Document ID: EPA-HQ-OAR-2002-0058-3373
Agency: epa
Document Type: Proposed Rule
Title: National Emission Standards for Hazardous Air Pollutants for Major Sources: Industrial, Commercial, and Institutional Boilers and Process Heaters
Posted Date: 2011-12-23T05:00Z

[Federal Register Volume 76, Number 247 (Friday, December 23, 2011)]
[Proposed Rules]
[Pages 80598-80672]
From the Federal Register Online via the Government Printing Office [www.gpo.gov]
[FR Doc No: 2011-31667]

[[Page 80597]]

Vol. 76

Friday,

No. 247

December 23, 2011

Part V

Environmental Protection Agency

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40 CFR Part 63

National Emission Standards for Hazardous Air Pollutants for Major 
Sources: Industrial, Commercial, and Institutional Boilers and Process 
Heaters; Proposed Rule

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

[[Page 80598]]

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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.

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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?

[[Page 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:

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                                                        Examples of
           Category               NAICS code \1\   potentially regulated
                                                          entities
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Any industry using a boiler or                211  Extractors of crude
 process heater as defined in                       petroleum and
 the proposed rule.                                 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.

[[Page 80600]]

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,

[[Page 80601]]

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.
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    \1\ Heat 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).

                            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]
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                                  Filterable
                              Particulate Matter     Hydrogen
                                (Filterable PM)   chloride (HCl)   Mercury (Hg)       Carbon       Alternate CO
         Subcategory          (or total selected   (lb per MMBtu   (lb per MMBtu   monoxide(CO)     CEMS limit,
                                metals) (lb per   of heat input)  of heat input)     (ppm @3%        (ppm @3%
                                 MMBtu of heat          \a\             \a\         oxygen) \a\     oxygen) \b\
                                  input) \a\
----------------------------------------------------------------------------------------------------------------
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           0.044 (5.9E-05)              NA              NA              41              28
 Pulverized Coal............
Existing--Biomass Wet Stoker/    0.029 (5.7E-05)              NA              NA             790             410
 Sloped Grate/Other.........
Existing--Biomass Kiln-Dried        0.32 (0.004)              NA              NA             250              ND
 Stoker/Sloped Grate/Other..
Existing--Biomass Fluidized        0.11 (0.0012)              NA              NA             370             180
 Bed........................
Existing--Biomass Suspension      0.051 (0.0011)              NA              NA              58           1,400
 Burner.....................
Existing--Biomass Dutch          0.036 (2.4E-04)              NA              NA             810             440
 Ovens/Pile Burners.........
Existing--Biomass Fuel Cells     0.033 (4.9E-05)              NA              NA           1,500              ND
Existing--Biomass Hybrid          0.44 (4.9E-04)              NA              NA           3,900             730
 Suspension Grate...........
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             \c\ 0.0080              NA              NA              18          \e\ 91
 Liquid.....................
Existing--Gas 2 (Other          0.0067 (2.4E-04)          0.0017         7.9E-06               4              ND
 Process Gases).............
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    0.0013 (2.8E-05)              NA              NA               9              28
 Coal.......................
New--Biomass Wet Stoker/         0.029 (2.6E-05)              NA              NA             590             410
 Sloped Grate/Other.........
New--Biomass Kiln-Dried            0.32 (0.0040)              NA              NA             250              ND
 Stoker/Sloped Grate/Other..
New--Biomass Fluidized Bed..    0.0098 (4.2E-05)              NA              NA             230             180
New--Biomass Suspension           0.051 (0.0011)              NA              NA              58           1,400
 Burner.....................
New--Biomass Dutch Ovens/        0.036 (4.1E-05)              NA              NA             810             440
 Pile Burners...............
New--Biomass Fuel Cells.....     0.011 (4.9E-05)              NA              NA             210              ND
New--Biomass Hybrid              0.026 (4.9E-04)              NA              NA           1,500             730
 Suspension Grate...........
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       0.0067 (2.4E-04)          0.0017         7.9E-06               4              ND
 Gases).....................
----------------------------------------------------------------------------------------------------------------
NA--Not applicable; ND--No data available.
\a\ 3-run average, unless otherwise noted.
\b\ 10-day rolling average, unless otherwise noted.
\c\ Total selected metals alternative limits are not available to units in any of the liquid subcategories.
\d\ 1-day block average.

[[Page 80602]]

 
\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 site-specific 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 site-specific 
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 site-specific minimum sorbent injection 
rate operating limit. If different acid gas sorbents and/or injection 
rates are used during the HCl test, the lowest hourly

[[Page 80603]]

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 site-specific 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 site-specific 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)

[[Page 80604]]

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 Sec.  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.

[[Page 80605]]

    (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.

