycling, and infrequent 

hours of needed operation prompted us 

to look at longer averaging periods on 

which to base operating compliance 

determination. We are aware from 

studies of emissions over long averaging 

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

average emissions for a operating in 

compliance will have a variability of 

about half of that represented by the 

results of short term testing. Given that 

short term tests are representative of 

distinct points along a continuum of 

that inherent operational variability, we 

believe it appropriate to propose 30-day 

averages in order to provide a means for 

the source operator to account for that 

variability by applying a long term 

average for establishing compliance. We 

expect more problematic control system 

variability (e.g., ESP transformer failure 

or scrubber venturi fan failure) to result 

in deviations from a 30-day average 

relative to compliance almost as much 

as for a shorter term average. 

E. Emission Limits 

1. Additional Data Received. The EPA 

received additional data from 

stakeholders and incorporated all of the 

data into the MACT database. The new 

data include 36 Hg test runs, 168 p.m. 

test runs, 24 dioxin/furan test runs, 133 

CO test runs, 63 HCl test runs, and 22 

TSM test runs. In addition to the stack 

test data, the EPA received fuel analyses 

for 3 facilities and over 51,000 hours of 

CO CEMS data from 3 facilities. Finally, 

stakeholders submitted corrections to 

data and to descriptions of combustion 

units. We have incorporated these 

corrections into the project database. 

For details on the new data and data 

corrections, see the memorandum in the 

docket entitled ‘‘Revised Handling and 

Processing of Corrections and New Data 

in the EPA ICR Databases (October 

2011).’’ 

2. Quality Assurance Activities on 

Best Performers. The EPA requested 

copies of all of the emission test reports 

for the best performing units in each 

subcategory in order to perform 

additional quality assurance. These test 

reports document the test results for the 

summary test data that were submitted 

to the EPA as part of the EPA’s Phase 

1 information collection request. This 

review resulted in multiple changes to 

data and invalidation of some emission 

tests. Overall, this effort improved the 

quality of the data provided by industry. 

For details on the quality assurance 

effort, see the memorandum in the 

docket entitled ‘‘Data Quality Review of 

Best Performers for PM, Hg, HCl, CO, 

and Dioxin/Furan Emissions from ICI 


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2American Society of Mechanical Engineers, 

Reference Method Accuracy and Precision 

(ReMAP): Phase 1, Precision of Manual Stack 

Emission Measurements, CRTD Vol. 60, February 

2001. 

Boilers and Process Heaters at Major 

Sources of HAP (October 2011).’’ 

3. Incorporation of Minimum 

Detection Levels and Measurement 

Imprecision. In developing the final 

rule, the EPA incorporated procedures 

to ensure that the available 

measurement methods would provide 

accurate emissions measurements at the 

levels set for the various standards. The 

preamble to the final rule described 

these procedures, but stakeholders did 

not have an opportunity to comment on 

them. The EPA has made minor 

adjustments to the methods used to 

account for measurement imprecision 

and presents the rationale in the 

following paragraphs. We are soliciting 

comment on the procedures described 

below. 

Test method measurement 

imprecision is a contributor to the 

variability of a set of emissions data. 

One element is associated with method 

detection capabilities, and a second is a 

function of the measurement value. 

Measurement imprecision is 

proportionally highest for values 

measured below or near a method’s 

detection level; measurement 

imprecision proportionally decreases for 

values measured above the method 

detection level. The probability 

procedures applied in calculating the 

floor or an emission limit inherently 

and reasonably account for emissions 

data variability, including measurement 

imprecision, when the database 

includes multiple tests from multiple 

emissions units for which all data are 

measured significantly above the 

method detection level. This is less true 

when the database includes emissions 

occurring below method detection 

capabilities that are reported as the 

method detection level values. 

The EPA’s guidance to data collection 

respondents for reporting pollutant 

emissions specified the criteria for 

determining test-specific method 

detection levels. Under those criteria, 

about a 1 percent probability of an error 

exists that a pollutant measured at the 

method detection level is present when 

in fact it is absent. Such a probability is 

also called a false positive or the alpha, 

Type I, error. Because of sample and 

emissions matrix effects, laboratory 

techniques, sample size, and other 

factors, method detection levels 

normally vary from test to test for any 

specific test method and pollutant 

measurement. The expected 

measurement imprecision is 50 percent 

or greater. Pollutant measurement 

imprecision decreases to a consistent 

relative 10 to 15 percent for values 

measured at a level about three times 

the method detection level.2 Also in 

accordance with our guidance, source 

owners identified emissions data which 

were measured below the method 

detection level and reported those 

values as equal to the method detection 

level as determined for that test. One 

effect of reporting data in this manner 

is that the resulting database is 

somewhat truncated at the lower end of 

the measurement range (i.e., no values 

reported below the test-specific method 

detection level). A floor or emissions 

limit that is based on a truncated 

database or otherwise includes values 

measured near the method detection 

level may not adequately account for the 

effects of measurement imprecision on 

the data variability. 

We applied the following procedures 

to account for the effect of measurement 

imprecision associated with a database 

that includes method detection level 

data. In response to the comments and 

internal concerns about the quality of 

measurements at very low emissions 

limits especially for new sources, we 

revised the procedure for identifying a 

representative detection level (RDL). 

The procedure for determining an RDL 

starts with identifying all of the 

available reported pollutant specific 

method detection levels for the best 

performing units regardless of any 

subcategory (e.g., existing or new, fuel 

type, etc.). From that combined pool of 

data, we calculate the arithmetic mean 

value. By limiting the data set to those 

tests used to establish the floor or 

emissions limit (i.e., from the best 

performers), the result also represents 

the best performing testing companies 

and laboratories, and data from 

underperforming laboratories are 

effectively removed from the floor 

analysis. The outcome should minimize 

the effect of a test(s) with an 

inordinately high method detection 

level (because, for example, the sample 

volume was too small, the laboratory 

technique was insufficiently sensitive, 

or the procedure for determining the 

detection level was other than that 

specified). We then call the resulting 

mean of the method detection levels as 

the RDL as characteristic of accepted 

source emissions measurement 

performance. 

The second step in the process is to 

calculate three times the RDL to 

compare with the calculated floor or 

emissions limit. This step is similar to 

what have used before including for the 

Portland cement MACT determination. 

We use the multiplication factor of three 

to approximate a 99 percent upper 

confidence interval for a data set of 

seven or more values. For comparing to 

the floor, if three times the RDL were 

less than the calculated floor or 

emissions limit (e.g., calculated from the 

upper prediction limit (UPL)), we would 

conclude that measurement variability 

was adequately addressed. The 

calculated floor or emissions limit 

would need no adjustment. If, on the 

other hand, the value equal to three 

times the RDL is greater than the UPL, 

we would conclude that the calculated 

floor or emissions limit does not 

account entirely for measurement 

variability. In this situation, we 

substituted the value equal to three 

times the RDL for the calculated floor or 

emissions limit. 

We determined the RDL for each 

pollutant using data from tests of all the 

best performers for all of the final 

regulatory subcategories (i.e., pooled 

test data). We applied the same 

pollutant-specific RDL and emissions 

limit adjustment procedure to all 

subcategories for which we established 

emissions limits. We believe that 

emissions limits adjusted in this manner 

better ensure that measurement 

variability is adequately addressed 

relative to compliance determinations 

than did the procedure applied for 

calculations in the June 4, 2010, 

proposed rule that may have been based 

on data sets smaller than seven tests and 

as few as one test. We also believe that 

the emissions testing procedures and 

technologies available now and in the 

future will be adequate to provide the 

measurement certainty sufficient for 

sources to demonstrate compliance at 

the levels of the adjusted emissions 

limits. 

4. CO CEMS-Based Alternative 

Emission Limits and Monitoring. As an 

alternative to CO stack testing and 

oxygen monitoring, we are proposing a 

compliance option that allows the use of 

CO CEMS. Some petitioners noted that 

some affected sources currently use CO 

CEMS and that installing additional 

monitoring equipment should not be 

required if a unit elects to comply using 

existing CO CEMS equipment. In 

addition, petitioners stated that due to 

the highly variable nature of CO 

emissions, an emission limit based on 

CO CEMS data from boilers over time 

would more adequately capture the true 

variability in CO emissions over various 

operating conditions. In response to 

these requests, the EPA has calculated a 

CO CEMS-based MACT floor for each 

subcategory for which data were 

available. Facilities would have the 

option to comply with the alternative 


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CO CEMS-based limits through 

monitoring with CO CEMS. Through the 

Section 114 Information Collection 

Requests and additional voluntary data 

submittals, a limited amount of CEMS 

data was available to compute CO CEMS 

limits. Most sources that reported CEMS 

data had 30 days of data either reported 

as hourly or daily averages. Given this 

limited length of time, we selected a 10- 

day rolling averaging period in order to 

allow us to compute multiple data 

points from each source’s dataset. If 

sources reported CEMS data on both an 

hourly and daily average basis, we first 

computed daily averages from the 

hourly data. Next, we combined the two 

datasets, sorted the data in sequential 

calendar data order and computed a 

series of 10-day rolling averages from 

each unit. CEMS data on a 10-day 

rolling average basis could be calculated 

for the following subcategories: 

fluidized bed units designed to burn 

coal/solid fossil fuel, pulverized coal 

boilers designed to burn coal/solid fossil 

fuel, stokers designed to burn coal/solid 

fossil fuel, dutch ovens/pile burners 

designed to burn biomass/bio-based 

solids, fluidized bed units designed to 

burn biomass/bio-based solids, hybrid 

suspension grate boiler designed to burn 

biomass/bio-based solids, stokers/ 

sloped grate/others designed to burn 

wet biomass fuel, suspension burners 

designed to burn biomass/bio-based 

solids and units design to burn heavy 

liquids. CO CEMS data on a 10-day 

rolling average basis data were not 

available for the fuel cell units designed 

to burn biomass/bio-based solids, 

biomass dry stoker units, and units 

designed to burn gas 2 (other) gases. 

Alternate CO CEMS-based limits are not 

being proposed for these units, but if 

data are provided for those 

subcategories prior to March 1, 2012, 

those data will be considered for use in 

the final rule. A very limited amount of 

CEMS data were available from units 

designed to burn light liquid fuel and 

units designed to burn liquid fuel 

located in non-continental States and 

territories, but not enough data points 

were available to compute a 10-day 

rolling average. We do have data 

sufficient to develop CO CEMS-based 

limits on a 1-day block average basis for 

light liquid units and a 3-hour rolling 

average basis for non-continental liquid 

units, as discussed below. If sufficient 

additional data are provided by March 

1, 2012, the EPA will consider adjusting 

the averaging times similar to the other 

emission limits. 

In most cases, only one or two units 

in each subcategory have CO CEMS data 

available. The memorandum ‘‘CO CEMS 

MACT Floor Analysis (October 2011) for 

the Industrial, Commercial, and 

Institutional Boilers and Process Heaters 

National Emission Standards for 

Hazardous Air Pollutants—Major 

Source’’ provides a complete breakdown 

of the CO CEMS data that were 

available. The EPA is requesting the 

submittal of additional CO CEMS data 

to achieve a more robust dataset for the 

purposes of revising the CO CEMS 

MACT floor calculations. Please provide 

your dataset in an electronic 

spreadsheet or database format with the 

data reduced to hourly CO averages 

reported as ppmvd. You should include 

the oxygen associated with each 

measurement or report the data at a 

standardized oxygen concentration, 

preferably adjusted to 3 percent oxygen. 

The EPA is expecting to receive 

additional CEMS data before the final 

rule and to incorporate those data if 

received in time. The data will likely 

change the CO CEMS floors, and may 

also result in different averaging times, 

depending on the extent of the data. 

In order to identify the dataset that 

would be used to compute a CO CEMS 

MACT floor emission limit, the EPA 

first identified all of the units identified 

as best performers based on their 

reported stack test results that had 10- 

day rolling average CO CEMS data 

available. Refer to the memo ‘‘Revised 

MACT Floor Analysis (October 2011) for 

the Industrial, Commercial, and 

Institutional Boilers and Process Heaters 

National Emission Standards for 

Hazardous Air Pollutants—Major 

Source,’’ for more information on how 

the best performing CO stack tests were 

identified for each subcategory. 

However, there was very little overlap 

in the number of best performing units 

that had both stack test and CO CEMS 

data available. After comparing the data, 

only three subcategories would have 

best performing units with both stack 

test and applicable CEMS data. Given 

these data gaps, we opted to rank CO 

CEMS data based on each units 

minimum 10-day rolling average CO 

CEMS value and then determining the 

best performers for each subcategory. 

For the three subcategories where we 

have CEMS data for units that are part 

of the stack test-based MACT floors, we 

included the CEMS data from those 

units in the CEMS-based floors because 

those units are demonstrated best 

performers for CO. We discuss two 

exceptions below, where the data did 

not allow the use of a 10-day averaging 

period. Within each subcategory, we 

ranked the minimum 10-day rolling 

averages from lowest to highest to 

determine the best performing 12 

percent. Then, we identified any best 

performers based on the CO stack test 

data that provided CO CEMS data, and 

we included those data in the MACT 

floor pool. Next, we used all of the daily 

averages from the best performing units 

to compute a MACT floor based on a 99 

percent UPL. 

For the units designed to burn light 

liquid fuels, the data were insufficient 

to calculate 10-day rolling averages. 

Based on the available data, the 

averaging basis selected was 1 day. For 

the units designed to burn liquid fuel in 

the non-continental liquid units 

subcategory, the data were insufficient 

to calculate 10-day rolling averages. 

Based on the available data, the 

averaging basis selected was 3 hours for 

non-continental liquid units. Only one 

of the non-continental boilers submitted 

CO CEMS data, with a total of 24 hourly 

averages. In this case, we used each of 

the hourly averages from this unit to 

compute a MACT floor based on a 99 

percent UPL. The EPA is aware that the 

averaging time selection and whether 

rolling or block averaging is selected 

impacts the UPL calculation and ability 

to demonstrate compliance. We believe 

that the averaging times selected for this 

proposal are reasonable and note that, to 

some extent, they are dictated by the 

limited datasets. The EPA is requesting 

comment on the most appropriate 

averaging time (e.g., hourly, daily) and 

length of rolling period (e.g., 10-day, 30- 

day) to use when calculating the CO 

CEMS MACT floors and requests 

specific discussion and new data to 

support your comments. The length of 

the averaging time will be affected by 

the available data in each subcategory. 

The EPA also is requesting comment on 

the approach used to calculate the UPLbased MACT floors. 

Ranking the dataset according to the 

minimum 10-day rolling average does 

not necessarily correlate with the 

ranking used to identify the best 

performing 12 percent of units with CO 

stack test data used to calculate the 

stack test-based floors for CO. Separate 

sets of units in the stack test and CEMS 

data sets create the possibility of 

incongruent results between the two 

compliance options. To evaluate 

whether our selection of the units 

identified as best performers for CO 

CEMS data correlates to the units 

identified as best performers for stack 

test data, we compared the CEMS data 

and the computed stack test CO MACT 

floor for each subcategory. Each unit 

identified as a best performing unit in 

the CO CEMS analysis had at least one 

3-hour CEMS average at or below the 

corresponding stack test CO MACT floor 

for the subcategory, which suggests that 


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the units identified as best performers 

based on the CEMS data are comparable 

to the units identified as best performers 

based on the stack test data. The EPA 

specifically requests comment on the 

ranking methodology which should be 

used, with discussion on whether CO 

CEMS best performers should be 

selected from units also identified as 

best performers from their stack test 

data, or if a value other than the 

minimum 10-day rolling average should 

be used as the basis for ranking the data. 

Given the limited data available, the 

proposed new source CO CEMS floors 

are similar to existing source floors 

since the existing source CO CEMS UPL 

for each subcategory was determined 

using data from a single unit, with two 

exceptions. The fluidized bed units 

designed to burn biomass/bio-based 

solids and stokers/sloped grate/others 

designed to burn wet biomass fuel each 

have two units in the existing source 

floor calculations, whereas the new 

source floor would be based on the 

single best performer. In the case of wet 

biomass stoker/sloped grate/other, the 

computed new source floor would be 

higher than the existing source, so the 

value reverts to the existing source 

value. 

The 99 percent UPL calculations for 

CO CEMS used the following statistical 

formula: 

Where: 

n = the number of daily averages (or hourly 

averages for non-continental units) 

m = the number of test runs in the 

compliance average 

In this case, m equals 10 given the 10- 

day rolling average compliance period 

for all subcategories except for noncontinental liquid, where m equals 3 for 

the 3-hour averaging period. Similar to 

previous analysis of the distribution of 

the dataset for stack test data MACT 

floor calculations, the distribution of 

each CEMS dataset was classified as 

either a normal distribution or lognormal distribution. In the case of the 

CEMS datasets from each of the best 

performers, the datasets were each lognormally distributed. See the ‘‘CO 

CEMS MACT Floor Analysis (November 

2011) for the Industrial, Commercial, 

and Institutional Boilers and Process 

Heaters National Emission Standards for 

Hazardous Air Pollutants—Major 

Source’’ for further details about the 

calculations. 

For each subcategory the analysis 

showed that the datasets were 

lognormally distributed. Given the 

rolling-average compliance metric, 

many of the datasets also exhibit 

varying degrees of autocorrelation. 

Autocorrelation describes the 

correlation between values of the 

process at different points in time. 

Although the UPL calculation is affected 

by autocorrelation, no adjustments were 

made to incorporate autocorrelation in 

this dataset. Depending on the final 

compliance metric selected, EPA may 

adjust the dataset for the promulgated 

rule to better address autocorrelation. 

The EPA is requesting comment on 

incorporating autocorrelation into the 

analysis. 

The EPA considered, but is not 

proposing, an additional final step for 

establishing the CO CEMS-based floors. 

When we compared the performance of 

the units in the top half of the MACT 

floor pool (usually a single unit) to the 

UPL-based floor level, it was revealed 

that the calculated UPL-based floor level 

resulted in the best performing units in 

some subcategories not meeting the 

limit up to about 25 percent of the time. 

The following final step in the floor 

setting process for CEMS-based limits 

could be used to adjust the CO CEMSbased limits to reflect the level achieved 

at all times by the best performing 

sources (i.e., the top half of the MACT 

floor units). In those instances where 

the best 6 percent of units did not meet 

the calculated limit at all times, the 

limit was adjusted to reflect the actual 

level that was demonstrated to be 

achieved at all times by those units (the 

highest 10-day, 1-day, or 3-hour average, 

as applicable, from the best 6 percent of 

units). The CO CEMS-based emission 

limits based on this approach are shown 

in Table 2 of this preamble. The EPA is 

requesting comment on whether this 

final step is appropriate for developing 

CO CEMS-based MACT floors for boilers 

and process heaters. 

TABLE 2—ALTERNATIVE APPROACH CO CEMS-BASED EMISSION LIMITS FOR BOILERS AND PROCESS HEATERS

Subcategory 

Alternate CO 

CEMS limit, 

(ppm @3% oxygen) 

New and Existing—Coal Stoker .................................................................................................................................................. 34 

New and Existing—Coal Fluidized Bed ....................................................................................................................................... 78 

New and Existing—Coal-Burning Pulverized Coal ...................................................................................................................... 35 

New and Existing—Biomass Wet Stoker/Sloped Grate/Other .................................................................................................... 920 

New and Existing—Biomass Kiln-Dried Stoker/Sloped Grate/Other .......................................................................................... (1) 

New and Existing—Biomass Fluidized Bed ................................................................................................................................ 480 

New and Existing—Biomass Suspension Burner ....................................................................................................................... 2,300 

New and Existing—Biomass Dutch Ovens/Pile Burners ............................................................................................................ 440 

New and Existing—Biomass Fuel Cells ...................................................................................................................................... (1) 

New and Existing—Biomass Hybrid Suspension Grate .............................................................................................................. 1,400 

New and Existing—Heavy Liquid ................................................................................................................................................ 18 

New and Existing—Light Liquid ................................................................................................................................................... 60 

New and Existing—non-Continental Liquid ................................................................................................................................. 120 

New and Existing—Gas 2 (Other Process Gases) ..................................................................................................................... (1) 

1 No data. 


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F. MACT Floor Methodology 

1. Standards for Dioxin/Furans. 

Petitioners requested that EPA revise 

the procedure used to calculate the final 

emission limits for dioxin/furans, with 

the primary issue being the low levels 

and how detection limits should be 

considered. The EPA re-assessed the 

lowest level that can be accurately 

measured for dioxin/furan emissions 

from boilers and process heaters. When 

we compared those levels to the levels 

of emissions from all of the units that 

had test data available, we found that 

for all subcategories of units, emissions 

were below the value that can be 

accurately measured. Details on the 

establishment of the level that can be 

accurately measured are provided in the 

docket memorandum entitled: Updated 

data and procedure for handling below 

detection level data in analyzing various 

pollutant emissions databases for MACT 

and RTR emissions limits. As discussed 

in section V.A.2 of this preamble, the 

EPA is now proposing to regulate 

dioxin/furan emissions with a work 

practice standard in lieu of numeric 

emission limits. 

2. Filling Data Gaps for NonContinental Liquid Units. The EPA 

included numeric emission limits for 

non-continental liquid units in the final 

rule. However, data were not available 

for all of the regulated pollutants, and 

EPA relied on the MACT floors for 

liquid units to establish some of the 

emission limits. Petitioners requested 

that in cases where data gaps exist, a 

more appropriate substitution would be 

to establish floors based on units that 

combust No. 6 fuel oil, which is the fuel 

that the non-continental units are 

designed to combust. While the EPA 

agrees that for estimating emission from 

these units, use of data from No. 6 oilfired units may be appropriate even 

though some design differences have 

been identified (see FR 76 15635, March 

21, 2011), we are proposing a different 

approach for setting emission limits for 

non-continental liquid units. Additional 

data were submitted to EPA for PM and 

CO from non-continental units, and the 

proposed PM and CO limits are based 

on these data from within the 

subcategory. For HCl and Hg, which are 

considered fuel-based pollutants that 

are not dependent on combustor design, 

the EPA is proposing to base limits for 

all liquid units on the entire data set 

from liquid-fired units. The currently 

available data and information do not 

indicate that Hg and HCl should be 

considered separately for liquid units 

designed to combust various types of 

liquids, and we therefore are proposing 

Hg and HCl emission limits that are 

based on the available data for all liquid 

units. The EPA requests comment on 

this approach, and to the extent that 

other approaches are suggested, the EPA 

requests data and rationale to support 

any suggested alternative approaches. 

3. Selection of Confidence Level for 

CO. In the final rule, the EPA selected 

the use of a 99.9 percent confidence 

interval for calculating the MACT floor 

for CO emissions. A petitioner requested 

reconsideration of this selection given 

the fact that the EPA used a 99 percent 

confidence interval for all of the other 

emission limits in the final rule. The 

petitioner pointed out that if the data 

are highly variable, the 99 percent 

confidence interval should adequately 

reflect the variability of emissions as 

well as for the data sets for other 

pollutants. In the development of the 

final rule, the 99.9 percent confidence 

interval was selected in part because the 

standards covered periods of startup 

and shutdown, while the data did not 

reflect CO emissions during those 

periods. While the EPA finalized work 

practice standards for startup and 

shutdown periods, the selection of the 

confidence interval was not revisited 

due to time constraints. The EPA is now 

proposing to use a 99 percent 

confidence interval in order to maintain 

a consistent methodology with the 

development of the MACT floors for 

other pollutants, and because optional 

CO CEMS-based limits are being 

proposed that would allow sources 

additional flexibility in meeting the 

requirements of the rule. 

G. Tune-Up Work Practices 

1. Requirements for Small and 

Limited-Use Units. Petitioners requested 

that the EPA reconsider the tune-up 

work practices for a subset of very small 

units. Specifically, petitioners requested 

that small natural gas- and light oil-fired 

units (petitioners defined ‘‘small’’ at 

various levels between 2 MMBtu/hr and 

10 MMBtu/hr) be exempted from the 

rule. While the EPA disagrees that small 

units should be exempt from the rule, 

the EPA agrees that for the smallest 

natural gas-, refinery gas, other clean gas 

(that meets the fuel specification) and 

light liquid-fired units, decreased tuneup frequency is appropriate. The large 

number of small units that can be 

located at an individual facility, 

particularly an institution, provides 

logistical issues with completion of 

tune-ups on an annual basis. For 

instance, one institution has over 700 

identical small natural gas-fired units 

that would, under the final rule, each be 

subject to a biennial tune-up 

requirement. We are proposing to 

change that requirement for natural 

gas-, refinery gas, other clean gas (that 

meets the fuel specification) and light 

liquid-fired units equal to or less than 

5 MMBtu/hr to a tune-up once every 5 

years, with the initial tune-up required 

by the compliance date and subsequent 

tune-ups being required at intervals no 

greater than 5 years from the previous 

tune-up. 

2. Clarifications of Certain Tune-up 

Provisions. Petitioners requested several 

changes to the tune-up requirements 

and timing of completing the various 

aspects of tune-ups. The issues and the 

EPA’s proposed responses, are 

presented in the following paragraphs. 

First, petitioners questioned the 

requirement that burner inspections 

(part of the tune-up) must be completed 

at least once every 36 months, even if 

this requirement causes a unit to be shut 

down that otherwise would not have 

been. The EPA agrees that the burner 

inspection should not cause units to 

shut down and is proposing to remove 

the ‘‘every 36 months’’ requirement. 

Instead, we are proposing that burner 

inspections that cannot be completed 

during a tune-up can be delayed until 

the next scheduled shutdown. 

Second, petitioners requested that CO 

adjustments that are required as part of 

a tune-up be allowed to be completed 

within 30 days of the tune-up in order 

to allow for multiple adjustments and 

optimization of CO emissions. The EPA 

agrees that this is a reasonable change 

and is proposing to allow 30 days from 

the date the tune-up is completed. 

Third, the EPA included a burner 

inspection requirement that is difficult 

or impossible for certain units to meet. 

The EPA is proposing to clarify this 

provision so as not to require a physical 

inspection that cannot reasonably be 

completed. 

3. Conducting Initial Tune-ups at New 

Sources. Petitioners requested that the 

EPA clarify the timing of tune-ups with 

respect to the compliance dates for 

existing and new sources. For new 

units, the EPA recognizes that, as 

petitioners pointed out, units are 

generally tuned as part of installation, 

but a learning curve exists for how to 

most efficiently operate new units. 

Accordingly, the EPA is proposing that 

the initial tune-up after startup must be 

completed within one year of startup. 

H. Energy Assessment 

1. Scope. Petitioners requested that 

the EPA clarify the scope of the energy 

assessment. Specifically, petitioners 

requested that the scope be clearly 

limited to only those energy use systems 

that are located on-site and associated 

with the affected boilers and process 

heaters. The final definition for ‘‘Energy 


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use system’’ was intended only to list 

examples of potential systems that may 

use the energy generated by affected 

boilers and process heaters. We did not 

intend that the energy assessment 

would include energy use systems using 

electricity purchased from an off-site 

source. We also did not intend that the 

energy assessment include energy use 

systems located off-site. We are 

proposing to revise the definition of 

‘‘Energy assessment’’ to clarify our 

intent. 

2. Compliance Date. Petitioners 

requested that the EPA clarify the due 

date of the energy assessment. All 

emission standards must be met by the 

compliance date, even if compliance 

demonstrations are sometimes allowed 

after the compliance date. In order to 

meet the requirements of the rule, 

energy assessments must, therefore, be 

completed by the compliance date for 

existing sources. 

3. Maximum Duration Requirements. 

Petitioners requested that the EPA 

reconsider the stated ‘‘maximum time’’ 

to conduct the energy assessment 

because the maximum times were not 

included in the proposal, and 

stakeholders had no opportunity to 

comment. The concern raised by 

petitioners is that, as the final definition 

of ‘‘Energy assessment’’ is worded, a 

deviation and a potential violation 

could occur if the energy assessment 

effort exceeds these time limits. Our 

intent for including the ‘‘maximum 

time’’ in the final rule definition was to 

minimize the burden on the smaller fuel 

use facilities, many of which are likely 

small entities, by limiting the extent of 

the energy assessment. Our concern was 

that if there was no time limit, these 

small facilities would have no means to 

limit the time/effort of an outside energy 

assessor that is contracted to perform 

the energy assessment. We have revised 

the definition of ‘‘Energy assessment’’ to 

change the maximum time from 1 day 

to 8 technical hours and from three days 

to 24 technical hours. This would allow 

sources to perform longer assessments at 

their discretion. 

I. Affirmative Defense Provisions During 

Malfunctions 

The EPA finalized affirmative defense 

provisions for malfunctions. As part of 

this reconsideration proposal, we are 

soliciting comments on the affirmative 

defense provisions that were included 

in the final rule. The rationale for the 

affirmative defense provisions is 

provided in the preamble to the final 

rule. See 76 FR 15642. 

J. Work Practices During Startup and 

Shutdown 

1. Work Practices. The EPA finalized 

a work practice standard for periods of 

startup and shutdown that requires 

facilities to minimize emissions 

consistent with manufacturers’ 

recommended procedures. Petitioners 

requested that the EPA clarify whether 

the requirement applies to the boiler or 

the control device manufacturer. The 

EPA is proposing to amend the work 

practice standard so that manufacturers’ 

recommended procedures are no longer 

referenced, although the EPA expects 

that facilities will follow such 

procedures for both the boiler system 

and any air pollution control devices. 

The EPA is proposing to amend the 

work practice standard as described in 

section III.E of this preamble. The 

rationale for justifying work practice 

standards for periods of startup and 

shutdown is described in the preamble 

to the final rule. See 76 FR 15642. 

Additionally, we do not have emissions 

data for startup and shutdown periods 

sufficient to establish numeric 

emissions standards for these periods. 

The only available data is limited CO 

emissions data, which is unlikely to 

reflect actual emissions of the best 

performing units during startup and 

shutdown. The rationale for the 

proposed changes to the work practice 

standard is discussed below. The EPA is 

now proposing to define startup and 

shutdown periods and is proposing 

more specific requirements than those 

in the final rule. The definitions of 

startup and shutdown would provide 

clarity regarding which periods of 

operation are subject to the work 

practice standards rather than numeric 

emission limits and the associated 

requirements. The proposed definitions 

specify that only the periods of time 

between a complete shutdown of a unit 

(no fuel being combusted) and the time 

that a unit first reaches 25 percent load 

qualify as startup, and only the periods 

of time between the time that a unit last 

reaches 25 percent load and the time 

when a unit is completely shut down 

(no fuel being combusted) qualify as 

shutdown. These definitions are 

intended to ensure that units cannot 

cycle in and out of startup or shutdown. 

The EPA recognizes that it may be 

necessary to establish a maximum time 

period to ensure that units cannot 

operate in startup or shutdown mode for 

extended periods of time, and is 

soliciting comment on the appropriate 

time period or time periods for the 

various unit designs. The EPA believes 

that a work practice standard that 

applies during such periods should 

require more than a general duty to 

reduce emissions, which is essentially 

what was required in the final rule. 

General duty requirements do not 

constitute appropriate work practice 

standards under section 112(h). We are 

soliciting comment on the rationale for 

work practice standards during periods 

of startup and shutdown as well as the 

proposed work practice standard and 

the rationale for proposing changes to 

the standard. We also are soliciting 

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. Because the EPA did not 

propose work practice standards for 

startup and shutdown periods in the 

June 4, 2010, proposed rule, members of 

the public did not have the opportunity 

to comment on those standards or the 

rationale for the standards prior to 

issuance of the final rule. 

2. Operating Parameters and Opacity 

Limits. Petitioners requested that EPA 

clarify that the operating limits and 

opacity limits do not apply during 

periods of startup and shutdown. 

Having finalized work practice 

standards for these periods of time, EPA 

agrees that the requested clarification is 

what was intended in the final rule. 

K. Applicability 

1. Exemption for Units Serving as 

Control Devices. In the final rule, the 

EPA exempted any boiler or process 

heater that is used as a control device 

to comply with another subpart of part 

63, provided that at least 50 percent of 

the heat input to the boiler is provided 

by the gas stream that is regulated under 

another subpart. Petitioners requested 

that EPA extend the exemption to units 

that serve as control devices for EPA 

standards issued under parts 60 or 61 of 

the CAA. We recognize that part 61 is 

another part relevant to the NESHAP 

program and should be treated the same 

as the exemption provided for part 63. 

Although part 60 does not regulate HAP, 

the EPA does want to continue to use 

combustion controls for organic 

pollutants that part 60 addresses, as it 

provides a pollution prevention strategy 

and reduces the need for facilities to 

install other combustion equipment to 

serve as dedicated control devices for 

NSPS and NESHAP regulated gas 

streams (e.g., thermal oxidizers and 

flares). In addition, many of the 

potential add-on combustion 

technologies do not recover energy, and 

the resulting combustion using these 

technologies would emit approximately 

the same level of contaminants as a 

boiler without the added benefit of 


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energy recovery. Therefore, the EPA is 

now proposing to exempt any boiler or 

process heater that is used as a control 

device to comply with standards issued 

under part 60, part 61, or part 63 of the 

CAA, provided that at least 50 percent 

of the heat input to the boiler is 

provided by a gas stream that is subject 

to standards under those parts. 

2. Waste Heat Boilers and Process 

Heaters. Petitioners requested that the 

EPA clarify that waste heat process 

heaters, like waste heat boilers, are not 

subject to the standards. Petitioners are 

correct that the EPA intended to exempt 

waste heat process heaters from the rule, 

and the EPA is amending the definition 

of process heater to exclude waste heat 

process heaters. We also are clarifying 

that waste heat boilers and process 

heaters can include supplemental 

burners as long as those burners 

combust only Gas 1 fuels, up to 50 

percent of their heat input. 

3. Units Firing Comparable Fuels. 

Petitioners requested that the EPA 

clarify whether boilers and process 

heaters burning comparable fuels, as 

defined under the Resource 

Conservation and Recovery Act (RCRA), 

are subject to the NESHAP for 

industrial, commercial, and institutional 

boilers and process heaters. Section 

261.38 states that hazardous secondary 

materials (i.e., spent materials, sludges 

and byproducts) that have fuel value 

and whose hazardous constituent levels 

are comparable to those found in fuel oil 

that could be burned in their place are 

not solid wastes and hence not 

hazardous wastes under Subtitle C of 

RCRA. These materials are called 

comparable fuels. Since comparable 

fuels are not hazardous waste, boilers 

and process heaters burning comparable 

fuels are not subject to the NESHAP for 

hazardous waste combustors (part 63, 

Subpart EEE), which includes boilers 

and process heaters that burn RCRA 

hazardous waste. Therefore, boilers and 

process heaters burning comparable 

fuels are covered by the NESHAP for 

industrial, commercial, and institutional 

boilers and process heaters. 

4. Residential Unit Exemption. During 

the initial phases of implementation of 

the area source boiler rule, stakeholders 

requested clarification from the EPA on 

the applicability of the area source rule 

to residential boilers, particularly those 

units at individual residences located at 

institutional facilities. The EPA’s intent 

was not to cover such units, and during 

reconsideration, the EPA is amending 

the area source rule accordingly. 

Similarly, the final major source rule 

could be interpreted to cover residential 

boilers at large institutions, which was 

not the intent of the rule. Accordingly, 

the EPA is proposing to exempt 

residential boilers from the rule and is 

proposing the following definition of 

residential boiler to the major source 

rule: Residential boiler means a boiler, 

used in a dwelling containing four or 

fewer family units, to provide heat and/ 

or hot water. This definition includes 

boilers used primarily to provide heat 

and/or hot water for a dwelling 

containing four or fewer families located 

at an institutional facility (e.g., 

university campus, military base, 

church grounds) or commercial/ 

industrial facility (e.g., farm). 

L. Compliance 

1. Extending Compliance Dates. On 

May 18, 2011, the EPA issued a stay of 

the effective date of the final rule. The 

EPA is proposing several revisions to 

the standards in this rule. As such, we 

are proposing to revise the compliance 

date for existing sources to three years 

after the date of publication of the final 

reconsideration rule. This date is being 

proposed in order to enable facilities 

sufficient time to install controls and 

make compliance-related decisions. For 

new sources, the EPA is proposing that 

the compliance date is 60 days after the 

date of publication of the final 

reconsideration rule, or upon startup, 

whichever is later. This date assumes 

that the final reconsideration rule will 

be subject to the Congressional Review 

Act, which will delay the effective date 

of the rule by 60 days. We are proposing 

to extend the compliance dates for all 

standards for several reasons. First, the 

proposed changes to the emission limits 

for units in every subcategory and the 

proposed use of work practice standards 

for dioxin/furan emissions for all 

subcategories will have a significant 

impact on the compliance strategies that 

are selected by the affected sources. For 

instance, the proposed changes in PM 

emission limits for existing biomass 

fluidized bed, hybrid suspension grate, 

and the newly proposed dry stoker 

subcategories would require different 

PM control selections than the emission 

limits finalized in March 2011. The 

proposed changes in Hg, HCl and PM 

emission limits for units designed to 

burn liquid fuels are likely to result in 

different compliance responses and 

control selections for all of these 

pollutants. For coal stoker units, the 

increased stringency of the proposed 

PM and HCl emission limits would 

require increased control efficiencies 

that, while not necessarily changing the 

types of controls needed, may impact 

the design of those controls. Second, 

when the EPA announced the 

reconsideration and postponed the 

effective date, it indicated to industry 

that requirements could change 

significantly. The resulting uncertainty 

has limited the ability of affected 

sources to begin making appropriate 

selections of control technologies and 

other compliance decisions. Even if 

significant changes were not being 

proposed, an extended compliance date 

would likely be necessary to provide 

enough time for facilities to achieve 

compliance. Third, most of the dioxin 

emission limits that were finalized in 

March 2011 were below the level that 

the EPA has now determined can be 

accurately measured using the required 

test method. This was pointed out by 

stakeholders who petitioned the EPA to 

move to a work practice approach 

because the levels of dioxin/furan were 

too low to accurately measure and 

resulted in a high degree of uncertainty 

regarding how to meet the limits. The 

uncertainty resulted in the inability of 

sources to select dioxin/furan control 

technology, and also prevented sources 

from selecting controls for other 

pollutants because the emission controls 

must be designed to work properly 

when operated together. For instance, if 

a source required an ESP for PM control 

but needed carbon injection to 

potentially meet a very low dioxin/furan 

emission limit, the source may choose a 

fabric filter for PM control instead of an 

ESP. Alternatively, if a source no longer 

needed carbon injection, the particulate 

loading to the PM control device would 

be decreased, which may result in a 

different design or possibly a selection 

of a different control technology. 

Finally, the EPA has received comments 

that the availability of control 

equipment and vendors to install 

control equipment for boilers is in 

question due to the large number of 

units requiring controls in conjunction 

with the parallel rulemaking for electric 

generating units that will require 

controls from many of the same 

vendors. While the EPA believes that 

the maximum time allotted under 

section 112, 3 years after promulgation 

along with an additional year for 

installation of controls that must be 

approved on a case-by-case basis by the 

permitting authority, provides enough 

time for boilers to achieve compliance, 

the EPA recognizes that maintaining the 

compliance dates from the March 2011 

final rule would essentially provide less 

than 2 years for sources to meet the final 

standards, whose stringency will not be 

determined until the reconsideration is 

final. For all of the reasons discussed 

above, the EPA is proposing that the 

compliance date for existing sources is 

three years after the date of publication 

of the final reconsideration rule. The 


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EPA is requesting comment on the 

proposed changes to the compliance 

dates. 