[[Page 80606]]

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 biomass-based 
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

[[Page 80607]]

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 output-based 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 output-based 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 output-based 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 combustion-based pollutant. Differences in PM particle 
size, applicability of air-pollution 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

[[Page 80608]]

that could be used to justify a subcategory. However, we identified 
several design differences, including the need for steam atomization or 
high-pressure 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 
liquid-fired 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/bio-based 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 non-continental 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 non-
continental 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 non-continental 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 
non-continental 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 non-continental 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 non-continental 
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 Kiln-Dried 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 on-site, 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

[[Page 80609]]

``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

[[Page 80610]]

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

[[Page 80611]]

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.
---------------------------------------------------------------------------

    \2\ American Society of Mechanical Engineers, Reference Method 
Accuracy and Precision (ReMAP): Phase 1, Precision of Manual Stack 
Emission Measurements, CRTD Vol. 60, February 2001.
---------------------------------------------------------------------------

    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

[[Page 80612]]

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 UPL-based 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

[[Page 80613]]

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:
[GRAPHIC] [TIFF OMITTED] TP23DE11.028

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 non-continental 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 log-normal distribution. In the case of 
the CEMS datasets from each of the best performers, the datasets were 
each log-normally 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 
CEMS-based 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
------------------------------------------------------------------------
                                                      Alternate CO  CEMS
                     Subcategory                        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/                   920
 Other..............................................
New and Existing--Biomass Kiln-Dried Stoker/Sloped                   (1)
 Grate/Other........................................
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.

[[Page 80614]]

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 Non-Continental 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 oil-fired 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 tune-up 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

[[Page 80615]]

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

[[Page 80616]]

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

[[Page 80617]]

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 Sec.   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.

[[Page 80618]]

 
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),             Revise these paragraphs by removing the
 63.7515(f), and 63.7520(d).    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)       Revise the subparagraphs to clarify that
 through (iv).                  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   Revise this paragraph by clarifying
 63.7521(d)(2).                 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)       Revise the subparagraphs to clarify that
 through (iv).                  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)           Revise this paragraph to: 1. Clarify that
 [formerly (b)(3)].             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),  Amend these paragraphs to change the date
 and (c)(3).                    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    Revise the reference to Equation 12 to
 (c)(3).                        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    Revise the names and definitions of the
 (f).                           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.

[[Page 80619]]

 
                               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       Change the references to Equation 9 to
 (a)(3)(iii).                   Equation 11 to accommodate the change in
                                numbering of equations.
40 CFR 63.7540(a)(4), (a)(5),  Revise these paragraphs to clarify that
 and (a)(6).                    certain fuels are not subject to the
                                fuel analysis requirements.
40 CFR 63.7540(a)(5) and       Change the reference to Equation 11 to
 (a)(5)(iii).                   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   Revise this paragraph to specify that
 (a)(12).                       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    Revise paragraph (h) and adding
 (j).                           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.

[[Page 80620]]

 
                               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      Revise the sampling volumes collected and
 DDDDD.                         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.

[[Page 80621]]

                                          Table 4--Summary of Emissions Reductions for Existing and New Sources
                                                                        [Tons/yr]
--------------------------------------------------------------------------------------------------------------------------------------------------------
                                                                                                     Non
                   Source                           Subcategory            HCl           PM        mercury             Mercury \b\               VOC
                                                                                                  metals \a\
--------------------------------------------------------------------------------------------------------------------------------------------------------
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            158           29            4  0.001 to 0.01................          169
                                              units.
                                              Gas 1 (NG/RG) units....           21          118          0.9  0.01.........................           85
                                             Gas 1 Metallurgical               0.4            3         0.02  0.001........................           23
                                              Furnaces.
                                             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                 0            0            0  0............................            0
                                              Furnaces.
                                             Gas 2 (other) units.....            0            0            0  0............................            0
--------------------------------------------------------------------------------------------------------------------------------------------------------
 
\a\ Includes antimony, arsenic, beryllium, cadmium, chromium, cobalt, lead, manganese, nickel, and selenium.
\b\Hg 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; 
tune-ups, 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

[[Page 80622]]

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
----------------------------------------------------------------------------------------------------------------
                                                                                    Testing and     Annualized
                                                    Estimated/                      monitoring    cost(10 \6\ $/
            Source                 Subcategory       Projected     Capital costs    annualized          yr)
                                                     number of      (10 \6\ $)     costs (10 \6\   (considering
                                                  affected units                       $/yr)       fuel savings)
----------------------------------------------------------------------------------------------------------------
Existing Units................  Coal units......             616           2,713              46             953
                                Biomass units...             508             639              33             169
                                Heavy Liquid                 322             769             8.4             264
                                 units.
                                Light Liquid                 581             930             5.1             277
                                 units.
                                Non-Continental               44             181             1.5              42
                                 Liquid units.
                                Gas 1 (NG/RG)             11,911              77             0.9           (295)
                                 units.
                                Gas 2 (other)                129             132             2.3              55
                                 units.
Energy Assessment.............  ALL.............           1,704             N/A             N/A              28
                                                    (Facilities)
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)              1,762              11               0         \a\ 5.1
                                 units.
                                Gas 2 (other)                  0               0               0               0
                                 units.
----------------------------------------------------------------------------------------------------------------
\a\ Total 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-to-revenue 
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