2. Reduced Testing Frequency and 

Detection Levels. In the final rule, the 

EPA changed the stack testing 

requirements to allow units that 

demonstrate compliance for a particular 

pollutant at a level at or below 75 

percent of the emission limit for 2 

consecutive years to forego stack testing 

for up to 37 months. The EPA is 

maintaining this provision for most of 

the emission limits and is soliciting 

comment on this provision. The EPA 

also included, in the final rule analyses, 

a method to ensure that emission limits 

are set at levels that can be measured by 

the available test methods. During the 

development of the rule, the EPA 

carefully considered comments 

regarding the very low levels of some of 

the finalized emission limits that were 

based on a level no less than 3 times the 

‘‘representative detection limit’’ or RDL. 

In cases where the calculated MACT 

floors were lower than the 3 times the 

RDL value, the calculated floor value 

was replaced by the 3 times the RDL 

value. For these values, which again 

represent the lowest level that can be 

measured, units can qualify for skip 

testing by meeting the limit rather than 

a level that cannot be accurately 

measured. 

3. Fuel Analysis of Gaseous Fuels at 

Co-Fired Units. Petitioners requested 

that the EPA clarify the fuel analysis 

requirements for co-fired units that 

combust Gas 1 fuels along with either 

solid or liquid fuels. The EPA is 

clarifying that Gas 1 fuels are not 

included in the fuel analysis 

requirement. 

4. Coal Sampling Techniques. 

Petitioners requested that the EPA allow 

for automated coal sampling systems. 

The EPA did not intend to exclude these 

techniques in the final rule and is 

adding clarifying language to allow for 

automated coal sampling techniques. 

M. Other Issues Open for Comment 

1. Stakeholders asked the EPA to 

consider, for units that are retrofitted to 

switch to natural gas as a compliance 

option, allowing those units to average 

emissions with units of the original unit 

design. These parties suggested that 

continuing to allow such averaging 

would be consistent with EPA’s general 

approach of specifying emission 

standards for affected facilities, but 

otherwise allowing the facilities to 

comply however they see fit. They also 

pointed out that this may allow for more 

effective controls overall. For example, 

they suggested that without allowing for 

averaging of units that switch to cleaner 

fuels as a compliance option, natural gas 

conversion is a less attractive option 

than if such averaging was allowed, 

because a facility would not have the 

ability to offset emissions using that 

unit. In this case, these stakeholders 

believe that installing controls that 

result in fewer emissions reductions 

than switching to natural gas may be a 

perverse outcome. They suggested that 

continuing to allow averaging across 

subcategories in cases where fuel 

switching has been used to achieve 

compliance would instead encourage 

fuel switching to cleaner fuels, which is 

environmentally beneficial. The EPA is 

requesting comment on the potential 

benefit of this suggested approach, and 

how such an approach could be justified 

and incorporated into the rule. 

2. Stakeholders requested that EPA 

consider creating a subcategory for units 

that are installed and used in place of 

flares that are currently used to combust 

process gases. The EPA is requesting 

comment on how such a subcategory 

could be justified and incorporated into 

the rule. The stakeholders also 

suggested that it would be appropriate 

to assume that the emissions from 

process gases diverted from flares to 

boilers have ‘‘zero emissions’’ for the 

purposes of classifying the boiler they 

are combusted in. Since the process 

gases must be combusted in either 

event, they requested that the EPA 

develop an approach where we use a 

concept similar to the emissions 

averaging provisions, for example, to 

simply assume that combustion of such 

process gases in a boiler rather than a 

flare should not be counted as emissions 

from the boiler because there is no net 

increase in emissions. The EPA requests 

comment on how such an approach 

could be justified and incorporated into 

the rule. 

VI. Technical Corrections and 

Clarifications 

We are proposing several technical 

corrections. These amendments are 

being proposed to correct inaccuracies 

and oversights that were promulgated in 

the final rule and to make the rule 

language consistent with provisions 

addressed through this reconsideration. 

These proposed changes are described 

in Table 3 of this preamble. We request 

comment on all of these proposed 

changes. 

TABLE 3—MISCELLANEOUS PROPOSED TECHNICAL CORRECTIONS TO 40 CFR PART 63, SUBPART DDDDD 

Section of subpart DDDDD Description of proposed correction 

40 CFR 63.7491(m) ............................................ Clarify the language in this paragraph to use the word ‘‘unit’’ instead of ‘‘boiler.’’ 

40 CFR 63.7495(b) ............................................. Revise this paragraph to include a provision in § 63.6(i) 

40 CFR 63.7499(f)–(s) ........................................ Revise and add new paragraphs to accommodate the addition of new subcategories of boilers 

and process heaters. 

40 CFR 63.7499(d) ............................................. Revise the term ‘‘stokers’’ to ‘‘stokers/sloped grate/other units’’ consistent with how the data 

for this rule was analyzed. 

40 CFR 63.7500(d) ............................................. Revise this paragraph by adding a new paragraph (d) to clarify that the emission standards 

apply at all times, except during startup and shutdown, during which time you must comply 

only with Table 3. 

40 CFR 63.7501(b) ............................................. Revise terms in this paragraph to correct spelling errors. 

40 CFR 63.7505(c) ............................................. Revise this paragraph by removing the reference to Table 12; this table is not included because this is a proposed rule. 

40 CFR 63.7510(a) ............................................. Revise this paragraph to create four subparagraphs (1)–(4) to clarify our intent on fuel analysis 

requirements for gaseous fuels. 

40 CFR 63.7510(b) ............................................. Revise this paragraph to clarify that certain fuels are not subject to the fuel analysis requirements and that units using a continuous emission monitoring system for mercury or hydrogen chloride are exempt from the performance testing and operating limit requirements. 

40 CFR 63.7510(c) ............................................. Revise this paragraph to clarify that units using a continuous emission monitoring system for 

carbon monoxide are exempt from the performance testing and operating limit requirements. 

40 CFR 63.7510(d) ............................................. Revise this paragraph to clarify that owners and operators electing to comply with the alternative total selected metals limit are not required to install a PM CPMS. 


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80618 Federal Register / Vol. 76, No. 247 / Friday, December 23, 2011 / Proposed Rules 

TABLE 3—MISCELLANEOUS PROPOSED TECHNICAL CORRECTIONS TO 40 CFR PART 63, SUBPART DDDDD—Continued 

Section of subpart DDDDD Description of proposed correction 

40 CFR 63.7510(g) and (h) ................................ Insert a new paragraph (g) and renumber (g) to (h). Paragraph (g) will clarify the compliance 

provisions for new sources with respect to the work practice and tune-up provisions. 

40 CFR 63.7510(f), 63.7515(f), and 63.7520(d) Revise these paragraphs by removing the references to Table 12; this table is not included because this is a proposed rule. 

40 CFR 63.7521(a) ............................................. Revise this paragraph to clarify that fuel analysis cannot be used with gaseous fuels to demonstrate compliance with the limits for total selected metals or hydrogen chloride given 

method limitations. We are also proposing to revise this paragraph to clarify that a fuel gas 

system consisting of multiple gaseous fuels collected and mixed with each other is considered a single fuel type and sampling and analysis is only required of the combined fuel gas 

system. 

40 CFR 63.7521(b) ............................................. Revise this paragraph to clarify that the fuel monitoring plan is needed only if you are required 

to conduct fuel analyses. 

40 CFR 63.7521(b)(1) ........................................ Revise this paragraph to add a cross reference to the section describing the initial compliance 

demonstration. 

40 CFR 63.7521(b)(2)(ii) through (iv) ................. Revise the subparagraphs to clarify that the requirements apply to each anticipated fuel type. 

40 CFR 63.7521(c)(1)(ii) ..................................... Revise this paragraph by changing wording from ‘‘1-hour’’ to ‘‘one-hour’’. 

Clarify the different sampling circumstances for performance stack testing and monthly sampling. 

40 CFR 63.7521(c)(2)(ii) and 63.7521(d)(2) ...... Revise this paragraph by clarifying wording describing sampling requirements to provide more 

flexibility for automated sampling and reduce overly prescriptive language. 

40 CFR 63.7521(e) ............................................. Reference equations 7, 8, and 9 within this paragraph to add clarity. 

40 CFR 63.7521(f) .............................................. Add three sub-paragraphs to this paragraph to organize exemptions from fuel specification 

analyses. 

40 CFR 63.7521(g)(1) ........................................ Revise this paragraph to add a cross reference to the section describing the initial compliance 

demonstration. 

40 CFR 63.7521(g)(2)(ii) through (iv) ................. Revise the subparagraphs to clarify that the requirements apply to each anticipated fuel type. 

40 CFR 63.7522(b) ............................................. Revise this paragraph to add several subparagraphs to clarify that emissions averaging may 

not include units using CEMS or PM CPMS; that averaging may only be within units in a 

subcategory subject to the same numerical emission limit; and that emissions averaging is 

not allowed for certain subcategories of units for certain emission limits. 

40 CFR 63.7522(e)(2) ........................................ Add the units for emission limits to add clarity (pounds per million Btu). 

Revise the definition of the term ‘‘Sm’’ in Equation 2 to clarify that maximum steam generation 

is in units of pounds per hour. 

40 CFR 63.7525(a) ............................................. Remove a reference to Table 12; this table is not included because this is a proposed rule. 

40 CFR 63.7525(b)(3) ........................................ Change language from ‘‘concentrations’’ to ‘‘rates’’ to provide clarity. 

40 CFR 63.7525(b)(5) ........................................ Revise this paragraph by changing wording from ‘‘1-hour’’ to ‘‘one-hour’’. 

40 CFR 63.7525(d)(3) ........................................ Revise the paragraph to add a reference to 65.7535(d) to replace a description of other situations that constitute a monitoring deviation. 

40 CFR 63.7525(d)(4) ........................................ Change from the 12-hour block average to 30-day rolling average as specified in the revised 

Table 8 to subpart DDDDD. 

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

CFR 63.7510(a)(2), instead of repeating the information in that paragraph. 

40 CFR 63.7530(b)(4) [formerly (b)(3)] .............. Revise this paragraph to: 1. Clarify that you are not required to establish and comply with the 

operating parameter limits when you are using a CEMS to monitor and demonstrate compliance with the applicable emission limit. 

2. Clarify in the subparagraphs which parameters are applicable to specific types of control devices. 

3. Add a new subparagraph to address PM controls used in conjunction with a PM CPMS. 

4. Add a new paragraph to address particulate wet scrubbers as distinct from acid-gas wet 

scrubbers. 

40 CFR 63.7530(c)(2) ......................................... Revise the references to Equation 9 to be Equation 10, to accommodate the change in numbering of equations. 

40 CFR 63.7530(c)(3) ......................................... Revise the references to Equation 9 to be Equation 10, to accommodate the change in numbering of equations. 

40 CFR 63.7530(c)(4) ......................................... Revise the references to Equation 9 to be Equation 10, to accommodate the change in numbering of equations. 

40 CFR 63.7530(h) ............................................. Remove a reference to Table 12; this table is not included because this is a proposed rule. 

40 CFR 63.7533(b)(2) ........................................ Amend this paragraph to clarify that the use of emission credits from implementation of energy 

conservation measures can only be used by existing units, and that these credits can be 

used to demonstrate initial and on-going compliance. 

40 CFR 63.7533(c), (c)(1)(i), and (c)(3) ............. Amend these paragraphs to change the date after which energy conservation measures can 

be used to generate credits from January 14, 2011, to January 1, 2008. January 1, 2008 is 

the same cut-off date for using a pre-existing energy assessment to satisfy the energy assessment requirement in Table 3 to subpart DDDDD. 

40 CFR 63.7533(c)(2)(i) and (c)(3) .................... Revise the reference to Equation 12 to Equation 14, to accommodate the change in numbering of equations. 

40 CFR 63.7533(c)(3)(i) ..................................... Revise Equation 12 in this section to clarify the summation to be performed in that equation, 

and to clarify that the energy credits are expressed as a decimal fraction of the baseline energy input. 

40 CFR 63.7533(c)(3)(i) and (f) .......................... Revise the names and definitions of the terms in Equations 12 and 13 to be consistent. 

40 CFR 63.7533(c)(f) .......................................... Revise the paragraph to remove the reference to (f)(1) and (2) because there is no paragraph 

(2) and only a single paragraph is needed. 


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TABLE 3—MISCELLANEOUS PROPOSED TECHNICAL CORRECTIONS TO 40 CFR PART 63, SUBPART DDDDD—Continued 

Section of subpart DDDDD Description of proposed correction 

Change the reference to Equation 13 to Equation 15, to accommodate the change in numbering of equations. 

40 CFR 63.7535 ................................................. Revise the title of this section to add clarity. 

40 CFR 63.7535(b) ............................................. Add language to the paragraph to clarify that you must operate monitoring systems while the 

unit is operating and compliance is required. Add ‘‘scheduled CMS maintenance’’ to the list 

of periods during which you are not required to collect data from a monitoring system. 

40 CFR 63.7535(c) ............................................. Amend this paragraph to clarify that operators must record results of CMS performance audits, 

dates and duration of periods when the CMS is out of control to completion of the corrective 

actions necessary to return the CMS to normal operation. Also adding language to clarify 

that all collected data must be used to assess compliance. 

40 CFR 63.7535(d) ............................................. Revise the paragraph to remove references to ‘‘out-of-control periods’’ and to add ‘‘system accuracy audits’’ to the list of periods during which data do not need to be collected. 

40 CFR 63.7540(a) ............................................. Add references to Tables 1, 2, 3, and 4 to add clarity. 

40 CFR 63.7540(a)(2) ........................................ Split this paragraph into two subparagraphs for clarity. 

40 CFR 63.7540(a)(3) ........................................ Revise the paragraph to clarify that fuel analysis for hydrogen chloride is applicable for only 

solid and liquid fuels, and to clarify that certain fuels are not subject to the fuel analysis requirements. 

40 CFR 63.7540(a)(3) and (a)(3)(iii) .................. Change the references to Equation 9 to Equation 11 to accommodate the change in numbering of equations. 

40 CFR 63.7540(a)(4), (a)(5), and (a)(6) ........... Revise these paragraphs to clarify that certain fuels are not subject to the fuel analysis requirements. 

40 CFR 63.7540(a)(5) and (a)(5)(iii) .................. Change the reference to Equation 11 to Equation 12 to accommodate the change in numbering of equations. 

40 CFR 63.7540(a)(9) ........................................ Revise this paragraph and the subparagraphs to remove the references to the EPA performance specifications for a PM CEMS, and replace them with a reference to the PM CPMS 

provisions in the facility’s site-specific monitoring plan required by 40 CFR 63.7505. 

40 CFR 63.7540(a)(10)(i) and (a)(12) ................ Revise this paragraph to specify that required burner inspections be done at the next burner 

shutdown, whether it is scheduled or unscheduled. 

40 CFR 63.7541 (a)(3) and (4) .......................... Change the 3-hour parameter averages to 30-day rolling parameter averages to match Table 

8 to subpart DDDDD. 

40 CFR 63.7545(e)(3) ........................................ Remove a reference to Table 12 (this table is not included because this is a proposed rule), 

and adding language to clarify that this applies to facilities ‘‘not using a CO CEMS to demonstrate compliance.’’ 

40 CFR 63.7545(f) .............................................. Revise the paragraph to include units that burn ‘‘gaseous fuel subject to another subpart of 

this part’’ to add clarity. 

40 CFR 63.7550(c)(6) ......................................... Change the reference to Equation 10 to Equation 11, to accommodate the change in numbering of equations. 

40 CFR 63.7550(h), (i), and (j) ........................... Revise paragraph (h) and adding paragraphs (i) and (j) to provide additional instruction on 

submitting data to EPA from performance emission tests, CEMS performance evaluations, 

and quarterly data from CEMS and CPMS consistent with the proposed monitoring requirements. 

40 CFR 63.7555(d) ............................................. Remove a reference to Table 12; this table is not included because this is a proposed rule. 

40 CFR 63.7555(d)(2) ........................................ Correct an inaccurate reference to 40 CFR 241.3(b)(1)and (2), and to add a sentence to clarify 

that certain units exempt from the incinerator standards under section 129(g)(1) of the Clean 

Air Act do not need to maintain the records described in this paragraph. 

40 CFR 63.7555(d)(4) ........................................ Change the reference to Equation 10 to Equation 11, to accommodate the change in numbering of equations. 

40 CFR 63.7555(d)(5) ........................................ Change the reference to Equation 11 to Equation 12, to accommodate the change in numbering of equations. 

40 CFR 63.7555(h) ............................................. Revise the paragraph to include units that burn ‘‘gaseous fuel subject to another subpart of 

this part’’ to add clarity. 

40 CFR 63.7575 ................................................. Revise the definition of process heater to include units heating hot water as a process heat 

transfer medium. 

Edit the definition of each solid fuel combustor design-based subcategory to establish a hierarchy and assisted affected sources by clarifying applicability for units with multiple combustor types. 

Revise the definition of ‘‘dutch oven’’ to clarify that fluidized bed boilers are not part of the 

dutch oven design category. 

Revise the definition of ‘‘energy assessment’’ to clarify the length of days for each category of 

facilities. 

Revise the definition of ‘‘equivalent’’ to remove references to hydrogen sulfide. 

Revise the definition of ‘‘fluidized bed boiler’’ to clarify that pulverized coal boilers are not included. 

Revise the definition of ‘‘hybrid suspension grate boiler’’ to clarify that ‘‘the fuel combusted in 

these units exceed a moisture content of 40 percent on an as-fired basis’’ and ‘‘Fluidized 

bed, dutch oven, and pile burner designs are not part of the hybrid suspension grate boiler 

design category.’’ 

Revise the definition of ‘‘fuel cell’’ to clarify that ‘‘fluidized bed, dutch oven, pile burner, hybrid 

suspension grate, and suspension burners are not part of the fuel cell subcategory.’’ 

Revise the definition of ‘‘liquid fuel’’ to include vegetable oil. 


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80620 Federal Register / Vol. 76, No. 247 / Friday, December 23, 2011 / Proposed Rules 

TABLE 3—MISCELLANEOUS PROPOSED TECHNICAL CORRECTIONS TO 40 CFR PART 63, SUBPART DDDDD—Continued 

Section of subpart DDDDD Description of proposed correction 

Revise the definition of ‘‘process heater’’ to include ‘‘units heating hot water as a process heat 

transfer medium’’ and to clarify that ‘‘waste heat process heaters are excluded from this definition’’ similar to the exemption allowed for waste heat boilers. 

Revise the definition of ‘‘steam output’’ to include a description of the total energy output for a 

boiler that generates only electricity. 

Revise the definition of ‘‘stoker’’ to clarify that ‘‘fluidized bed, dutch oven, pile burner, hybrid 

suspension grate, suspension burners, and fuel cells are not considered to be a stoker design.’’ 

Revise the term ‘‘suspension boiler’’ to instead be ‘‘suspension burner’’, to provide consistent 

terminology throughout the rule and to clarify that ‘‘fluidized bed, dutch oven, pile burner, 

and hybrid suspension grate units are not part of the suspension burner subcategory.’’ 

Revise the definition of ‘‘waste heat boiler’’ to clarify that the definition includes fired and 

unfired waste heat boilers. 

Revise the definition of ‘‘waste heat process heater to clarify that the definition includes fired 

and unfired waste heat process heaters. 

Add new definitions of ‘‘30-day rolling average’’, ‘‘average annual heat input rate’’, ‘‘biodiesel’’, 

‘‘daily block average’’, ‘‘heavy liquid’’, ‘‘light liquid’’, ‘‘other combustor’’, ‘‘oxygen analyzer’’, 

‘‘oxygen trim system’’, ‘‘pile burner’’, ‘‘residential boiler’’, ‘‘sloped grate’’, ‘‘stoker/sloped 

grate/other unit designed to burn kiln dried biomass’’, ‘‘stoker/sloped grate/other unit designed to burn wet biomass’’, ‘‘total selected metals’’, ‘‘unit designed to burn heavy liquid 

subcategory’’, ‘‘unit designed to burn light liquid subcategory’’, and ‘‘vegetable oil’’. 

Remove the definition of ‘‘liquid fuel subcategory.’’ 

Tables 1 and 2 to subpart DDDDD .................... Revise the sampling volumes collected and also the prescribed span values associated with 

the emission measurement methods to account for changes in the numerical emission limits 

and to be consistent with the proposed emission limits. 

Table 3 to subpart DDDDD ................................ Revise items 1, 2, and 3 to account for the proposed changes in the tune-up requirements. 

Revise item 4c to clarify the major systems ‘‘consuming energy from affected boilers and process heaters and which are under the control of the boiler/process heater owner/operator.’’ 

Revise item 5 to remove the reference to Table 12; this table is not included because this is a 

proposed rule. 

Table 4 to subpart DDDDD ................................ Revise the operating limits for items 1 and 2 to read ‘‘one-hour’’ instead of ‘‘1-hour’’. 

Revise certain items in the table to clarify the applicability of the parameter operating limits, 

and to reflect that replace PM CEMS with PM CPMS requirements. 

Revise items 1, 2, and 4 in the table to reflect the fact that we are proposing that compliance 

with the operating limits is based on a 30-day rolling average. 

Table 6 to subpart DDDDD ................................ Revise items 1, 2, and 3 to provide additional instruction on demonstrating compliance. 

Revise item 4 to replace the requirements for hydrogen sulfide in other gas 1 fuels with requirements for total selected metals in solid fuels. 

Table 7 to subpart DDDDD ................................ Revise item 1 to include total selected metals with PM and mercury, and to clarify the applicability of the operating limits described in that item. 

Table 8 to subpart DDDDD ................................ Include provisions for demonstrating continuous compliance with a PM CPMS, to reflect proposed changes elsewhere in the rule. 

Revise various items to reflect the proposed change from 12-hour block averages to 30-day 

rolling averages for demonstrating compliance. 

Revise the operating load compliance provisions to be consistent with the operating limit in 

Table 4 to subpart DDDDD. 

Table 11 to subpart DDDDD .............................. Delete Table 11 to subpart DDDDD to be consistent with the proposal to remove the numerical emission limits for dioxin/furan emissions. 

Table 12 to subpart DDDDD .............................. Remove Table 12 to subpart DDDDD because this is a proposed rule and Table 12 was needed only because the rule published on March 21, 2011 (76 FR 15608) was a final rule. 

VII. Impacts of This Proposed Rule 

A. What are the air impacts? 

Table 4 of this preamble illustrates, 

for each basic fuel subcategory, the 

emissions reductions achieved by the 

proposed rule (i.e., the difference in 

emissions between a boiler or process 

heater controlled to the floor level of 

control and boilers or process heaters at 

the current baseline) for new and 

existing sources. Nationwide emissions 

of selected HAP (i.e., HCl, HF, Hg, 

metals, and volatile organic compound 

(VOC)) will be reduced by 45,000 tons 

per year for existing units and 19 tons 

per year for new units. Emissions of HCl 

will be reduced by 37,000 tons per year 

for existing units and 0 tons per year for 

new units. Emissions of Hg will be 

reduced between 0.5 to 1.8 tons per year 

for existing units and 20.2 pounds per 

year for new units. Emissions of 

filterable PM will be reduced by 41,200 

tons per year for existing units and 

1,500 tons per year for new units. 

Emissions of non-mercury metals (i.e., 

antimony, arsenic, beryllium, cadmium, 

chromium, cobalt, lead, manganese, 

nickel, and selenium) will be reduced 

by 2,200 tons per year for existing units 

and 19 tons per year for new units. In 

addition, emissions of SO2 are estimated 

to be reduced by 558,400 tons per year 

for existing sources and 0 tons per year 

for new sources. A discussion of the 

methodology used to estimate emissions 

and emissions reductions is presented 

in ‘‘Revised (November 2011) 

Methodology for Estimating Cost and 

Emission Impacts for Industrial, 

Commercial, and Institutional Boilers 

and Process Heaters NESHAP—Major 

Source’’ in the docket. 


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TABLE 4—SUMMARY OF EMISSIONS REDUCTIONS FOR EXISTING AND NEW SOURCES

[Tons/yr] 

Source Subcategory HCl PM 

Non 

mercury 

metals a

Mercury b VOC 

Existing Units ...................... Limited Use ...................................... 1 2 0.45 2.2E–04 ............ 1 

Solid units ........................................ 34,815 34,830 271 0.4 to 1.4 .......... 2,487 

Liquid units ....................................... 2,039 6,240 1,905 0.04 to 0.3 ........ 1,815 

Non-Continental Liquid units ........... 158 29 4 0.001 to 0.01 .... 169 

Gas 1 (NG/RG) units ....................... 21 118 0.9 0.01 .................. 85 

Gas 1 Metallurgical Furnaces .......... 0.4 3 0.02 0.001 ................ 23 

Gas 2 (other) units ........................... 4 11 0.07 0.004 to 0.005 .. 138 

New Units ........................... Solid units ........................................ 0 1,462 19 0.01 .................. 0 

Liquid units ....................................... 0 0 0 0 ....................... 0 

Gas 1 units ...................................... 0 0 0 0 ....................... 0 

Gas 1 Metallurgical Furnaces .......... 0 0 0 0 ....................... 0 

Gas 2 (other) units ........................... 0 0 0 0 ....................... 0 

a Includes antimony, arsenic, beryllium, cadmium, chromium, cobalt, lead, manganese, nickel, and selenium. 

bHg reductions are presented as a range due to adjustments on reported fractions and limits of detection. See memorandum entitled ‘‘Revised 

(November 2011) Methodology for Estimating Cost and Emissions Impacts for Industrial, Commercial, Institutional Boilers and Process Heaters 

National Emission Standards for Hazardous Air Pollutants—Major Source’’ for a description of the two methods for estimating Hg reductions. 

B. What are the water and solid waste 

impacts? 

The EPA estimated the additional 

water usage that would result from 

installing wet scrubbers to meet the 

emission limits for HCl would be 1.2 

billion gallons per year for existing 

sources and 0 gallons per year for new 

sources. In addition to the increased 

water usage, an additional 416 million 

gallons per year of wastewater would be 

produced for existing sources and 0 

gallons per year for new sources. The 

annual costs of treating the additional 

wastewater are $2.3 million for existing 

sources and $0 for new sources. These 

costs are accounted for in the control 

costs estimates. 

The EPA estimated the additional 

solid waste that would result from the 

MACT floor level of control to be 

286,000 tons per year for existing 

sources and 1,700 tons per year for new 

sources. Solid waste is generated from 

flyash and dust captured in PM and Hg 

controls as well as from spent carbon 

that is injected into exhaust streams or 

used to filter gas streams. The costs of 

handling the additional solid waste 

generated are $12.0 million for existing 

sources and $70,600 for new sources. 

These costs are also accounted for in the 

control costs estimates. 

A discussion of the methodology used 

to estimate impacts is presented in 

‘‘Revised (November 2011) Methodology 

for Estimating Cost and Emission 

Impacts for Industrial, Commercial, and 

Institutional Boilers and Process Heaters 

NESHAP—Major Source’’ in the Docket. 

C. What are the energy impacts? 

The EPA expects an increase of 

approximately 1.5 billion kilowatt hours 

(kWh) in national annual energy usage 

as a result of the proposed rule. Of this 

amount, 1.4 billion kWh would be from 

existing sources and 120 million kWh 

from new sources. The increase results 

from the electricity required to operate 

control devices, such as wet scrubbers, 

electrostatic precipitators, and fabric 

filters which are expected to be installed 

to meet the proposed rule. Additionally, 

the EPA expects work practice 

standards such as boilers tune-ups and 

combustion controls will improve the 

efficiency of boilers, resulting in an 

estimated fuel savings of 47.3 trillion 

BTU each year from existing sources. 

The EPA did not estimate fuel savings 

and efficiency improvements on new 

boilers since new boilers are expected to 

be tuned-up up upon installation and 

will not achieve additional fuel savings 

in the first year. This fuel savings 

estimate includes only those fuel 

savings resulting from Gas 1, liquid, and 

coal fuels and it is based on the 

assumption that the work practice 

standards will achieve 1 percent 

improvement in efficiency. 

D. What are the cost impacts? 

To estimate the national cost impacts 

of the proposed rule for existing 

sources, we developed average baseline 

emission factors for each fuel type/ 

control device combination based on the 

emission data obtained and contained in 

the Boiler MACT emission database. If 

a unit reported emission data, we 

assigned its unit-specific emission data 

as its baseline emissions. For units that 

did not report emission data, we 

assigned the appropriate emission 

factors to each existing unit in the 

inventory database, based on the 

average emission factors for boilers with 

similar fuel, design, and control devices. 

We then compared each unit’s baseline 

emission factors to the proposed MACT 

floor emission limit to determine if 

control devices were needed to meet the 

emission limits. The control analysis 

considered fabric filters and activated 

carbon injection to be the primary 

control devices for Hg control; 

electrostatic precipitators for units 

meeting Hg limits but requiring 

additional control to meet the PM or 

total selected metals limits; wet 

scrubbers or fabric filters with dry 

injection to meet the HCl limits; tuneups, replacement burners, combustion 

controls, and oxidation catalysts for CO 

and organic HAP control; and tune-ups 

for dioxin/furan control. We identified 

where one control device could achieve 

reductions in multiple pollutants, for 

example a fabric filter was expected to 

achieve both PM and Hg control, in 

order to avoid overestimating the costs. 

We also included costs for testing and 

monitoring requirements contained in 

the proposed rule. The resulting total 

national cost impact of the proposed 

rule is 5.4 billion dollars in capital 

expenditures and 1.9 billion dollars per 

year in total annual costs. Considering 

estimated fuel savings resulting from 

work practice standards and combustion 

controls, the total annualized costs are 

reduced to 1.5 billion dollars. The total 

capital and annual costs include costs 

for control devices, work practices, 

testing and monitoring. While these 


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costs are higher than the costs estimated 

for the final rule, these estimates are 

based on an inventory that includes 300 

additional units that were identified 

after the final rule was completed. The 

costs associated with the final rule 

inventory are just under $5.0 billion in 

capital expenditures and $1.75 billion 

in total annual costs ($1.35 billion 

considering fuel savings). Table 5 of this 

preamble shows the capital and annual 

cost impacts for each subcategory. Costs 

include testing and monitoring costs, 

but not recordkeeping and reporting 

costs. 

TABLE 5—SUMMARY OF CAPITAL AND ANNUAL COSTS FOR NEW AND EXISTING SOURCES

Source Subcategory 

Estimated/ 

Projected 

number of 

affected units 

Capital costs 

(10 6 $) 

Testing and 

monitoring 

annualized 

costs 

(10 6 $/yr) 

Annualized 

cost(10 6 $/yr) 

(considering 

fuel savings) 

Existing Units .................................... Coal units ......................................... 616 2,713 46 953 

Biomass units ................................... 508 639 33 169 

Heavy Liquid units ............................ 322 769 8.4 264 

Light Liquid units .............................. 581 930 5.1 277 

Non-Continental Liquid units ............ 44 181 1.5 42 

Gas 1 (NG/RG) units ....................... 11,911 77 0.9 (295) 

Gas 2 (other) units ........................... 129 132 2.3 55 

Energy Assessment .......................... ALL ................................................... 1,704 

(Facilities) 

N/A N/A 28 

New Units .......................................... Coal units ......................................... 0 0 0 0 

Biomass units ................................... 82 381 5.6 a 99 

Liquid units ....................................... 0 0 0 0 

Gas 1 (NG/RG) units ....................... 1,762 11 0 a 5.1 

Gas 2 (other) units ........................... 0 0 0 0 

aTotal annualized costs for new units do not account for fuel savings since no fuel savings are estimated in the first year for new units. 

Using Department of Energy 

projections on fuel expenditures, the 

number of additional boilers that could 

be potentially constructed was 

estimated. The resulting total national 

cost impact of the proposed rule for new 

boilers in the 3rd year is 393 million 

dollars in capital expenditures and 104 

million dollars per year in total annual 

costs. 

Potential control device cost savings 

and increased recordkeeping and 

reporting costs associated with the 

emissions averaging provisions in the 

proposed rule are not accounted for in 

either the capital or annualized cost 

estimates. 

A discussion of the methodology used 

to estimate cost impacts is presented in 

‘‘Revised (November 2011) Methodology 

for Estimating Cost and Emission 

Impacts for Industrial, Commercial, and 

Institutional Boilers and Process Heaters 

NESHAP—Major Source’’ in the Docket. 

E. What are the economic impacts? 

The EPA analyzed the economic 

impacts of this proposed rule using the 

methodology that was discussed in the 

final rule RIA and in the preamble to the 

final rule. See FR 76 15651. The market 

impact results are very similar to the 

results presented in the final rule and 

the RIA. The agency’s economic model 

suggests the average national price 

increases for industrial sectors are less 

than 0.01 percent, while average annual 

domestic production may fall by less 

than 0.01 percent. Because of higher 

domestic prices, imports slightly rise. 

The increase in US trade deficit is now 

1.93 billion dollars (2006$). For the RIA, 

it was 1.86 billion dollars (2006$). The 

results for sales tests for small 

businesses were somewhat reduced. For 

the sales tests using small companies 

identified in the Combustion Survey, 

the mean cost to receipts dropped from 

4 percent in the RIA to 2 percent for this 

proposed rule and the median was 0.2 

percent for both. The number of parent 

companies with sales tests exceeding 3 

percent dropped from 8 in the RIA to 6 

for this proposed rule. There was no 

change in the results for small public 

entities. Median cost is still about $1.1 

million and representative small major 

public entities would have cost-torevenue ratios above 10 percent. The 

change in employment estimates 

between the RIA and the proposal is 

minimal. In the RIA for the final rule, 

we estimated employment changes 

ranging between ¥3100 to +6,500 

employees, with a central estimate of 

+1,700. For this proposal, we estimate 

employment changes ranging between 

¥3000 to +6,300 employees, with a 

central estimate of +1,600. These 

estimated annual employment changes 

compared to the baseline employment, 

and are for the time period for which 

the annualized cost applies (2015 to 

2029). 

The benefits estimates increased for 

this proposal. In the RIA for the final 

rule, we estimated benefits ranging from 

$22 billion (2008$) to 54 billion (2008$) 

at a 3 percent discount rate. For this 

proposal, we estimate benefits ranging 

from $27 billion (2008$) to 67 billion 

(2008$) at a 3 percent discount rate. The 

range for the RIA was $20 billion 

(2008$) to 49 billion (2008$) at a 7 

percent discount rate. The range for this 

proposal is $25 billion (2008$) to 61 

billion (2008$) at a 7 percent discount 

rate. 

F. What are the benefits of this proposed 

rule? 

We calculated health benefits using 

the methodology described in the RIA 

prepared for the March 21, 2011, final 

rule. We incorporated the revised 

emission reductions estimated for this 

reconsideration proposal into the 

analysis. We were unable to estimate the 

benefits from reducing exposure to HAP 

and ozone, ecosystem impairment, and 

visibility impairment, including 

reducing 187,000 tons of carbon 

monoxide, 37,000 tons of HCl, 1,000 

tons of HF, 1,000 to 3,600 pounds of Hg, 

and 2,200 tons of other metals. Please 

refer to the full description in the final 

Boiler RIA of the unquantified benefits 

as well as technical details of the 

analysis and its limitations and 

uncertainties. These monetized benefits 

are approximately 23 percent higher 

than the final rule benefits due to the 

increase in SO2 emission reductions 

associated with the additional units 

affected by the rule and the revised HCl 

limit. We estimate the total monetized 

benefits of this proposed regulatory 

action to be $27 billion to $67 billion 

(2008$, 3 percent discount rate) in the 

implementation year (2015). A summary 


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of the monetized benefits estimates at 

discount rates of 3 percent and 7 

percent is provided in Table 6 of this 

preamble. A summary of the avoided 

health incidences is provided in Table 

7 of this preamble. 

TABLE 6—SUMMARY OF THE MONETIZED BENEFITS ESTIMATES FOR THE FINAL BOILER MACT 

[Millions of 2008$] 1

Pollutant 

Emissions 

reductions 

(tons) 

Total monetized benefits (at 

3% discount rate) 

Total monetized benefits (at 7% 

discount rate) 

PM2.5-related benefits: 

Direct PM2.5 .......................................................................... 25,601 $1,800 to $4,500 .................. $1,700 to $4,100. 

SO2 ....................................................................................... 558,430 $25,000 to $63,000 .............. $23,000 to $57,000. 

Total .......................................................................................................... $27,000 to $67,000 .............. $25,000 to $61,000. 

1All estimates are for the implementation year (2015), and are rounded to two significant figures so numbers may not sum across rows. All 

fine particles are assumed to have equivalent health effects. Benefits from reducing hazardous air pollutants (HAP) are not included. These estimates do not include energy disbenefits valued at $5.8 to $75 million depending on the discount rate. These benefits reflect existing boilers and 

new boilers anticipated to come online by 2015. 

TABLE 7—SUMMARY OF THE AVOIDED HEALTH INCIDENCES FOR THE FINAL BOILER MACT 1

Avoided health 

incidences 

Avoided Premature Mortality ............................................................................................................................................................... 3,100–8,000 

Avoided Morbidity ................................................................................................................................................................................ ........................

Chronic Bronchitis ................................................................................................................................................................................ 2,000 

Acute Myocardial Infarction ................................................................................................................................................................. 4,900 

Hospital Admissions, Respiratory ........................................................................................................................................................ 750 

Hospital Admissions, Cardiovascular .................................................................................................................................................. 1,600 

Emergency Room Visits, Respiratory .................................................................................................................................................. 3,000 

Acute Bronchitis ................................................................................................................................................................................... 4,600 

Work Loss Days .................................................................................................................................................................................. 390,000 

Asthma Exacerbation ........................................................................................................................................................................... 51,000 

Minor Restricted Activity Days ............................................................................................................................................................. 2,300,000 

Lower Respiratory Symptoms ............................................................................................................................................................. 55,000 

Upper Respiratory Symptoms ............................................................................................................................................................. 41,000 

1All estimates are for the implementation year (2015), and are rounded to two significant figures. All fine particles are assumed to have equivalent health effects. Benefits from reducing HAP are not included. These benefits reflect existing boilers and new boilers anticipated to come online by 2015. 

G. What are the secondary air impacts? 

For units adding controls to meet the 

proposed emission limits, we anticipate 

very minor secondary air impacts. The 

combustion of fuel needed to generate 

additional electricity would yield slight 

increases in emissions, including 

nitrogen oxide (NOX), CO and SO2 and 

an increase in carbon dioxide (CO2) 

emissions. Since NOX and SO2 are 

covered by capped emissions trading 

programs, these pollutants do not 

contribute disbenefits from additional 

electricity demand. Additional CO2

emissions from increased electricity 

consumption are estimated to be 

931,000 tons per year from existing 

units and 79,700 tons per year from new 

units. Energy disbenefits due to 

increased CO2 emissions range from 

$5.8 million to $75 million depending 

on the discount rate, and thus do not 

affect the rounded monetized benefits. 