[[Page 80623]]

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\
----------------------------------------------------------------------------------------------------------------
                                    Emissions      Total monetized
           Pollutant               reductions      benefits (at 3%     Total monetized benefits (at 7% discount
                                     (tons)        discount rate)                       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  $25,000 to
                                        $67,000   $61,000..
----------------------------------------------------------------------------------------------------------------
\1\ All 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
------------------------------------------------------------------------
\1\ All 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

[[Page 80624]]

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 non-labor 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

[[Page 80625]]

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 Sec.  605(c), the EPA is not required to complete an initial 
regulatory flexibility analysis for this rule.
---------------------------------------------------------------------------

    \3\ Small 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.
---------------------------------------------------------------------------

    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 Sec.  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

[[Page 80626]]

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

[[Page 80627]]

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 tune-ups?
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

Sec.  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.

Sec.  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 Sec.  63.7575 that is located at, or is part of, a major 
source of HAP, except as specified in

[[Page 80628]]

Sec.  63.7491. For purposes of this subpart, a major source of HAP is 
as defined in Sec.  63.2, except that for oil and natural gas 
production facilities, a major source of HAP is as defined in Sec.  
63.761 (subpart HH of this part, National Emission Standards for 
Hazardous Air Pollutants from Oil and Natural Gas Production 
Facilities).

Sec.  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 Sec.  
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 Sec.  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 Sec.  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.

Sec.  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 Sec.  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 Sec.  
63.1200(b) is not covered by Subpart EEE.
    (n) Residential boilers as defined in this subpart.

Sec.  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 Sec.  
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 Sec.  63.7545 
according to the schedule in Sec.  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 Sec.  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

Sec.  63.7499  What are the subcategories of boilers and process 
heaters?

    The subcategories of boilers and process heaters, as defined in 
Sec.  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.

Sec.  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

[[Page 80629]]

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 Sec.  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 Sec.  
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 Sec.  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 tune-up as specified in Sec.  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 
Sec.  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.

Sec.  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 Sec.  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 Sec.  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 
Sec.  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

Sec.  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 Sec.  
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

[[Page 80630]]

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 Sec.  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 Sec.  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 Sec.  63.8(d) and the elements described in 
paragraphs (d)(1)(i) through (iii) of this section. You must submit 
this site-specific monitoring plan, if requested, at least 60 days 
before your initial performance evaluation of your CMS. 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 Sec.  63.7525. Using the process 
described in Sec.  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 Sec.  63.8(c)(1)(ii), (c)(3), and 
(c)(4)(ii);
    (ii) Ongoing data quality assurance procedures in accordance with 
the general requirements of Sec.  63.8(d); and
    (iii) Ongoing recordkeeping and reporting procedures in accordance 
with the general requirements of Sec.  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

Sec.  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 Sec.  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 Sec.  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 Sec.  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 Sec.  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 Sec.  63.7521 and Table 6 to this subpart. If 
gaseous fuels other than natural gas, refinery gas, or other gas 1 
fuels are co-fired with other fuels and those gaseous fuels are subject 
to another subpart of this part, you are not required to conduct a fuel 
analysis of those fuels according to Sec.  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 Sec.  63.7530 and Table 
7 to this subpart.
    (4) Conduct CMS performance evaluations according to Sec.  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 Sec.  63.7521 and Table 6 to this subpart and establish 
operating limits according to Sec.  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 Sec.  
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

[[Page 80631]]

compliance demonstration for PM is to conduct a performance test in 
accordance with Sec.  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 Sec.  63.7495 and according to the 
applicable provisions in Sec.  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 Sec.  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 Sec.  
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 Sec.  63.7595 and according to the applicable provisions in Sec.  
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 Sec.  
63.7540(a).
    (h) For affected sources that ceased burning solid waste consistent 
with Sec.  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.

Sec.  63.7515  When must I conduct subsequent performance tests, fuel 
analyses, or tune-ups?

    (a) You must conduct all applicable performance tests according to 
Sec.  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 Sec.  
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 Sec.  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 Sec.  63.7540(a)(10), (11), or (12), respectively. 
Each annual tune-up specified in Sec.  63.7540(a)(10) must be no more 
than 13 months after the previous tune-up. Each biennial tune-up 
specified in Sec.  63.7540(a)(11) must be conducted no more than 25 
months after the previous tune-up. Each 5-year tune-up specified in 
Sec.  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 Sec.  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 Sec.  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 Sec.  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 
Sec.  63.7530 and Table 7 to this subpart, as applicable. The reports 
for all subsequent performance tests must include all applicable 
information required in Sec.  63.7550.

Sec.  63.7520  What stack tests and procedures must I use?

    (a) You must conduct all performance tests according to Sec.  
63.7(c), (d), (f), and (h). You must also develop a site-specific stack 
test plan according to the requirements in Sec.  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.

[[Page 80632]]

    (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 Sec.  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.

Sec.  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 Sec.  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 Sec.  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 site-specific 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 
cross-section 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 one-hour 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.

[[Page 80633]]

    (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 one-quarter 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 Sec.  
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 Sec.  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 site-specific 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.

Sec.  63.7522  Can I use emissions averaging to comply with this 
subpart?

    (a) As an alternative to meeting the requirements of Sec.  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

[[Page 80634]]

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 Sec.  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.
[GRAPHIC] [TIFF OMITTED] TP23DE11.029

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 Sec.  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.

[GRAPHIC] [TIFF OMITTED] TP23DE11.030

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 Sec.  63.7530(c). If you are taking 
credit for energy conservation measures from a unit according to 
Sec.  63.7533, use the adjusted emission level for that unit, 
Eadj, determined according to Sec.  63.7533 for that 
unit.
So = Maximum steam output capacity of unit, i, in units of million 
Btu per hour, as defined in Sec.  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.

[GRAPHIC] [TIFF OMITTED] TP23DE11.031

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 Sec.  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 Sec.  
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

[[Page 80635]]

are complying with the emission limits on a steam generation (output) 
basis.

[GRAPHIC] [TIFF OMITTED] TP23DE11.032

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 Sec.  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.

[GRAPHIC] [TIFF OMITTED] TP23DE11.033

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 Sec.  63.7530(c). If you are taking 
credit for energy conservation measures from a unit according to 
Sec.  63.7533, use the adjusted emission level for that unit, 
Eadj, determined according to Sec.  63.7533 for that 
unit.
So = The steam output for that calendar month from unit, i, in units 
of million Btu, as defined in Sec.  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.
[GRAPHIC] [TIFF OMITTED] TP23DE11.034

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 Sec.  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.
[GRAPHIC] [TIFF OMITTED] TP23DE11.035

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;

[[Page 80636]]

    (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 Sec.  63.7520;
    (v) The operating parameters to be monitored for each control 
system or device consistent with Sec.  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 Sec.  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 
Sec.  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.
[GRAPHIC] [TIFF OMITTED] TP23DE11.036

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 
Sec.  63.7520 in the common stack. If affected units and non-affected 
units vent to the common stack, the non-affected 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 Sec.  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.

Sec.  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 
Sec.  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 Sec.  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 Sec.  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

[[Page 80637]]

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 Sec.  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 Sec.  
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 Sec.  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 
Sec.  63.7535(c). Periods when CO data are unavailable may constitute 
monitoring deviations as specified in Sec.  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 site-specific monitoring plan 
developed in accordance with Sec.  63.7505(d), the requirements in 
Sec.  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 Sec.  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 Sec.  
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 Sec.  63.8(e) and according to 
Performance Specification 1 at appendix B to part 60 of this chapter.
    (3) As specified in Sec.  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 Sec.  63.8(g)(2).
    (5) You must include in your site-specific monitoring plan 
procedures and acceptance criteria for operating and maintaining each 
COMS according to the requirements in Sec.  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 Sec.  
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

[[Page 80638]]

paragraphs (d)(1) through (5) of this section by the compliance date 
specified in Sec.  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 Sec.  
63.7535(b), and comply with the data calculation requirements specified 
in Sec.  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 
Sec.  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 
Sec.  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

[[Page 80639]]

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 Sec.  63.7540(a)(14) for a 
mercury CEMS and Sec.  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.

Sec.  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 Sec.  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 Sec.  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 Sec.  
63.7520, Table 7 to this subpart, and paragraph (b)(4) of this section, 
as applicable. You must also conduct fuel analyses according to Sec.  
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 Sec.  63.7510(a)(2). (Note that Sec.  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.

[GRAPHIC] [TIFF OMITTED] TP23DE11.037

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 Sec.  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.

[GRAPHIC] [TIFF OMITTED] TP23DE11.038

[[Page 80640]]

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 Sec.  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.

[GRAPHIC] [TIFF OMITTED] TP23DE11.039

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 Sec.  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 Sec.  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 Sec.  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 Sec.  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 Sec.  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 Sec.  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 Sec.  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 Sec.  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

[[Page 80641]]

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.