VIII. Relationship of This Proposed 

Action to Section 112(c)(6) of the Clean 

Air Act 

Section 112(c)(6) of the CAA requires 

the EPA to identify categories of sources 

of seven specified pollutants to assure 

that sources accounting for not less than 

90 percent of the aggregate emissions of 

each such pollutant are subject to 

standards under CAA Section 112(d)(2) 

or 112(d)(4). The EPA has identified 

‘‘Industrial Coal Combustion,’’ 

‘‘Industrial Oil Combustion,’’ Industrial 

Wood/Wood Residue Combustion,’’ 

‘‘Commercial Coal Combustion,’’ 

‘‘Commercial Oil Combustion’’ and 

‘‘Commercial Wood/Wood Residue 

Combustion’’ as source categories that 

emit two of the seven CAA Section 

112(c)(6) pollutants: polycyclic organic 

matter (POM) and Hg. (The POM 

emitted is composed of 16 polyaromatic 

hydrocarbons and extractable organic 

matter.) In the Federal Register notice 

Source Category Listing for Section 

112(d)(2) Rulemaking Pursuant to 

Section 112(c)(6) Requirements, 63 FR 

17838, 17849, Table 2 (1998), the EPA 

identified ‘‘Industrial Coal 

Combustion,’’ ‘‘Industrial Oil 

Combustion,’’ ‘‘Industrial Wood/Wood 

Residue Combustion,’’ ‘‘Commercial 

Coal Combustion,’’ ‘‘Commercial Oil 

Combustion’’ and ‘‘Commercial Wood/ 

Wood Residue Combustion’’ as source 

categories ‘‘subject to regulation’’ for 

purposes of CAA Section 112(c)(6) with 

respect to the CAA Section 112(c)(6) 

pollutants that these units emit. 

For Hg, the 112(c)(6) requirement is 

directly met through the proposed 

emission limits for Hg. Through these 

emission limits, the types of boilers and 

process heaters listed in section 

112(c)(6) are subject to regulation. 

For POM, which are byproducts of 

combustion, the formation of POM is 

effectively reduced by the combustion 

and post-combustion practices required 

to comply with the CAA Section 112 

standards. The tune-up requirement for 

all major source units and the CO 

emission limits will ensure that good 

combustion practices are followed, thus 

minimizing emissions of organic HAP, 

including POM. Any POM that do form 


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during combustion would be reduced by 

the various post-combustion controls. 

The add-on PM control systems (either 

fabric filter or wet scrubber) and 

activated carbon injection in the fabric 

filter-based systems would reduce 

emissions of these organic pollutants. It 

is, therefore, reasonable to conclude that 

POM emissions will be substantially 

controlled. Thus, while this final rule 

does not identify specific numerical 

emission limits for POM, emissions of 

POM are, for the reasons noted below, 

nonetheless ‘‘subject to regulation’’ for 

purposes of Section 112(c)(6) of the 

CAA. In lieu of establishing numerical 

emissions limits for pollutants such as 

POM, we regulate surrogate substances. 

While we have not identified specific 

numerical limits for POM, CO serves as 

an effective surrogate for this HAP, 

because CO, like POM, is formed as a 

byproduct of combustion, and both 

would increase with an increase in the 

level of incomplete combustion. 

Consequently, we have concluded that 

the emissions limits for CO function as 

a surrogate for control of POM, such that 

it is not necessary to require numerical 

emissions limits for POM with respect 

to boilers and process heaters to satisfy 

CAA Section 112(c)(6). 

To further address POM and Hg 

emissions, this final rule also includes 

an energy assessment provision that 

encourage modifications to the facility 

to reduce energy demand that lead to 

these emissions. 

IX. Statutory and Executive Order 

Reviews 

A. Executive Order 12866: Regulatory 

Planning and Review and Executive 

Order 13563: Improving Regulation and 

Regulatory Review 

Under section 3(f)(1) of Executive 

Order 12866 (58 FR 51735, October 4, 

1993), this action is an ‘‘economically 

significant regulatory action’’ because it 

is likely to have an annual effect on the 

economy of $100 million or more or 

adversely affect in a material way the 

economy, a sector of the economy, 

productivity, competition, jobs, the 

environment, public health or safety, or 

State, local, or tribal governments or 

communities. Accordingly, the EPA 

submitted this action to the Office of 

Management and Budget (OMB) for 

review under Executive Orders 12866 

and 13563 (76 FR 3821, January 21, 

2011) and any changes made in 

response to OMB recommendations 

have been documented in the docket for 

this action. 

Because this action is proposing 

changes to a final rule and does not 

increase costs by an amount that would 

qualify the proposed rule, by itself, as a 

major rule, the EPA did not prepare a 

new RIA for this action. Instead, the 

EPA prepared an assessment of the 

changes in the costs and benefits of this 

proposed rule compared to the costs and 

benefits associated with the March 21, 

2011, final rule. Overall, the costs and 

impacts are estimated to be similar to 

the costs and impacts associated with 

the final rule, although the distribution 

is somewhat different and the number of 

affected units in the inventory has 

increased by about 300 units. When 

comparing the costs using only those 

sources that were part of the final rule 

inventory, the costs have decreased. The 

EPA re-ran the multimarket model to 

assess changes in economic impacts, 

and this analysis confirmed that the 

overall economic impacts are similar to 

the final rule. The benefits are projected 

to increase by about 23 percent because 

of the increase in the estimated SO2

reductions. A summary of the costs and 

benefits of the final rule is provided in 

the preamble to the final rule (see 76 FR 

15658) and the detailed analysis for the 

final rule is provided in the RIA for the 

final rule. In addition, memoranda are 

provided in the docket to document the 

changes in costs, economic impacts, and 

benefits associated with this proposed 

rule. 

B. Paperwork Reduction Act 

The information collection 

requirements in this proposed rule will 

be submitted for approval to the OMB 

under the Paperwork Reduction Act, 44 

U.S.C. 3501 et seq. The Information 

Collection Request (ICR) document 

prepared by the EPA has been assigned 

EPA ICR number 2028.07. The 

information collection requirements are 

not enforceable until OMB approves 

them. 

The information requirements are 

based on notification, recordkeeping, 

and reporting requirements in the 

NESHAP General Provisions (40 CFR 

part 63, subpart A), which are 

mandatory for all operators subject to 

national emission standards. These 

recordkeeping and reporting 

requirements are specifically authorized 

by section 114 of the CAA (42 U.S.C. 

7414). All information submitted to the 

EPA pursuant to the recordkeeping and 

reporting requirements for which a 

claim of confidentiality is made is 

safeguarded according to agency 

policies set forth in 40 CFR part 2, 

subpart B. 

This proposed rule would require 

maintenance inspections of the control 

devices but would not require any 

notifications or reports beyond those 

required by the General Provisions aside 

from a notification of intent to 

commence burning solid waste 

materials and notification of alternative 

fuel use for those units that are in the 

Gas 1 subcategory but burn liquid fuels 

for periodic testing, or during periods of 

gas curtailment or gas supply 

emergencies. The recordkeeping 

requirements require only the specific 

information needed to determine 

compliance. The annual monitoring, 

reporting, and recordkeeping burden for 

this collection (averaged over the first 3 

years after the effective date of the 

standards) is estimated to be $96.2 

million. This includes 324,954 labor 

hours per year at a total labor cost of 

$30.7 million per year, and total nonlabor capital costs of $65.5 million per 

year. This estimate includes initial and 

annual performance test, conducting an 

documenting an energy assessment, 

conducting fuel specifications for Gas 1 

units, repeat testing under worst-case 

conditions for solid fuel units, 

conducting and documenting a tune-up, 

semiannual excess emission reports, 

maintenance inspections, developing a 

monitoring plan, notifications, and 

recordkeeping. Monitoring, testing, 

tune-up and energy assessment costs 

and cost were also included in the cost 

estimates presented in the control costs 

impacts estimates in section VII.D of 

this preamble. The total burden for the 

Federal government (averaged over the 

first 3 years after the effective date of the 

standard) is estimated to be 97,613 

hours per year at a total labor cost of 

$5.1 million per year. Burden is defined 

at 5 CFR 1320.3(b). 

An agency may not conduct or 

sponsor, and a person is not required to 

respond to, a collection of information 

unless it displays a currently valid OMB 

control number. The OMB control 

numbers for the EPA’s regulations in 40 

CFR are listed in 40 CFR part 9. 

To comment on the agency’s need for 

this information, the accuracy of the 

provided burden estimates, and any 

suggested methods for minimizing 

respondent burden, the EPA has 

established a public docket for this rule, 

which includes this ICR, under Docket 

ID number EPA–HQ–OAR–2002–0058. 

Submit any comments related to the ICR 

to the EPA and OMB. See ADDRESSES

section at the beginning of this notice 

for where to submit comments to the 

EPA. Send comments to OMB at the 

Office of Information and Regulatory 

Affairs, Office of Management and 

Budget, 725 17th Street NW., 

Washington, DC 20503, Attention: Desk 

Office for the EPA. Since OMB is 

required to make a decision concerning 

the ICR between 30 and 60 days after 

December 23, 2011, a comment to OMB 


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3Small entities include small businesses, small 

organizations, and small governmental 

jurisdictions. For purposes of assessing the impacts 

of today’s rule on small entities, small entity is 

defined as: (1) A small business according to Small 

Business Administration (SBA) size standards by 

the North American Industry Classification System 

category of the owning entity. The range of small 

business size standards for the affected industries 

ranges from 500 to 1,000 employees, except for 

petroleum refining and electric utilities. In these 

latter two industries, the size standard is 1,500 

employees and a mass throughput of 75,000 barrels/ 

day or less, and 4 million kilowatt-hours of 

production or less, respectively; (2) a small 

governmental jurisdiction that is a government of a 

city, county, town, school district or special district 

with a population of less than 50,000; and (3) a 

small organization that is any not-for-profit 

enterprise which is independently owned and 

operated and is not dominant in its field. 

is best assured of having its full effect 

if OMB receives it by January 23, 2012. 

The final rule will respond to any OMB 

or public comments on the information 

collection requirements contained in 

this proposal. 

C. Regulatory Flexibility Act 

The Regulatory Flexibility Act (RFA) 

generally requires an agency to prepare 

a regulatory flexibility analysis of any 

rule subject to notice and comment 

rulemaking requirements under the 

Administrative Procedure Act or any 

other statute unless the agency certifies 

that the rule will not have a significant 

economic impact on a substantial 

number of small entities.3 The RFA also 

allows an agency to ‘‘consider a series 

of closely related rules as one rule for 

the purposes of sections’’ 603 (initial 

regulatory flexibility analysis) and 604 

(final regulatory flexibility analysis) in 

order to avoid ‘‘duplicative action.’’ 5 

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

closely related to the final major source 

rule, which the EPA signed on February 

21, 2011. The EPA prepared initial 

regulatory flexibility analyses in 

connection with the major source rule. 

Therefore, pursuant to § 605(c), the EPA 

is not required to complete an initial 

regulatory flexibility analysis for this 

rule. 

The EPA has been concerned with 

potential small entity impacts since it 

began developing the major source rule. 

The EPA conducted outreach to small 

entities and, pursuant to § 609 of RFA, 

convened a Small Business Advocacy 

Review Panel to obtain advice and 

recommendations from small entity 

representatives. 

Pursuant to the RFA, the EPA used 

the Panel’s report and prepared both an 

initial regulatory flexibility analysis and 

a final regulatory flexibility analysis in 

connection with the closely related 

major source rule. Convening an 

additional Panel and preparing an 

additional initial regulatory flexibility 

analysis would be procedurally 

duplicative and is unnecessary given 

that the issues here are within the scope 

of those considered by the Panel. In 

addition, this reconsideration proposal 

would decrease capital and annualized 

costs on small entities by about 3 

percent and 10 percent, respectively, 

relative to the closely related final rule. 

We invite comments on the aspects of 

the proposal outlined in section V of 

this preamble and their impacts on 

small entities. 

D. Unfunded Mandates Reform Act 

Title II of the Unfunded Mandates 

Reform Act of 1995 (UMRA), 2 U.S.C. 

1531–1538, requires federal agencies, 

unless otherwise prohibited by law, to 

assess the effects of their regulatory 

actions on state, local, and tribal 

governments and the private sector. 

This March 21, 2011, final rule 

contained a federal mandate that may 

result in expenditures of $100 million or 

more for state, local, and tribal 

governments, in the aggregate, or the 

private sector in any one year. 

Accordingly, the EPA prepared under 

section 202 of the UMRA a written 

statement for the final rule. The 

discussion below has been updated to 

reflect the proposed changes. 

1. Statutory Authority 

As discussed in section I of this 

preamble, the statutory authority for this 

proposed rulemaking is section 112 of 

the CAA. Title III of the CAA 

Amendments was enacted to reduce 

nationwide air toxic emissions. Section 

112(b) of the CAA lists the 188 

chemicals, compounds, or groups of 

chemicals deemed by Congress to be 

HAP. These toxic air pollutants are to be 

regulated by NESHAP. 

Section 112(d) of the CAA directs us 

to develop NESHAP which require 

existing and new major sources to 

control emissions of HAP using MACT 

based standards. This NESHAP applies 

to all ICI boilers and process heaters 

located at major sources of HAP 

emissions. 

2. Social Costs and Benefits 

The regulatory impact analysis 

prepared for the final rule, which we 

have not revised for this proposed rule, 

including the agency’s assessment of 

costs and benefits, is detailed in the 

‘‘Regulatory Impact Analysis for the 

Final Industrial Boilers and Process 

Heaters MACT (2011)’’ in the docket. 

Based on estimated compliance costs 

associated with this proposed rule and 

the predicted change in prices and 

production in the affected industries, 

the estimated social costs of this 

proposed rule are $1.49 billion (2008 

dollars). 

It is estimated that 3 years after 

implementation of this proposed rule, 

HAP would be reduced by 45,000 tons 

per year, including reductions in HCl, 

hydrogen fluoride, metallic HAP 

including Hg, and several other organic 

HAP from boilers and process heaters. 

Studies have determined a relationship 

between exposure to these HAP and the 

onset of cancer, however, the agency is 

unable to provide a monetized estimate 

of the HAP benefits at this time. In 

addition, there are significant annual 

reductions in fine particulate matter 

(PM2.5) and in SO2 that would occur, 

including 25,000 thousand tons of PM2.5

and 558 thousand tons of SO2. These 

reductions occur within 3 years after the 

implementation of the proposed 

regulation and are expected to continue 

throughout the life of the affected 

sources. The major health effect 

associated with reducing PM2.5 and 

PM2.5 precursors (such as SO2) is a 

reduction in premature mortality. Other 

health effects associated with PM2.5

emission reductions include avoiding 

cases of chronic bronchitis, heart 

attacks, asthma attacks, and work-lost 

days (i.e., days when employees are 

unable to work). While we are unable to 

monetize the benefits associated with 

the HAP emissions reductions, we are 

able to monetize the benefits associated 

with the PM2.5 and SO2 emissions 

reductions. For SO2 and PM2.5, we 

estimated the benefits associated with 

health effects of PM but were unable to 

quantify all categories of benefits 

(particularly those associated with 

ecosystem and visibility effects). Our 

estimates of the monetized benefits in 

2015 associated with the 

implementation of the proposed 

alternative range from $27 billion (2008 

dollars) to $67 billion (2008 dollars) 

when using a 3 percent discount rate (or 

from $25 billion (2008 dollars) to $61 

billion (2008 dollars) when using a 7 

percent discount rate). This estimate, at 

a 3 percent discount rate, is about $25 

billion (2008 dollars) to $65 billion 

(2008 dollars) higher than the estimated 

social costs shown earlier in this 

section. The general approach used to 

value benefits is discussed in more 

detail earlier in this preamble. For more 

detailed information on the benefits 

estimated for the rulemaking, refer to 

the RIA and the memos updating the 

impacts and benefits in the docket. 

3. Future and Disproportionate Costs 

The UMRA requires that we estimate, 

where accurate estimation is reasonably 

feasible, future compliance costs 

imposed by this proposed rule and any 


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disproportionate budgetary effects. Our 

estimates of the future compliance costs 

of the rule are discussed previously in 

this preamble. 

We do not believe that there will be 

any disproportionate budgetary effects 

of this proposed rule on any particular 

areas of the country, state or local 

governments, types of communities 

(e.g., urban, rural), or particular industry 

segments. See the results of the 

‘‘Regulatory Impact Analysis for the 

Final Industrial Boilers and Process 

Heaters MACT (2011).’’ 

4. Effects on the National Economy 

The UMRA requires that we estimate 

the effect of this proposed rule on the 

national economy. To the extent 

feasible, we must estimate the effect on 

productivity, economic growth, full 

employment, creation of productive 

jobs, and international competitiveness 

of the U.S. goods and services, if we 

determine that accurate estimates are 

reasonably feasible and that such effect 

is relevant and material. 

The nationwide economic impact of 

this proposed rule is presented in the 

‘‘Regulatory Impact Analysis for the 

Final Industrial Boilers and Process 

Heaters MACT (2011)’’ and two 

memoranda that are included in the 

docket, entitled ‘‘Health Benefits for 

Boiler MACT Reconsideration Proposal’’ 

and ‘‘Regulatory Impact Results for the 

Reconsideration Proposal for National 

Emission Standards for Hazardous Air 

Pollutants for Industrial, Commercial, 

and Institutional Boilers and Process 

Heaters at Major Sources,’’ which 

update the RIA analyses. This analysis 

provides estimates of the effect of this 

rule on some of the categories 

mentioned above. The results of the 

economic impact analysis are 

summarized previously in this 

preamble. The results show that there 

will be a small impact on prices and 

output, and little impact on 

communities that may be affected by 

this proposed rule. In addition, there 

should be little impact on energy 

markets (in this case, coal, natural gas, 

petroleum products, and electricity). 

Hence, the potential impacts on the 

categories mentioned above should be 

small. 

5. Consultation With Government 

Officials 

The UMRA requires that we describe 

the extent of the agency’s prior 

consultation with affected state, local, 

and tribal officials, summarize the 

officials’ comments or concerns, and 

summarize our response to those 

comments or concerns. In addition, 

section 203 of the UMRA requires that 

we develop a plan for informing and 

advising small governments that may be 

significantly or uniquely impacted by a 

proposal. We consulted with State and 

local air pollution control officials 

during the development of the final 

rule. We have also held meetings on this 

proposed rule with many of the 

stakeholders from numerous individual 

companies, institutions, environmental 

groups, consultants and vendors, labor 

unions, and other interested parties. We 

have added materials to the docket to 

document these meetings. 

Consistent with section 205, the EPA 

has identified and considered a 

reasonable number of regulatory 

alternatives. Additional information on 

the costs and environmental impacts of 

these regulatory alternatives is 

presented in the docket. The regulatory 

alternative upon which the emission 

limits in this proposed rule are based 

represents the MACT floors for all 

subcategories and, as a result, it is the 

least costly and least burdensome 

alternative. 

This rule is not subject to the 

requirements of section 203 of UMRA 

because it contains no regulatory 

requirements that might significantly or 

uniquely affect small governments. 

While some small governments may 

have some sources affected by this 

proposed rule, the impacts are not 

expected to be significant. Therefore, 

this proposed rule is not subject to the 

requirements of section 203 of the 

UMRA. 

E. Executive Order 13132: Federalism 

This action does not have federalism 

implications. It will not have substantial 

direct effects on the states, on the 

relationship between the national 

government and the states, or on the 

distribution of power and 

responsibilities among the various 

levels of government, as specified in 

Executive Order 13132. This proposed 

rule will not impose direct compliance 

costs on state or local governments, and 

will not preempt state law. Thus, 

Executive Order 13132 does not apply 

to this action. 

In the spirit of Executive Order 13132, 

and consistent with EPA policy to 

promote communications between the 

EPA and state and local governments, 

the EPA specifically solicits comment 

on this proposed action from state and 

local officials. 

F. Executive Order 13175: Consultation 

and Coordination With Indian Tribal 

Governments 

This action does not have tribal 

implications, as specified in Executive 

Order 13175 (65 FR 67249, November 9, 

2000). It 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 (62 FR 19885, April 23, 1997) as 

applying only to those regulatory 

actions that concern health or safety 

risks, such that the analysis required 

under section 5–501 of the Executive 

Order has the potential to influence the 

regulation. This action is not subject to 

Executive Order 13045 because it is 

based solely on technology 

performance. 

H. Executive Order 13211: Actions 

Concerning Regulations That 

Significantly Affect Energy Supply, 

Distribution, or Use 

This action is not a ‘‘significant 

energy action’’ as defined in Executive 

Order 13211 (66 FR 28355, May 22, 

2001), because it is not likely to have a 

significant adverse effect on the supply, 

distribution, or use of energy. For the 

March 21, 2011, final rule, we estimated 

a 0.05 percent price increase for the 

energy sector and a ¥0.02 percent 

percentage change in production. We 

estimated a 0.09 percent increase in 

energy imports. For more information 

on the estimated energy effects, please 

refer to the ‘‘Regulatory Impact Analysis 

for the Final Industrial Boilers and 

Process Heaters MACT (2011).’’ The 

analysis is available in the public 

docket. While we did not redo the RIA 

for this proposed action, the energy 

impacts for existing sources decreased 

slightly, and the energy impacts for new 

source increased due to the increased 

number of new sources that is now 

projected. Overall, the projected energy 

use increased slightly but would not 

change the analysis that was conducted 

for the final rule. Therefore, we 

conclude that the proposed rule when 

implemented 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 


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Act of 1995 (NTTAA), Public Law 104– 

113,(15 U.S.C. 272 note) directs the EPA 

to use voluntary consensus standards in 

its regulatory activities unless to do so 

would be inconsistent with applicable 

law or otherwise impractical. Voluntary 

consensus standards are technical 

standards (e.g., materials specifications, 

test methods, sampling procedures, and 

business practices) that are developed or 

adopted by voluntary consensus 

standards bodies. NTTAA directs the 

EPA to provide Congress, through OMB, 

explanations when the agency decides 

not use available and applicable 

voluntary consensus standards. The 

EPA is not proposing the use of any 

additional EPA test methods, and, 

therefore, the NTTAA discussion in the 

March 21, 2011, final rule is still valid. 

See 76 FR 15660–15662. 

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. 

For the March 2011 final rule, the 

EPA determined that rule would not 

have disproportionately high and 

adverse human health or environmental 

effects on minority or low-income 

populations because it increases the 

level of environmental protection for all 

affected populations without having any 

disproportionately high and adverse 

human health or environmental effects 

on any population, including any 

minority or low-income population. 

Compared to the final rule, while the 

proposed amendments are somewhat 

less stringent for some subcategories of 

units and more stringent for some 

others, the overall increased health 

benefits demonstrate that the 

conclusions from the environmental 

justice analysis conducted for the final 

rule are still valid. 

List of Subjects in 40 CFR Part 63 

Environmental protection, 

Administrative practice and procedure, 

Air pollution control, Hazardous 

substances, Intergovernmental relations, 

Reporting and recordkeeping 

requirements. 

Dated: December 2, 2011. 

Lisa P. Jackson, 

Administrator. 

For the reasons cited in the preamble, 

and under the authority of 42 U.S.C. 

7401 et seq., Subpart DDDDD of 40 CFR 

part 63 is proposed to be revised to read 

as follows: 

PART 63—[AMENDED] 

Subpart DDDDD—National Emission 

Standards for Hazardous Air Pollutants 

for Major Sources: Industrial, 

Commercial, and Institutional Boilers 

and Process Heaters 

Sec. 

What This Subpart Covers 

63.7480 What is the purpose of this 

subpart? 

63.7485 Am I subject to this subpart? 

63.7490 What is the affected source of this 

subpart? 

63.7491 Are any boilers or process heaters 

not subject to this subpart? 

63.7495 When do I have to comply with 

this subpart? 

Emission Limitations and Work Practice 

Standards 

63.7499 What are the subcategories of boilers 

and process heaters? 

63.7500 What emission limitations, work 

practice standards, and operating limits 

must I meet? 

63.7501 How can I assert an affirmative 

defense if I exceed an emission 

limitations during a malfunction? 

General Compliance Requirements 

63.7505 What are my general requirements 

for complying with this subpart? 

Testing, Fuel Analyses, and Initial 

Compliance Requirements 

63.7510 What are my initial compliance 

requirements and by what date must I 

conduct them? 

63.7515 When must I conduct subsequent 

performance tests, fuel analyses, or tuneups? 

63.7520 What stack tests and procedures 

must I use? 

63.7521 What fuel analyses, fuel 

specification, and procedures must I use? 

63.7522 Can I use emissions averaging to 

comply with this subpart? 

63.7525 What are my monitoring, 

installation, operation, and maintenance 

requirements? 

63.7530 How do I demonstrate initial 

compliance with the emission 

limitations, fuel specifications and work 

practice standards? 

63.7533 Can I use emission credits earned 

from implementation of energy 

conservation measures to comply with 

this subpart? 

Continuous Compliance Requirements 

63.7535 Is there a minimum amount of 

monitoring data I must obtain? 

63.7540 How do I demonstrate continuous 

compliance with the emission 

limitations, fuel specifications and work 

practice standards? 

63.7541 How do I demonstrate continuous 

compliance under the emissions 

averaging provision? 

Notification, Reports, and Records 

63.7545 What notifications must I submit 

and when? 

63.7550 What reports must I submit and 

when? 

63.7555 What records must I keep? 

63.7560 In what form and how long must I 

keep my records? 

Other Requirements and Information 

63.7565 What parts of the General 

Provisions apply to me? 

63.7570 Who implements and enforces this 

subpart? 

63.7575 What definitions apply to this 

subpart? 

Tables to Subpart DDDDD of Part 63 

Table 1 to Subpart DDDDD of Part 63— 

Emission Limits for New or 

Reconstructed Boilers and Process 

Heaters 

Table 2 to Subpart DDDDD of Part 63— 

Emission Limits for Existing Boilers and 

Process Heaters (Units with heat input 

capacity of 10 million Btu per hour or 

greater) 

Table 3 to Subpart DDDDD of Part 63—Work 

Practice Standards 

Table 4 to Subpart DDDDD of Part 63— 

Operating Limits for Boilers and Process 

Heaters 

Table 5 to Subpart DDDDD of Part 63— 

Performance Testing Requirements 

Table 6 to Subpart DDDDD of Part 63—Fuel 

Analysis Requirements 

Table 7 to Subpart DDDDD of Part 63— 

Establishing Operating Limits 

Table 8 to Subpart DDDDD of Part 63— 

Demonstrating Continuous Compliance 

Table 9 to Subpart DDDDD of Part 63— 

Reporting Requirements 

Table 10 to Subpart DDDDD of Part 63— 

Applicability of General Provisions to 

Subpart DDDDD 

What This Subpart Covers 

§ 63.7480 What is the purpose of this 

subpart? 

This subpart establishes national 

emission limitations and work practice 

standards for hazardous air pollutants 

(HAP) emitted from industrial, 

commercial, and institutional boilers 

and process heaters located at major 

sources of HAP. This subpart also 

establishes requirements to demonstrate 

initial and continuous compliance with 

the emission limitations and work 

practice standards. 

§ 63.7485 Am I subject to this subpart? 

You are subject to this subpart if you 

own or operate an industrial, 

commercial, or institutional boiler or 

process heater as defined in § 63.7575 

that is located at, or is part of, a major 

source of HAP, except as specified in 


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§ 63.7491. For purposes of this subpart, 

a major source of HAP is as defined in 

§ 63.2, except that for oil and natural gas 

production facilities, a major source of 

HAP is as defined in § 63.761 (subpart 

HH of this part, National Emission 

Standards for Hazardous Air Pollutants 

from Oil and Natural Gas Production 

Facilities). 

§ 63.7490 What is the affected source of 

this subpart? 

(a) This subpart applies to new, 

reconstructed, and existing affected 

sources as described in paragraphs (a)(1) 

and (2) of this section. 

(1) The affected source of this subpart 

is the collection at a major source of all 

existing industrial, commercial, and 

institutional boilers and process heaters 

within a subcategory as defined in 

§ 63.7575. 

(2) The affected source of this subpart 

is each new or reconstructed industrial, 

commercial, or institutional boiler or 

process heater, as defined in § 63.7575, 

located at a major source. 

(b) A boiler or process heater is new 

if you commence construction of the 

boiler or process heater after June 4, 

2010, and you meet the applicability 

criteria at the time you commence 

construction. 

(c) A boiler or process heater is 

reconstructed if you meet the 

reconstruction criteria as defined in 

§ 63.2, you commence reconstruction 

after June 4, 2010, and you meet the 

applicability criteria at the time you 

commence reconstruction. 

(d) A boiler or process heater is 

existing if it is not new or reconstructed. 

§ 63.7491 Are any boilers or process 

heaters not subject to this subpart? 

The types of boilers and process 

heaters listed in paragraphs (a) through 

(n) of this section are not subject to this 

subpart. 

(a) An electric utility steam generating 

unit. 

(b) A recovery boiler or furnace 

covered by subpart MM of this part. 

(c) A boiler or process heater that is 

used specifically for research and 

development. This does not include 

units that provide heat or steam to a 

process at a research and development 

facility. 

(d) A hot water heater as defined in 

this subpart. 

(e) A refining kettle covered by 

subpart X of this part. 

(f) An ethylene cracking furnace 

covered by subpart YY of this part. 

(g) Blast furnace stoves as described 

in EPA–453/R–01–005 (incorporated by 

reference, see § 63.14). 

(h) Any boiler or process heater that 

is part of the affected source subject to 

another subpart of this part (i.e., another 

National Emission Standards for 

Hazardous Air Pollutants in 40 CFR part 

63). 

(i) Any boiler or process heater that is 

used as a control device to comply with 

another subpart of this part, or part 60 

or part 61 of this chapter provided that 

at least 50 percent of the heat input to 

the boiler or process heater is provided 

by the gas stream that is regulated under 

another subpart. 

(j) Temporary boilers as defined in 

this subpart. 

(k) Blast furnace gas fuel-fired boilers 

and process heaters as defined in this 

subpart. 

(l) Any boiler specifically listed as an 

affected source in any standard(s) 

established under section 129 of the 

Clean Air Act. 

(m) A unit that burns hazardous waste 

covered by Subpart EEE of this part. A 

unit that is exempt from Subpart EEE as 

specified in § 63.1200(b) is not covered 

by Subpart EEE. 

(n) Residential boilers as defined in 

this subpart. 

§ 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 [DATE 60 

DAYS AFTER THE FINAL RULE IS 

PUBLISHED IN THE Federal Register] 

or upon startup of your boiler or process 

heater, whichever is later. 

(b) If you have an existing boiler or 

process heater, you must comply with 

this subpart no later than [DATE 3 

YEARS AFTER PUBLICATION OF THE 

FINAL RULE IN THE Federal Register], 

except as provided in § 63.6(i). 

(c) If you have an area source that 

increases its emissions or its potential to 

emit such that it becomes a major source 

of HAP, paragraphs (c)(1) and (2) of this 

section apply to you. 

(1) Any new or reconstructed boiler or 

process heater at the existing source 

must be in compliance with this subpart 

upon startup. 

(2) Any existing boiler or process 

heater at the existing source must be in 

compliance with this subpart within 3 

years after the source becomes a major 

source. 

(d) You must meet the notification 

requirements in § 63.7545 according to 

the schedule in § 63.7545 and in subpart 

A of this part. Some of the notifications 

must be submitted before you are 

required to comply with the emission 

limits and work practice standards in 

this subpart. 

(e) If you own or operate an 

industrial, commercial, or institutional 

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 

on the effective date of the switch from 

waste to fuel. 

Emission Limitations and Work 

Practice Standards 

§ 63.7499 What are the subcategories of 

boilers and process heaters? 

The subcategories of boilers and 

process heaters, as defined in § 63.7575 

are: 

(a) Pulverized coal/solid fossil fuel 

units. 

(b) Stokers designed to burn coal/ 

solid fossil fuel. 

(c) Fluidized bed units designed to 

burn coal/solid fossil fuel. 

(d) Stokers/sloped grate/other units 

designed to burn kiln dried biomass/ 

bio-based solids. 

(e) Stokers/sloped grate/other units 

designed to burn wet biomass/bio-based 

solids. 

(f) Fluidized bed units designed to 

burn biomass/bio-based solid. 

(g) Suspension burners designed to 

burn biomass/bio-based solid. 

(h) Dutch ovens/pile burners designed 

to burn biomass/bio-based solid. 

(i) Fuel cells designed to burn 

biomass/bio-based solid. 

(j) Hybrid suspension/grate burners 

designed to burn wet biomass/bio-based 

solid. 

(k) Units designed to burn solid fuel. 

(l) Units designed to burn liquid fuel. 

(m) Units designed to burn heavy 

liquid fuel. 

(n) Units designed to burn light liquid 

fuel. 

(o) Units designed to burn liquid fuel 

in non-continental states or territories. 

(p) Units designed to burn natural gas, 

refinery gas or other gas 1 fuels. 

(q) Units designed to burn gas 2 

(other) gases. 

(r) Metal process furnaces. 

(s) Limited-use boilers and process 

heaters. 

§ 63.7500 What emission limitations, work 

practice standards, and operating limits 

must I meet? 

(a) You must meet the requirements in 

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

section, except as provided in 

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

section. You must meet these 

requirements at all times, except as 

provided in paragraph (e) of this 

section. 

(1) You must meet each emission 

limit and work practice standard in 


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Tables 1 through 3 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 (i.e., 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 that generate 

steam. The output-based emission limits 

are not applicable to process heaters 

that do not generate steam. 

(2) You must meet each operating 

limit in Table 4 to this subpart that 

applies to your boiler or process heater. 

If you use a control device or 

combination of control devices not 

covered in Table 4 to this subpart, or 

you wish to establish and monitor an 

alternative operating limit and 

alternative monitoring parameters, you 

must apply to the EPA Administrator for 

approval of alternative monitoring 

under § 63.8(f). 

(3) At all times, you must operate and 

maintain any affected source, including 

associated air pollution control 

equipment and monitoring equipment, 

in a manner consistent with safety and 

good air pollution control practices for 

minimizing emissions. Determination of 

whether such operation and 

maintenance procedures are being used 

will be based on information available 

to the Administrator that may include, 

but is not limited to, monitoring results, 

review of operation and maintenance 

procedures, review of operation and 

maintenance records, and inspection of 

the source. 

(b) As provided in § 63.6(g), EPA may 

approve use of an alternative to the 

work practice standards in this section. 

(c) Limited-use boilers and process 

heaters must complete a biennial tuneup as specified in § 63.7540. They are 

not subject to the emission limits in 

Tables 1 and 2 to this subpart, the 

annual tune-up requirement in Table 3 

to this subpart, or the operating limits 

in Table 4 to this subpart. Major sources 

that have limited-use boilers and 

process heaters must complete an 

energy assessment as specified in Table 

3 to this subpart if the source has other 

existing boilers subject to this subpart 

that are not limited-use boilers. 

(d) Boilers and process heaters with a 

heat input capacity of less than 5 

million Btu per hour in the units 

designed to burn natural gas, refinery 

gas or other gas 1 fuels subcategory; 

units designed to burn gas 2 (other) 

fuels subcategory, or units designed to 

burn light liquid fuels subcategory must 

complete a tune-up every 5 years as 

specified in § 63.7540. 

(e) These standards apply at all times, 

except during periods of startup and 

shutdown, during which time you must 

comply only with Table 3 to this 

subpart. 

§ 63.7501 How can I assert an affirmative 

defense if I exceed an emission limitations 

during a malfunction? 

In response to an action to enforce the 

emission limitations and operating 

limits set forth in § 63.7500 you may 

assert an affirmative defense to a claim 

for civil penalties for exceeding such 

standards that are caused by 

malfunction, as defined at § 63.2. 

Appropriate penalties may be assessed, 

however, if you fail to meet your burden 

of proving all of the requirements in the 

affirmative defense. The affirmative 

defense shall not be available for claims 

for injunctive relief. 

(a) To establish the affirmative 

defense in any action to enforce such a 

limit, you must timely meet the 

notification requirements in paragraph 

(b) of this section, and must prove by a 

preponderance of evidence that: 

(1) The excess emissions: 

(i) Were caused by a sudden, 

infrequent, and unavoidable failure of 

air pollution control and monitoring 

equipment, process equipment, or a 

process to operate in a normal or usual 

manner, and 

(ii) Could not have been prevented 

through careful planning, proper design 

or better operation and maintenance 

practices; and 

(iii) Did not stem from any activity or 

event that could have been foreseen and 

avoided, or planned for; and 

(iv) Were not part of a recurring 

pattern indicative of inadequate design, 

operation, or maintenance; and 

(2) Repairs were made as 

expeditiously as possible when the 

applicable emission limitations were 

being exceeded. Off-shift and overtime 

labor were used, to the extent 

practicable to make these repairs; and 

(3) The frequency, amount and 

duration of the excess emissions 

(including any bypass) were minimized 

to the maximum extent practicable 

during periods of such emissions; and 

(4) If the excess emissions resulted 

from a bypass of control equipment or 

a process, then the bypass was 

unavoidable to prevent loss of life, 

personal injury, or severe property 

damage; and 

(5) All possible steps were taken to 

minimize the impact of the excess 

emissions on ambient air quality, the 

environment and human health; and 

(6) All emissions monitoring and 

control systems were kept in operation 

if at all possible, consistent with safety 

and good air pollution control practices; 

and 

(7) All of the actions in response to 

the excess emissions were documented 

by properly signed, contemporaneous 

operating logs; and 

(8) At all times, the facility was 

operated in a manner consistent with 

good practices for minimizing 

emissions; and 

(9) A written root cause analysis has 

been prepared, the purpose of which is 

to determine, correct, and eliminate the 

primary causes of the malfunction and 

the excess emissions resulting from the 

malfunction event at issue. The analysis 

shall also specify, using best monitoring 

methods and engineering judgment, the 

amount of excess emissions that were 

the result of the malfunction. 

(b) Notification. The owner or 

operator of the facility experiencing an 

exceedance of its emission limitation(s) 

during a malfunction shall notify the 

Administrator by telephone or facsimile 

(fax) transmission as soon as possible, 

but no later than 2 business days after 

the initial occurrence of the 

malfunction, if it wishes to avail itself 

of an affirmative defense to civil 

penalties for that malfunction. The 

owner or operator seeking to assert an 

affirmative defense shall also submit a 

written report to the Administrator 

within 45 days of the initial occurrence 

of the exceedance of the standard in 

§ 63.7500 to demonstrate, with all 

necessary supporting documentation, 

that it has met the requirements set forth 

in paragraph (a) of this section. The 

owner or operator may seek an 

extension of this deadline for up to 30 

additional days by submitting a written 

request to the Administrator before the 

expiration of the 45-day period. Until a 

request for an extension has been 

approved by the Administrator, the 

owner or operator is subject to the 

requirement to submit such report 

within 45 days of the initial occurrence 

of the exceedance. 

General Compliance Requirements 

§ 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 limits apply to you at all 

times except for the periods noted in 

§ 63.7500(e). 

(b) [Reserved] 

(c) You must demonstrate compliance 

with all applicable emission limits 

using performance testing, fuel analysis, 

or continuous monitoring systems 

(CMS), including a continuous 

emissions monitoring system (CEMS), 

continuous opacity monitoring system 

(COMS), continuous parameter 


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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, 

mercury, or total selected metals 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 total 

selected metals alternative standard or 

the hydrogen chloride standard.) 

Otherwise, you must demonstrate 

compliance for hydrogen chloride, 

mercury, or total selected metals using 

performance testing, if subject to an 

applicable emission limit listed in Table 

1 or 2 to this subpart. 