[GRAPHIC] [TIFF OMITTED] TP23DE11.040

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 Sec.  63.7521, in units of pounds 
per million Btu.
SD = Standard deviation of the pollutant concentration in the fuel 
samples analyzed according to Sec.  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.

[GRAPHIC] [TIFF OMITTED] TP23DE11.041

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.

[GRAPHIC] [TIFF OMITTED] TP23DE11.042

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.

[GRAPHIC] [TIFF OMITTED] TP23DE11.043

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 Sec.  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 Sec.  63.7575, you 
must conduct an initial fuel specification analyses according to Sec.  
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 Sec.  63.7521(f) 
through (i) and Sec.  63.7540(c)

[[Page 80642]]

and maintain records of the results of the testing as outlined in Sec.  
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.

Sec.  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 
output-based 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 Sec.  63.7522(e) and for demonstrating 
monthly compliance according to Sec.  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:

    [GRAPHIC] [TIFF OMITTED] TP23DE11.044
    

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 Sec.  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.

[[Page 80643]]

[GRAPHIC] [TIFF OMITTED] TP23DE11.045

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

Sec.  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 site-specific monitoring plan required by Sec.  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 Sec.  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 
site-specific 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.

Sec.  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 
Sec. Sec.  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 Sec.  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 
Sec.  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 Sec.  63.7510(a)(2)(i) through (iii). You may exclude the 
fuels described in Sec.  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 Sec.  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 Sec.  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 Sec.  63.7530. If the 
results of recalculating the maximum chlorine input using Equation 7 of 
Sec.  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 Sec.  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 Sec.  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 Sec.  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 Sec.  63.7530 according to the procedures specified in paragraphs 
(a)(5)(i) through (iii) of this

[[Page 80644]]

section. You are not required to complete fuel analyses for the fuels 
described in Sec.  63.7510(a)(2)(i) through (iii). You may exclude the 
fuels described in Sec.  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 Sec.  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 Sec.  
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 Sec.  63.7530. If the results 
of recalculating the maximum mercury input using Equation 8 of Sec.  
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 Sec.  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 Sec.  63.7530(b). You are not required 
to complete fuel analyses for the fuels described in Sec.  
63.7510(a)(2)(i) through (iii). You may exclude the fuels described in 
Sec.  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 Sec.  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 Sec. Sec.  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 Sec.  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 Sec.  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 
limited-use boilers and process heaters, as defined in Sec.  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 Sec.  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 tune-up 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

[[Page 80645]]

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 
Sec.  63.7530. If the results of recalculating the maximum total 
selected metals input using Equation 9 of Sec.  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 Sec.  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 Sec.  63.7530(b). You are not required to complete 
fuel analyses for the fuels described in Sec.  63.7510(a)(2)(i) through 
(iii). You may exclude the fuels described in Sec.  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 Sec.  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 Sec.  63.7510(a)(2)(i) through (iii). You 
may exclude the fuels described in Sec.  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 Sec.  
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 Sec.  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 
Sec.  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 Sec.  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 Sec.  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.

Sec.  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 Sec.  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.

[[Page 80646]]

Notification, Reports, and Records

Sec.  63.7545  What notifications must I submit and when?

    (a) You must submit to the delegated authority all of the 
notifications in Sec.  63.7(b) and (c), Sec.  63.8(e), (f)(4) and (6), 
and Sec.  63.9(b) through (h) that apply to you by the dates specified.
    (b) As specified in Sec.  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 Sec.  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 Sec.  63.7530(a), you must submit a 
Notification of Compliance Status according to Sec.  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 Sec.  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 Sec.  241.3, whether the fuel(s) were processed from discarded 
non-hazardous secondary materials within the meaning of Sec.  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 Sec.  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 Sec.  
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 Sec.  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 Sec.  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 Sec.  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.

Sec.  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 Sec.  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

[[Page 80647]]

tune-up according to Sec.  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 Sec.  
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 
Sec.  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 Sec.  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 Sec.  70.6(a)(3)(iii)(A) or Sec.  
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 
non-waste 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 Sec.  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 Sec.  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 Sec.  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 Sec.  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 Sec.  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 Sec.  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 Sec.  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 Sec.  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 Sec.  
63.7530 or the maximum mercury input operating limit using Equation 8 
of Sec.  63.7530, or the maximum total selected metals input operating 
limit using Equation 9 of Sec.  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 Sec. Sec.  63.7521 and 63.7530 for affected 
sources subject to emission limits, and any fuel specification analyses 
conducted according to Sec.  63.7521(f) and Sec.  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 Sec.  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

[[Page 80648]]

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 Sec.  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 Sec.  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 Sec.  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 Sec.  
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 (low-level) and high-level checks.
    (3) The date, time, and duration that each CMS was out of control, 
including the information in Sec.  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 Sec.  70.6(a)(3)(iii)(A) or Sec.  
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 Sec.  70.6(a)(3)(iii)(A) or 
Sec.  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 Sec.  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

[[Page 80649]]

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.

Sec.  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 
Sec.  63.10(b)(2)(xiv).
    (2) Records of performance tests, fuel analyses, or other 
compliance demonstrations and performance evaluations as required in 
Sec.  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 Sec.  63.10(b)(2)(vii) through (xi).
    (2) Monitoring data for continuous opacity monitoring system during 
a performance evaluation as required in Sec.  63.6(h)(7)(i) and (ii).
    (3) Previous (i.e., superseded) versions of the performance 
evaluation plan as required in Sec.  63.8(d)(3).
    (4) Request for alternatives to relative accuracy test for CEMS as 
required in Sec.  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 Sec.  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 
Sec.  241.3(b)(4), you must keep records as to how the operations that 
produced the fuel satisfy the definition of processing in Sec.  241.2. 
If the fuel received a non-waste determination pursuant to the petition 
process submitted under Sec.  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 Sec.  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 
Sec.  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 Sec.  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 Sec.  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 Sec.  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 Sec.  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 Sec.  
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 Sec.  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 Sec.  
63.7522, you must additionally keep a copy of the emission averaging 
implementation plan required in Sec.  63.7522(g), all calculations 
required under Sec.  63.7522, including monthly

[[Page 80650]]

records of heat input or steam generation, as applicable, and 
monitoring records consistent with Sec.  63.7541.
    (f) If you elect to use emission credits from energy conservation 
measures to demonstrate compliance according to Sec.  63.7533, you must 
keep a copy of the Implementation Plan required in Sec.  63.7533(d) and 
copies of all data and calculations used to establish credits according 
to Sec.  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 Sec.  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.

Sec.  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 Sec.  63.10(b)(1).
    (b) As specified in Sec.  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 Sec.  63.10(b)(1). 
You can keep the records off site for the remaining 3 years.

Other Requirements and Information

Sec.  63.7565  What parts of the General Provisions apply to me?

    Table 10 to this subpart shows which parts of the General 
Provisions in Sec. Sec.  63.1 through 63.15 apply to you.

Sec.  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 Sec.  63.7500(a) and (b) under Sec.  
63.6(g).
    (2) Approval of alternative opacity emission limits in Sec.  
63.7500(a) under Sec.  63.6(h)(9).
    (3) Approval of major change to test methods in Table 5 to this 
subpart under Sec.  63.7(e)(2)(ii) and (f) and as defined in Sec.  
63.90, and alternative analytical methods requested under Sec.  
63.7521(b)(2).
    (4) Approval of major change to monitoring under Sec.  63.8(f) and 
as defined in Sec.  63.90, and approval of alternative operating 
parameters under Sec.  63.7500(a)(2) and Sec.  63.7522(g)(2).
    (5) Approval of major change to recordkeeping and reporting under 
Sec.  63.10(e) and as defined in Sec.  63.90.

Sec.  63.7575  What definitions apply to this subpart?

    Terms used in this subpart are defined in the Clean Air Act, in 
Sec.  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 Sec.  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 
Sec.  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

[[Page 80651]]

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, 
sub-bituminous, or lignite by ASTM D388 (incorporated by reference, see 
Sec.  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 Sec.  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 one-third of 
its potential electric output capacity and more than 25 megawatts 
electrical output to any utility power distribution system for sale is 
considered an electric utility steam generating unit. To be ``capable 
of combusting'' fossil fuels, an EGU would need to have these fuels 
allowed in their operating permits and have the appropriate fuel 
handling facilities on-site or otherwise available (e.g., coal handling 
equipment, including coal storage area, belts and conveyers, 
pulverizers, etc.; oil storage facilities). In addition, fossil fuel-
fired EGU means any EGU that fired fossil fuel for more than 10.0 
percent of the average annual heat input in any 3 consecutive calendar 
years or for more than 15.0 percent of the annual heat input during any 
one calendar year after [COMPLIANCE DATE OF THE FINAL EGU RULE].
    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 air-conditioning systems; 
hot water systems; building envelop; and lighting.
    Equivalent means the following only as this term is used in Table 6 
to this subpart:

[[Page 80652]]

    (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, sub-bituminous 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, on-spec 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.