(d) If you demonstrate compliance 

with any applicable emission limit 

through performance testing and 

subsequent compliance with operating 

limits (including the use of CPMS), or 

with a CEMS, or COMS, you must 

develop a site-specific monitoring plan 

according to the requirements in 

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

section for the use of any CEMS, COMS, 

or CPMS. This requirement also applies 

to you if you petition the EPA 

Administrator for alternative monitoring 

parameters under § 63.8(f). 

(1) For each CMS required in this 

section (including CEMS, COMS, or 

CPMS), you must develop, and submit 

to the delegated authority for approval 

upon request, a site-specific monitoring 

plan that addresses design, data 

collection, and the quality assurance 

and quality control elements outlined in 

§ 63.8(d) and the elements described in 

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

section. You must submit this sitespecific monitoring plan, if requested, at 

least 60 days before your initial 

performance evaluation of your CMS. 

This requirement to develop and submit 

a site specific monitoring plan does not 

apply to affected sources with existing 

monitoring plans that apply to CEMS 

and COMS prepared under appendix B 

to part 60 of this chapter and that meet 

the requirements of § 63.7525. Using the 

process described in § 63.8(f)(4), you 

may request approval of alternative 

monitoring system quality assurance 

and quality control procedures in place 

of those specified in this paragraph and, 

if approved, include the alternatives in 

your site-specific monitoring plan. 

(i) Installation of the CMS sampling 

probe or other interface at a 

measurement location relative to each 

affected process unit such that the 

measurement is representative of 

control of the exhaust emissions (e.g., 

on or downstream of the last control 

device); 

(ii) Performance and equipment 

specifications for the sample interface, 

the pollutant concentration or 

parametric signal analyzer, and the data 

collection and reduction systems; and 

(iii) Performance evaluation 

procedures and acceptance criteria (e.g., 

calibrations, accuracy audits, analytical 

drift). 

(2) In your site-specific monitoring 

plan, you must also address paragraphs 

(d)(2)(i) through (iii) of this section. 

(i) Ongoing operation and 

maintenance procedures in accordance 

with the general requirements of 

§ 63.8(c)(1)(ii), (c)(3), and (c)(4)(ii); 

(ii) Ongoing data quality assurance 

procedures in accordance with the 

general requirements of § 63.8(d); and 

(iii) Ongoing recordkeeping and 

reporting procedures in accordance with 

the general requirements of § 63.10(c) 

(as applicable in Table 10 to this 

subpart), (e)(1), and (e)(2)(i). 

(3) You must conduct a performance 

evaluation of each CMS in accordance 

with your site-specific monitoring plan. 

(4) You must operate and maintain 

the CMS in continuous operation 

according to the site-specific monitoring 

plan. 

Testing, Fuel Analyses, and Initial 

Compliance Requirements 

§ 63.7510 What are my initial compliance 

requirements and by what date must I 

conduct them? 

(a) For affected sources that are 

required to or elect to demonstrate 

compliance with any of the applicable 

emission limits in Tables 1 or 2 of this 

subpart through performance testing, 

your initial compliance requirements 

include all the following: 

(1) Conduct performance tests 

according to § 63.7520 and Table 5 to 

this subpart. 

(2) Conduct a fuel analysis for each 

type of fuel burned in your boiler or 

process heater according to § 63.7521 

and Table 6 to this subpart, except as 

specified in paragraphs (a)(2)(i) through 

(iii) of this section. 

(i) For affected sources that burn a 

single type of fuel, you are not required 

to conduct a fuel analysis for each type 

of fuel burned in your boiler or process 

heater according to § 63.7521 and Table 

6 to this subpart. For purposes of this 

subpart, units that use a supplemental 

fuel only for startup, unit shutdown, 

and transient flame stability purposes 

still qualify as affected sources that burn 

a single type of fuel, and the 

supplemental fuel is not subject to the 

fuel analysis requirements under 

§ 63.7521 and Table 6 to this subpart. 

(ii) When natural gas, refinery gas, 

other gas 1 fuels are co-fired with other 

fuels, you are not required to conduct a 

fuel analysis of those 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 cofired with other fuels and those gaseous 

fuels are subject to another subpart of 

this part, you are not required to 

conduct a fuel analysis of those fuels 

according to § 63.7521 and Table 6 to 

this subpart. 

(iii) You are not required to conduct 

a chlorine fuel analysis for any gaseous 

fuels. You must still conduct a fuel 

analysis for mercury on gaseous fuels 

unless the fuel is exempted in 

paragraphs (a)(2)(i) through (iii) of this 

section. 

(3) Establish operating limits 

according to § 63.7530 and Table 7 to 

this subpart. 

(4) Conduct CMS performance 

evaluations according to § 63.7525. 

(b) For affected sources that elect to 

demonstrate compliance with the 

applicable emission limits in Tables 1 or 

2 of this subpart for hydrogen chloride, 

mercury or total selected metals through 

fuel analysis, your initial compliance 

requirement is to conduct a fuel analysis 

for each type of fuel burned in your 

boiler or process heater according to 

§ 63.7521 and Table 6 to this subpart 

and establish operating limits according 

to § 63.7530 and Table 8 to this subpart. 

The fuels described in paragraph 

(a)(2)(i) through (iii) of this section are 

exempt from these fuel analysis and 

operating limit requirements. Boilers 

and process heaters that use a CEMS for 

mercury or hydrogen chloride are 

exempt from the performance testing 

and operating limit requirements 

specified in paragraph (a) of this 

section. 

(c) If your boiler or process heater is 

subject to a carbon monoxide limit, your 

initial compliance demonstration for 

carbon monoxide is to conduct a 

performance test for carbon monoxide 

according to Table 5 to this subpart, or 

conduct a performance evaluation of 

your continuous carbon monoxide 

monitor, if applicable, according to 

§ 63.7525(a). Boilers and process heaters 

that use a continuous emission 

monitoring system for carbon monoxide 

are exempt from the initial carbon 

monoxide performance testing and 

oxygen concentration operating limit 

requirements specified in paragraph (a) 

of this section. 

(d) If your boiler or process heater 

subject to a PM limit has an average 

annual heat input rate greater than 250 

MMBtu per hour from solid fossil fuel 

and/or residual oil, your initial 


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compliance demonstration for PM is to 

conduct a performance test in 

accordance with § 63.7520 and Table 5 

to this subpart. Owners of boilers and 

process heaters who elect to comply 

with the alternative total selected metals 

limit are not required to install a CPMS. 

(e) For existing affected sources, you 

must complete the initial compliance 

demonstration, 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. You must complete an initial 

tune-up by following the procedures 

described in § 63.7540(a)(10)(i) through 

(vi) and complete the one-time energy 

assessment specified in Table 3 to this 

subpart, both no later than the 

compliance date specified in § 63.7495. 

(f) For new or reconstructed affected 

sources, you must complete the initial 

compliance demonstration with the 

emission limits no later than [DATE 240 

DAYS AFTER PUBLICATION OF THE 

FINAL RULE IN THE Federal Register] 

or within 180 days after startup of the 

source, whichever is later. 

(g) For new or reconstructed affected 

sources, you must demonstrate initial 

compliance with the applicable work 

practice standards in Table 3 to this 

subpart no later than the compliance 

date that is specified in § 63.7595 and 

according to the applicable provisions 

in § 63.7(a)(2). You must conduct the 

initial tune-up within 365 days after 

startup of the source. Thereafter, you are 

required to complete the applicable 

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

specified in § 63.7540(a). 

(h) For affected sources that ceased 

burning solid waste consistent with 

§ 63.7495(e) and for which your initial 

compliance date has passed, you must 

demonstrate compliance within 60 days 

of the effective date of the waste-to-fuel 

switch. If you have not conducted your 

compliance demonstration for this 

subpart within the previous 12 months, 

you must complete all compliance 

demonstrations for this subpart before 

you commence or recommence 

combustion of solid waste. 

§ 63.7515 When must I conduct 

subsequent performance tests, fuel 

analyses, or tune-ups? 

(a) You must conduct all applicable 

performance tests according to § 63.7520 

on an annual basis, except as specified 

in paragraphs (b) through (e) of this 

section. Annual performance tests must 

be completed no more than 13 months 

after the previous performance test, 

except as specified in paragraphs (b) 

through (e) of this section. 

(b) You can conduct performance tests 

less often for a given pollutant if your 

performance tests for the pollutant for at 

least 2 consecutive years show that your 

emissions are at or below 75 percent of 

the emission limit (or, in limited 

instances as specified in Tables 1 and 2 

to this subpart, at or below the emission 

limit) and if there are no changes in the 

operation of the affected source or air 

pollution control equipment that could 

increase emissions. In this case, you do 

not have to conduct a performance test 

for that pollutant for the next 2 years. 

You must conduct a performance test 

during the third year and no more than 

37 months after the previous 

performance test. If you elect to 

demonstrate compliance using emission 

averaging under § 63.7522, you must 

continue to conduct performance tests 

annually. 

(c) If your boiler or process heater 

continues to meet the emission limit for 

the pollutant, you may choose to 

conduct performance tests for the 

pollutant every third year if your 

emissions are at or below 75 percent of 

the emission limit (or, in limited 

instances as specified in Tables 1 and 2 

to this subpart, at or below the emission 

limit) and if there are no changes in the 

operation of the affected source or air 

pollution control equipment that could 

increase emissions, but each such 

performance test must be conducted no 

more than 37 months after the previous 

performance test. If you elect to 

demonstrate compliance using emission 

averaging under § 63.7522, you must 

continue to conduct performance tests 

annually. The requirement to test at 

maximum chloride input level is 

waived unless the stack test is 

conducted for hydrogen chloride. The 

requirement to test at maximum 

mercury input level is waived unless 

the stack test is conducted for mercury. 

The requirement to test at maximum 

total selected metals input level is 

waived unless the stack test is 

conducted for total selected metals. 

(d) If a performance test shows 

emissions exceeded the emission limit 

or 75 percent of the emission limit (as 

specified in Tables 1 and 2) for a 

pollutant, you must conduct annual 

performance tests for that pollutant 

until all performance tests over a 

consecutive 2-year period meet the 

required level (either 75 percent of the 

emission or the emission limit, as 

specified in Tables 1 and 2). 

(e) 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, the first 

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

be no later than 13 months, 25 months, 

or 61 months, respectively, after the 

initial startup of the new or 

reconstructed affected source. 

(f) If you demonstrate compliance 

with the mercury, hydrogen chloride, or 

total selected metals based on fuel 

analysis, you must conduct a monthly 

fuel analysis according to § 63.7521 for 

each type of fuel burned that is subject 

to an emission limit in Table 1 or 2 to 

this subpart. If you burn a new type of 

fuel, you must conduct a fuel analysis 

before burning the new type of fuel in 

your boiler or process heater. You must 

still meet all applicable continuous 

compliance requirements in § 63.7540. 

If 12 consecutive monthly fuel analyses 

demonstrate compliance, you may 

request decreased fuel analysis 

frequency by applying to the EPA 

Administrator for approval of 

alternative monitoring under § 63.8(f). 

(g) You must report the results of 

performance tests and the associated 

initial fuel analyses within 90 days after 

the completion of the performance tests. 

This report must also verify that the 

operating limits for your affected source 

have not changed or provide 

documentation of revised operating 

limits established according to § 63.7530 

and Table 7 to this subpart, as 

applicable. The reports for all 

subsequent performance tests must 

include all applicable information 

required in § 63.7550. 

§ 63.7520 What stack tests and procedures 

must I use? 

(a) You must conduct all performance 

tests according to § 63.7(c), (d), (f), and 

(h). You must also develop a sitespecific stack test plan according to the 

requirements in § 63.7(c). You shall 

conduct all performance tests under 

such conditions as the Administrator 

specifies to you based on representative 

performance of the affected source for 

the period being tested. Upon request, 

you shall make available to the 

Administrator such records as may be 

necessary to determine the conditions of 

the performance tests. 


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(b) You must conduct each 

performance test according to the 

requirements in Table 5 to this subpart. 

(c) You must conduct each 

performance test under the specific 

conditions listed in Tables 5 and 7 to 

this subpart. You must conduct 

performance tests at representative 

operating load conditions while burning 

the type of fuel or mixture of fuels that 

has the highest content of chlorine and 

mercury, and total selected metals if you 

are opting to comply with the total 

selected metals alternative standard, 

and you must demonstrate initial 

compliance and establish your operating 

limits based on these performance tests. 

These requirements could result in the 

need to conduct more than one 

performance test. Following each 

performance test and until the next 

performance test, you must comply with 

the operating limit for operating load 

conditions specified in Table 4 to this 

subpart. 

(d) You must conduct three separate 

test runs for each performance test 

required in this section, as specified in 

§ 63.7(e)(3). Each test run must comply 

with the minimum applicable sampling 

times or volumes specified in Tables 1 

and 2 to this subpart. 

(e) To determine compliance with the 

emission limits, you must use the F– 

Factor methodology and equations in 

sections 12.2 and 12.3 of EPA Method 

19 at 40 CFR part 60, appendix A–7 of 

this chapter to convert the measured 

particulate matter concentrations, the 

measured hydrogen chloride 

concentrations, the measured mercury 

concentrations, and the measured total 

selected metals concentrations that 

result from the initial performance test 

to pounds per million Btu heat input 

emission rates using F-factors. 

§ 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, 

you must also conduct fuel analyses for 

total selected metals if you are opting to 

comply with the total selected metals 

alternative standard. For gas 2 (other) 

fuels, you must conduct fuel analysis 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 

total selected metals alternative 

standard or the hydrogen chloride 

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, 

hydrogen chloride, or total selected 

metals in Tables 1 and 2 to this subpart. 

Gaseous and liquid fuels are exempt 

from the sampling requirements in 

paragraphs (c) and (d) of this section 

and Table 6 of this subpart. 

(b) You must develop and submit a 

site-specific fuel monitoring plan to the 

EPA Administrator for review and 

approval according to the following 

procedures and requirements in 

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

if you are required to conduct fuel 

analyses as specified in § 63.7510. 

(1) You must submit the fuel analysis 

plan no later than 60 days before the 

date that you intend to conduct the 

initial compliance demonstration 

described in § 63.7510. 

(2) You must include the information 

contained in paragraphs (b)(2)(i) 

through (vi) of this section in your fuel 

analysis plan. 

(i) The identification of all fuel types 

anticipated to be burned in each boiler 

or process heater. 

(ii) For each anticipated fuel type, the 

notification of whether you or a fuel 

supplier will be conducting the fuel 

analysis. 

(iii) For each anticipated fuel type, a 

detailed description of the sample 

location and specific procedures to be 

used for collecting and preparing the 

composite samples if your procedures 

are different from paragraph (c) or (d) of 

this section. Samples should be 

collected at a location that most 

accurately represents the fuel type, 

where possible, at a point prior to 

mixing with other dissimilar fuel types. 

(iv) For each anticipated fuel type, the 

analytical methods from Table 6, with 

the expected minimum detection levels, 

to be used for the measurement of 

chlorine or mercury. 

(v) If you request to use an alternative 

analytical method other than those 

required by Table 6 to this subpart, you 

must also include a detailed description 

of the methods and procedures that you 

are proposing to use. Methods in Table 

6 shall be used until the requested 

alternative is approved. 

(vi) If you will be using fuel analysis 

from a fuel supplier in lieu of sitespecific sampling and analysis, the fuel 

supplier must use the analytical 

methods required by Table 6 to this 

subpart. 

(c) At a minimum, you must obtain 

three composite fuel samples for each 

fuel type according to the procedures in 

paragraph (c)(1) or (2) of this section, or 

use an automated sampling mechanism 

that provides representative composite 

fuel samples for each fuel type that 

includes both coarse and fine material. 

(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. For monthly sampling, each 

composite sample shall be collected at 

approximately equal 10-day intervals 

during the month. 

(2) If sampling from a fuel pile or 

truck, you must collect fuel samples 

according to paragraphs (c)(2)(i) through 

(iii) of this section. 

(i) For each composite sample, you 

must select a minimum of five sampling 

locations uniformly spaced over the 

surface of the pile. 

(ii) At each sampling site, you must 

dig into the pile to a uniform depth of 

approximately 18 inches. You must 

insert a clean shovel into the hole and 

withdraw a sample, making sure that 

large pieces do not fall off during 

sampling; use the same shovel to collect 

all samples. 

(iii) You must transfer all samples to 

a clean plastic bag for further 

processing. 

(d) You must prepare each composite 

sample according to the procedures in 

paragraphs (d)(1) through (7) of this 

section. 

(1) You must thoroughly mix and 

pour the entire composite sample over 

a clean plastic sheet. 

(2) You must break large sample 

pieces (e.g., larger than 3 inches) into 

smaller sizes. 

(3) You must make a pie shape with 

the entire composite sample and 

subdivide it into four equal parts. 

(4) You must separate one of the 

quarter samples as the first subset. 


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(5) If this subset is too large for 

grinding, you must repeat the procedure 

in paragraph (d)(3) of this section with 

the quarter sample and obtain a onequarter subset from this sample. 

(6) You must grind the sample in a 

mill. 

(7) You must use the procedure in 

paragraph (d)(3) of this section to obtain 

a one-quarter subsample for analysis. If 

the quarter sample is too large, 

subdivide it further using the same 

procedure. 

(e) You must determine the 

concentration of pollutants in the fuel 

(mercury and/or chlorine and/or total 

selected metals) in units of pounds per 

million Btu of each composite sample 

for each fuel type according to the 

procedures in Table 6 to this subpart, 

for use in Equations 7, 8, and 9 of this 

subpart. 

(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 (3) of this 

section. 

(1) You are not required to conduct 

the fuel specification analyses in 

paragraphs (g) through (i) of this section 

for natural gas or refinery gas. 

(2) You are not required to conduct 

the fuel specification analyses in 

paragraphs (g) through (i) of this section 

for gaseous fuels that are subject to 

another subpart of this part. 

(3) You are not required to conduct 

the fuel specification analyses in 

paragraphs (g) through (i) of this section 

on gaseous fuels for units that are 

complying with the limits for units 

designed to burn gas 2 (other) fuels. 

(g) You must develop and submit a 

site-specific fuel analysis plan for other 

gas 1 fuels to the EPA Administrator for 

review and approval according to the 

following procedures and requirements 

in paragraphs (g)(1) and (2) of this 

section. 

(1) You must submit the fuel analysis 

plan no later than 60 days before the 

date that you intend to conduct the 

initial compliance demonstration 

described in § 63.7510. 

(2) You must include the information 

contained in paragraphs (g)(2)(i) through 

(vi) of this section in your fuel analysis 

plan. 

(i) The identification of all gaseous 

fuel types other than those exempted 

from fuel specification analysis under 

(f)(1) through (3) of this section 

anticipated to be burned in each boiler 

or process heater. 

(ii) For each anticipated fuel type, the 

notification of whether you or a fuel 

supplier will be conducting the fuel 

specification analysis. 

(iii) For each anticipated fuel type, a 

detailed description of the sample 

location and specific procedures to be 

used for collecting and preparing the 

samples if your procedures are different 

from the sampling methods contained in 

Table 6 to this subpart. Samples should 

be collected at a location that most 

accurately represents the fuel type, 

where possible, at a point prior to 

mixing with other dissimilar fuel types. 

If multiple boilers or process heaters are 

fueled by a common fuel stream it is 

permissible to conduct a single gas 

specification at the common point of gas 

distribution. 

(iv) For each anticipated fuel type, the 

analytical methods from Table 6 to this 

subpart, with the expected minimum 

detection levels, to be used for the 

measurement of mercury. 

(v) If you request to use an alternative 

analytical method other than those 

required by Table 6 to this subpart, you 

must also include a detailed description 

of the methods and procedures that you 

are proposing to use. Methods in Table 

6 to this subpart shall be used until the 

requested alternative is approved. 

(vi) If you will be using fuel analysis 

from a fuel supplier in lieu of sitespecific sampling and analysis, the fuel 

supplier must use the analytical 

methods required by Table 6 to this 

subpart. 

(h) You must obtain a single fuel 

sample for each fuel type according to 

the sampling procedures listed in Table 

6 for fuel specification of gaseous fuels. 

(i) You must determine the 

concentration in the fuel of mercury, in 

units of microgram per cubic meter, dry 

basis, of each sample for each gas 1 fuel 

type according to the procedures in 

Table 6 to this subpart. 

§ 63.7522 Can I use emissions averaging 

to comply with this subpart? 

(a) As an alternative to meeting the 

requirements of § 63.7500 for particulate 

matter, hydrogen chloride, or mercury 

on a boiler or process heater-specific 

basis, if you have more than one 

existing boiler or process heater in any 

subcategory located at your facility, you 

may demonstrate compliance by 

emissions averaging, if your averaged 

emissions are not more than 90 percent 

of the applicable emission limit, 

according to the procedures in this 

section. You may not include new 

boilers or process heaters in an 

emissions average. 

(b) For a group of two or more existing 

boilers or process heaters in the same 

subcategory that each vent to a separate 

stack, you may average particulate 

matter, hydrogen chloride, or mercury 

emissions among existing units to 

demonstrate compliance with the limits 

in Table 2 to this subpart as specified in 

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

section, if you satisfy the requirements 

in paragraphs (c) through (g) of this 

section. 

(1) You may not include in an average 

units using a CEMS or PM CPMS for 

demonstrating compliance, even if the 

use of a CEMS or PM CPMS is optional. 

(2) For Hg and HCl, averaging is 

allowed as follows: 

(i) You may average among units in 

any of the solid fuel subcategories. 

(ii) You may average among units in 

any of the liquid fuel subcategories. 

(iii) You may average among units in 

a subcategory of units designed to burn 

gas 2 (other) fuels. 

(iv) You may not average across the 

liquid, solid fuel, and gas 2 (other) 

subcategories. 

(3) For particulate matter, averaging is 

only allowed between units within each 

of the following combustor level 

subcategories and you may not average 

across subcategories: 

(i) Pulverized coal/solid fossil fuel 

units. 

(ii) Stokers designed to burn coal/ 

solid fossil fuel. 

(iii) Fluidized bed units designed to 

burn coal/solid fossil fuel. 

(iv) Stokers/sloped grate/other units 

designed to burn kiln dried biomass/ 

bio-based solids. 

(v) Stokers/sloped grate/other units 

designed to burn wet biomass/bio-based 

solids. 

(vi) Fluidized bed units designed to 

burn biomass/bio-based solid. 

(vii) Suspension burners designed to 

burn biomass/bio-based solid. 

(viii) Dutch ovens/pile burners 

designed to burn biomass/bio-based 

solid. 

(ix) Fuel Cells designed to burn 

biomass/bio-based solid. 

(x) Hybrid suspension/grate burners 

designed to burn wet biomass/bio-based 

solid. 

(xi) Units designed to burn heavy 

liquid fuel. 

(xii) Units designed to burn light 

liquid fuel. 

(xiii) Units designed to burn liquid 

fuel in non-continental states or 

territories. 

(xiv) Units designed to burn gas 2 

(other) gases. 

(c) For each existing boiler or process 

heater in the averaging group, the 

emission rate achieved during the initial 


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compliance test for the HAP being 

averaged must not exceed the emission 

level that was being achieved on [DATE 

60 DAYS AFTER PUBLICATION OF 

THE FINAL RULE IN THE Federal 

Register] 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 [DATE 60 

DAYS AFTER PUBLICATION OF THE 

FINAL RULE IN THE Federal Register]. 

(d) The averaged emissions rate from 

the existing boilers and process heaters 

participating in the emissions averaging 

option must be in compliance with the 

limits in Table 2 to this subpart at all 

times following the compliance date 

specified in § 63.7495. 

(e) You must demonstrate initial 

compliance according to paragraph 

(e)(1) or (2) of this section using the 

maximum rated heat input capacity or 

maximum steam generation capacity of 

each unit and the results of the initial 

performance tests or fuel analysis. 

(1) You must use Equation 1a or 1b of 

this section to demonstrate that the 

particulate matter, hydrogen chloride, or 

mercury emissions from all existing 

units participating in the emissions 

averaging option for that pollutant do 

not exceed the emission limits in Table 

2 to this subpart. Use Equation 1a if you 

are complying with the emission limits 

on a heat input basis and use Equation 

1b if you are complying with the 

emission limits on a steam generation 

(output) basis. 

Where: 

AveWeightedEmissions = Average weighted 

emissions for particulate matter, 

hydrogen chloride, or mercury, in units 

of pounds per million Btu of heat input. 

Er = Emission rate (as determined during the 

initial compliance demonstration) of 

particulate matter, hydrogen chloride, or 

mercury from unit, i, in units of pounds 

per million Btu of heat input. Determine 

the emission rate for particulate matter, 

hydrogen chloride, or mercury by 

performance testing according to Table 5 

to this subpart, or by fuel analysis for 

hydrogen chloride or mercury using the 

applicable equation in § 63.7530(c). 

Hm = Maximum rated heat input capacity of 

unit, i, in units of million Btu per hour. 

n = Number of units participating in the 

emissions averaging option. 

1.1 = Required discount factor. 

Where: 

AveWeightedEmissions = Average weighted 

emissions for particulate matter, 

hydrogen chloride, or mercury, in units 

of pounds per million Btu of steam 

output. 

Er = Emission rate (as determined during the 

initial compliance demonstration) of 

particulate matter, hydrogen chloride, or 

mercury from unit, i, in units of pounds 

per million Btu of steam output. 

Determine the emission rate for 

particulate matter, hydrogen chloride, or 

mercury by performance testing 

according to Table 5 to this subpart, or 

by fuel analysis for hydrogen chloride or 

mercury using the applicable equation in 

§ 63.7530(c). If you are taking credit for 

energy conservation measures from a 

unit according to § 63.7533, use the 

adjusted emission level for that unit, Eadj, 

determined according to § 63.7533 for 

that unit. 

So = Maximum steam output capacity of 

unit, i, in units of million Btu per hour, 

as defined in § 63.7575. 

n = Number of units participating in the 

emissions averaging option. 

1.1 = Required discount factor. 

(2) If you are not capable of 

determining the maximum rated heat 

input capacity of one or more boilers 

that generate steam, you may use 

Equation 2 of this section as an 

alternative to using Equation 1a of this 

section to demonstrate that the 

particulate matter, hydrogen chloride, or 

mercury emissions from all existing 

units participating in the emissions 

averaging option do not exceed the 

emission limits for that pollutant in 

Table 2 to this subpart that are in 

pounds per million Btu of heat input. 

Where: 

AveWeightedEmissions = Average weighted 

emission level for PM, hydrogen 

chloride, or mercury, in units of pounds 

per million Btu of heat input. 

Er = Emission rate (as determined during the 

most recent compliance demonstration) 

of particulate matter, hydrogen chloride, 

or mercury from unit, i, in units of 

pounds per million Btu of heat input. 

Determine the emission rate for 

particulate matter, hydrogen chloride, or 

mercury by performance testing 

according to Table 5 to this subpart, or 

by fuel analysis for hydrogen chloride or 

mercury using the applicable equation in 

§ 63.7530(c). 

Sm = Maximum steam generation capacity by 

unit, i, in units of pounds per hour. 

Cfi = Conversion factor, calculated from the 

most recent compliance test, in units of 

million Btu of heat input per pounds of 

steam generated for unit, i. 

1.1 = Required discount factor. 

(f) After the initial compliance 

demonstration described in paragraph 

(e) of this section, you must demonstrate 

compliance on a monthly basis 

determined at the end of every month 

(12 times per year) according to 

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

section. The first monthly period begins 

on the compliance date specified in 

§ 63.7495. 

(1) For each calendar month, you 

must use Equation 3a or 3b of this 

section to calculate the average 

weighted emission rate for that month. 

Use Equation 3a and the actual heat 

input for the month for each existing 

unit participating in the emissions 

averaging option if you are complying 

with emission limits on a heat input 

basis. Use Equation 3b and the actual 

steam generation for the month if you 


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are complying with the emission limits 

on a steam generation (output) basis. 

Where: 

AveWeightedEmissions = Average weighted 

emission level for particulate matter, 

hydrogen chloride, or mercury, in units 

of pounds per million Btu of heat input, 

for that calendar month. 

Er = Emission rate (as determined during the 

most recent compliance demonstration) 

of particulate matter, hydrogen chloride, 

or mercury from unit, i, in units of 

pounds per million Btu of heat input. 

Determine the emission rate for 

particulate matter, hydrogen chloride, or 

mercury by performance testing 

according to Table 5 to this subpart, or 

by fuel analysis for hydrogen chloride or 

mercury using the applicable equation in 

§ 63.7530(c). 

Hb = The heat input for that calendar month 

to unit, i, in units of million Btu. 

n = Number of units participating in the 

emissions averaging option. 

1.1 = Required discount factor. 

Where: 

AveWeightedEmissions = Average weighted 

emission level for particulate matter, 

hydrogen chloride, or mercury, in units 

of pounds per million Btu of steam 

output, for that calendar month. 

Er = Emission rate (as determined during the 

most recent compliance demonstration) 

of particulate matter, hydrogen chloride, 

or mercury from unit, i, in units of 

pounds per million Btu of steam output. 

Determine the emission rate for 

particulate matter, hydrogen chloride, or 

mercury by performance testing 

according to Table 5 to this subpart, or 

by fuel analysis for hydrogen chloride or 

mercury using the applicable equation in 

§ 63.7530(c). If you are taking credit for 

energy conservation measures from a 

unit according to § 63.7533, use the 

adjusted emission level for that unit, Eadj, 

determined according to § 63.7533 for 

that unit. 

So = The steam output for that calendar 

month from unit, i, in units of million 

Btu, as defined in § 63.7575. 

n = Number of units participating in the 

emissions averaging option. 

1.1 = Required discount factor. 

(2) If you are not capable of 

monitoring heat input, you may use 

Equation 4 of this section as an 

alternative to using Equation 3a of this 

section to calculate the average 

weighted emission rate using the actual 

steam generation from the boilers 

participating in the emissions averaging 

option. 

Where: 

AveWeightedEmissions = average weighted 

emission level for PM, hydrogen 

chloride, or mercury, in units of pounds 

per million Btu of heat input for that 

calendar month. 

Er = Emission rate (as determined during the 

most recent compliance demonstration 

of particulate matter, hydrogen chloride, 

or mercury from unit, i, in units of 

pounds per million Btu of heat input. 

Determine the emission rate for 

particulate matter, hydrogen chloride, or 

mercury by performance testing 

according to Table 5 to this subpart, or 

by fuel analysis for hydrogen chloride or 

mercury using the applicable equation in 

§ 63.7530(c). 

Sa = Actual steam generation for that 

calendar month by boiler, i, in units of 

pounds. 

Cfi = Conversion factor, as calculated during 

the most recent compliance test, in units 

of million Btu of heat input per pounds 

of steam generated for boiler, i. 

1.1 = Required discount factor. 

(3) Until 12 monthly weighted average 

emission rates have been accumulated, 

calculate and report only the average 

weighted emission rate determined 

under paragraph (f)(1) or (2) of this 

section for each calendar month. After 

12 monthly weighted average emission 

rates have been accumulated, for each 

subsequent calendar month, use 

Equation 5 of this section to calculate 

the 12-month rolling average of the 

monthly weighted average emission 

rates for the current calendar month and 

the previous 11 calendar months. 

Where: 

Eavg = 12-month rolling average emission 

rate, (pounds per million Btu heat input) 

ERi = Monthly weighted average, for calendar 

month ‘‘i’’ (pounds per million Btu heat 

input), as calculated by paragraph (f)(1) 

or (2) of this section. 

(g) You must develop, and submit to 

the applicable delegated authority for 

review and approval, an 

implementation plan for emission 

averaging according to the following 

procedures and requirements in 

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

section. 

(1) You must submit the 

implementation plan no later than 180 

days before the date that the facility 

intends to demonstrate compliance 

using the emission averaging option. 

(2) You must include the information 

contained in paragraphs (g)(2)(i) through 

(vii) of this section in your 

implementation plan for all emission 

sources included in an emissions 

average: 

(i) The identification of all existing 

boilers and process heaters in the 

averaging group, including for each 

either the applicable HAP emission 

level or the control technology installed 

as of [DATE 60 DAYS AFTER 

PUBLICATION OF THE FINAL RULE IN 

THE Federal Register] and the date on 

which you are requesting emission 

averaging to commence; 

(ii) The process parameter (heat input 

or steam generated) that will be 

monitored for each averaging group; 


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(iii) The specific control technology or 

pollution prevention measure to be used 

for each emission boiler or process 

heater in the averaging group and the 

date of its installation or application. If 

the pollution prevention measure 

reduces or eliminates emissions from 

multiple boilers or process heaters, the 

owner or operator must identify each 

boiler or process heater; 

(iv) The test plan for the measurement 

of particulate matter, hydrogen chloride, 

or mercury emissions in accordance 

with the requirements in § 63.7520; 

(v) The operating parameters to be 

monitored for each control system or 

device consistent with § 63.7500 and 

Table 4, and a description of how the 

operating limits will be determined; 

(vi) If you request to monitor an 

alternative operating parameter 

pursuant to § 63.7525, you must also 

include: 

(A) A description of the parameter(s) 

to be monitored and an explanation of 

the criteria used to select the 

parameter(s); and 

(B) A description of the methods and 

procedures that will be used to 

demonstrate that the parameter 

indicates proper operation of the control 

device; the frequency and content of 

monitoring, reporting, and 

recordkeeping requirements; and a 

demonstration, to the satisfaction of the 

applicable delegated authority, that the 

proposed monitoring frequency is 

sufficient to represent control device 

operating conditions; and 

(vii) A demonstration that compliance 

with each of the applicable emission 

limit(s) will be achieved under 

representative operating load 

conditions. Following each compliance 

demonstration and until the next 

compliance demonstration, you must 

comply with the operating limit for 

operating load conditions specified in 

Table 4 to this subpart. 

(3) The delegated authority shall 

review and approve or disapprove the 

plan according to the following criteria: 

(i) Whether the content of the plan 

includes all of the information specified 

in paragraph (g)(2) of this section; and 

(ii) Whether the plan presents 

sufficient information to determine that 

compliance will be achieved and 

maintained. 

(4) The applicable delegated authority 

shall not approve an emission averaging 

implementation plan containing any of 

the following provisions: 

(i) Any averaging between emissions 

of differing pollutants or between 

differing sources; or 

(ii) The inclusion of any emission 

source other than an existing unit in the 

same subcategory. 

(h) For a group of two or more 

existing affected units, each of which 

vents through a single common stack, 

you may average particulate matter, 

hydrogen chloride, or mercury 

emissions to demonstrate compliance 

with the limits for that pollutant in 

Table 2 to this subpart if you satisfy the 

requirements in paragraph (i) or (j) of 

this section. 

(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) For all other groups of units subject 

to the common stack requirements of 

paragraph (h) of this section, including 

situations where the exhaust of affected 

units are each individually controlled 

and then sent to a common stack, the 

owner or operator may elect to: 

(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), parts 

per million (ppm), or nanograms per dry 

standard cubic meter (ng/dscm). 

ELi = Appropriate emission limit from Table 

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

MMBtu, ppm or ng/dscm. 

Hi = Heat input from unit i, MMBtu. 

(2) Conduct performance tests 

according to procedures specified in 

§ 63.7520 in the common stack. If 

affected units and non-affected units 

vent to the common stack, the nonaffected units must be shut down or 

vented to a different stack during the 

performance test unless the facility 

determines to demonstrate compliance 

with the non-affected units venting to 

the stack; and 

(3) Meet the applicable operating limit 

specified in § 63.7540 and Table 8 to 

this subpart for each emissions control 

system (except that, if each unit venting 

to the common stack has an applicable 

opacity operating limit, then a single 

continuous opacity monitoring system 

may be located in the common stack 

instead of in each duct to the common 

stack). 

(k) The common stack of a group of 

two or more existing boilers or process 

heaters in the same subcategory subject 

to paragraph (h) of this section may be 

treated as a separate stack for purposes 

of paragraph (b) of this section and 

included in an emissions averaging 

group subject to paragraph (b) of this 

section. 

§ 63.7525 What are my monitoring, 

installation, operation, and maintenance 

requirements? 

(a) If your boiler or process heater is 

subject to a carbon monoxide emission 

limit in Table 1 or 2 to this subpart, you 

must install, operate, and maintain an 

oxygen analyzer system as defined in 

§ 63.7575, or a carbon monoxide 

continuous emission monitoring system 

(CO CEMS) according to the procedures 

in paragraphs (a)(1) through (10) of this 

section. 

(1) The oxygen analyzer system or the 

CO CEMS must be installed by the 

compliance date specified in § 63.7495. 

If a CO CEMS is used, the carbon 

monoxide level shall be monitored at 

the outlet of the boiler or process heater. 

(2) You must operate the oxygen trim 

system with the oxygen level set at the 

minimum percent oxygen by volume 

that is established as the operating limit 

for oxygen according to Table 4 to this 

subpart. 

(3) Each CO CEMS must be installed, 

operated, and maintained according to 

the applicable procedures under 

Performance Specification 4, 4A, or 4B 

at 40 CFR part 60, appendix B, and 

according to the site-specific monitoring 

plan developed according to 

§ 63.7505(d). 

(4) For a new unit, the initial 

performance evaluation shall be 

completed no later than [DATE 240 

DAYS AFTER PUBLICATION OF THE 

FINAL RULE IN THE Federal Register] 

or 180 days after the date of initial 

startup, whichever is later. For an 


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existing unit, the initial performance 

evaluation shall be completed no later 

than [DATE 3 YEARS AND 180 DAYS 

AFTER PUBLICATION OF THE FINAL 

RULE IN THE Federal Register]. 

(5) You must conduct a performance 

evaluation of each CO CEMS according 

to the requirements in § 63.8(e) and 

according to Performance Specification 

4, 4A, or 4B at 40 CFR part 60, appendix 

B. During each relative accuracy test run 

of the CO CEMS, emission data for 

carbon monoxide must be collected 

concurrently (or within a 30- to 60- 

minute period) by both the CO CEMS 

and by Method 10, 10A, or 10B at 40 

CFR part 60, appendix A–4. The relative 

accuracy testing must be at 

representative operating conditions. 

(6) For each CO CEMS, you must 

follow the quality assurance procedures 

(e.g., quarterly accuracy determinations 

and daily calibration drift tests) of 

Procedure 1 of appendix F to part 60. 

The span value of the CO CEMS must 

be two times the applicable CO 

emission limit, expressed as a 

concentration. 

(7) Each CO CEMS must complete a 

minimum of one cycle of operation 

(sampling, analyzing, and data 

recording) for each successive 15- 

minute period. Collect at least four CO 

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. 

(8) The CO CEMS data must be 

reduced as specified in § 63.8(g)(2). 

(9) You must calculate one-hour 

arithmetic averages, corrected to 3 

percent oxygen from each hour of CO 

CEMS data in parts per million carbon 

monoxide concentration. For all 

subcategories except for units designed 

to burn liquid fuels in non-continental 

states and territories, the one-hour 

arithmetic averages required shall be 

used to calculate the boiler operating 

day daily arithmetic average emissions. 

Calculate a 10-day rolling average from 

the daily averages. For units designed to 

burn liquid fuels in non-continental 

states and territories, the one-hour 

arithmetic averages required shall be 

used to calculate the 3-hour arithmetic 

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 carbon 

monoxide concentration from the 

hourly values. 

(10) For purposes of collecting CO 

data, you must operate the CO CEMS as 

specified in § 63.7535(b). You must use 

all the data collected during all periods 

in calculating data averages and 

assessing compliance, except that you 

must exclude certain data as specified 

in § 63.7535(c). Periods when CO data 

are unavailable may constitute 

monitoring deviations as specified in 

§ 63.7535(d). 

(b) If your boiler or process heater has 

an average annual heat input rate greater 

than 250 MMBtu per hour from solid 

fossil fuel and/or residual oil, and you 

demonstrate compliance with the PM 

limit instead of the alternative total 

selected metals limit, you must install, 

certify, 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. For 

other boilers or process heaters, you 

may elect to use a PM CPMS 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). 

(1) Install, certify, operate, and 

maintain your PM CPMS according to 

the procedures in your approved sitespecific monitoring plan developed in 

accordance with § 63.7505(d), the 

requirements in § 63.7540(a)(9), and 

(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 

may be expressed as milliamps, stack 

concentration, or other raw data signal. 

(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 be capable of 

detecting and responding to particulate 

matter concentrations of no greater than 

0.5 milligram per actual cubic meter. 

(2) For a new unit, complete the 

initial performance evaluation no later 

than [DATE 240 DAYS AFTER 

PUBLICATION OF THE FINAL RULE IN 

THE Federal Register] or 180 days after 

the date of initial startup, whichever is 

later. For an existing unit, complete the 

initial performance evaluation no later 

than [DATE 3 YEARS AND 180 DAYS 

AFTER PUBLICATION OF THE FINAL 

RULE IN THE Federal Register]. 

(3) Collect PM CPMS hourly average 

output data for all boiler operating 

hours except as indicated in 

§ 63.7535(a) through (d). Express the PM 

CPMS output as millamps, PM 

concentration, or other raw data signal 

value. 

(4) Calculate the arithmetic 30-day 

rolling average of all of the hourly 

average PM CPMS output data collected 

during all boiler operating hours (e.g., 

milliamps, PM concentration, raw data 

signal). 

(c) If you have an applicable opacity 

operating limit in this rule, and are not 

otherwise required or elect to install and 

operate a PM CPMS or a bag leak 

detection system, you must install, 

operate, certify and maintain each 

COMS according to the procedures in 

paragraphs (c)(1) through (7) of this 

section by the compliance date specified 

in § 63.7495. 

(1) Each COMS must be installed, 

operated, and maintained according to 

Performance Specification 1 at appendix 

B to part 60 of this chapter. 

(2) You must conduct a performance 

evaluation of each COMS according to 

the requirements in § 63.8(e) and 

according to Performance Specification 

1 at appendix B to part 60 of this 

chapter. 

(3) As specified in § 63.8(c)(4)(i), each 

COMS must complete a minimum of 

one cycle of sampling and analyzing for 

each successive 10-second period and 

one cycle of data recording for each 

successive 6-minute period. 

(4) The COMS data must be reduced 

as specified in § 63.8(g)(2). 

(5) You must include in your sitespecific monitoring plan procedures and 

acceptance criteria for operating and 

maintaining each COMS according to 

the requirements in § 63.8(d). At a 

minimum, the monitoring plan must 

include a daily calibration drift 

assessment, a quarterly performance 

audit, and an annual zero alignment 

audit of each COMS. 

(6) You must operate and maintain 

each COMS according to the 

requirements in the monitoring plan 

and the requirements of § 63.8(e). You 

must identify periods the COMS is out 

of control including any periods that the 

COMS fails to pass a daily calibration 

drift assessment, a quarterly 

performance audit, or an annual zero 

alignment audit. Any 6-minute period 

for which the monitoring system is out 

of control and data are not available for 

a required calculation constitutes a 

deviation from the monitoring 

requirements. 

(7) You must determine and record all 

the 6-minute averages (and daily block 

averages as applicable) collected for 

periods during which the COMS is not 

out of control. 

(d) If you have an operating limit that 

requires the use of a CMS other than a 

PM CPMS or COMS, you must install, 

operate, and maintain each CMS 

according to the procedures in 


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paragraphs (d)(1) through (5) of this 

section by the compliance date specified 

in § 63.7495. 

(1) The continuous parameter 

monitoring system must complete a 

minimum of one cycle of operation for 

each successive 15-minute period. You 

must have a minimum of four 

successive cycles of operation to have a 

valid hour of data. 

(2) You must operate the monitoring 

system as specified in § 63.7535(b), and 

comply with the data calculation 

requirements specified in § 63.7535(c). 

(3) Any 15-minute period for which 

the monitoring system is out-of-control 

and data are not available for a required 

calculation constitutes a deviation from 

the monitoring requirements. Other 

situations that constitute a monitoring 

deviation are specified in § 63.7535(d). 

(4) You must determine the 30-day 

rolling average of all recorded readings, 

except as provided in paragraph (d)(3) 

of this section. 

(5) You must record the results of 

each inspection, calibration, and 

validation check. 

(e) If you have an operating limit that 

requires the use of a flow monitoring 

system, you must meet the requirements 

in paragraphs (d) and (e)(1) through (4) 

of this section. 

(1) You must install the flow sensor 

and other necessary equipment in a 

position that provides a representative 

flow. 

(2) You must use a flow sensor with 

a measurement sensitivity of no greater 

than 2 percent of the expected flow rate. 

(3) You must minimize the effects of 

swirling flow or abnormal velocity 

distributions due to upstream and 

downstream disturbances. 

(4) You must conduct a flow 

monitoring system performance 

evaluation in accordance with your 

monitoring plan at the time of each 

performance test but no less frequently 

than annually. 

(f) If you have an operating limit that 

requires the use of a pressure 

monitoring system, you must meet the 

requirements in paragraphs (d) and (f)(1) 

through (6) of this section. 

(1) Install the pressure sensor(s) in a 

position that provides a representative 

measurement of the pressure (e.g., PM 

scrubber pressure drop). 

(2) Minimize or eliminate pulsating 

pressure, vibration, and internal and 

external corrosion. 

(3) Use a pressure sensor with a 

minimum tolerance of 1.27 centimeters 

of water or a minimum tolerance of 1 

percent of the pressure monitoring 

system operating range, whichever is 

less. 

(4) Perform checks at least once each 

process operating day to ensure pressure 

measurements are not obstructed (e.g., 

check for pressure tap pluggage daily). 

(5) Conduct a performance evaluation 

of the pressure monitoring system in 

accordance with your monitoring plan 

at the time of each performance test but 

no less frequently than annually. 

(6) If at any time the measured 

pressure exceeds the manufacturer’s 

specified maximum operating pressure 

range, conduct a performance 

evaluation of the pressure monitoring 

system in accordance with your 

monitoring plan and confirm that the 

pressure monitoring system continues to 

meet the performance requirements in 

you monitoring plan. Alternatively, 

install and verify the operation of a new 

pressure sensor. 

(g) If you have an operating limit that 

requires a pH monitoring system, you 

must meet the requirements in 

paragraphs (d) and (g)(1) through (4) of 

this section. 

(1) Install the pH sensor in a position 

that provides a representative 

measurement of scrubber effluent pH. 

(2) Ensure the sample is properly 

mixed and representative of the fluid to 

be measured. 

(3) Conduct a performance evaluation 

of the pH monitoring system in 

accordance with your monitoring plan 

at least once each process operating day. 

(4) Conduct a performance evaluation 

(including a two-point calibration with 

one of the two buffer solutions having 

a pH within 1 of the pH of the operating 

limit) of the pH monitoring system in 

accordance with your monitoring plan 

at the time of each performance test but 

no less frequently than quarterly. 

(h) If you have an operating limit that 

requires a secondary electric power 

monitoring system for an electrostatic 

precipitator (ESP) operated with a wet 

scrubber, you must meet the 

requirements in paragraphs (h)(1) and 

(2) of this section. 

(1) Install sensors to measure 

(secondary) voltage and current to the 

precipitator collection plates. 

(2) Conduct a performance evaluation 

of the electric power monitoring system 

in accordance with your monitoring 

plan at the time of each performance 

test but no less frequently than 

annually. 

(i) If you have an operating limit that 

requires the use of a monitoring system 

to measure sorbent injection rate (e.g., 

weigh belt, weigh hopper, or hopper 

flow measurement device), you must 

meet the requirements in paragraphs (d) 

and (i)(1) and (2) of this section. 

(1) Install the system in a position(s) 

that provides a representative 

measurement of the total sorbent 

injection rate. 

(2) Conduct a performance evaluation 

of the sorbent injection rate monitoring 

system in accordance with your 

monitoring plan at the time of each 

performance test but no less frequently 

than annually. 

(j) If you are not required to use a PM 

CPMS and elect to use a fabric filter bag 

leak detection system to comply with 

the requirements of this subpart, you 

must install, calibrate, maintain, and 

continuously operate the bag leak 

detection system as specified in 

paragraphs (j)(1) through (6) of this 

section. 

(1) You must install a bag leak 

detection sensor(s) in a position(s) that 

will be representative of the relative or 

absolute particulate matter loadings for 

each exhaust stack, roof vent, or 

compartment (e.g., for a positive 

pressure fabric filter) of the fabric filter. 

(2) Conduct a performance evaluation 

of the bag leak detection system in 

accordance with your monitoring plan 

and consistent with the guidance 

provided in EPA–454/R–98–015 

(incorporated by reference, see § 63.14). 

(3) Use a bag leak detection system 

certified by the manufacturer to be 

capable of detecting particulate matter 

emissions at concentrations of 10 

milligrams per actual cubic meter or 

less. 

(4) Use a bag leak detection system 

equipped with a device to record 

continuously the output signal from the 

sensor. 

(5) Use a bag leak detection system 

equipped with a system that will alert 

when an increase in relative particulate 

matter emissions over a preset level is 

detected. The alarm must be located 

where it can be easily heard or seen by 

plant operating personnel. 

(6) Where multiple bag leak detectors 

are required, the system’s 

instrumentation and alarm may be 

shared among detectors. 

(k) For each unit that meets the 

definition of limited-use boiler or 

process heater, you must monitor and 

record the operating hours per year for 

that unit. 

(l) For each unit for which you decide 

to demonstrate compliance with the 

mercury or hydrogen chloride emissions 

limits in Tables 1 or 2 of this subpart by 

use of a CEMS for mercury or hydrogen 

chloride, you must install, certify, 

maintain, and operate a CEMS 

measuring emissions discharged to the 

atmosphere and record the output of the 

system as specified in paragraphs (l)(1) 

through (8) of this section. For hydrogen 

chloride, this option for an affected unit 

takes effect on the date a final 


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performance specification for a 

hydrogen chloride CEMS is published 

in the Federal Register or the date of 

approval of a site-specific monitoring 

plan. 

(1) Notify the Administrator one 

month before starting use of the CEMS, 

and notify the Administrator one month 

before stopping use of the CEMS. 

(2) Each CEMS shall be installed, 

certified, operated, and maintained 

according to the requirements in 

§ 63.7540(a)(14) for a mercury CEMS 

and § 63.7540(a)(15) for a hydrogen 

chloride CEMS. 

(3) For a new unit, you must complete 

the initial performance evaluation of the 

CEMS by the latest of the dates specified 

in paragraph (l)(3)(i) through (iii) of this 

section. 

(i) No later than [DATE 240 DAYS 

AFTER PUBLICATION OF THE FINAL 

RULE IN THE Federal Register]. 

(ii) No later 180 days after the date of 

initial startup. 

(iii) No later 180 days after notifying 

the Administrator before starting to use 

the CEMS in place of performance 

testing or fuel analysis to demonstrate 

compliance. 

(4) For an existing unit, you must 

complete the initial performance 

evaluation by the latter of the two dates 

specified in paragraph (l)(4)(i) and (ii) of 

this section. 

(i) No later than [DATE 3 YEARS AND 

180 DAYS AFTER PUBLICATION OF 

THE FINAL RULE IN THE Federal 

Register]. 

(ii) No later 180 days after notifying 

the Administrator before starting to use 

the CEMS in place of performance 

testing or fuel analysis to demonstrate 

compliance. 

(5) Compliance with the applicable 

emissions limit shall be determined 

based on the 30-day rolling average of 

the hourly arithmetic average emissions 

rates using the continuous monitoring 

system outlet data. The 30-day rolling 

arithmetic average emission rate (lb/ 

MMBtu) shall be calculated using the 

equations in EPA Reference Method 19 

at 40 CFR part 60, appendix A–7, but 

substituting the mercury or hydrogen 

chloride concentration for the pollutant 

concentrations normally used in 

Method 19. 

(6) Collect CEMS hourly averages for 

all operating hours on a 30-day rolling 

average basis. Collect at least four CMS 

data values representing the four 15- 

minute periods in an hour, or at least 

two 15-minute data values during an 

hour when CMS calibration, quality 

assurance, or maintenance activities are 

being performed. 

(7) The one-hour arithmetic averages 

required shall be expressed in lb/ 

MMBtu and shall be used to calculate 

the boiler operating day daily arithmetic 

average emissions. 

(8) If you are using an add-on control 

to comply with the mercury or hydrogen 

chloride emission limit, you are allowed 

to substitute the use of the mercury or 

hydrogen chloride CEMS for the 

applicable fuel analysis, annual 

performance test, and operating limits 

specified in Table 4 to this subpart to 

demonstrate compliance with the 

mercury or hydrogen chloride emissions 

limit. 

§ 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. If 

applicable, you must also install, 

operate, and maintain all applicable 

CMS (including CEMS, COMS, and 

continuous parameter monitoring 

systems) according to § 63.7525. 

(b) If you demonstrate compliance 

through performance 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 total selected metals 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) You must establish the maximum 

chlorine fuel input (Clinput) during the 

initial fuel analysis according to the 

procedures in paragraphs (b)(1)(i) 

through (iii) of this section. 

(i) You must determine the fuel type 

or fuel mixture that you could burn in 

your boiler or process heater that has 

the highest content of chlorine. 

(ii) During the fuel analysis for 

hydrogen chloride, you must determine 

the fraction of the total heat input for 

each fuel type burned (Qi) based on the 

fuel mixture that has the highest content 

of chlorine, and the average chlorine 

concentration of each fuel type burned 

(Ci). 

(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. 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. 

n = Number of different fuel types burned in 

your boiler or process heater for the 

mixture that has the highest content of 

chlorine. 

(2) You must establish the maximum 

mercury fuel input level (Mercuryinput) 

during the initial fuel analysis using the 

procedures in paragraphs (b)(2)(i) 

through (iii) of this section. 

(i) You must determine the fuel type 

or fuel mixture that you could burn in 

your boiler or process heater that has 

the highest content of mercury. 

(ii) During the compliance 

demonstration for mercury, you must 

determine the fraction of total heat 

input for each fuel burned (Qi) based on 

the fuel mixture that has the highest 

content of mercury, and the average 

mercury concentration of each fuel type 

burned (HGi). 

(iii) You must establish a maximum 

mercury input level using Equation 8 of 

this section. 


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80640 Federal Register / Vol. 76, No. 247 / Friday, December 23, 2011 / Proposed Rules 

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. 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. 

n = Number of different fuel types burned in 

your boiler or process heater for the 

mixture that has the highest content of 

mercury. 

(3) If you opt to comply with the 

alternative total selected metals limit, 

you must establish the maximum total 

selected metals fuel input (TSMinput) 

for solid fuels during the initial fuel 

analysis according to the procedures in 

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

section. 

(i) You must determine the fuel type 

or fuel mixture that you could burn in 

your boiler or process heater that has 

the highest content of total selected 

metals. 

(ii) During the fuel analysis for total 

selected metals, you must determine the 

fraction of the total heat input for each 

fuel type burned (Qi) based on the fuel 

mixture that has the highest content of 

total selected metals, and the average 

total selected metals concentration of 

each fuel type burned (TSMi). 

(iii) You must establish a maximum 

total selected metals input level using 

Equation 9 of this section. 

Where: 

TSMinput = Maximum amount of total 

selected metals entering the boiler or 

process heater through fuels burned in 

units of pounds per million Btu. 

TSMi = Arithmetic average concentration of 

total selected metals 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 total selected 

metals. 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. 

n = Number of different fuel types burned in 

your boiler or process heater for the 

mixture that has the highest content of 

total selected metals. 

(4) You must establish parameter 

operating limits according to paragraphs 

(b)(4)(i) through (vii) of this section. As 

indicated in Table 4 to this subpart, you 

are not required to establish and comply 

with the operating parameter limits 

when you are using a CEMS to monitor 

and demonstrate compliance with the 

applicable emission limit for that 

control device parameter. 

(i) For a wet acid gas scrubber, you 

must establish the minimum scrubber 

effluent pH 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 

hydrogen chloride and mercury 

emissions, you must establish one set of 

minimum scrubber effluent pH, liquid 

flow rate, and pressure drop operating 

limits. The minimum scrubber effluent 

pH operating limit must be established 

during the hydrogen chloride 

performance test. If you conduct 

multiple performance tests, you must 

set the minimum liquid flow rate 

operating limit at the higher of the 

minimum values established during the 

performance tests. 

(ii) For any particulate control device 

(e.g., ESP, particulate wet scrubber, 

fabric filter) for which you use a PM 

CPMS, you must establish your 

operating limit during the three-run 

performance during which you 

demonstrate compliance with your 

applicable limit. The PM CPMS 

operating limit is the 1-hour average PM 

CPMS output value recorded during the 

performance test. If you conduct 

separate performance tests for PM and 

total selected metals, you must set the 

maximum PM CPMS operating limits at 

the lower of maximum PM CPMS values 

established during the performance 

tests. 

(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 

particulate matter and total selected 

metals 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 hydrogen chloride 

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. 

(iv) For an electrostatic precipitator 

operated with a wet scrubber, you must 

establish the minimum voltage and 

secondary amperage (or total power 

input), as defined in § 63.7575, as your 

operating limits during the three-run 

performance test during which you 

demonstrate compliance with your 

applicable limit. (These operating limits 

do not apply to electrostatic 

precipitators that are operated as dry 

controls without a wet scrubber.) 

(v) For a dry scrubber, you must 

establish the minimum sorbent injection 

rate for each sorbent, as defined in 

§ 63.7575, as your operating limit during 

the three-run performance test during 

which you demonstrate compliance 

with your applicable limit. 

(vi) For activated carbon injection, 

you must establish the minimum 

activated carbon injection rate, as 

defined in § 63.7575, as your operating 

limit during the three-run performance 

test during which you demonstrate 

compliance with your applicable limit. 

(vii) The operating limit for boilers or 

process heaters with fabric filters that 

demonstrate continuous compliance 

through bag leak detection systems is 

that a bag leak detection system be 

installed according to the requirements 

in § 63.7525, and that each fabric filter 

must be operated such that the bag leak 

detection system alarm does not sound 

more than 5 percent of the operating 

time during a 6-month period. 

(c) If you elect to demonstrate 

compliance with an applicable emission 

limit through fuel analysis, you must 

conduct fuel analyses according to 

§ 63.7521 and follow the procedures in 

paragraphs (c)(1) through (5) of this 

section. 

(1) If you burn more than one fuel 

type, you must determine the fuel 

mixture you could burn in your boiler 

or process heater that would result in 

the maximum emission rates of the 

pollutants that you elect to demonstrate 

compliance through fuel analysis. 

(2) You must determine the 90th 

percentile confidence level fuel 


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pollutant concentration of the 

composite samples analyzed for each 

fuel type using the one-sided z-statistic 

test described in Equation 10 of this 

section. 

Where: 

P90 = 90th percentile confidence level 

pollutant concentration, in pounds per 

million Btu. 

Mean = Arithmetic average of the fuel 

pollutant concentration in the fuel 

samples analyzed according to § 63.7521, 

in units of pounds per million Btu. 

SD = Standard deviation of the pollutant 

concentration in the fuel samples 

analyzed according to § 63.7521, in units 

of pounds per million Btu. 

T = t distribution critical value for 90th 

percentile (0.1) probability for the 

appropriate degrees of freedom (number 

of samples minus one) as obtained from 

a Distribution Critical Value Table. 

(3) To demonstrate compliance with 

the applicable emission limit for 

hydrogen chloride, the hydrogen 

chloride emission rate that you calculate 

for your boiler or process heater using 

Equation 11 of this section must not 

exceed the applicable emission limit for 

hydrogen chloride. 

Where: 

HCl = Hydrogen chloride 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 10 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 hydrogen 

chloride 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 12 of this section 

must not exceed the applicable emission 

limit for mercury. 

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 10 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 total 

selected metals for solid fuels, the total 

selected metals emission rate that you 

calculate for your boiler or process 

heater from solid fuels using Equation 

13 of this section must not exceed the 

applicable emission limit for total 

selected metals. 

Where: 

Metals = Total selected metals emission rate 

from the boiler or process heater in units 

of pounds per million Btu. 

TSMi90 = 90th percentile confidence level 

concentration of total selected metals in 

fuel, i, in units of pounds per million Btu 

as calculated according to Equation 10 of 

this section. 

Qi = Fraction of total heat input from fuel 

type, i, based on the fuel mixture that 

has the highest total selected metals 

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 total 

selected metals content. 

(d) If you own or operate an existing 

unit with a heat input capacity of less 

than 10 million Btu per hour, 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 is an 

accurate depiction of your facility. 

(f) You must submit the Notification 

of Compliance Status containing the 

results of the initial compliance 

demonstration according to the 

requirements in § 63.7545(e). 

(g) If you elect to demonstrate that a 

gaseous fuel meets the specifications of 

an other gas 1 fuel as defined in 

§ 63.7575, you must conduct an initial 

fuel specification analyses according to 

§ 63.7521(f) through (i). If the mercury 

constituents in the gaseous fuels will 

never exceed the specification included 

in the definition, you will include a 

signed certification with the 

Notification of Compliance Status that 

the initial fuel specification test meets 

the gas specification outlined in the 

definition of other gas 1 fuels. If your 

gas constituents could vary above the 

specification, you will conduct monthly 

testing according to the procedures in 

§ 63.7521(f) through (i) and § 63.7540(c) 


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80642 Federal Register / Vol. 76, No. 247 / Friday, December 23, 2011 / Proposed Rules 

and maintain records of the results of 

the testing as outlined in § 63.7555(g). 

(h) If you own or operate a unit 

subject to emission limits in Tables 1 or 

2 to this subpart, you must meet the 

work practice standard according to 

Table 3 of this subpart. You must 

submit a signed statement in the 

Notification of Compliance Status report 

that indicates that you employed good 

combustion practices and you 

maintained oxygen concentrations as 

specified by the boiler manufacturer for 

each startup and shutdown event. 

§ 63.7533 Can I use emission credits 

earned from implementation of energy 

conservation measures to comply with this 

subpart? 

(a) If you elect to comply with the 

alternative equivalent steam outputbased emission limits, instead of the 

heat input-based limits listed in Table 2 

to this subpart, and you want to take 

credit for implementing energy 

conservation measures identified in an 

energy assessment, you may 

demonstrate compliance using emission 

reduction credits according to the 

procedures in this section. You may use 

this compliance approach for an 

existing affected boiler for 

demonstrating initial compliance 

according to § 63.7522(e) and for 

demonstrating monthly compliance 

according to § 63.7522(f). Owners or 

operators using this compliance 

approach must establish an emissions 

benchmark, calculate and document the 

emission credits, develop an 

Implementation Plan, comply with the 

general reporting requirements, and 

apply the emission credit according to 

the procedures in paragraphs (b) 

through (f) of this section. You cannot 

use this compliance approach for a new 

or reconstructed affected boiler. 

(b) For each existing affected boiler 

for which you intend to apply emissions 

credits, establish a benchmark from 

which emission reduction credits may 

be generated by determining the actual 

annual fuel heat input to the affected 

boiler before initiation of an energy 

conservation activity to reduce energy 

demand (i.e., fuel usage) according to 

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

section. The benchmark shall be 

expressed in trillion Btu per year heat 

input. 

(1) The benchmark from which 

emission credits may be generated shall 

be determined by using the most 

representative, accurate, and reliable 

process available for the source. The 

benchmark shall be established for a 

one-year period before the date that an 

energy demand reduction occurs, unless 

it can be demonstrated that a different 

time period is more representative of 

historical operations. 

(2) Determine the starting point from 

which to measure progress. Inventory 

all fuel purchased and generated on-site 

(off-gases, residues) in physical units 

(MMBtu, million cubic feet, etc.). 

(3) Document all uses of energy from 

the affected boiler. Use the most recent 

data available. 

(4) Collect non-energy related facility 

and operational data to normalize, if 

necessary, the benchmark to current 

operations, such as building size, 

operating hours, etc. If possible, use 

actual data that are current and timely 

rather than estimated data. 

(c) Emissions credits can be generated 

if the energy conservation measures 

were implemented after January 1, 2008 

and if sufficient information is available 

to determine the appropriate value of 

credits. 

(1) The following emission points 

cannot be used to generate emissions 

averaging credits: 

(i) Energy conservation measures 

implemented on or before January 1, 

2008, unless the level of energy demand 

reduction is increased after January 1, 

2008, in which case credit will be 

allowed only for change in demand 

reduction achieved after January 1, 

2008. 

(ii) Emission credits on shut-down 

boilers. Boilers that are shut down 

cannot be used to generate credits. 

(2) For all points included in 

calculating emissions credits, the owner 

or operator shall: 

(i) Calculate annual credits for all 

energy demand points. Use Equation 14 

to calculate credits. Energy conservation 

measures that meet the criteria of 

paragraph (c)(1) of this section shall not 

be included, except as specified in 

paragraph (c)(1)(i) of this section. 

(3) Credits are generated by the 

difference between the benchmark that 

is established for each affected boiler, 

and the actual energy demand 

reductions from energy conservation 

measures implemented after January 1, 

2008. Credits shall be calculated using 

Equation 14 of this section as follows: 

(i) The overall equation for calculating 

credits is: 

Where: 

ECredits = Energy Input Savings for all 

energy conservation measures 

implemented for an affected boiler, 

expressed as a decimal fraction of the 

baseline energy input. 

EISiactual = Energy Input Savings for each 

energy conservation measure, i, 

implemented for an affected boiler, 

million Btu per year. 

EIbaseline = Energy Input baseline for the 

affected boiler, million Btu per year. 

n = Number of energy conservation measures 

included in the emissions credit for the 

affected boiler. 

(d) The owner or operator shall 

develop and submit for approval an 

Implementation Plan containing all of 

the information required in this 

paragraph for all boilers to be included 

in an emissions credit approach. The 

Implementation Plan shall identify all 

existing affected boilers to be included 

in applying the emissions credits. The 

Implementation Plan shall include a 

description of the energy conservation 

measures implemented and the energy 

savings generated from each measure 

and an explanation of the criteria used 

for determining that savings. You must 

submit the implementation plan for 

emission credits to the applicable 

delegated authority for review and 

approval no later than 180 days before 

the date on which the facility intends to 

demonstrate compliance using the 

emission credit approach. 

(e) The emissions rate as calculated 

using Equation 15 of this section from 

each existing boiler participating in the 

emissions credit option must be in 

compliance with the limits in Table 2 to 

this subpart at all times following the 

compliance date specified in § 63.7495. 

(f) You must use Equation 15 of this 

section to demonstrate initial 

compliance by demonstrating that the 

emissions from the affected boiler 

participating in the emissions credit 

compliance approach do not exceed the 

emission limits in Table 2 to this 

subpart. 


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Where: 

Eadj = Emission level adjusted by applying 

the emission credits earned, lb per 

million Btu steam output for the affected 

boiler. 

Em = Emissions measured during the 

performance test, lb per million Btu 

steam output for the affected boiler. 

ECredits = Emission credits from Equation 14 

for the affected boiler. 

Continuous Compliance Requirements 

§ 63.7535 Is there a minimum amount of 

monitoring data I must obtain? 

(a) You must monitor and collect data 

according to this section and the sitespecific monitoring plan required by 

§ 63.7505(d). 

(b) You must operate the monitoring 

system and collect data at all required 

intervals at all times that the affected 

source is operating and compliance is 

required, except for periods of 

monitoring system malfunctions or out 

of control periods (see § 63.8(c)(7) of 

this part), and required monitoring 

system quality assurance or control 

activities, including, as applicable, 

calibration checks, required zero and 

span adjustments, and scheduled CMS 

maintenance as defined in your sitespecific monitoring plan. A monitoring 

system malfunction is any sudden, 

infrequent, not reasonably preventable 

failure of the monitoring system to 

provide valid data. Monitoring system 

failures that are caused in part by poor 

maintenance or careless operation are 

not malfunctions. You are required to 

complete monitoring system repairs in 

response to monitoring system 

malfunctions or out-of-control periods 

and to return the monitoring system to 

operation as expeditiously as 

practicable. 

(c) You may not use data recorded 

during monitoring system malfunctions 

or out-of-control periods, repairs 

associated with monitoring system 

malfunctions or out-of-control periods, 

or required monitoring system quality 

assurance or 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. 

§ 63.7540 How do I demonstrate 

continuous compliance with the emission 

limitations, fuel specifications and work 

practice standards? 

(a) You must demonstrate continuous 

compliance with each emission limit in 

Tables 1 and 2 to this subpart, the work 

practice standards in Table 3 to this 

subpart, and the operating limits in 

Table 4 to this subpart that applies to 

you according to the methods specified 

in Table 8 to this subpart and 

paragraphs (a)(1) through (17) of this 

section. 

(1) Following the date on which the 

initial compliance demonstration is 

completed or is required to be 

completed under §§ 63.7 and 63.7510, 

whichever date comes first, operation 

above the established maximum or 

below the established minimum 

operating limits shall constitute a 

deviation of established operating limits 

listed in Table 4 of this subpart except 

during performance tests conducted to 

determine compliance with the 

emission limits or to establish new 

operating limits. Operating limits must 

be confirmed or reestablished during 

performance tests. 

(2) As specified in § 63.7550(c), 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: 

(i) Lower emissions of hydrogen 

chloride, mercury, and total selected 

metals than the applicable emission 

limit for each pollutant, if you 

demonstrate compliance through fuel 

analysis. 

(ii) Lower fuel input of chlorine, 

mercury, and total selected metals than 

the maximum values calculated during 

the last performance test, if you 

demonstrate compliance through 

performance testing. 

(3) If you demonstrate compliance 

with an applicable hydrogen chloride 

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 hydrogen 

chloride emission rate using Equation 

11 of § 63.7530 according to paragraphs 

(a)(3)(i) through (iii) of this section. You 

are not required to complete 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 hydrogen chloride 

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 hydrogen chloride 

emission rate from your boiler or 

process heater under these new 

conditions using Equation 11 of 

§ 63.7530. The recalculated hydrogen 

chloride emission rate must be less than 

the applicable emission limit. 

(4) If you demonstrate compliance 

with an applicable hydrogen chloride 

emission limit through performance 

testing and you plan to burn a new type 

of fuel or a new mixture of fuels, you 

must recalculate the maximum chlorine 

input using Equation 7 of § 63.7530. If 

the results of recalculating the 

maximum chlorine input using 

Equation 7 of § 63.7530 are greater than 

the maximum chlorine input level 

established during the previous 

performance test, then you must 

conduct a new performance test within 

60 days of burning the new fuel type or 

fuel mixture according to the 

procedures in § 63.7520 to demonstrate 

that the hydrogen chloride emissions do 

not exceed the emission limit. You must 

also establish new operating limits 

based on this performance test 

according to the procedures in 

§ 63.7530(b). In recalculating the 

maximum chlorine input and 

establishing the new operating limits, 

you are not required to complete fuel 

analyses for and include the fuels 

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

(iii). 

(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 12 of § 63.7530 

according to the procedures specified in 

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


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section. You are not required to 

complete 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 12 of § 63.7530. The 

recalculated mercury emission rate must 

be less than the applicable emission 

limit. 

(6) If you demonstrate compliance 

with an applicable mercury emission 

limit through performance testing, and 

you plan to burn a new type of fuel or 

a new mixture of fuels, you must 

recalculate the maximum mercury input 

using Equation 8 of § 63.7530. If the 

results of recalculating the maximum 

mercury input using Equation 8 of 

§ 63.7530 are higher than the maximum 

mercury input level established during 

the previous performance test, then you 

must conduct a new performance test 

within 60 days of burning the new fuel 

type or fuel mixture according to the 

procedures in § 63.7520 to demonstrate 

that the mercury emissions do not 

exceed the emission limit. You must 

also establish new operating limits 

based on this performance test 

according to the procedures in 

§ 63.7530(b). You are not required to 

complete 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. 

(7) If your unit is controlled with a 

fabric filter, and you demonstrate 

continuous compliance using a bag leak 

detection system, you must initiate 

corrective action within 1 hour of a bag 

leak detection system alarm and 

complete corrective actions as soon as 

practical, and operate and maintain the 

fabric filter system such that the alarm 

does not sound more than 5 percent of 

the operating time during a 6-month 

period. You must also keep records of 

the date, time, and duration of each 

alarm, the time corrective action was 

initiated and completed, and a brief 

description of the cause of the alarm 

and the corrective action taken. You 

must also record the percent of the 

operating time during each 6-month 

period that the alarm sounds. In 

calculating this operating time 

percentage, if inspection of the fabric 

filter demonstrates that no corrective 

action is required, no alarm time is 

counted. If corrective action is required, 

each alarm shall be counted as a 

minimum of 1 hour. If you take longer 

than 1 hour to initiate corrective action, 

the alarm time shall be counted as the 

actual amount of time taken to initiate 

corrective action. 

(8) If you install a CO CEMS 

according to § 63.7525(a), then you must 

meet the requirements in paragraphs 

(a)(8)(i) through (iii) of this section. 

(i) Continuously monitor CO 

according to §§ 63.7525(a) and 63.7535. 

(ii) Maintain a CO emission level 

below or at your applicable alternative 

CO CEMS-based standard in Tables 1 or 

2 to this subpart at all times. 

(iii) Keep records of CO levels 

according to § 63.7555(b). 

(9) The owner or operator of an 

affected source using a PM CPMS to 

meet requirements of this subpart shall 

install, certify, operate, and maintain 

the PM CPMS in accordance with your 

site-specific monitoring plan as required 

in § 63.7505(d). 

(10) If your boiler or process heater is 

in either the natural gas, refinery gas, 

other gas 1, or Metal Process Furnace 

subcategories and has a heat input 

capacity of 10 million Btu per hour or 

greater, you must conduct a tune-up of 

the boiler or process heater annually to 

demonstrate continuous compliance as 

specified in paragraphs (a)(10)(i) 

through (vi) of this section. This 

requirement does not apply to limiteduse boilers and process heaters, as 

defined in § 63.7575. 

(i) As applicable, inspect the burner, 

and clean or replace any components of 

the burner as necessary (you may delay 

the burner inspection until the next 

scheduled or unscheduled unit 

shutdown); 

(ii) Inspect the flame pattern, as 

applicable, and adjust the burner as 

necessary to optimize the flame pattern. 

The adjustment should be consistent 

with the manufacturer’s specifications, 

if available; 

(iii) Inspect the system controlling the 

air-to-fuel ratio, as applicable, and 

ensure that it is correctly calibrated and 

functioning properly; 

(iv) Optimize total emissions of 

carbon monoxide. This optimization 

should be consistent with the 

manufacturer’s specifications, if 

available; 

(v) Measure the concentrations in the 

effluent stream of carbon monoxide in 

parts per million, by volume, and 

oxygen in volume percent, before and 

after the adjustments are made 

(measurements may be either on a dry 

or wet basis, as long as it is the same 

basis before and after the adjustments 

are made); and 

(vi) Maintain on-site and submit, if 

requested by the Administrator, an 

annual report containing the 

information in paragraphs (a)(10)(vi)(A) 

through (C) of this section, 

(A) The concentrations of carbon 

monoxide in the effluent stream in parts 

per million by volume, and oxygen in 

volume percent, measured before and 

after the adjustments of the boiler; 

(B) A description of any corrective 

actions taken as a part of the 

combustion adjustment; and 

(C) The type and amount of fuel used 

over the 12 months prior to the annual 

adjustment, but only if the unit was 

physically and legally capable of using 

more than one type of fuel during that 

period. Units sharing a fuel meter may 

estimate the fuel used by each unit. 

(11) If your boiler or process heater 

has a heat input capacity of less than 10 

million Btu per hour (except as 

specified in paragraph (a)(12) of this 

section), or meets the definition of 

limited-use boiler or process heater in 

§ 63.7575, you must conduct a biennial 

tune-up of the boiler or process heater 

as specified in paragraphs (a)(10)(i) 

through (a)(10)(vi) of this section to 

demonstrate continuous compliance. 

(12) If your boiler or process heater 

has a heat input capacity of less than 5 

million Btu per hour, and the unit is in 

the units designed to burn natural gas, 

refinery gas or other gas 1 fuels, units 

designed to burn gas 2 (other), or units 

designed to burn light liquid 

subcategories, you must conduct a tuneup of the boiler or process heater every 

5 years as specified in paragraphs 

(a)(10)(i) through (vi) of this section to 

demonstrate continuous compliance. 

You may delay the burner inspection 

specified in paragraph (a)(10)(i) of this 

section until the next scheduled or 

unscheduled unit shutdown, but you 

must inspect each burner at least once 

every 72 months. 

(13) If the unit is not operating on the 

required date for a tune-up, the tune-up 

must be conducted within one week of 

startup. 

(14) If you are using a CEMS 

measuring mercury emissions to meet 

requirements of this subpart you must 

install, certify, operate, and maintain 

the mercury CEMS as specified in 

paragraphs (a)(14)(i) and (ii) of this 

section. 

(i) Operate the mercury CEMS in 

accordance with performance 


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specification 12A of 40 CFR part 60, 

appendix B or operate a sorbent trap 

based integrated monitor in accordance 

with performance specification 12B of 

40 CFR part 60, appendix B. The 

duration of the performance test must be 

a calendar month. For each calendar 

month in which the unit operates, you 

must obtain hourly mercury 

concentration data, and stack gas 

volumetric flow rate data. 

(ii) If you are using a mercury CEMS, 

you must install, operate, calibrate, and 

maintain an instrument for 

continuously measuring and recording 

the mercury mass emissions rate to the 

atmosphere according to the 

requirements of performance 

specifications 6 and 12A of 40 CFR part 

60, appendix B, and quality assurance 

procedure 6 of 40 CFR part 60, appendix 

F. 

(15) If you are using a CEMS to 

measure hydrogen chloride emissions to 

meet requirements of this subpart, you 

must install, certify, operate, and 

maintain the hydrogen chloride CEMS 

as specified in paragraphs (a)(15)(i) and 

(ii) of this section. This option for an 

affected unit takes effect on the date a 

final performance specification for a 

hydrogen chloride CEMS is published 

in the Federal Register or the date of 

approval of a site-specific monitoring 

plan. 

(i) Operate the continuous emissions 

monitoring system in accordance with 

the applicable performance 

specification in 40 CFR part 60, 

appendix B. The duration of the 

performance test must be a calendar 

month. For each calendar month in 

which the unit operates, you must 

obtain hourly hydrogen chloride 

concentration data, and stack gas 

volumetric flow rate data. 

(ii) If you are using a hydrogen 

chloride continuous emissions 

monitoring system, you must install, 

operate, calibrate, and maintain an 

instrument for continuously measuring 

and recording the hydrogen chloride 

mass emissions rate to the atmosphere 

according to the requirements of the 

applicable performance specification of 

40 CFR part 60, appendix B, and the 

quality assurance procedures of 40 CFR 

part 60, appendix F. 