[[Page 80653]]

    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 Sec.  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. On-site gaseous fuel system emergencies or equipment 
failures qualify as periods of supply interruption when the emergency 
or failure is beyond the control of the facility.
    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 Sec.  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

[[Page 80654]]

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 Sec.  
63.14(b)).
    Responsible official means responsible official as defined in Sec.  
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:

[GRAPHIC] [TIFF OMITTED] TP23DE11.046

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:

[GRAPHIC] [TIFF OMITTED] TP23DE11.047

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:

[GRAPHIC] [TIFF OMITTED] TP23DE11.048

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:

[GRAPHIC] [TIFF OMITTED] TP23DE11.049

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:

[GRAPHIC] [TIFF OMITTED] TP23DE11.050

[[Page 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/bio-based 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 Voie-Creuse, 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

[[Page 80656]]

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 Sec.  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]
----------------------------------------------------------------------------------------------------------------
                                                      The emissions must
                                                        not exceed the     Or the emissions
If your boiler or process heater                      following emission    must not exceed       Using this
  is in this subcategory . . .     For the following    limits, except       the following    specified sampling
                                   pollutants . . .    during periods of  alternative output- volume or test run
                                                          startup and     based limits . . .    duration . . .
                                                        shutdown . . .
----------------------------------------------------------------------------------------------------------------
1. Units in all subcategories     a. Hydrogen         0.022 lb per MMBtu  0.025 lb per MMBtu  For M26A, collect
 designed to burn solid fuel.      Chloride.           of heat input.      of steam output     a minimum of 1
                                                                           or 0.28 lb per      dscm per run; for
                                                                           MWh.                M26 collect a
                                                                                               minimum of 120
                                                                                               liters per run
                                  b. Mercury........  8.60E-07 lb per     9.4E-07 lb per      For M29, collect a
                                                       MMBtu of heat       MMBtu of steam      minimum of 4 dscm
                                                       input.              output or 1.1 E-    per run; for M30A
                                                                           05 lb per MWh.      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        a. Carbon monoxide  9 ppm by volume on  0.0074 lb per       1 hr minimum
 designed to burn coal/solid       (CO) (or CEMS).     a dry basis         MMBtu of steam      sampling time,
 fossil fuel.                                          corrected to 3      output or 0.092     use a span value
                                                       percent oxygen, 3-  lb per MWh; 3-run   of 20 ppmv for
                                                       run average; or     average.            Method 10.
                                                       (28 ppm by volume
                                                       on a dry basis
                                                       corrected to 3
                                                       percent oxygen,
                                                       10-day rolling
                                                       average).
                                  b. Filterable       0.0013 lb per       0.0013 lb per       Collect a minimum
                                   Particulate         MMBtu of heat       MMBtu of steam      of 3 dscm per
                                   Matter (or Total    input; or (2.8E-    output or 0.016     run.
                                   Selected Metals).   05 \a\ lb per       lb per MWh; or
                                                       MMBtu of heat       (2.8E-05 \a\ lb
                                                       input).             per MMBtu of
                                                                           steam output or
                                                                           3.5E-04 \a\ lb
                                                                           per MWh).
3. Stokers designed to burn coal/ a. CO (or CEMS)...  19 ppm by volume    0.017 lb per MMBtu  1 hr minimum
 solid fossil fuel.                                    on a dry basis      of steam output     sampling time,
                                                       corrected to 3      or 0.20 lb per      use a span value
                                                       percent oxygen, 3-  MWh; 3-run          of 30 ppmv for
                                                       run average; or     average.            Method 10.
                                                       (34 ppm by volume
                                                       on a dry basis
                                                       corrected to 3
                                                       percent oxygen,
                                                       10-day rolling
                                                       average).

[[Page 80657]]