(16) If you demonstrate compliance 

with an applicable total selected metals 

emission limit through performance 

testing, and you plan to burn a new type 

of fuel or a new mixture of fuels, you 

must recalculate the maximum total 

selected metals input using Equation 9 

of § 63.7530. If the results of 

recalculating the maximum total 

selected metals input using Equation 9 

of § 63.7530 are higher than the 

maximum total selected input level 

established during the previous 

performance test, then you must 

conduct a new performance test within 

60 days of burning the new fuel type or 

fuel mixture according to the 

procedures in § 63.7520 to demonstrate 

that the total selected metals emissions 

do not exceed the emission limit. You 

must also establish new operating limits 

based on this performance test 

according to the procedures in 

§ 63.7530(b). You are not required to 

complete 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 total 

selected metals emission rate. 

(17) If you demonstrate compliance 

with an applicable total selected metals 

emission limit through fuel analysis for 

solid fuels, and you plan to burn a new 

type of fuel, you must recalculate the 

total selected metals emission rate using 

Equation 13 of § 63.7530 according to 

the procedures specified in paragraphs 

(a)(5)(i) through (iii) of this section. You 

are not required to complete 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 total selected metals 

emission rate. 

(i) You must determine the total 

selected metals 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 total selected metals. 

(iii) Recalculate the total selected 

metals emission rate from your boiler or 

process heater under these new 

conditions using Equation 13 of 

§ 63.7530. The recalculated total 

selected metals emission rate must be 

less than the applicable emission limit. 

(b) You must report each instance in 

which you did not meet each emission 

limit and operating limit in Tables 1 

through 4 to this subpart that apply to 

you. These instances are deviations 

from the emission limits or operating 

limits, respectively, in this subpart. 

These deviations must be reported 

according to the requirements in 

§ 63.7550. 

(c) If you elected to demonstrate that 

the unit meets the specification for 

mercury for the other gas 1 subcategory 

and you cannot submit a signed 

certification under § 63.7545(g) because 

the constituents could exceed the 

specification, you must conduct 

monthly fuel specification testing of the 

gaseous fuels, according to the 

procedures in § 63.7521(f) through (i). 

(d) For periods of startup and 

shutdown, you must meet the work 

practice standards according to Table 3 

of this subpart. 

§ 63.7541 How do I demonstrate 

continuous compliance under the 

emissions averaging provision? 

(a) Following the compliance date, the 

owner or operator must demonstrate 

compliance with this subpart on a 

continuous basis by meeting the 

requirements of paragraphs (a)(1) 

through (5) of this section. 

(1) For each calendar month, 

demonstrate compliance with the 

average weighted emissions limit for the 

existing units participating in the 

emissions averaging option as 

determined in § 63.7522(f) and (g). 

(2) You must maintain the applicable 

opacity limit according to paragraphs 

(a)(2)(i) and (ii) of this section. 

(i) For each existing unit participating 

in the emissions averaging option that is 

equipped with a dry control system and 

not vented to a common stack, maintain 

opacity at or below the applicable limit. 

(ii) For each group of units 

participating in the emissions averaging 

option where each unit in the group is 

equipped with a dry control system and 

vented to a common stack that does not 

receive emissions from non-affected 

units, maintain opacity at or below the 

applicable limit at the common stack. 

(3) For each existing unit participating 

in the emissions averaging option that is 

equipped with a wet scrubber, maintain 

the 30-day rolling average parameter 

values at or below the operating limits 

established during the most recent 

performance test. 

(4) For each existing unit participating 

in the emissions averaging option that 

has an approved alternative operating 

plan, maintain the 30-day rolling 

average parameter values at or below the 

operating limits established in the most 

recent performance test. 

(5) For each existing unit participating 

in the emissions averaging option 

venting to a common stack 

configuration containing affected units 

from other subcategories, maintain the 

appropriate operating limit for each unit 

as specified in Table 4 to this subpart 

that applies. 

(b) Any instance where the owner or 

operator fails to comply with the 

continuous monitoring requirements in 

paragraphs (a)(1) through (5) of this 

section is a deviation. 


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Notification, Reports, and Records 

§ 63.7545 What notifications must I submit 

and when? 

(a) You must submit to the delegated 

authority all of the notifications in 

§ 63.7(b) and (c), § 63.8(e), (f)(4) and (6), 

and § 63.9(b) through (h) that apply to 

you by the dates specified. 

(b) As specified in § 63.9(b)(2), if you 

startup your affected source before 

[DATE 60 DAYS AFTER THE DATE OF 

PUBLICATION OF THE FINAL RULE IN 

THE Federal Register], you must submit 

an Initial Notification not later than 120 

days after [DATE 60 DAYS AFTER THE 

DATE OF PUBLICATION OF THE 

FINAL RULE IN THE Federal Register]. 

(c) As specified in § 63.9(b)(4) and 

(b)(5), if you startup your new or 

reconstructed affected source on or after 

[DATE 60 DAYS AFTER PUBLICATION 

OF THE FINAL RULE IN THE FEDERAL 

REGISTER], you must submit an Initial 

Notification not later than 15 days after 

the actual date of startup of the affected 

source. 

(d) If you are required to conduct a 

performance test you must submit a 

Notification of Intent to conduct a 

performance test at least 60 days before 

the performance test is scheduled to 

begin. 

(e) If you are required to conduct an 

initial compliance demonstration as 

specified in § 63.7530(a), you must 

submit a Notification of Compliance 

Status according to § 63.9(h)(2)(ii). For 

the initial compliance demonstration for 

each affected source, you must submit 

the Notification of Compliance Status, 

including all performance test results 

and fuel analyses, before the close of 

business on the 60th day following the 

completion of all performance test and/ 

or other initial compliance 

demonstrations for the affected source 

according to § 63.10(d)(2). The 

Notification of Compliance Status report 

must contain all the information 

specified in paragraphs (e)(1) through 

(8), as applicable. 

(1) A description of the affected 

unit(s) including identification of which 

subcategory the unit is in, the design 

heat input capacity of the unit, a 

description of the add-on controls used 

on the unit, description of the fuel(s) 

burned, including whether the fuel(s) 

were determined by you or EPA through 

a petition process to be a non-waste 

under § 241.3, whether the fuel(s) were 

processed from discarded nonhazardous secondary materials within 

the meaning of § 241.3, and justification 

for the selection of fuel(s) burned during 

the compliance demonstration. 

(2) Summary of the results of all 

performance tests and fuel analyses, and 

calculations conducted to demonstrate 

initial compliance including all 

established operating limits. 

(3) A summary of the maximum 

carbon monoxide emission levels 

recorded during the performance test to 

show that you have met any applicable 

emission standard in Table 1 or 2 to this 

subpart, if you are not using a CO CEMS 

to demonstrate compliance. 

(4) Identification of whether you plan 

to demonstrate compliance with each 

applicable emission limit through 

performance testing, a CEMS, or fuel 

analysis. 

(5) Identification of whether you plan 

to demonstrate compliance by emissions 

averaging and identification of whether 

you plan to demonstrate compliance by 

using emission credits through energy 

conservation: 

(i) If you plan to demonstrate 

compliance by emission averaging, 

report the emission level that was being 

achieved or the control technology 

employed on [DATE 60 DAYS AFTER 

PUBLICATION OF THE FINAL RULE IN 

THE Federal Register]. 

(6) A signed certification that you 

have met all applicable emission limits 

and work practice standards. 

(7) If you had a deviation from any 

emission limit, work practice standard, 

or operating limit, you must also submit 

a description of the deviation, the 

duration of the deviation, and the 

corrective action taken in the 

Notification of Compliance Status 

report. 

(8) In addition to the information 

required in § 63.9(h)(2), your 

notification of compliance status must 

include the following certification(s) of 

compliance, as applicable, and signed 

by a responsible official: 

(i) ‘‘This facility complies with the 

requirements in § 63.7540(a)(10), (11), or 

(12) to conduct an annual, biennial, or 

5-year tune-up, as applicable, of each 

unit.’’ 

(ii) ‘‘This facility has had an energy 

assessment performed according to 

§ 63.7530(e).’’ 

(iii) Except for units that qualify for a 

statutory exemption as provided in 

section 129(g)(1) of the Clean Air Act, 

include the following: ‘‘No secondary 

materials that are solid waste were 

combusted in any affected unit.’’ 

(f) If you operate a unit designed to 

burn natural gas, refinery gas, or other 

gas 1 fuels that is subject to this subpart, 

and you intend to use a fuel other than 

natural gas, refinery gas, gaseous fuel 

subject to another subpart of this part, 

or other gas 1 fuel to fire the affected 

unit during a period of natural gas 

curtailment or supply interruption, as 

defined in § 63.7575, you must submit 

a notification of alternative fuel use 

within 48 hours of the declaration of 

each period of natural gas curtailment or 

supply interruption, as defined in 

§ 63.7575. The notification must include 

the information specified in paragraphs 

(f)(1) through (5) of this section. 

(1) Company name and address. 

(2) Identification of the affected unit. 

(3) Reason you are unable to use 

natural gas or equivalent fuel, including 

the date when the natural gas 

curtailment was declared or the natural 

gas supply interruption began. 

(4) Type of alternative fuel that you 

intend to use. 

(5) Dates when the alternative fuel use 

is expected to begin and end. 

(g) If you intend to commence or 

recommence combustion of solid waste, 

you must provide 30 days prior notice 

of the date upon which you will 

commence or recommence combustion 

of solid waste. The notification must 

identify: 

(1) The name of the owner or operator 

of the affected source, the location of the 

source, the boiler(s) or process heater(s) 

that will commence burning solid 

waste, and the date of the notice. 

(2) The currently applicable 

subcategory under this subpart. 

(3) The date on which you became 

subject to the currently applicable 

emission limits. 

(4) The date upon which you will 

commence combusting solid waste. 

(h) If you intend to switch fuels, and 

this fuel switch may result in the 

applicability of a different subcategory, 

you must provide 30 days prior notice 

of the date upon which you will switch 

fuels. The notification must identify: 

(1) The name of the owner or operator 

of the affected source, the location of the 

source, the boiler(s) that will switch 

fuels, and the date of the notice. 

(2) The currently applicable 

subcategory under this subpart. 

(3) The date on which you became 

subject to the currently applicable 

standards. 

(4) The date upon which you will 

commence the fuel switch. 

§ 63.7550 What reports must I submit and 

when? 

(a) You must submit each report in 

Table 9 to this subpart that applies to 

you. 

(b) Unless the EPA Administrator has 

approved a different schedule for 

submission of reports under § 63.10(a), 

you must submit each report by the date 

in Table 9 to this subpart and according 

to the requirements in paragraphs (b)(1) 

through (5) of this section. For units that 

are subject only to a requirement to 

conduct an annual, biennial, or 5-year 


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tune-up according to § 63.7540(a)(10), 

(11), or (12), respectively, and not 

subject to emission limits or operating 

limits, you may submit only an annual, 

biennial, or 5-year compliance report, as 

applicable, as specified in paragraphs 

(b)(1) through (5) of this section, instead 

of a semi-annual compliance report. 

(1) The first compliance report must 

cover the period beginning on the 

compliance date that is specified for 

your affected source 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 compliance report must 

be postmarked or delivered 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 your source in 

§ 63.7495. The first annual, biennial, or 

5-year compliance report must be 

postmarked no later than January 31. 

(3) Each subsequent 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 compliance 

report must be postmarked or delivered 

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 no later than January 31. 

(5) For each affected source that is 

subject to permitting regulations 

pursuant to part 70 or part 71 of this 

chapter, and if the delegated authority 

has established dates for submitting 

semiannual reports pursuant to 

§ 70.6(a)(3)(iii)(A) or § 71.6(a)(3)(iii)(A), 

you may submit the first and subsequent 

compliance reports according to the 

dates the delegated authority has 

established instead of according to the 

dates in paragraphs (b)(1) through (4) of 

this section. 

(c) The compliance report must 

contain the information required in 

paragraphs (c)(1) through (13) of this 

section. 

(1) Company name and address. 

(2) 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. 

(3) Date of report and beginning and 

ending dates of the reporting period. 

(4) The total fuel use by each affected 

source subject to an emission limit, for 

each calendar month within the 

semiannual (or annual, biennial, or 5- 

year) reporting period, including, but 

not limited to, a description of the fuel, 

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

basis for concluding that the fuel is not 

a waste, and the total fuel usage amount 

with units of measure. 

(5) A summary of the results of the 

annual performance tests for affected 

sources subject to an emission limit, a 

summary of any fuel analyses associated 

with performance tests, and 

documentation of any operating limits 

that were reestablished during this test, 

if applicable. 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, a 

comparison of the emission level you 

achieved in the last 2 performance tests 

to the 75 percent emission limit 

threshold required in § 63.7515(b) or (c), 

and a statement as to whether there 

have been any operational changes since 

the last performance test that could 

increase emissions. 

(6) A signed statement indicating that 

you burned no new types of fuel in an 

affected source subject to an emission 

limit. Or, if you did burn a new type of 

fuel and are subject to a hydrogen 

chloride emission limit, you must 

submit the calculation of chlorine input, 

using Equation 5 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 hydrogen chloride 

emission rate using Equation 11 of 

§ 63.7530 that demonstrates that your 

source is still meeting the emission limit 

for hydrogen chloride 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 12 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 total selected metals 

emission limit, you must submit the 

calculation of total selected metals 

input, using Equation 9 of § 63.7530, 

that demonstrates that your source is 

still within its maximum total selected 

metals input level established during 

the previous performance testing (for 

sources that demonstrate compliance 

through performance testing), or you 

must submit the calculation of total 

selected metals emission rate, using 

Equation 13 of § 63.7530, that 

demonstrates that your source is still 

meeting the emission limit for total 

selected metals emissions (for boilers or 

process heaters that demonstrate 

compliance through fuel analysis). 

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

fuel in an affected source 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 total selected metals 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. 

(8) A summary of any monthly fuel 

analyses conducted to demonstrate 

compliance according to §§ 63.7521 and 

63.7530 for affected sources subject to 

emission limits, and any fuel 

specification analyses conducted 

according to § 63.7521(f) and 

§ 63.7530(g). 

(9) 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. 

(10) If there were no deviations from 

the monitoring requirements including 

no periods during which the CMSs, 

including CEMS, COMS, and 

continuous parameter monitoring 

systems, 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. 

(11) If a malfunction occurred during 

the reporting period, the report must 

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 


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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. 

(12) 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. 

(13) 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). 

(14) For units subject to emission 

limits in Tables 1 or 2 of this subpart, 

for each startup or shutdown event 

during the reporting period, report the 

percentage concentration of oxygen in 

the firebox on an hourly basis 

throughout the event, the calendar date 

and length of each event, and the reason 

for each event. 

(d) For each deviation from an 

emission limit or operating limit in this 

subpart that occurs at an affected source 

where you are not using a CMS to 

comply with that emission limit or 

operating limit, the compliance report 

must additionally contain the 

information required in paragraphs 

(d)(1) through (4) of this section. 

(1) The total operating time of each 

affected source during the reporting 

period. 

(2) A description of the deviation and 

which emission limit or operating limit 

from which you deviated. 

(3) Information on the number, 

duration, and cause of deviations 

(including unknown cause), as 

applicable, and the corrective action 

taken. 

(4) A copy of the test report if the 

annual performance test showed a 

deviation from the emission limits. 

(e) For each deviation from an 

emission limit, operating limit, and 

monitoring requirement in this subpart 

occurring at an affected source where 

you are using a CMS to comply with 

that emission limit or operating limit, 

you must include the information 

required in paragraphs (e)(1) through 

(12) of this section. This includes any 

deviations from your site-specific 

monitoring plan as required in 

§ 63.7505(d). 

(1) The date and time that each 

deviation started and stopped and 

description of the nature of the 

deviation (i.e., what you deviated from). 

(2) The date and time that each CMS 

was inoperative, except for zero (lowlevel) and high-level checks. 

(3) The date, time, and duration that 

each CMS was out of control, including 

the information in § 63.8(c)(8). 

(4) The date and time that each 

deviation started and stopped. 

(5) A summary of the total duration of 

the deviation during the reporting 

period and the total duration as a 

percent of the total source operating 

time during that reporting period. 

(6) An analysis of the total duration of 

the deviations during the reporting 

period into those that are due to control 

equipment problems, process problems, 

other known causes, and other 

unknown causes. 

(7) A summary of the total duration of 

CMS’s downtime during the reporting 

period and the total duration of CMS 

downtime as a percent of the total 

source operating time during that 

reporting period. 

(8) An identification of each 

parameter that was monitored at the 

affected source for which there was a 

deviation. 

(9) A brief description of the source 

for which there was a deviation. 

(10) A brief description of each CMS 

for which there was a deviation. 

(11) The date of the latest CMS 

certification or audit for the system for 

which there was a deviation. 

(12) A description of any changes in 

CMSs, processes, or controls since the 

last reporting period for the source for 

which there was a deviation. 

(f) Each affected source that has 

obtained a Title V operating permit 

pursuant to part 70 or part 71 of this 

chapter must report all deviations as 

defined in this subpart in the 

semiannual monitoring report required 

by § 70.6(a)(3)(iii)(A) or 

§ 71.6(a)(3)(iii)(A). If an affected source 

submits a compliance report pursuant to 

Table 9 to this subpart along with, or as 

part of, the semiannual monitoring 

report required by § 70.6(a)(3)(iii)(A) or 

§ 71.6(a)(3)(iii)(A), and the compliance 

report includes all required information 

concerning deviations from any 

emission limit, operating limit, or work 

practice requirement in this subpart, 

submission of the compliance report 

satisfies any obligation to report the 

same deviations in the semiannual 

monitoring report. However, submission 

of a compliance report does not 

otherwise affect any obligation the 

affected source may have to report 

deviations from permit requirements to 

the delegated authority. 

(g) (Reserved) 

(h) Within 60 days after the date of 

completing each performance test, you 

must transmit the results of the 

performance tests required by this 

subpart to EPA’s WebFIRE database by 

using the Compliance and Emissions 

Data Reporting Interface (CEDRI) that is 

accessed through EPA’s Central Data 

Exchange (CDX) (http://www.epa.gov/ 

cdx). Performance test data must be 

submitted in the file format generated 

through use of EPA’s Electronic 

Reporting Tool (ERT) (see http:// 

www.epa.gov/ttn/chief/ert/index.html). 

Only data collected using test methods 

on the ERT Web site are subject to this 

requirement for submitting reports 

electronically to WebFIRE. Owners or 

operators who claim that some of the 

information being submitted for 

performance tests is confidential 

business information (CBI) must submit 

a complete ERT file including 

information claimed to be CBI on a 

compact disk or other commonly used 

electronic storage media (including, but 

not limited to, flash drives) to the EPA. 

The electronic media must be clearly 

marked as CBI and mailed to U.S. EPA/ 

OAPQS/CORE CBI Office, Attention: 

WebFIRE Administrator, MD C404–02, 

4930 Old Page Rd., Durham, NC 27703. 

The same ERT file with the CBI omitted 

must be submitted to EPA via CDX as 

described earlier in this paragraph. At 

the discretion of the delegated authority, 

you must also submit these reports, 

including the confidential business 

information, to the delegated authority 

in the format specified by the delegated 

authority. 

(i) Within 60 days after the date of 

completing each CEMS (CO and Hg) 

performance evaluation test, as defined 

in § 63.2 and required by this subpart, 

you must submit the relative accuracy 

test audit data electronically into EPA’s 

Central Data Exchange by using the 

Electronic Reporting Tool as described 

in paragraph (h) of this section. Only 

data collected using test methods 

compatible with ERT are subject to this 

requirement to be submitted 

electronically to EPA’s CDX. 

(j) Within 60 days after the reporting 

periods ending on March 31, June 30, 

September 30, and December 31, you 

must transmit quarterly reports to EPA’s 

WebFIRE database by using the 

Compliance and Emissions Data 

Reporting Interface (CEDRI) that is 

accessed through EPA’s Central Data 

Exchange (CDX) (www.epa.gov/cdx). For 

each reporting period, the quarterly 

reports must include all of the 


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calculated 30 day rolling average values 

based on the daily CEMS (CO and Hg) 

and CPMS (PM CPMS output, scrubber 

pH, scrubber liquid flow rate, scrubber 

pressure drop) data. 

§ 63.7555 What records must I keep? 

(a) You must keep records according 

to paragraphs (a)(1) and (2) of this 

section. 

(1) A copy of each notification and 

report that you submitted to comply 

with this subpart, including all 

documentation supporting any Initial 

Notification or Notification of 

Compliance Status or semiannual 

compliance report that you submitted, 

according to the requirements in 

§ 63.10(b)(2)(xiv). 

(2) Records of performance tests, fuel 

analyses, or other compliance 

demonstrations and performance 

evaluations as required in 

§ 63.10(b)(2)(viii). 

(b) For each CEMS, COMS, and 

continuous monitoring system you must 

keep records according to paragraphs 

(b)(1) through (5) of this section. 

(1) Records described in 

§ 63.10(b)(2)(vii) through (xi). 

(2) Monitoring data for continuous 

opacity monitoring system during a 

performance evaluation as required in 

§ 63.6(h)(7)(i) and (ii). 

(3) Previous (i.e., superseded) 

versions of the performance evaluation 

plan as required in § 63.8(d)(3). 

(4) Request for alternatives to relative 

accuracy test for CEMS as required in 

§ 63.8(f)(6)(i). 

(5) Records of the date and time that 

each deviation started and stopped. 

(c) You must keep the records 

required in Table 8 to this subpart 

including records of all monitoring data 

and calculated averages for applicable 

operating limits, such as opacity, 

pressure drop, pH, and operating load, 

to show continuous compliance with 

each emission limit and operating limit 

that applies to you. 

(d) For each boiler or process heater 

subject to an emission limit in Table 1 

or 2 to this subpart, you must also keep 

the applicable records in paragraphs 

(d)(1) through (9) of this section. 

(1) You must keep records of monthly 

fuel use by each boiler or process heater, 

including the type(s) of fuel and 

amount(s) used. 

(2) If you combust non-hazardous 

secondary materials that have been 

determined not to be solid waste 

pursuant to § 241.3(b)(1) and (2), you 

must keep a record that documents how 

the secondary material meets each of the 

legitimacy criteria. If you combust a fuel 

that has been processed from a 

discarded non-hazardous secondary 

material pursuant to § 241.3(b)(4), you 

must keep records as to how the 

operations that produced the fuel satisfy 

the definition of processing in § 241.2. 

If the fuel received a non-waste 

determination pursuant to the petition 

process submitted under § 241.3(c), you 

must keep a record that documents how 

the fuel satisfies the requirements of the 

petition process. Units exempt from the 

incinerator standards under section 

129(g)(1) of the Clean Air Act because 

they are qualifying facilities burning a 

homogeneous waste stream do not need 

to maintain the records described in this 

paragraph (d)(2). 

(3) You must keep records of monthly 

hours of operation by each boiler or 

process heater that meets the definition 

of limited-use boiler or process heater. 

(4) 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 hydrogen chloride 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 hydrogen chloride 

emission rates, using Equation 11 of 

§ 63.7530, that were done to 

demonstrate compliance with the 

hydrogen chloride emission limit. 

Supporting documentation should 

include results of any fuel analyses and 

basis for the estimates of maximum 

chlorine fuel input or hydrogen chloride 

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 hydrogen chloride 

emission rate, for each boiler and 

process heater. 

(5) 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 12 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. 

(6) If, consistent with § 63.7515(b) and 

(c), you choose to stack test less 

frequently than annually, you must keep 

annual records that document that your 

emissions in the previous stack test(s) 

were less than 75 percent of the 

applicable emission limit (or, in specific 

instances noted in Tables 1 and 2 to this 

subpart, less than the applicable 

emission limit), and document that 

there was no change in source 

operations including fuel composition 

and operation of air pollution control 

equipment that would cause emissions 

of the relevant pollutant to increase 

within the past year. 

(7) Records of the occurrence and 

duration of each malfunction of the 

boiler or process heater, or of the 

associated air pollution control and 

monitoring equipment. 

(8) Records of actions taken during 

periods of malfunction to minimize 

emissions in accordance with the 

general duty to minimize emissions in 

§ 63.7500(a)(3), including corrective 

actions to restore the malfunctioning 

boiler or process heater, air pollution 

control, or monitoring equipment to its 

normal or usual manner of operation. 

(9) A copy of all calculations and 

supporting documentation of maximum 

total selected metals fuel input, using 

Equation 9 of § 63.7530, that were done 

to demonstrate continuous compliance 

with the total selected metals 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 total selected metals 

emission rates, using Equation 13 of 

§ 63.7530, that were done to 

demonstrate compliance with the total 

selected metals emission limit. 

Supporting documentation should 

include results of any fuel analyses and 

basis for the estimates of maximum total 

selected metals fuel input or total 

selected metals 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 

total selected metals fuel input, or total 

selected metals emission rates, for each 

boiler and process heater. 

(e) If you elect to average emissions 

consistent with § 63.7522, you must 

additionally keep a copy of the emission 

averaging implementation plan required 

in § 63.7522(g), all calculations required 

under § 63.7522, including monthly 


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records of heat input or steam 

generation, as applicable, and 

monitoring records consistent with 

§ 63.7541. 

(f) If you elect to use emission credits 

from energy conservation measures to 

demonstrate compliance according to 

§ 63.7533, you must keep a copy of the 

Implementation Plan required in 

§ 63.7533(d) and copies of all data and 

calculations used to establish credits 

according to § 63.7533(b), (c), and (f). 

(g) If you elected to demonstrate that 

the unit meets the specification for 

mercury for the other gas 1 subcategory 

and you cannot submit a signed 

certification under § 63.7545(g) because 

the constituents could exceed the 

specification, you must maintain 

monthly records of the calculations and 

results of the fuel specification for 

mercury in Table 6. 

(h) If you operate a unit designed to 

burn natural gas, refinery gas, or other 

gas 1 fuel that is subject to this subpart, 

and you use an alternative fuel other 

than natural gas, refinery gas, gaseous 

fuel subject to another subpart under 

this part, or other gas 1 fuel, you must 

keep records of the total hours per 

calendar year that alternative fuel is 

burned. 

(i) For each startup or shutdown 

event, you must maintain records that 

boiler operators have completed training 

for startup and shutdown procedures. 

§ 63.7560 In what form and how long must 

I keep my records? 

(a) Your records must be in a form 

suitable and readily available for 

expeditious review, according to 

§ 63.10(b)(1). 

(b) As specified in § 63.10(b)(1), you 

must keep each record for 5 years 

following the date of each occurrence, 

measurement, maintenance, corrective 

action, report, or record. 

(c) You must keep each record on site, 

or they must be accessible from on site 

(for example, through a computer 

network), for at least 2 years after the 

date of each occurrence, measurement, 

maintenance, corrective action, report, 

or record, according to § 63.10(b)(1). 

You can keep the records off site for the 

remaining 3 years. 

Other Requirements and Information 

§ 63.7565 What parts of the General 

Provisions apply to me? 

Table 10 to this subpart shows which 

parts of the General Provisions in 

§§ 63.1 through 63.15 apply to you. 

§ 63.7570 Who implements and enforces 

this subpart? 

(a) This subpart can be implemented 

and enforced by EPA, or a delegated 

authority such as your state, local, or 

tribal agency. If the EPA Administrator 

has delegated authority to your state, 

local, or tribal agency, then that agency 

(as well as EPA) has the authority to 

implement and enforce this subpart. 

You should contact your EPA Regional 

Office to find out if this subpart is 

delegated to your state, local, or tribal 

agency. 

(b) In delegating implementation and 

enforcement authority of this subpart to 

a state, local, or tribal agency under 40 

CFR part 63, subpart E, the authorities 

listed in paragraphs (b)(1) through (5) of 

this section are retained by the EPA 

Administrator and are not transferred to 

the state, local, or tribal agency, 

however, EPA retains oversight of this 

subpart and can take enforcement 

actions, as appropriate. 

(1) Approval of alternatives to the 

non-opacity emission limits and work 

practice standards in § 63.7500(a) and 

(b) under § 63.6(g). 

(2) Approval of alternative opacity 

emission limits in § 63.7500(a) under 

§ 63.6(h)(9). 

(3) Approval of major change to test 

methods in Table 5 to this subpart 

under § 63.7(e)(2)(ii) and (f) and as 

defined in § 63.90, and alternative 

analytical methods requested under 

§ 63.7521(b)(2). 

(4) Approval of major change to 

monitoring under § 63.8(f) and as 

defined in § 63.90, and approval of 

alternative operating parameters under 

§ 63.7500(a)(2) and § 63.7522(g)(2). 

(5) Approval of major change to 

recordkeeping and reporting under 

§ 63.10(e) and as defined in § 63.90. 

§ 63.7575 What definitions apply to this 

subpart? 

Terms used in this subpart are 

defined in the Clean Air Act, in § 63.2 

(the General Provisions), and in this 

section as follows: 

30-day rolling average means the 

arithmetic mean of all valid data from 

30 successive operating days that is 

calculated for each operating day using 

the data from that operating day and the 

previous 29 operating days. 

Affirmative defense means, in the 

context of an enforcement proceeding, a 

response or defense put forward by a 

defendant, regarding which the 

defendant has the burden of proof, and 

the merits of which are independently 

and objectively evaluated in a judicial 

or administrative proceeding. 

Annual heat input means the heat 

input for the 12 months preceding the 

compliance demonstration. 

Average annual heat input rate means 

annual heat input divided by the hours 

of operation for the 12 months 

preceding the compliance 

demonstration. 

Bag leak detection system means a 

group of instruments that are capable of 

monitoring particulate matter loadings 

in the exhaust of a fabric filter (i.e., 

baghouse) in order to detect bag failures. 

A bag leak detection system includes, 

but is not limited to, an instrument that 

operates on electrodynamic, 

triboelectric, light scattering, light 

transmittance, or other principle to 

monitor relative particulate matter 

loadings. 

Benchmarking means a process of 

comparison against standard or average. 

Biodiesel means a mono-akyl ester 

derived from biomass and conforming to 

ASTM D6751–08, Standard 

Specification for Biodiesel Fuel Blend 

Stock (B100) for Middle Distillate Fuels 

(incorporated by reference, see § 63.14). 

Biomass or bio-based solid fuel means 

any biomass-based solid fuel that is not 

a solid waste. This includes, but is not 

limited to, wood residue; wood 

products (e.g., trees, tree stumps, tree 

limbs, bark, lumber, sawdust, sander 

dust, chips, scraps, slabs, millings, and 

shavings); animal manure, including 

litter and other bedding materials; 

vegetative agricultural and silvicultural 

materials, such as logging residues 

(slash), nut and grain hulls and chaff 

(e.g., almond, walnut, peanut, rice, and 

wheat), bagasse, orchard prunings, corn 

stalks, coffee bean hulls and grounds. 

This definition of biomass is not 

intended to suggest that these materials 

are or are not solid waste. 

Blast furnace gas fuel-fired boiler or 

process heater means an industrial/ 

commercial/institutional boiler or 

process heater that receives 90 percent 

or more of its total annual gas volume 

from blast furnace gas. 

Boiler means an enclosed device 

using controlled flame combustion and 

having the primary purpose of 

recovering thermal energy in the form of 

steam or hot water. Controlled flame 

combustion refers to a steady-state, or 

near steady-state, process wherein fuel 

and/or oxidizer feed rates are 

controlled. A device combusting solid 

waste, as defined in § 241.3, is not a 

boiler unless the device is exempt from 

the definition of a solid waste 

incineration unit as provided in section 

129(g)(1) of the Clean Air Act. Waste 

heat boilers that use only natural gas, 

refinery gas, or other gas 1 fuels for 

supplemental fuel are excluded from 

this definition. 

Boiler system means the boiler and 

associated components, such as, the 

feed water system, the combustion air 

system, the fuel system (including 

burners), blowdown system, combustion 


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control system, and energy consuming 

systems. 

Calendar year means the period 

between January 1 and December 31, 

inclusive, for a given year. 

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 for creating useful 

heat, including but not limited to, 

solvent-refined coal, coal-oil mixtures, 

and coal-water mixtures. Coal derived 

gases are excluded from this definition. 

Coal refuse means any by-product of 

coal mining or coal cleaning operations 

with an ash content greater than 50 

percent (by weight) and a heating value 

less than 13,900 kilojoules per kilogram 

(6,000 Btu per pound) on a dry basis. 

Commercial/institutional boiler 

means a boiler used in commercial 

establishments or institutional 

establishments such as medical centers, 

research centers, institutions of higher 

education, hotels, and laundries to 

provide steam and/or hot water. 

Common stack means the exhaust of 

emissions from two or more affected 

units through a single flue. Affected 

units with a common stack may each 

have separate air pollution control 

systems located before the common 

stack, or may have a single air pollution 

control system located after the exhausts 

come together in a single flue. 

Cost-effective energy conservation 

measure means a measure that is 

implemented to improve the energy 

efficiency of the boiler or facility that 

has a payback (return of investment) 

period of 2 years or less. 

Daily block average means the 

arithmetic mean of all valid emission 

concentrations or parameter levels 

recorded when a unit is operating 

measured over the 24-hour period from 

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

(midnight). 

Deviation. (1) Means any instance in 

which an affected source subject to this 

subpart, or an owner or operator of such 

a source: 

(i) Fails to meet any requirement or 

obligation established by this subpart 

including, but not limited to, any 

emission limit, operating limit, or work 

practice standard; or 

(ii) Fails to meet any term or 

condition that is adopted to implement 

an applicable requirement in this 

subpart and that is included in the 

operating permit for any affected source 

required to obtain such a permit. 

(2) A deviation is not always a 

violation. The determination of whether 

a deviation constitutes a violation of the 

standard is up to the discretion of the 

entity responsible for enforcement of the 

standards. 

Dioxins/furans means tetra- through 

octa-chlorinated dibenzo-p-dioxins and 

dibenzofurans. 

Distillate oil means fuel oils, 

including recycled oils, that comply 

with the specifications for fuel oil 

numbers 1 and 2, as defined by ASTM 

D396 (incorporated by reference, see 

§ 63.14). 

Dry scrubber means an add-on air 

pollution control system that injects dry 

alkaline sorbent (dry injection) or sprays 

an alkaline sorbent (spray dryer) to react 

with and neutralize acid gas in the 

exhaust stream forming a dry powder 

material. Sorbent injection systems in 

fluidized bed boilers and process 

heaters are included in this definition. 

A dry scrubber is a dry control system. 

Dutch oven means a unit having a 

refractory-walled cell connected to a 

conventional boiler setting. Fuel 

materials are introduced through an 

opening in the roof of the dutch oven 

and burn in a pile on its floor. Fluidized 

bed boilers are not part of the dutch 

oven design category. 

Electric utility steam generating unit 

means a fossil fuel-fired combustion 

unit of more than 25 megawatts that 

serves a generator that produces 

electricity for sale. A fossil fuel-fired 

unit that cogenerates steam and 

electricity and supplies more than onethird of its potential electric output 

capacity and more than 25 megawatts 

electrical output to any utility power 

distribution system for sale is 

considered an electric utility steam 

generating unit. To be ‘‘capable of 

combusting’’ fossil fuels, an EGU would 

need to have these fuels allowed in their 

operating permits and have the 

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

handling equipment, including coal 

storage area, belts and conveyers, 

pulverizers, etc.; oil storage facilities). In 

addition, fossil fuel-fired EGU means 

any EGU that fired fossil fuel for more 

than 10.0 percent of the average annual 

heat input in any 3 consecutive calendar 

years or for more than 15.0 percent of 

the annual heat input during any one 

calendar year after [COMPLIANCE 

DATE OF THE FINAL EGU RULE]. 

Electrostatic precipitator (ESP) means 

an add-on air pollution control device 

used to capture particulate matter by 

charging the particles using an 

electrostatic field, collecting the 

particles using a grounded collecting 

surface, and transporting the particles 

into a hopper. An electrostatic 

precipitator is usually a dry control 

system. 

Emission credit means emission 

reductions above those required by this 

subpart. Emission credits generated may 

be used to comply with the emissions 

limits. Credits may come from pollution 

prevention projects that result in 

reduced fuel use by affected units. 

Shutdowns cannot be used to generate 

credits. 

Energy assessment means the 

following only as this term is used in 

Table 3 to this subpart. 

(1) Energy assessment for facilities 

with affected boilers and process heaters 

using less than 0.3 trillion Btu per year 

heat input will be 8 technical labor 

hours in length maximum, but may be 

longer at the discretion of the owner or 

operator of the affected source. The 

boiler system and energy use system 

accounting for at least 50 percent of the 

energy output will be evaluated to 

identify energy savings opportunities, 

within the limit of performing an 8-hour 

energy assessment. 

(2) The Energy assessment for 

facilities with affected boilers and 

process heaters using 0.3 to 1.0 trillion 

Btu per year will be 24 technical labor 

hours in length maximum, but may be 

longer at the discretion of the owner or 

operator. The boiler system and any 

energy use system accounting for at 

least 33 percent of the energy output 

will be evaluated to identify energy 

savings opportunities, within the limit 

of performing a 24-hour energy 

assessment. 

(3) In the Energy assessment for 

facilities with affected boilers and 

process heaters using greater than 1.0 

trillion Btu per year, the boiler system 

and any energy use system accounting 

for at least 20 percent of the energy 

output will be evaluated to identify 

energy savings opportunities. 

Energy management practices means 

the set of practices and procedures 

designed to manage energy use that are 

demonstrated by the facility’s energy 

policies, a facility energy manager and 

other staffing responsibilities, energy 

performance measurement and tracking 

methods, an energy saving goal, action 

plans, operating procedures, internal 

reporting requirements, and periodic 

review intervals used at the facility. 

Energy use system includes, but is not 

limited to, process heating; compressed 

air systems; machine drive (motors, 

pumps, fans); process cooling; facility 

heating, ventilation, and airconditioning systems; hot water 

systems; building envelop; and lighting. 

Equivalent means the following only 

as this term is used in Table 6 to this 

subpart: 


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(1) An equivalent sample collection 

procedure means a published voluntary 

consensus standard or practice (VCS) or 

EPA method that includes collection of 

a minimum of three composite fuel 

samples, with each composite 

consisting of a minimum of three 

increments collected at approximately 

equal intervals over the test period. 

(2) An equivalent sample compositing 

procedure means a published VCS or 

EPA method to systematically mix and 

obtain a representative subsample (part) 

of the composite sample. 

(3) An equivalent sample preparation 

procedure means a published VCS or 

EPA method that: Clearly states that the 

standard, practice or method is 

appropriate for the pollutant and the 

fuel matrix; or is cited as an appropriate 

sample preparation standard, practice or 

method for the pollutant in the chosen 

VCS or EPA determinative or analytical 

method. 

(4) An equivalent procedure for 

determining heat content means a 

published VCS or EPA method to obtain 

gross calorific (or higher heating) value. 

(5) An equivalent procedure for 

determining fuel moisture content 

means a published VCS or EPA method 

to obtain moisture content. If the sample 

analysis plan calls for determining 

metals (especially the mercury, 

selenium, or arsenic) using an aliquot of 

the dried sample, then the drying 

temperature must be modified to 

prevent vaporizing these metals. On the 

other hand, if metals analysis is done on 

an ‘‘as received’’ basis, a separate 

aliquot can be dried to determine 

moisture content and the metals 

concentration mathematically adjusted 

to a dry basis. 

(6) An equivalent pollutant (mercury, 

hydrogen chloride) determinative or 

analytical procedure means a published 

VCS or EPA method that clearly states 

that the standard, practice, or method is 

appropriate for the pollutant and the 

fuel matrix and has a published 

detection limit equal or lower than the 

methods listed in Table 6 to this subpart 

for the same purpose. 

Fabric filter means an add-on air 

pollution control device used to capture 

particulate matter by filtering gas 

streams through filter media, also 

known as a baghouse. A fabric filter is 

a dry control system. 

Federally enforceable means all 

limitations and conditions that are 

enforceable by the EPA Administrator, 

including the requirements of 40 CFR 

parts 60 and 61, requirements within 

any applicable state implementation 

plan, and any permit requirements 

established under 40 CFR 52.21 or 

under 40 CFR 51.18 and 40 CFR 51.24. 

Fluidized bed boiler means a boiler 

utilizing a fluidized bed combustion 

process that is not a pulverized coal 

boiler. 

Fluidized bed combustion means a 

process where a fuel is burned in a bed 

of granulated particles, which are 

maintained in a mobile suspension by 

the forward flow of air and combustion 

products. 

Fuel cell means a boiler type in which 

the fuel is dropped onto suspended 

fixed grates and is fired in a pile. The 

refractory-lined fuel cell uses 

combustion air preheating and 

positioning of secondary and tertiary air 

injection ports to improve boiler 

efficiency. Fluidized bed, dutch oven, 

pile burner, hybrid suspension grate, 

and suspension burners are not part of 

the fuel cell subcategory. 

Fuel type means each category of fuels 

that share a common name or 

classification. Examples include, but are 

not limited to, bituminous coal, subbituminous coal, lignite, anthracite, 

biomass, residual oil. Individual fuel 

types received from different suppliers 

are not considered new fuel types. 

Gaseous fuel includes, but is not 

limited to, natural gas, process gas, 

landfill gas, coal derived gas, refinery 

gas, and biogas. Blast furnace gas is 

exempted from this definition. 

Heat input means heat derived from 

combustion of fuel in a boiler or process 

heater and does not include the heat 

input from preheated combustion air, 

recirculated flue gases, or exhaust gases 

from other sources such as gas turbines, 

internal combustion engines, kilns, etc. 

Heavy Liquid includes residual oil 

and any other liquid fuel not classified 

as a light liquid. 

Hourly average means the arithmetic 

average of at least four CMS data values 

representing the four 15-minute periods 

in an hour, or at least two 15-minute 

data values during an hour when CMS 

calibration, quality assurance, or 

maintenance activities are being 

performed. 

Hot water heater means a closed 

vessel with a capacity of no more than 

120 U.S. gallons in which water is 

heated by combustion of gaseous or 

liquid fuel and is withdrawn for use 

external to the vessel at pressures not 

exceeding 160 psig, including the 

apparatus by which the heat is 

generated and all controls and devices 

necessary to prevent water temperatures 

from exceeding 210 degrees Fahrenheit 

(99 degrees Celsius). Hot water boilers 

(i.e., not generating steam) combusting 

gaseous or liquid fuel with a heat input 

capacity of less than 1.6 million Btu per 

hour are included in this definition. Hot 

water heater also means a tankless unit 

that provides on demand hot water. 

Hybrid suspension grate boiler means 

a boiler designed with air distributors to 

spread the fuel material over the entire 

width and depth of the boiler 

combustion zone. The fuel combusted 

in these units exceed a moisture content 

of 40 percent on an as-fired basis. The 

drying and much of the combustion of 

the fuel takes place in suspension, and 

the combustion is completed on the 

grate or floor of the boiler. Fluidized 

bed, dutch oven, and pile burner 

designs are not part of the hybrid 

suspension grate boiler design category. 

Industrial boiler means a boiler used 

in manufacturing, processing, mining, 

and refining or any other industry to 

provide steam and/or hot water. 

Light liquid includes distillate oil, 

biodiesel or vegetable oil. 

Limited-use boiler or process heater 

means any boiler or process heater that 

burns any amount of solid, liquid, or 

gaseous fuels, has a rated capacity of 

greater than 10 MMBtu per hour heat 

input, and has a federally enforceable 

limit of no more than 876 hours per year 

of operation. 

Liquid fuel includes, but is not 

limited to, distillate oil, residual oil, onspec used oil, biodiesel and vegetable 

oil. 

Load fraction means the actual heat 

input of the boiler or process heater 

divided by the average operating load 

determined according to Table 7 to this 

subpart. 

Metal process furnaces include 

natural gas-fired annealing furnaces, 

preheat furnaces, reheat furnaces, aging 

furnaces, heat treat furnaces, and 

homogenizing furnaces. 

Million Btu (MMBtu) means one 

million British thermal units. 

Minimum activated carbon injection 

rate means load fraction (percent) 

multiplied by the lowest hourly average 

activated carbon injection rate measured 

according to Table 7 to this subpart 

during the most recent performance test 

demonstrating compliance with the 

applicable emission limits. 

Minimum pressure drop means the 

lowest hourly average pressure drop 

measured according to Table 7 to this 

subpart during the most recent 

performance test demonstrating 

compliance with the applicable 

emission limit. 

Minimum scrubber effluent pH means 

the lowest hourly average sorbent liquid 

pH measured at the inlet to the wet 

scrubber according to Table 7 to this 

subpart during the most recent 

performance test demonstrating 

compliance with the applicable 

hydrogen chloride emission limit. 


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Minimum scrubber liquid flow rate 

means the lowest hourly average liquid 

flow rate (e.g., to the PM scrubber or to 

the acid gas scrubber) measured 

according to Table 7 to this subpart 

during the most recent performance test 

demonstrating compliance with the 

applicable emission limit. 

Minimum scrubber pressure drop 

means the lowest hourly average 

scrubber pressure drop measured 

according to Table 7 to this subpart 

during the most recent performance test 

demonstrating compliance with the 

applicable emission limit. 

Minimum sorbent injection rate 

means load fraction (percent) multiplied 

by the lowest hourly average sorbent 

injection rate for each sorbent measured 

according to Table 7 to this subpart 

during the most recent performance test 

demonstrating compliance with the 

applicable emission limits. 

Minimum total secondary electric 

power means the lowest hourly average 

total secondary electric power 

determined from the values of 

secondary voltage and secondary 

current to the electrostatic precipitator 

measured according to Table 7 to this 

subpart during the most recent 

performance test demonstrating 

compliance with the applicable 

emission limits. 

Natural gas means: 

(1) A naturally occurring mixture of 

hydrocarbon and nonhydrocarbon gases 

found in geologic formations beneath 

the earth’s surface, of which the 

principal constituent is methane; or 

(2) Liquid petroleum gas, as defined 

in ASTM D1835 (incorporated by 

reference, see § 63.14); or 

(3) A mixture of hydrocarbons that 

maintains a gaseous state at ISO 

conditions. Additionally, natural gas 

must either be composed of at least 70 

percent methane by volume or have a 

gross calorific value between 34 and 43 

mega joules (MJ) per dry standard cubic 

meter (910 and 1,150 Btu per dry 

standard cubic foot); or 

(4) Propane or propane derived 

synthetic natural gas. Propane means a 

colorless gas derived from petroleum 

and natural gas, with the molecular 

structure C3H8. 

Opacity means the degree to which 

emissions reduce the transmission of 

light and obscure the view of an object 

in the background. 

Operating day means a 24-hour 

period between 12 midnight and the 

following midnight during which any 

fuel is combusted at any time in the 

boiler or process heater unit. It is not 

necessary for fuel to be combusted for 

the entire 24-hour period. 

Other combustor means a unit 

designed to burn solid fuel that is not 

classified as a dutch oven, fluidized 

bed, fuel cell, hybrid suspension grate 

boiler, pulverized coal boiler, stoker, 

sloped grate, or suspension boiler as 

defined in this subpart. 

Other gas 1 fuel means a gaseous fuel 

that is not natural gas or refinery gas 

and does not exceed the maximum 

concentration of 40 micrograms/cubic 

meters of mercury. 

Oxygen analyzer system means all 

equipment required to determine the 

oxygen content of a gas stream and used 

to monitor oxygen in the boiler flue gas 

or firebox. This definition includes 

oxygen trim systems. The source owner 

or operator must install, calibrate, 

maintain, and operate the oxygen 

analyzer system in accordance with the 

manufacturer’s recommendations. 

Oxygen trim system means a system of 

monitors that is used to maintain excess 

air at the desired level in a combustion 

device. A typical system consists of a 

flue gas oxygen and/or carbon monoxide 

monitor that automatically provides a 

feedback signal to the combustion air 

controller. 

Particulate matter (PM) means any 

finely divided solid or liquid material, 

other than uncombined water, as 

measured by the test methods specified 

under this subpart, or an approved 

alternative method. 

Period of gas curtailment or supply 

interruption means a period of time 

during which the supply of gaseous fuel 

to an affected facility is halted for 

reasons beyond the control of the 

facility. The act of entering into a 

contractual agreement with a supplier of 

natural gas established for curtailment 

purposes does not constitute a reason 

that is under the control of a facility for 

the purposes of this definition. An 

increase in the cost or unit price of 

natural gas due to normal market 

fluctuations not during periods of 

supplier delivery restriction does not 

constitute a period of natural gas 

curtailment or supply interruption. Onsite gaseous fuel system emergencies or 

equipment failures qualify as periods of 

supply interruption when the 

emergency or failure is beyond the 

control of the facility. 

Pile burner means a boiler design 

incorporating a design where the 

anticipated biomass fuel has a high 

relative moisture content. Grates serve 

to support the fuel, and underfire air 

flowing up through the grates provides 

oxygen for combustion, cools the grates, 

promotes turbulence in the fuel bed, 

and fires the fuel. The most common 

form of pile burning is the dutch oven. 

Process heater means an enclosed 

device using controlled flame, and the 

unit’s primary purpose is to transfer 

heat indirectly to a process material 

(liquid, gas, or solid) or to a heat transfer 

material for use in a process unit, 

instead of generating steam. Process 

heaters include units heating hot water 

as a process heat transfer medium. 

Process heaters are devices in which the 

combustion gases do not come into 

direct contact with process materials. A 

device combusting solid waste, as 

defined in § 241.3, is not a process 

heater unless the device is exempt from 

the definition of a solid waste 

incineration unit as provided in section 

129(g)(1) of the Clean Air Act. Process 

heaters do not include units used for 

comfort heat or space heat, food 

preparation for on-site consumption, or 

autoclaves. Waste heat process heaters 

that use only natural gas, refinery gas, 

or other gas 1 fuels for supplemental 

fuel are excluded from this definition. 

Pulverized coal boiler means a boiler 

in which pulverized coal or other solid 

fossil fuel is introduced into an air 

stream that carries the coal to the 

combustion chamber of the boiler where 

it is fired in suspension. 

Qualified energy assessor means: 

(1) Someone who has demonstrated 

capabilities to evaluate energy savings 

opportunities for steam generation and 

major energy using systems, including, 

but not limited to: 

(i) Boiler combustion management. 

(ii) Boiler thermal energy recovery, 

including 

(A) Conventional feed water 

economizer, 

(B) Conventional combustion air 

preheater, and 

(C) Condensing economizer. 

(iii) Boiler blowdown thermal energy 

recovery. 

(iv) Primary energy resource selection, 

including 

(A) Fuel (primary energy source) 

switching, and 

(B) Applied steam energy versus 

direct-fired energy versus electricity. 

(v) Insulation issues. 

(vi) Steam trap and steam leak 

management. 

(vi) Condensate recovery. 

(viii) Steam end-use management. 

(2) Capabilities and knowledge 

includes, but is not limited to: 

(i) Background, experience, and 

recognized abilities to perform the 

assessment activities, data analysis, and 

report preparation. 

(ii) Familiarity with operating and 

maintenance practices for steam or 

process heating systems. 

(iii) Additional potential steam 

system improvement opportunities 


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including improving steam turbine 

operations and reducing steam demand. 

(iv) Additional process heating system 

opportunities including effective 

utilization of waste heat and use of 

proper process heating methods. 

(v) Boiler-steam turbine cogeneration 

systems. 

(vi) Industry specific steam end-use 

systems. 

Refinery gas means any gas that is 

generated at a petroleum refinery and is 

combusted. Refinery gas includes 

natural gas when the natural gas is 

combined and combusted in any 

proportion with a gas generated at a 

refinery. Refinery gas includes gases 

generated from other facilities when that 

gas is combined and combusted in any 

proportion with gas generated at a 

refinery. 

Residential boiler means a boiler used 

in a dwelling containing four or fewer 

family units to provide heat and/or hot 

water. This definition includes boilers 

used primarily to provide heat and/or 

hot water for a dwelling containing four 

or fewer families located at an 

institutional facility (e.g., university 

campus, military base, church grounds) 

or commercial/industrial facility (e.g., 

farm). 

Residual oil means crude oil, and all 

fuel oil numbers 4, 5 and 6, as defined 

in ASTM D396–10 (incorporated by 

reference, see § 63.14(b)). 

Responsible official means 

responsible official as defined in § 70.2. 

Shutdown means the period that 

begins when a unit last operates at 25 

percent load and ending with a state of 

no fuel combustion in the unit. 

Sloped grate means a unit where the 

solid fuel is fed to the top of the grate 

from where it slides downwards; while 

sliding the fuel first dries and then 

ignites and burns. The ash is deposited 

at the bottom of the grate. Fluidized bed, 

dutch oven, pile burner, hybrid 

suspension grate, suspension burners, 

and fuel cells are not considered to be 

a sloped grate design. 

Solid fossil fuel includes, but is not 

limited to, coal, coke, petroleum coke, 

and tire derived fuel. 

Solid fuel means any solid fossil fuel 

or biomass or bio-based solid fuel. 

Startup means the period between the 

state of no combustion in the unit to the 

period where the unit first achieves 25 

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

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 calculated 

using Equations 16 through 20 of this 

section, as appropriate: 

(i) For emission limits for boilers in 

the solid fuel subcategory use Equation 

16 of this section: 

Where: 

ELOBE = Emission limit in units of pounds 

per megawatt-hour. 

ELT = Appropriate emission limit from Table 

1 or 2 of this subpart in units of pounds 

per million Btu heat input. 

(ii) For PM and CO emission limits for 

boilers in one of the subcategories of 

units designed to burn coal use 

Equation 17 of this section: 

Where: 

ELOBE = Emission limit in units of pounds 

per megawatt-hour. 

ELT = Appropriate emission limit from Table 

1 or 2 of this subpart in units of pounds 

per million Btu heat input. 

(iii) For PM and CO emission limits 

for boilers in one of the subcategories of 

units designed to burn biomass use 

Equation 18 of this section: 

Where: 

ELOBE = Emission limit in units of pounds 

per megawatt-hour. 

ELT = Appropriate emission limit from Table 

1 or 2 of this subpart in units of pounds 

per million Btu heat input. 

(iv) For emission limits for boilers in 

the one of the subcategories of units 

designed to burn liquid fuels use 

Equation 19 of this section: 

Where: 

ELOBE = Emission limit in units of pounds 

per megawatt-hour. 

ELT = Appropriate emission limit from Table 

1 or 2 of this subpart in units of pounds 

per million Btu heat input. 

(v) For emission limits for boilers in 

the Gas 2 subcategory use Equation 20 

of this section: 


sroberts on DSK5SPTVN1PROD with PROPOSALSEP23DE11.046</GPH> EP23DE11.047</GPH> EP23DE11.048</GPH> EP23DE11.049</GPH> EP23DE11.050</GPH>
Federal Register / Vol. 76, No. 247 / Friday, December 23, 2011 / Proposed Rules 80655 

Where: 

ELOBE = Emission limit in units of pounds 

per megawatt-hour. 

ELT = Appropriate emission limit from Table 

1 or 2 of this subpart in units of pounds 

per million Btu heat input. 

Stoker means a unit consisting of a 

mechanically operated fuel feeding 

mechanism, a stationary or moving grate 

to support the burning of fuel and admit 

under-grate air to the fuel, an overfire 

air system to complete combustion, and 

an ash discharge system. This definition 

of stoker includes air swept stokers. 

There are two general types of stokers: 

underfeed and overfeed. Overfeed 

stokers include mass feed and spreader 

stokers. Fluidized bed, dutch oven, pile 

burner, hybrid suspension grate, 

suspension burners, and fuel cells are 

not considered to be a stoker design. 

Stoker/sloped grate/other unit 

designed to burn kiln dried biomass 

means the unit is in the units designed 

to burn biomass/bio-based solid 

subcategory that is either a stoker, 

sloped grate, or other combustor design 

and is not in the stoker/sloped grate/ 

other units designed to burn wet 

biomass subcategory. 

Stoker/sloped grate/other unit 

designed to burn wet biomass means the 

unit is in the units designed to burn 

biomass/bio-based solid subcategory 

that is either a stoker, sloped grate, or 

other combustor design and any of the 

biomass/bio-based solid fuel combusted 

in the unit exceeds 20 percent moisture. 

Suspension burner means a unit 

designed to feed the fuel by means of 

fuel distributors. The distributors inject 

air at the point where the fuel is 

introduced into the boiler in order to 

spread the fuel material over the boiler 

width. The drying (and much of the 

combustion) occurs while the material 

is suspended in air. The combustion of 

the fuel material is completed on a grate 

or floor below. Suspension boilers 

almost universally are designed to have 

high heat release rates to dry quickly the 

wet fuel as it is blown into the boilers. 

Fluidized bed, dutch oven, pile burner, 

and hybrid suspension grate units are 

not part of the suspension burner 

subcategory. 

Temporary boiler means any gaseous 

or liquid fuel boiler that is designed to, 

and is capable of, being carried or 

moved from one location to another by 

means of, for example, wheels, skids, 

carrying handles, dollies, trailers, or 

platforms. A boiler is not a temporary 

boiler if any one of the following 

conditions exists: 

(1) The equipment is attached to a 

foundation. 

(2) The boiler or a replacement 

remains at a location for more than 12 

consecutive months. Any temporary 

boiler that replaces a temporary boiler at 

a location and performs the same or 

similar function will be included in 

calculating the consecutive time period. 

(3) The equipment is located at a 

seasonal facility and operates during the 

full annual operating period of the 

seasonal facility, remains at the facility 

for at least 2 years, and operates at that 

facility for at least 3 months each year. 

(4) The equipment is moved from one 

location to another in an attempt to 

circumvent the residence time 

requirements of this definition. 

Total selected metals means the 

combination of the following metallic 

hazardous air pollutants: arsenic, 

beryllium, cadmium, chromium, lead, 

manganese, nickel and selenium. 

Tune-up means adjustments made to 

a boiler in accordance with procedures 

supplied by the manufacturer (or an 

approved specialist) to optimize the 

combustion efficiency. 

Unit designed to burn biomass/biobased solid subcategory includes any 

boiler or process heater that burns at 

least 10 percent biomass or bio-based 

solids on an annual heat input basis in 

combination with solid fossil fuels, 

liquid fuels, or gaseous fuels. 

Unit designed to burn coal/solid fossil 

fuel subcategory includes any boiler or 

process heater that burns any coal or 

other solid fossil fuel alone or at least 

10 percent coal or other solid fossil fuel 

on an annual heat input basis in 

combination with liquid fuels, gaseous 

fuels, or less than 10 percent biomass 

and bio-based solids on an annual heat 

input basis. 

Unit designed to burn gas 1 

subcategory includes any boiler or 

process heater that burns only natural 

gas, refinery gas, and/or other gas 1 

fuels; with the exception of liquid fuels 

burned for periodic testing not to exceed 

a combined total of 48 hours during any 

calendar year, or during periods of gas 

curtailment and gas supply 

emergencies. 

Unit designed to burn gas 2 (other) 

subcategory includes any boiler or 

process heater that is not in the unit 

designed to burn gas 1 subcategory and 

burns any gaseous fuels either alone or 

in combination with less than 10 

percent coal/solid fossil fuel, less than 

10 percent biomass/bio-based solid fuel, 

and less than 10 percent liquid fuels on 

an annual heat input basis. 

Unit designed to burn heavy liquid 

subcategory means a unit in the unit 

designed to burn liquid subcategory 

where at least 10 percent of the heat 

input from liquid fuels on an annual 

heat input basis comes from heavy 

liquids. 

Unit designed to burn light liquid 

subcategory means a unit in the unit 

designed to burn liquid subcategory that 

is not part of the unit designed to burn 

heavy liquid subcategory. 

Unit designed to burn liquid 

subcategory includes any boiler or 

process heater that burns any liquid 

fuel, but less than 10 percent coal/solid 

fossil fuel and less than 10 percent 

biomass/bio-based solid fuel on an 

annual heat input basis, either alone or 

in combination with gaseous fuels. 

Gaseous fuel boilers and process heaters 

that burn liquid fuel for periodic testing 

of liquid fuel, maintenance, or operator 

training, not to exceed a combined total 

of 48 hours during any calendar year or 

during periods of maintenance, operator 

training, or testing of liquid fuel, not to 

exceed a combined total of 48 hours 

during any calendar year are not 

included in this definition. Gaseous fuel 

boilers and process heaters that burn 

liquid fuel during periods of gas 

curtailment or gas supply emergencies 

of any duration are also not included in 

this definition. 

Unit designed to burn liquid fuel that 

is a non-continental unit means an 

industrial, commercial, or institutional 

boiler or process heater designed to 

burn liquid fuel located in the State of 

Hawaii, the Virgin Islands, Guam, 

American Samoa, the Commonwealth of 

Puerto Rico, or the Northern Mariana 

Islands. 

Unit designed to burn solid fuel 

subcategory means any boiler or process 

heater that burns only solid fuels or at 

least 10 percent solid fuel on an annual 

heat input basis in combination with 

liquid fuels or gaseous fuels. 

Vegetable oil means oils extracted 

from vegetation. 

Voluntary Consensus Standards or 

VCS mean technical standards (e.g., 

materials specifications, test methods, 

sampling procedures, business 

practices) developed or adopted by one 

or more voluntary consensus bodies. 

EPA/Office of Air Quality Planning and 

Standards, by precedent, has only used 

VCS that are written in English. 

Examples of VCS bodies are: American 

Society of Testing and Materials (ASTM 

100 Barr Harbor Drive, P.O. Box CB700, 

West Conshohocken, Pennsylvania 

19428–B2959, (800) 262–1373, http:// 

www.astm.org), American Society of 

Mechanical Engineers (ASME ASME, 

Three Park Avenue, New York, NY 

10016–5990, (800) 843–2763, http:// 

www.asme.org), International Standards 

Organization (ISO 1, ch. de la VoieCreuse, Case postale 56, CH–1211 

Geneva 20, Switzerland, +41 22 749 01 

11, http://www.iso.org/iso/home.htm), 

Standards Australia (AS Level 10, The 


sroberts on DSK5SPTVN1PROD with PROPOSALS
80656 Federal Register / Vol. 76, No. 247 / Friday, December 23, 2011 / Proposed Rules 

Exchange Centre, 20 Bridge Street, 

Sydney, GPO Box 476, Sydney NSW 

2001, + 61 2 9237 6171 http:// 

www.stadards.org.au), British Standards 

Institution (BSI, 389 Chiswick High 

Road, London, W4 4AL, United 

Kingdom, +44 (0)20 8996 9001, http:// 

www.bsigroup.com), Canadian 

Standards Association (CSA 5060 

Spectrum Way, Suite 100, Mississauga, 

Ontario L4W 5N6, Canada, (800) 463– 

6727, http://www.csa.ca), European 

Committee for Standardization (CEN 

CENELEC Management Centre Avenue 

Marnix 17 B–1000 Brussels, Belgium 

+32 2 550 08 11, http://www.cen.eu/ 

cen), and German Engineering 

Standards (VDI VDI Guidelines 

Department, P.O. Box 10 11 39 40002, 

Duesseldorf, Germany, +49 211 6214– 

230, http://www.vdi.eu). The types of 

standards that are not considered VCS 

are standards developed by: the United 

States, e.g., California (CARB) and Texas 

(TCEQ); industry groups, such as 

American Petroleum Institute (API), Gas 

Processors Association (GPA), and Gas 

Research Institute (GRI); and other 

branches of the U.S. government, e.g., 

Department of Defense (DOD) and 

Department of Transportation (DOT). 

This does not preclude EPA from using 

standards developed by groups that are 

not VCS bodies within their rule. When 

this occurs, EPA has done searches and 

reviews for VCS equivalent to these 

non-EPA methods. 

Waste heat boiler means a device that 

recovers normally unused energy and 

converts it to usable heat. Waste heat 

boilers are also referred to as heat 

recovery steam generators. This 

definition includes both fired and 

unfired waste heat boilers. 

Waste heat process heater means an 

enclosed device that recovers normally 

unused energy and converts it to usable 

heat. Waste heat process heaters are also 

referred to as recuperative process 

heaters. This definition includes both 

fired and unfired waste heat process 

heaters. 

Wet scrubber means any add-on air 

pollution control device that mixes an 

aqueous stream or slurry with the 

exhaust gases from a boiler or process 

heater to control emissions of 

particulate matter or to absorb and 

neutralize acid gases, such as hydrogen 

chloride. A wet scrubber creates an 

aqueous stream or slurry as a byproduct 

of the emissions control process. 

Work practice standard means any 

design, equipment, work practice, or 

operational standard, or combination 

thereof, that is promulgated pursuant to 

section 112(h) of the Clean Air Act. 

Tables to Subpart DDDDD of Part 63 

As stated in § 63.7500, you must 

comply with the following applicable 

emission limits: 

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

HEATERS

[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 

periods of startup and 

shutdown . . . 

Or the emissions must not 

exceed the following alternative output-based limits 

. . . 

Using this specified sampling volume or test run 

duration . . . 

1. Units in all subcategories designed to burn 

solid fuel.

a. Hydrogen Chloride ........ 0.022 lb per MMBtu of 

heat input.

0.025 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 ......................... 8.60E–07 lb per MMBtu of 

heat input.

9.4E–07 lb per MMBtu of 

steam output or 1.1 E– 

05 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. Pulverized coal boilers 

designed to burn coal/ 

solid fossil fuel.

a. Carbon monoxide (CO) 

(or CEMS).

9 ppm by volume on a dry 

basis corrected to 3 percent oxygen, 3-run average; or (28 ppm by volume on a dry basis corrected to 3 percent oxygen, 10-day rolling average).

0.0074 lb per MMBtu of 

steam output or 0.092 lb 

per MWh; 3-run average.

1 hr minimum sampling 

time, use a span value 

of 20 ppmv for Method 

10. 

b. Filterable Particulate 

Matter (or Total Selected 

Metals).

0.0013 lb per MMBtu of 

heat input; or (2.8E–05 a

lb per MMBtu of heat 

input).

0.0013 lb per MMBtu of 

steam output or 0.016 lb 

per MWh; or (2.8E–05 a

lb per MMBtu of steam 

output or 3.5E–04 a lb 

per MWh).

Collect a minimum of 3 

dscm per run. 

3. Stokers designed to 

burn coal/solid fossil fuel.

a. CO (or CEMS) .............. 19 ppm by volume on a 

dry basis corrected to 3 

percent oxygen, 3-run 

average; or (34 ppm by 

volume on a dry basis 

corrected to 3 percent 

oxygen, 10-day rolling 

average).

0.017 lb per MMBtu of 

steam output or 0.20 lb 

per MWh; 3-run average.

1 hr minimum sampling 

time, use a span value 

of 30 ppmv for Method 

10. 


sroberts on DSK5SPTVN1PROD with PROPOSALS
Federal Register / Vol. 76, No. 247 / Friday, December 23, 2011 / Proposed Rules 80657 

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

HEATERS—Continued 

[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 

periods of startup and 

shutdown . . . 

Or the emissions must not 

exceed the following alternative output-based limits 

. . . 

Using this specified sampling volume or test run 

duration . . . 

b. Filterable Particulate 

Matter (or Total Selected 

Metals).

0.028 lb per MMBtu of 

heat input; or (2.2E–05 a

lb per MMBtu of heat 

input).

0.028 lb per MMBtu of 

steam output or 0.35 lb 

per MWh; or (3.0E–05 a

lb per MMBtu of steam 

output or 2.7E–04 a lb 

per MWh).

Collect a minimum of 2 

dscm per run. 

4. Fluidized bed units designed to burn coal/solid 

fossil fuel.

a. CO (or CEMS) .............. 17 ppm by volume on a 

dry basis corrected to 3 

percent oxygen, 3-run 

average; or (59 ppm by 

volume on a dry basis 

corrected to 3 percent 

oxygen, 10-day rolling 

average).

0.015 lb per MMBtu of 

steam output or 0.18 lb 

per MWh; 3-run average.

1 hr minimum sampling 

time, use a span value 

of 40 ppmv for Method 

10. 

b. Filterable Particulate 

Matter (or Total Selected 

Metals).

0.0011 lb per MMBtu of 

heat input; or (1.7E–05 a

lb per MMBtu of heat 

input).

0.0012 lb per MMBtu of 

steam output or 0.014 lb 

per MWh; or (1.8E–05 a

lb per MMBtu of steam 

output or 2.1E–04 a lb 

per MWh).

Collect a minimum of 4 

dscm per run. 

5. Stokers/sloped grate/ 

others designed to burn 

wet biomass fuel.

a. CO (or CEMS) .............. 590 ppm by volume on a 

dry basis corrected to 3 

percent oxygen, 3-run 

average; or (410 ppm by 

volume on a dry basis 

corrected to 3 percent 

oxygen, 10-day rolling 

average).

0.56 lb per MMBtu of 

steam output or 6.5 lb 

per MWh; 3-run average.

1 hr minimum sampling 

time, use a span value 

of 600 ppmv for Method 

10. 

b. Filterable Particulate 

Matter (or Total Selected 

Metals).

0.029 lb per MMBtu of 

heat input; or (2.6E–05 

lb per MMBtu of heat 

input).

0.034 lb per MMBtu of 

steam output or 0.41 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. 

6. Stokers/sloped grate/ 

others designed to burn 

kiln-dried biomass fuel.

a. CO ................................. 250 ppm by volume on a 

dry basis corrected to 3 

percent oxygen.

0.23 lb per MMBtu of 

steam output or 2.8 lb 

per MWh.

1 hr minimum sampling 

time, use a span value 

of 400 ppmv for Method 

10. 

b. Filterable Particulate 

Matter (or Total Selected 

Metals).

0.32 lb per MMBtu of heat 

input; or (4.0E–03 lb per 

MMBtu of heat input).

0.37 lb per MMBtu of 

steam output or 4.5 lb 

per MWh; or (4.2E–03 lb 

per MMBtu of steam 

output or 0.056 lb per 

MWh).

Collect a minimum of 2 

dscm per run. 

7. 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 (180 ppm by 

volume on a dry basis 

corrected to 3 percent 

oxygen, 10-day rolling 

average).

0.22 lb per MMBtu of 

steam output or 2.6 lb 

per MWh; 3-run average.

1 hr minimum sampling 

time, use a span value 

of 400 ppmv for Method 

10. 

b. Filterable Particulate 

Matter (or Total Selected 

Metals).

0.0098 lb per MMBtu of 

heat input; or (4.2E–05 a

lb per MMBtu of heat 

input).

0.012 lb per MMBtu of 

steam output or 0.14 lb 

per MWh; or (5.4E–05 a

lb per MMBtu of steam 

output or 5.9E–04 a lb 

per MWh).

Collect a minimum of 3 

dscm per run. 


sroberts on DSK5SPTVN1PROD with PROPOSALS
80658 Federal Register / Vol. 76, No. 247 / Friday, December 23, 2011 / Proposed Rules 

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

HEATERS—Continued 

[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 

periods of startup and 

shutdown . . . 

Or the emissions must not 

exceed the following alternative output-based limits 

. . . 

Using this specified sampling volume or test run 

duration . . . 

8. Suspension burners designed to burn biomass/ 

bio-based solids.

a. CO (or CEMS) .............. 58 ppm by volume on a 

dry basis corrected to 3 

percent oxygen, 3-run 

average; or (1,400 ppm 

by volume on a dry 

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

0.046 lb per MMBtu of 

steam output or 0.64 lb 

per MWh; 3-run average.

1 hr minimum sampling 

time, use a span value 

of 100 ppmv for Method 

10. 

b. Filterable Particulate 

Matter (or Total Selected 

Metals).

0.051 lb per MMBtu of 

heat input; or (1.1E–03 

lb per MMBtu of heat 

input).

0.052 lb per MMBtu of 

steam output or 0.71 lb 

per MWh; or (0.0012 lb 

per MMBtu of steam 

output or 0.016 lb per 

MWh).

Collect a minimum of 1 

dscm per run. 

9. Dutch Ovens/Pile burners designed to burn biomass/bio-based solids.a. CO (or CEMS) .............. 810 ppm by volume on a 

dry basis corrected to 3 

percent oxygen, 3-run 

average; or (440 ppm by 

volume on a dry basis 

corrected to 3 percent 

oxygen, 10-day rolling 

average).

0.89 lb per MMBtu of 

steam output or 8.9 lb 

per MWh; 3-run average.

1 hr minimum sampling 

time, use a span value 

of 1000 ppmv for Method 10. 

b. Filterable Particulate 

Matter (or Total Selected 

Metals).

0.036 lb per MMBtu of 

heat input; or (4.1E–05 

lb per MMBtu of heat 

input).

0.050 lb per MMBtu of 

steam output or 0.51 lb 

per MWh; or (5.5E–05 lb 

per MMBtu of steam 

output or 5.8E–04 lb per 

MWh).

Collect a minimum of 1 

dscm per run. 

10. Fuel cell units designed to burn biomass/ 

bio-based solids.

a. CO ................................. 210 ppm by volume on a 

dry basis corrected to 3 

percent oxygen.

0.29 lb per MMBtu of 

steam output or 2.3 lb 

per MWh.

1 hr minimum sampling 

time, use a span value 

of 500 ppmv for Method 

10. 

b. Filterable Particulate 

Matter (or Total Selected 

Metals).

0.011 lb per MMBtu of 

heat input; or (4.9E–05 a

lb per MMBtu of heat 

input).

0.030 lb per MMBtu of 

steam output or 0.16 lb 

per MWh; or (8.6E–05 a

lb per MMBtu of steam 

output or 6.9E–04 a lb 

per MWh).

Collect a minimum of 1 

dscm per run. 

11. 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 (730 ppm by 

volume on a dry basis 

corrected to 3 percent 

oxygen, 10-day rolling 

average).

1.80 lb per MMBtu of 

steam output or 17 lb 

per MWh; 3-run average.

1 hr minimum sampling 

time, use a span value 

of 3000 ppmv for Method 10. 

b. Filterable Particulate 

Matter (or Total Selected 

Metals).

0.026 lb per MMBtu of 

heat input; or (4.9E–04 a

lb per MMBtu of heat 

input).

0.033 lb per MMBtu of 

steam output or 0.37 lb 

per MWh; or (6.2E–04 a

lb per MMBtu of steam 

output or 6.9E–03 a lb 

per MWh).

Collect a minimum of 3 

dscm per run. 

12. Units designed to burn 

liquid fuel.

a. Hydrogen Chloride ........ 0.0012 lb per MMBtu of 

heat input.

0.0013 lb per MMBtu of 

steam output or 0.017 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 ......................... 4.9E–07 a lb per MMBtu of 

heat input.

5.4E–07 a lb per MMBtu of 

steam output or 6.8E– 

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. 


sroberts on DSK5SPTVN1PROD with PROPOSALS
Federal Register / Vol. 76, No. 247 / Friday, December 23, 2011 / Proposed Rules 80659 

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

HEATERS—Continued 

[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 

periods of startup and 

shutdown . . . 

Or the emissions must not 

exceed the following alternative output-based limits 

. . . 

Using this specified sampling volume or test run 

duration . . . 

13. Units designed to burn 

heavy liquid fuel.

a. CO (or CEMS) .............. 10 ppm by volume on a 

dry basis corrected to 3 

percent oxygen, 3-run 

average; or (18 ppm by 

volume on a dry basis 

corrected to 3 percent 

oxygen, 10-day rolling 

average).

0.0091 lb per MMBtu of 

steam output or 0.11 lb 

per MWh; 3-run average.

1 hr minimum sampling 

time, use a span value 

of 30 ppmv for Method 

10. 

b. Filterable Particulate 

Matter.

0.013 lb per MMBtu of 

heat input.

0.015 lb per MMBtu of 

steam output or 0.18 lb 

per MWh.

Collect a minimum of 2 

dscm per run. 

14. Units designed to burn 

light liquid fuel.

a. CO (or CEMS) .............. 3 ppm by volume on a dry 

basis corrected to 3 percent oxygen; or (60 ppm 

by volume on a dry 

basis corrected to 3 percent oxygen, 1-day 

block average).

0.0031 lb per MMBtu of 

steam output or 0.033 lb 

per MWh.

1 hr minimum sampling 

time, use a span value 

of 10 ppmv for Method 

10. 

b. Filterable Particulate 

Matter.

0.0011 a lb per MMBtu of 

heat input for light liquid.

0.0015 a lb per MMBtu of 

steam output or 0.016 lb 

per MWh.

Collect a minimum of 3 

dscm per run. 

15. Units designed to burn 

liquid fuel located in noncontinental states and 

territories.

a. CO ................................. 18 ppm by volume on a 

dry basis corrected to 3 

percent oxygen, 3-run 

average based on stack 

test (91 ppm by volume 

on a dry basis corrected 

to 3 percent oxygen, 3- 

hour rolling average 

based on CEM).

0.017 lb per MMBtu of 

steam output or 0.20 lb 

per MWh; 3-run average.

1 hr minimum sampling 

time, use a span value 

of 40 ppmv for Method 

10. 

b. Filterable Particulate 

Matter.

0.0080 lb per MMBtu of 

heat input.

0.0087 lb per MMBtu of 

steam output or 0.11 lb 

per MWh.

Collect a minimum of 4 

dscm per run. 

16. Units designed to burn 

gas 2 (other) gases.

a. CO ................................. 4 ppm by volume on a dry 

basis corrected to 3 percent oxygen.

0.005 lb per MMBtu of 

steam output or 0.031 lb 

per MWh.

1 hr minimum sampling 

time, use a span value 

of 10 ppmv for Method 

10. 

b. Hydrogen Chloride ........ 0.0017 lb per MMBtu of 

heat input.

0.0029 lb per MMBtu of 

steam output or 0.018 lb 

per MWh.

For M26A, Collect a minimum of 1 dscm per run; 

for M26, collect a minimum of 120 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 Particulate 

Matter (or Total Selected 

Metals).

0.0067 lb per MMBtu of 

heat input; or (2.4E–04 

lb per MMBtu of heat 

input).

0.012 lb per MMBtu of 

steam output or 0.070 lb 

per MWh; or (4.0E–04 lb 

per MMBtu of steam 

output or 0.0025 lb per 

MWh).

Collect a minimum of 1 

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 75 percent of this limit in order to qualify for skip testing. b Incorporated by reference, see § 63.14. 


sroberts on DSK5SPTVN1PROD with PROPOSALS
80660 Federal Register / Vol. 76, No. 247 / Friday, December 23, 2011 / Proposed Rules 

As stated in § 63.7500, you must 

comply with the following applicable 

emission limits: 

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

[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 

periods of startup and 

shutdown . . . 

The emissions must not 

exceed the following alternative output-based limits 

. . . 

Using this specified sampling volume or test run 

duration . . . 

1. Units in all subcategories designed to burn 

solid fuel.

a. Hydrogen Chloride ........ 0.022 lb per MMBtu of 

heat input.

0.025 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 ......................... 3.1E–06 lb per MMBtu of 

heat input.

3.5E–06 lb per MMBtu of 

steam output or 4.0E–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. Pulverized coal boilers 

designed to burn coal/ 

solid fossil fuel.

a. CO (or CEMS) .............. 41 ppm by volume on a 

dry basis corrected to 3 

percent oxygen, 3-run 

average; or (28 ppm by 

volume on a dry basis 

corrected to 3 percent 

oxygen, 10-day rolling 

average).

0.035 lb per MMBtu of 

steam output or 0.42 lb 

per MWh; 3-run average.

1 hr minimum sampling 

time, use a span value 

of 100 ppmv for Method 

10. 

b. Filterable Particulate 

Matter (or Total Selected 

Metals).

0.044 lb per MMBtu of 

heat input; or (5.9E–05 

lb per MMBtu of heat 

input).

0.045 lb per MMBtu of 

steam output or 0.54 lb 

per MWh; or (6.0E–05 lb 

per MMBtu of steam 

output or 7.3E–04 lb per 

MWh).

Collect a minimum of 1 

dscm per run. 

3. Stokers designed to 

burn coal/solid fossil fuel.

a. CO (or CEMS) .............. 220 ppm by volume on a 

dry basis corrected to 3 

percent oxygen, 3-run 

average; or (34 ppm by 

volume on a dry basis 

corrected to 3 percent 

oxygen, 10-day rolling 

average).

0.20 lb per MMBtu of 

steam output or 2.3 lb 

per MWh; 3-run average.

1 hr minimum sampling 

time, use a span value 

of 400 ppmv for Method 

10. 

b. Filterable Particulate 

Matter (or Total Selected 

Metals).

0.028 lb per MMBtu of 

heat input; or (8.3E–05 

lb per MMBtu of heat 

input).

0.030 lb per MMBtu of 

steam output or 0.35 lb 

per MWh; or (8.8E–05 lb 

per MMBtu of steam 

output or 0.0011 lb per 

MWh).

Collect a minimum of 2 

dscm per run. 

4. Fluidized bed units designed to burn coal/solid 

fossil fuel.

a. CO (or CEMS) .............. 56 ppm by volume on a 

dry basis corrected to 3 

percent oxygen, 3-run 

average; or (59 ppm by 

volume on a dry basis 

corrected to 3 percent 

oxygen, 10-day rolling 

average).

0.049 lb per MMBtu of 

steam output or 0.57 lb 

per MWh; 3-run average.

1 hr minimum sampling 

time, use a span value 

of 100 ppmv for Method 

10. 

b. Filterable Particulate 

Matter (or Total Selected 

Metals).

0.088 lb per MMBtu of 

heat input; or (1.7E–05 

lb per MMBtu of heat 

input).

0.092 lb per MMBtu of 

steam output or 1.1 lb 

per MWh; or (1.8E–05 lb 

per MMBtu of steam 

output or 2.1E–04 lb per 

MWh).

Collect a minimum of 1 

dscm per run. 


sroberts on DSK5SPTVN1PROD with PROPOSALS
Federal Register / Vol. 76, No. 247 / Friday, December 23, 2011 / Proposed Rules 80661 

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

Continued 

[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 

periods of startup and 

shutdown . . . 

The emissions must not 

exceed the following alternative output-based limits 

. . . 

Using this specified sampling volume or test run 

duration . . . 

5. Stokers/sloped grate/ 

others designed to burn 

wet biomass fuel.

a. CO (or CEMS) .............. 790 ppm by volume on a 

dry basis corrected to 3 

percent oxygen, 3-run 

average; or (410 ppm by 

volume on a dry basis 

corrected to 3 percent 

oxygen, 10-day rolling 

average).

0.72 lb per MMBtu of 

steam output or 8.7 lb 

per MWh; 3-run average.

1 hr minimum sampling 

time, use a span value 

of 1000 ppmv for Method 10. 

b. Filterable Particulate 

Matter (or Total Selected 

Metals).

0.029 lb per MMBtu of 

heat input; or (5.7E–05 

lb per MMBtu of heat 

input).

0.034 lb per MMBtu of 

steam output or 0.41 lb 

per MWh; or (6.6E–05 lb 

per MMBtu of steam 

output or 8.0E–04 lb per 

MWh).

Collect a minimum of 2 

dscm per run. 

6. Stokers/sloped grate/ 

others designed to burn 

kiln-dried biomass fuel.

a. CO ................................. 250 ppm by volume on a 

dry basis corrected to 3 

percent oxygen.

0.23 lb per MMBtu of 

steam output or 2.8 lb 

per MWh.

1 hr minimum sampling 

time, use a span value 

of 500 ppmv for Method 

10. 

b. Filterable Particulate 

Matter (or Total Selected 

Metals).

0.32 lb per MMBtu of heat 

input; or (4.0E–03 lb per 

MMBtu of heat input).

0.37 lb per MMBtu of 

steam output or 4.5 lb 

per MWh; or (0.0046 lb 

per MMBtu of steam 

output or 0.056 lb per 

MWh).

Collect a minimum of 1 

dscm per run. 

7. Fluidized bed units designed to burn biomass/ 

bio-based solid.

a. CO (or CEMS) .............. 370 ppm by volume on a 

dry basis corrected to 3 

percent oxygen, 3-run 

average; or (180 ppm by 

volume on a dry basis 

corrected to 3 percent 

oxygen, 10-day rolling 

average).

0.36 lb per MMBtu of 

steam output or 4.1 lb 

per MWh; 3-run average.

1 hr minimum sampling 

time, use a span value 

of 500 ppmv for Method 

10. 

b. Filterable Particulate 

Matter (or Total Selected 

Metals).

0.11 lb per MMBtu of heat 

input; or (0.0012 lb per 

MMBtu of heat input).

0.14 lb per MMBtu of 

steam output or 1.6 lb 

per MWh; or (0.0015 lb 

per MMBtu of steam 

output or 0.017 lb per 

MWh).

Collect a minimum of 1 

dscm per run. 

8. Suspension burners designed to burn biomass/ 

bio-based solid.

a. CO (or CEMS) .............. 58 ppm by volume on a 

dry basis corrected to 3 

percent oxygen, 3-run 

average; or (1,400 ppm 

by volume on a dry 

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

0.046 lb per MMBtu of 

steam output or 0.64 lb 

per MWh; 3-run average.

1 hr minimum sampling 

time, use a span value 

of 100ppmv for Method 

10. 

b. Filterable Particulate 

Matter (or Total Selected 

Metals).

0.051 lb per MMBtu of 

heat input; or (0.0011 lb 

per MMBtu of heat 

input).

0.052 lb per MMBtu of 

steam output or 0.71 lb 

per MWh; or (0.0012 lb 

per MMBtu of steam 

output or 0.016 lb per 

MWh).

Collect a minimum of 1 

dscm per run. 

9. Dutch Ovens/Pile burners designed to burn biomass/bio-based solid.a. CO (or CEMS) .............. 810 ppm by volume on a 

dry basis corrected to 3 

percent oxygen, 3-run 

average; or (440 ppm by 

volume on a dry basis 

corrected to 3 percent 

oxygen, 10-day rolling 

average).

0.89 lb per MMBtu of 

steam output or 8.9 lb 

per MWh; 3-run average.

1 hr minimum sampling 

time, use a span value 

of 1000 ppmv for Method 10. 


sroberts on DSK5SPTVN1PROD with PROPOSALS
80662 Federal Register / Vol. 76, No. 247 / Friday, December 23, 2011 / Proposed Rules 

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

Continued 

[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 

periods of startup and 

shutdown . . . 

The emissions must not 

exceed the following alternative output-based limits 

. . . 

Using this specified sampling volume or test run 

duration . . . 

b. Filterable Particulate 

Matter (or Total Selected 

Metals).

0.036 lb per MMBtu of 

heat input; or (2.4E–04 

lb per MMBtu of heat 

input).

0.050 lb per MMBtu of 

steam output or 0.51 lb 

per MWh; or (3.4E–04 lb 

per MMBtu of steam 

output or 0.0034 lb per 

MWh).

Collect a minimum of 1 

dscm per run. 

10. Fuel cell units designed to burn biomass/ 

bio-based solid.

a. CO ................................. 1,500 ppm by volume on a 

dry basis corrected to 3 

percent oxygen.

3.2 lb per MMBtu of steam 

output or 17 lb per MWh.

1 hr minimum sampling 

time, use a span value 

of 2000 ppmv for Method 10. 

b. Filterable Particulate 

Matter (or Total Selected 

Metals).

0.033 lb per MMBtu of 

heat input; or (4.9E–05 

lb per MMBtu of heat 

input).

0.090 lb per MMBtu of 

steam output or 0.46 lb 

per MWh; or (1.4E–04 lb 

per MMBtu of steam 

output or 6.9E–04 lb per 

MWh).

Collect a minimum of 1 

dscm per run. 

11. Hybrid suspension 

grate units designed to 

burn biomass/bio-based 

solid.

a. CO (or CEMS) .............. 3,900 ppm by volume on a 

dry basis corrected to 3 

percent oxygen, 3-run 

average; or (730 ppm by 

volume on a dry basis 

corrected to 3 percent 

oxygen, 10-day rolling 

average).

3.9 lb per MMBtu of steam 

output or 43 lb per 

MWh; 3-run average.

1 hr minimum sampling 

time, use a span value 

of 5000 ppmv for Method 10. 

b. Filterable Particulate 

Matter (or Total Selected 

Metals).

0.44 lb per MMBtu of heat 

input; or (4.9E–04a lb 

per MMBtu of heat 

input).

0.55 lb per MMBtu of 

steam output or 6.2 lb 

per MWh; or (6.2E–04a

lb per MMBtu of steam 

output or 6.9E–03a lb 

per MWh).

Collect a minimum of 1 

dscm per run. 

12. Units designed to burn 

liquid fuel.

a. Hydrogen Chloride ........ 0.0012 lb per MMBtu of 

heat input.

0.0015 lb per MMBtu of 

steam output or 0.017 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 ......................... 2.6E–05 lb per MMBtu of 

heat input.

3.3E–05 lb per MMBtu of 

steam output or 3.6E–04 

lb per MWh.

For M29, collect a minimum of 2 dscm per run; 

for M30A or M30B collect a minimum sample 

as specified in the method, for ASTM D6784b

collect a minimum of 2 

dscm. 

13. Units designed to burn 

heavy liquid fuel.

a. CO (or CEMS) .............. 10 ppm by volume on a 

dry basis corrected to 3 

percent oxygen, 3-run 

average; or (18 ppm by 

volume on a dry basis 

corrected to 3 percent 

oxygen, 10-day rolling 

average).

0.0091 lb per MMBtu of 

steam output or 0.11 lb 

per MWh; 3-run average.

1 hr minimum sampling 

time, use a span value 

of 20 ppmv for Method 

10. 

b. Filterable Particulate 

Matter.

0.062 lb per MMBtu of 

heat input.

0.075 lb per MMBtu of 

steam output or 0.86 lb 

per MWh.

Collect a minimum of 1 

dscm per run. 

14. Units designed to burn 

light liquid fuel.

a. CO (or CEMS) .............. 7 ppm by volume on a dry 

basis corrected to 3 percent oxygen; or (60 ppm 

by volume on a dry 

basis corrected to 3 percent oxygen, 1-day 

block average).

0.0071 lb per MMBtu of 

steam output or 0.076 lb 

per MWh.

1 hr minimum sampling 

time, use a span value 

of 10 ppmv for Method 

10. 

b. Filterable Particulate 

Matter.

0.0034 lb per MMBtu of 

heat input.

0.0045 lb per MMBtu of 

steam output or 0.047 lb 

per MWh.

Collect a minimum of 3 

dscm per run. 


sroberts on DSK5SPTVN1PROD with PROPOSALS
Federal Register / Vol. 76, No. 247 / Friday, December 23, 2011 / Proposed Rules 80663 

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

Continued 

[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 

periods of startup and 

shutdown . . . 

The emissions must not 

exceed the following alternative output-based limits 

. . . 

Using this specified sampling volume or test run 

duration . . . 

15. Units designed to burn 

liquid fuel located in noncontinental states and 

territories.

a. CO (or CEMS) .............. 18 ppm by volume on a 

dry basis corrected to 3 

percent oxygen, 3-run 

average based on stack 

test (91 ppm by volume 

on a dry basis corrected 

to 3 percent oxygen, 3- 

hour rolling average 

based on CEM).

0.017 lb per MMBtu of 

steam output or 0.20 lb 

per MWh; 3-run average.

1 hr minimum sampling 

time, use a span value 

of 40 ppmv for Method 

10. 

b. Filterable Particulate 

Matter.

0.0080 lb per MMBtu of 

heat input.

0.0097 lb per MMBtu of 

steam output or 0.11 lb 

per MWh.

Collect a minimum of 2 

dscm per run. 

16. Units designed to burn 

gas 2 (other) gases.

a. CO ................................. 4 ppm by volume on a dry 

basis corrected to 3 percent oxygen.

0.0050 lb per MMBtu of 

steam output or 0.031 lb 

per MWh.

1 hr minimum sampling 

time, use a span value 

of 10 ppmv for Method 

10. 

b. Hydrogen Chloride ........ 0.0017 lb per MMBtu of 

heat input.

0.0029 lb per MMBtu of 

steam output or 0.018 lb 

per MWh.

For M26A, collect a minimum of 1 dscm per run; 

for M26, collect a minimum of 120 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 2 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 Particulate 

Matter (or Total Selected 

Metals).

0.0067 lb per MMBtu of 

heat input or (2.4E–04 lb 

per MMBtu of heat 

input).

0.012 lb per MMBtu of 

steam output or 0.070 lb 

per MWh; or (4.0E–04 lb 

per MMBtu of steam 

output or 0.0025 lb per 

MWh).

Collect a minimum of 1 

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 75 percent of this limit in order to qualify for skip testing. b Incorporated by reference, see § 63.14. 

As stated in § 63.7500, you must 

comply with the following applicable 

work practice standards: 

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

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

1. A new or existing boiler or process heater with heat input capacity of 

less than 5 million Btu per hour in any of the following subcategories: 

unit designed to burn natural gas, refinery gas or other gas 1 fuels; 

unit designed to burn gas 2 (other); or unit designed to burn light liquid.

Conduct a tune-up of the boiler or process heater every 5 years as 

specified in § 63.7540. 

2. A limited use boiler or process heater; or a new or existing boiler or 

process heater with heat input capacity of less than 10 million Btu 

per hour in the unit designed to burn heavy liquid or unit designed to 

burn solid fuel subcategories; or a new or existing boiler or process 

heater with heat input capacity of less than 10 million Btu per hour, 

but equal to or greater than 5 million Btu per hour, in any of the following subcategories: unit designed to burn natural gas, refinery gas 

or other gas 1 fuels; unit designed to burn gas 2 (other); or unit designed to burn light liquid.

Conduct a tune-up of the boiler or process heater biennially as specified in § 63.7540. 


sroberts on DSK5SPTVN1PROD with PROPOSALS
80664 Federal Register / Vol. 76, No. 247 / Friday, December 23, 2011 / Proposed Rules 

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

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

3. A new or existing boiler or process heater with heat input capacity of 

10 million Btu per hour or greater.

Conduct a tune-up of the boiler or process heater annually as specified 

in § 63.7540. Units in either the Gas 1 or Metal Process Furnace 

subcategories will conduct this tune-up as a work practice for all regulated emissions under this subpart. Units in all other subcategories 

will conduct this tune-up as a work practice for dioxins/furans. 

4. An existing boiler or process heater located at a major source facility Must have a one-time energy assessment performed on the major 

source facility by qualified energy assessor. An energy assessment 

completed on or after January 1, 2008, that meets or is amended to 

meet the energy assessment requirements in this table, satisfies the 

energy assessment requirement. The energy assessment must include: 

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

b. An evaluation of operating characteristics of the facility, specifications of energy using systems, operating and maintenance procedures, and unusual operating constraints. 

c. An inventory of major 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 practices and provide 

recommendations for improvements consistent with the definition of 

energy management practices. 

f. A list of major energy conservation measures. 

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 unit subject to emission limits in Tables 1 or 2 to 

this subpart.

You must employ good combustion practices and demonstrate that 

good combustion practices are maintained by monitoring O2 concentrations and optimizing those concentrations as specified by the 

boiler manufacturer; you must ensure that boiler operators are 

trained in startup and shutdown procedures, including maintenance 

and cleaning, safety, control device startup, and procedures to minimize emissions; and you must maintain records during periods of 

startup and shutdown and include in your compliance reports the O2

conditions/data for each event, length of startup/shutdown and reason for the startup/shutdown (i.e., normal/routine, problem/malfunction, outage). 

As stated in § 63.7500, you must 

comply with the applicable operating 

limits: 

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

If you demonstrate compliance using 

. . . You must meet these operating limits . . . 

1. Wet PM scrubber control on a boiler 

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 not using a hydrogen chloride 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 units 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 alarm does not sound more than 5 percent of the operating time during each 6-month period. 

4. Electrostatic precipitator control on 

units 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); or 

b. This option is only for boilers and process heaters not subject to PM CPMS or continuous compliance with an opacity limit (i.e., COMS). 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. 


sroberts on DSK5SPTVN1PROD with PROPOSALS
Federal Register / Vol. 76, No. 247 / Friday, December 23, 2011 / Proposed Rules 80665 

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

If you demonstrate compliance using 

. . . You must meet these operating limits . . . 

5. Dry scrubber or carbon injection control on a boiler 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 units 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 average operating load 

recorded during the most recent performance test. 

9. Oxygen Analyzer System .................... For boilers and process heaters subject to a carbon monoxide emission limit that demonstrate compliance with an O2 analyzer system as specified in § 63.7525(a), maintain the oxygen level such 

that it is not below the lowest hourly average oxygen concentration measured during the most recent CO performance test. 

As stated in § 63.7520, you must 

comply with the following requirements 

for performance testing for existing, new 

or reconstructed affected sources: 

TABLE 5—TO SUBPART DDDDD OF PART 63—PERFORMANCE TESTING REQUIREMENTS

To conduct a performance test for the 

following pollutant 

. . . 

You must . . . Using . . . 

1. Particulate Matter a. Select sampling ports location and 

the number of traverse points.

Method 1 at 40 CFR part 60, appendix A–1 of this chapter. 

b. Determine velocity and volumetric 

flow-rate of the stack gas.

Method 2, 2F, or 2G at 40 CFR part 60, appendix A–1 or A–2 to part 60 of this 

chapter. 

c. Determine oxygen or carbon dioxide 

concentration of the stack gas.

Method 3A or 3B at 40 CFR part 60, appendix A–2 to part 60 of this chapter, 

or ANSI/ASME PTC 19.10–1981.a

d. Measure the moisture content of the 

stack gas.

Method 4 at 40 CFR part 60, appendix A–3 of this chapter. 

e. Measure the particulate matter emission concentration.Method 5 or 17 (positive pressure fabric filters must use Method 5D) at 40 CFR 

part 60, appendix A–3 or A–6 of this chapter. 

f. Convert emissions concentration to lb 

per MMBtu emission rates.

Method 19 F-factor methodology at 40 CFR part 60, appendix A–7 of this chapter. 

2. Hydrogen chloride a. Select sampling ports location and 

the number of traverse points.

Method 1 at 40 CFR part 60, appendix A–1 of this chapter. 

b. Determine velocity and volumetric 

flow-rate of the stack gas.

Method 2, 2F, or 2G at 40 CFR part 60, appendix A–2 of this chapter. 

c. Determine oxygen or carbon dioxide 

concentration of the stack gas.

Method 3A or 3B at 40 CFR part 60, appendix A–2 of this chapter, or ANSI/ 

ASME PTC 19.10–1981.a

d. Measure the moisture content of the 

stack gas.

Method 4 at 40 CFR part 60, appendix A–3 of this chapter. 

e. Measure the hydrogen chloride emission concentration.Method 26 or 26A (M26 or M26A) at 40 CFR part 60, appendix A–8 of this 

chapter. 

f. Convert emissions concentration to lb 

per MMBtu emission rates.

Method 19 F-factor methodology at 40 CFR part 60, appendix A–7 of this chapter. 

3. Mercury ............... a. Select sampling ports location and 

the number of traverse points.

Method 1 at 40 CFR part 60, appendix A–1 of this chapter. 

b. Determine velocity and volumetric 

flow-rate of the stack gas.

Method 2, 2F, or 2G at 40 CFR part 60, appendix A–1 or A–2 of this chapter. 

c. Determine oxygen or carbon dioxide 

concentration of the stack gas.

Method 3A or 3B at 40 CFR part 60, appendix A–1 of this chapter, or ANSI/ 

ASME PTC 19.10–1981.a

d. Measure the moisture content of the 

stack gas.

Method 4 at 40 CFR part 60, appendix A–3 of this chapter. 

e. Measure the mercury emission concentration.Method 29, 30A, or 30B (M29, M30A, or M30B) at 40 CFR part 60, appendix 

A–8 of this chapter or Method 101A at 40 CFR part 60, appendix B of this 

chapter, or ASTM Method D6784.a

f. Convert emissions concentration to lb 

per MMBtu emission rates.

Method 19 F-factor methodology at 40 CFR part 60, appendix A–7 of this chapter. 

4. CO ...................... a. Select the sampling ports location 

and the number of traverse points.

Method 1 at 40 CFR part 60, appendix A–1 of this chapter. 

b. Determine oxygen concentration of 

the stack gas.

Method 3A or 3B at 40 CFR part 60, appendix A–3 of this chapter, or ASTM 

D6522–00 (Reapproved 2005), or ANSI/ASME PTC 19.10–1981.a

c. Measure the moisture content of the 

stack gas.

Method 4 at 40 CFR part 60, appendix A–3 of this chapter. 


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80666 Federal Register / Vol. 76, No. 247 / Friday, December 23, 2011 / Proposed Rules 

TABLE 5—TO SUBPART DDDDD OF PART 63—PERFORMANCE TESTING REQUIREMENTS—Continued 

To conduct a performance test for the 

following pollutant 

. . . 

You must . . . Using . . . 

d. Measure the CO emission concentration.Method 10 at 40 CFR part 60, appendix A–4 of this chapter. Use a span value 

of 2 times the concentration of the applicable emission limit. 

a Incorporated by reference, see § 63.14. 

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: 

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

To conduct a fuel analysis for the 

following pollutant . . . You must . . . Using . . . 

1. Mercury ................................... a. Collect fuel samples ................................................ Procedure in § 63.7521(c) 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 equivalent. 

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

c. Prepare composited fuel samples ........................... EPA SW–846–3050Ba (for solid samples), EPA SW– 

846–3020Aa (for liquid samples), ASTM D2013/ 

D2013M a (for coal), ASTM D5198 a (for biomass), 

or ASTME829 or EPA 3050 (for solid fuel), or EPA 

821–R–01–013 (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 for liquids and other solids, 

or ASTM D240 or equivalent. 

e. Determine moisture content of the fuel type ........... ASTM D3173 a, ASTM E871 a, or ASTM D5864, or 

ASTM D240 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. 

h. Calculate the mercury emission rate from the boiler or process heater in units of pounds per million 

Btu.

Equations 10 and 12 in § 63.7530. 

2. Hydrogen Chloride .................. a. Collect fuel samples ................................................ Procedure in § 63.7521(c) or ASTM D2234/D2234M a

(for coal) or ASTM D6323 a (for coal or biomass), 

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), EPA SW– 

846–3020Aa (for liquid samples), ASTM D2013/ 

D2013M a (for coal), or ASTM D5198 a (for biomass),or ASTM E829 (for solid fuel), or EPA 3050 

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 or equivalent. 

e. Determine moisture content of the fuel type ........... ASTM D3173 a or ASTM E871 a, or D5864, or ASTM 

D240 or equivalent. 

f. Measure chlorine concentration in fuel sample ....... EPA SW–846–9250 a, ASTM D6721 a, ASTM D4208 

(for coal), or EPA SW–846–5050 a or ASTM E776 a

(for solid fuel), or EPA SW–846–9056 or SW–846– 

9076 (for solids or liquids) or equivalent. 

g. Convert concentrations into units of pounds of hydrogen chloride per MMBtu of heat content.Equation 7 in § 63.7530. 

h. Calculate the hydrogen chloride emission rate from 

the boiler or process heater in units of pounds per 

million Btu.

Equations 10 and 11 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.

ASTM D5954 a, ASTM D6350 a, ISO 6978– 

1:2003(E) a, or ISO 6978–2:2003(E) a, or equivalent. 

4. Total Selected Metals for solid 

fuels.

a. Collect fuel samples ................................................ Procedure in § 63.7521(c) or ASTM D2234/D2234M a

(for coal) or ASTM D6323 a (for coal or biomass), 

or equivalent. 

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


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

To conduct a fuel analysis for the 

following pollutant . . . You must . . . Using . . . 

c. Prepare composited fuel samples ........................... EPA SW–846–3050Ba (for solid samples), EPA SW– 

846–3020Aa (for liquid samples), ASTM D2013/ 

D2013M a (for coal), ASTM D5198 a or TAPPI T266 

(for biomass), or ASTM E829 (for solid fuel), or 

EPA 3050 or equivalent. 

d. Determine heat content of the fuel type ................. ASTM D5865 a (for coal) or ASTM E711 a (for biomass), or ASTM D5864 for liquids and other solids, 

or ASTM D240 or equivalent. 

e. Determine moisture content of the fuel type ........... ASTM D3173 a or ASTM E871 a, or D5864, or ASTM 

D240 or equivalent. 

f. Measure total selected metals concentration in fuel 

sample.

ASTM D3683, or ASTM D4606, or ASTM D6357 or 

EPA 200.8 or or EPA SW–846–6020, or EPA SW– 

846–6020A, or ASTM E885, or EPA SW–846– 

6010B, EPA 7060 or EPA 7060A (for arsenic only), 

or EPA SW–846–7740 (for selenium only), 

g. Convert concentrations into units of pounds of total 

selected metals per MMBtu of heat content.

Equations 9 in § 63.7530. 

h. Calculate the total selected metals emission rate 

from the boiler or process heater in units of pounds 

per million Btu.

Equations 10 and 13 in § 63.7530. 

a Incorporated by reference, see § 63.14. 

As stated in § 63.7520, you must 

comply with the following requirements 

for establishing operating limits: 

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

If you have an applicable 

emission limit for . . . 

And your operating limits 

are based on . . . You must . . . Using . . . According to the following requirements . . . 

1. Particulate matter, total 

selected metals, 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 particulate matter 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 

particulate matter 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. Hydrogen Chloride ........ a. Wet scrubber operating 

parameters.

i. Establish site-specific 

minimum pressure drop, 

effluent pH, and flow 

rate operating limits according to § 63.7530(b).

(1) Data from the pressure 

drop, pH, and liquid 

flow-rate monitors and 

the hydrogen chloride 

performance test.

(a) You must collect pH 

and liquid flow-rate data 

every 15 minutes during 

the entire period of the 

performance tests. 


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80668 Federal Register / Vol. 76, No. 247 / Friday, December 23, 2011 / Proposed Rules 

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

If you have an applicable 

emission limit for . . . 

And your operating limits 

are based on . . . You must . . . Using . . . According to the following requirements . . . 

(b) Determine the 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 hydrogen chloride 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 hydrogen chloride 

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 

(e.g., for 50 percent 

load, multiply the injection rate operating limit 

by 0.5) to determine the 

required injection rate. 

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. 


sroberts on DSK5SPTVN1PROD with PROPOSALS
Federal Register / Vol. 76, No. 247 / Friday, December 23, 2011 / Proposed Rules 80669 

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

If you have an applicable 

emission limit for . . . 

And your operating limits 

are based on . . . You must . . . Using . . . According to the following requirements . . . 

(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 (e.g., actual heat 

input divided by heat 

input during performance test, for 50 percent 

load, multiply the injection rate operating limit 

by 0.5) to determine the 

required injection rate. 

4. Carbon monoxide .......... a. Oxygen .......................... i. Establish a unit-specific 

limit for minimum oxygen level according to 

§ 63.7520.

(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. 

As stated in § 63.7540, you must show 

continuous compliance with the 

emission limitations for affected sources 

according to the following: 

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

If you must meet the following operating limits or 

work practice standards . . . 

You must demonstrate continuous compliance by . . . 

1. Opacity ............................. a. Collecting the opacity monitoring system data according to § 63.7525(c) and § 63.7535; and 

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

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

2. PM CPMS ........................ a. Collecting the PM CPMS output data according to § 63.7525; 


sroberts on DSK5SPTVN1PROD with PROPOSALS
80670 Federal Register / Vol. 76, No. 247 / Friday, December 23, 2011 / Proposed Rules 

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

If you must meet the following operating limits or 

work practice standards . . . 

You must demonstrate continuous compliance by . . . 

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

c. Maintaining the 30-day rolling average PM CPMS output data to less than the operating limit established during the performance test according to § 63.7530. 

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)(9) are met. 

4. Wet Scrubber Pressure 

Drop and Liquid Flow-rate.

a. Collecting the pressure drop and liquid flow rate monitoring system data according to §§ 63.7525 and 63.7535; 

and 

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

c. Maintaining the 30-day rolling average pressure drop and liquid flow-rate at or above the operating limits established during the performance test according to § 63.7530(b). 

5. Wet Scrubber pH ............. a. Collecting the pH monitoring system data according to §§ 63.7525 and 63.7535; and 

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

c. Maintaining the 30-day rolling average pH at or above the operating limit established during the performance 

test according to § 63.7530(b). 

6. Dry Scrubber Sorbent or 

Carbon Injection Rate.

a. Collecting the sorbent or carbon injection rate monitoring system data for the dry scrubber according to 

§§ 63.7525 and 63.7535; and 

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

c. Maintaining the 30-day rolling average sorbent or carbon injection rate at or above the minimum sorbent or 

carbon injection rate as defined in § 63.7575. 

7. Electrostatic Precipitator 

Total Secondary Electric 

Power Input.

a. Collecting the total secondary electric power input monitoring system data for the electrostatic precipitator according to §§ 63.7525 and 63.7535; and 

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

c. Maintaining the 30-day rolling average total secondary electric power input at or above the operating limits established during the performance test according to § 63.7530(b). 

8. Fuel Pollutant Content ..... a. Only burning the fuel types and fuel mixtures used to demonstrate compliance with the applicable emission 

limit according to § 63.7530(b) or (c) as applicable; and 

b. Keeping monthly records of fuel use according to § 63.7540(a). 

9. Oxygen content ................ a. Continuously monitor the oxygen content using an oxygen trim system according to § 63.7525(a). 

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 carbon monoxide performance test. 

10. Carbon monoxide emissions.a. Continuously monitor the carbon monoxide concentration in the combustion exhaust according to § 63.7525(a). 

b. Correcting the data to 3 percent oxygen, and reducing the data to one-hour and daily block averages for all 

subcategories except units designed to burn liquid fuels located in non-continental states and territories; 

c. Reducing the data from the daily averages to 10-day rolling averages for all subcategories except units designed to burn liquid fuels located in non-continental states and territories; 

d. Reducing the data from the one-hour averages to three-hour averages for units designed to burn liquid fuels 

located in non-continental states and territories; 

e. Maintaining the 10-day rolling average carbon monoxide concentration at or below the applicable emission limit 

in Tables 1 or 2 of this subpart for all subcategories except units designed to burn liquid fuels located in noncontinental states and territories; and 

f. Maintaining the 3-hour rolling average carbon monoxide concentration at or below the applicable emission limit 

in Tables 1 or 2 of this subpart for units designed to burn liquid fuels located in non-continental states and territories. 

11. Boiler or process heater 

operating load.

a. Collecting operating load data or steam generation data every 15 minutes. 

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

As stated in § 63.7550, you must 

comply with the following requirements 

for reports: 

TABLE 9—TO SUBPART DDDDD OF PART 63—REPORTING REQUIREMENTS

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 (12); and ................................ Semiannually, annually, biennially, or 

every 5 years according to the requirements in § 63.7550(b). 


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TABLE 9—TO SUBPART DDDDD OF PART 63—REPORTING REQUIREMENTS—Continued 

You must submit 

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

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 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-of-control 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 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). 

As stated in § 63.7565, you must 

comply with the applicable General 

Provisions according to the following: 

TABLE 10—TO SUBPART DDDDD OF PART 63—APPLICABILITY OF GENERAL PROVISIONS TO SUBPART DDDDD 

Citation Subject Applies to subpart DDDDD 

§ 63.1 ................................................. Applicability ........................................................ Yes.

§ 63.2 ................................................. Definitions .......................................................... Yes. Additional terms defined in § 63.7575. 

§ 63.3 ................................................. Units and Abbreviations .................................... Yes. 

§ 63.4 ................................................. Prohibited Activities and Circumvention ............ Yes. 

§ 63.5 ................................................. Preconstruction Review and Notification Requirements.Yes. 

§ 63.6(a), (b)(1)–(b)(5), (b)(7), (c) ...... Compliance with Standards and Maintenance 

Requirements.

Yes. 

§ 63.6(e)(1)(i) ..................................... General duty to minimize emissions. ................ No. See § 63.7500(a)(3) for the general duty requirement. 

§ 63.6(e)(1)(ii) .................................... Requirement to correct malfunctions as soon 

as practicable.

No. 

§ 63.6(e)(3) ........................................ Startup, shutdown, and malfunction plan requirements.No. 

§ 63.6(f)(1) ......................................... Startup, shutdown, and malfunction exemptions for compliance with non-opacity emission standards.No. 

§ 63.6(f)(2) and (3) ............................. Compliance with non-opacity emission standards.Yes. 

§ 63.6(g) ............................................. Use of alternative standards ............................. Yes. 

§ 63.6(h)(1) ........................................ Startup, shutdown, and malfunction exemptions to opacity standards.No. See § 63.7500(a). 

§ 63.6(h)(2) to (h)(9) .......................... Determining compliance with opacity emission 

standards.

Yes. 

§ 63.6(i) .............................................. Extension of compliance ................................... Yes. Facilities may request extensions of compliance 

for the installation of combined heat and power or 

waste heat recovery as a means of complying with 

this subpart. 

§ 63.6(j) .............................................. Presidential exemption ...................................... Yes. 

§ 63.7(a), (b), (c), and (d) .................. Performance Testing Requirements .................. Yes. 

§ 63.7(e)(1) ........................................ Conditions for conducting performance tests. ... No. Subpart DDDDD specifies conditions for conducting 

performance tests at § 63.7520(a) to (c). 

§ 63.7(e)(2)–(e)(9), (f), (g), and (h) .... Performance Testing Requirements .................. Yes. 

§ 63.8(a) and (b) ................................ Applicability and Conduct of Monitoring ............ Yes. 

§ 63.8(c)(1) ......................................... Operation and maintenance of CMS ................. Yes. 

§ 63.8(c)(1)(i) ..................................... General duty to minimize emissions and CMS 

operation.

No. See § 63.7500(a)(3). 

§ 63.8(c)(1)(ii) ..................................... Operation and maintenance of CMS ................. Yes. 

§ 63.8(c)(1)(iii) .................................... Startup, shutdown, and malfunction plans for 

CMS.

No. 

§ 63.8(c)(2) to (c)(9) ........................... Operation and maintenance of CMS ................. Yes. 


sroberts on DSK5SPTVN1PROD with PROPOSALS
80672 Federal Register / Vol. 76, No. 247 / Friday, December 23, 2011 / Proposed Rules 

TABLE 10—TO SUBPART DDDDD OF PART 63—APPLICABILITY OF GENERAL PROVISIONS TO SUBPART DDDDD— 

Continued 

Citation Subject Applies to subpart DDDDD 

§ 63.8(d)(1) and (2) ............................ Monitoring Requirements, Quality Control Program.Yes. 

§ 63.8(d)(3) ........................................ Written procedures for CMS .............................. Yes, except for the last sentence, which refers to a 

startup, shutdown, and malfunction plan. Startup, 

shutdown, and malfunction plans are not required. 

§ 63.8(e) ............................................. Performance evaluation of a CMS .................... Yes. 

§ 63.8(f) .............................................. Use of an alternative monitoring method .......... Yes. 

§ 63.8(g) ............................................. Reduction of monitoring data ............................ Yes. 

§ 63.9 ................................................. Notification Requirements ................................. Yes. 

§ 63.10(a), (b)(1) ................................ Recordkeeping and Reporting Requirements ... Yes. 

§ 63.10(b)(2)(i) ................................... Recordkeeping of occurrence and duration of 

startups or shutdowns.

Yes. 

§ 63.10(b)(2)(ii) .................................. Recordkeeping of malfunctions ......................... No. See § 63.7555(d)(7) for recordkeeping of occurrence and duration and § 63.7555(d)(8) for actions 

taken during malfunctions. 

§ 63.10(b)(2)(iii) .................................. Maintenance records ......................................... Yes. 

§ 63.10(b)(2)(iv) and (v) ..................... Actions taken to minimize emissions during 

startup, shutdown, or malfunction.

No. 

§ 63.10(b)(2)(vi) ................................. Recordkeeping for CMS malfunctions ............... Yes. 

§ 63.10(b)(2)(vii) to (xiv) .................... Other CMS requirements .................................. Yes. 

§ 63.10(b)(3) ...................................... Recordkeeping requirements for applicability 

determinations.

No. 

§ 63.10(c)(1) to (9) ............................. Recordkeeping for sources with CMS ............... Yes. 

§ 63.10(c)(10) and (11) ...................... Recording nature and cause of malfunctions, 

and corrective actions.

No. See § 63.7555(d)(7) for recordkeeping of occurrence and duration and § 63.7555(d)(8) for actions 

taken during malfunctions. 

§ 63.10(c)(12) and (13) ...................... Recordkeeping for sources with CMS ............... Yes. 

§ 63.10(c)(15) ..................................... Use of startup, shutdown, and malfunction plan No. 

§ 63.10(d)(1) and (2) .......................... General reporting requirements ........................ Yes. 

§ 63.10(d)(3) ...................................... Reporting opacity or visible emission observation results.No. 

§ 63.10(d)(4) ...................................... Progress reports under an extension of compliance.Yes. 

§ 63.10(d)(5) ...................................... Startup, shutdown, and malfunction reports ..... No. See § 63.7550(c)(11) for malfunction reporting requirements. 

§ 63.10(e) ........................................... Additional reporting requirements for sources 

with CMS.

Yes. 

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

§ 63.11 ............................................... Control Device Requirements ........................... No. 

§ 63.12 ............................................... State Authority and Delegation ......................... Yes. 

§ 63.13–63.16 .................................... Addresses, Incorporation by Reference, Availability of Information, Performance Track 

Provisions.

Yes. 

§ 63.1(a)(5),(a)(7)–(a)(9), (b)(2), 

(c)(3)–(4), (d), 63.6(b)(6), (c)(3), 

(c)(4), (d), (e)(2), (e)(3)(ii), (h)(3), 

(h)(5)(iv), 63.8(a)(3), 63.9(b)(3), 

(h)(4), 63.10(c)(2)–(4), (c)(9).

Reserved ........................................................... No. 

[FR Doc. 2011–31667 Filed 12–22–11; 8:45 am] 

BILLING CODE 6560–50–P 


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