 
                                  b. Filterable       0.028 lb per MMBtu  0.028 lb per MMBtu  Collect a minimum
                                   Particulate         of heat input; or   of steam output     of 2 dscm per
                                   Matter (or Total    (2.2E-05 \a\ lb     or 0.35 lb per      run.
                                   Selected Metals).   per MMBtu of heat   MWh; or (3.0E-05
                                                       input).             \a\ lb per MMBtu
                                                                           of steam output
                                                                           or 2.7E-04 \a\ lb
                                                                           per MWh).
4. Fluidized bed units designed   a. CO (or CEMS)...  17 ppm by volume    0.015 lb per MMBtu  1 hr minimum
 to burn coal/solid fossil fuel.                       on a dry basis      of steam output     sampling time,
                                                       corrected to 3      or 0.18 lb per      use a span value
                                                       percent oxygen, 3-  MWh; 3-run          of 40 ppmv for
                                                       run average; or     average.            Method 10.
                                                       (59 ppm by volume
                                                       on a dry basis
                                                       corrected to 3
                                                       percent oxygen,
                                                       10-day rolling
                                                       average).
                                  b. Filterable       0.0011 lb per       0.0012 lb per       Collect a minimum
                                   Particulate         MMBtu of heat       MMBtu of steam      of 4 dscm per
                                   Matter (or Total    input; or (1.7E-    output or 0.014     run.
                                   Selected Metals).   05 \a\ lb per       lb per MWh; or
                                                       MMBtu of heat       (1.8E-05 \a\ lb
                                                       input).             per MMBtu of
                                                                           steam output or
                                                                           2.1E-04 \a\ lb
                                                                           per MWh).
5. Stokers/sloped grate/others    a. CO (or CEMS)...  590 ppm by volume   0.56 lb per MMBtu   1 hr minimum
 designed to burn wet biomass                          on a dry basis      of steam output     sampling time,
 fuel.                                                 corrected to 3      or 6.5 lb per       use a span value
                                                       percent oxygen, 3-  MWh; 3-run          of 600 ppmv for
                                                       run average; or     average.            Method 10.
                                                       (410 ppm by
                                                       volume on a dry
                                                       basis corrected
                                                       to 3 percent
                                                       oxygen, 10-day
                                                       rolling average).
                                  b. Filterable       0.029 lb per MMBtu  0.034 lb per MMBtu  Collect a minimum
                                   Particulate         of heat input; or   of steam output     of 2 dscm per
                                   Matter (or Total    (2.6E-05 lb per     or 0.41 lb per      run.
                                   Selected Metals).   MMBtu of heat       MWh; or (2.7E-05
                                                       input).             lb per MMBtu of
                                                                           steam output or
                                                                           3.7E-04 lb per
                                                                           MWh).
6. Stokers/sloped grate/others    a. CO.............  250 ppm by volume   0.23 lb per MMBtu   1 hr minimum
 designed to burn kiln-dried                           on a dry basis      of steam output     sampling time,
 biomass fuel.                                         corrected to 3      or 2.8 lb per MWh.  use a span value
                                                       percent oxygen.                         of 400 ppmv for
                                                                                               Method 10.
                                  b. Filterable       0.32 lb per MMBtu   0.37 lb per MMBtu   Collect a minimum
                                   Particulate         of heat input; or   of steam output     of 2 dscm per
                                   Matter (or Total    (4.0E-03 lb per     or 4.5 lb per       run.
                                   Selected Metals).   MMBtu of heat       MWh; or (4.2E-03
                                                       input).             lb per MMBtu of
                                                                           steam output or
                                                                           0.056 lb per MWh).
7. Fluidized bed units designed   a. CO (or CEMS)...  230 ppm by volume   0.22 lb per MMBtu   1 hr minimum
 to burn biomass/bio-based                             on a dry basis      of steam output     sampling time,
 solids.                                               corrected to 3      or 2.6 lb per       use a span value
                                                       percent oxygen, 3-  MWh; 3-run          of 400 ppmv for
                                                       run average; or     average.            Method 10.
                                                       (180 ppm by
                                                       volume on a dry
                                                       basis corrected
                                                       to 3 percent
                                                       oxygen, 10-day
                                                       rolling average).
                                  b. Filterable       0.0098 lb per       0.012 lb per MMBtu  Collect a minimum
                                   Particulate         MMBtu of heat       of steam output     of 3 dscm per
                                   Matter (or Total    input; or (4.2E-    or 0.14 lb per      run.
                                   Selected Metals).   05 \a\ lb per       MWh; or (5.4E-05
                                                       MMBtu of heat       \a\ lb per MMBtu
                                                       input).             of steam output
                                                                           or 5.9E-04 \a\ lb
                                                                           per MWh).

[[Page 80658]]

 
8. Suspension burners designed    a. CO (or CEMS)...  58 ppm by volume    0.046 lb per MMBtu  1 hr minimum
 to burn biomass/bio-based                             on a dry basis      of steam output     sampling time,
 solids.                                               corrected to 3      or 0.64 lb per      use a span value
                                                       percent oxygen, 3-  MWh; 3-run          of 100 ppmv for
                                                       run average; or     average.            Method 10.
                                                       (1,400 ppm by
                                                       volume on a dry
                                                       basis corrected
                                                       to 3 percent
                                                       oxygen, 10-day
                                                       rolling average).
                                  b. Filterable       0.051 lb per MMBtu  0.052 lb per MMBtu  Collect a minimum
                                   Particulate         of heat input; or   of steam output     of 1 dscm per
                                   Matter (or Total    (1.1E-03 lb per     or 0.71 lb per      run.
                                   Selected Metals).   MMBtu of heat       MWh; or (0.0012
                                                       input).             lb per MMBtu of
                                                                           steam output or
                                                                           0.016 lb per MWh).
9. Dutch Ovens/Pile burners       a. CO (or CEMS)...  810 ppm by volume   0.89 lb per MMBtu   1 hr minimum
 designed to burn biomass/bio-                         on a dry basis      of steam output     sampling time,
 based solids.                                         corrected to 3      or 8.9 lb per       use a span value
                                                       percent oxygen, 3-  MWh; 3-run          of 1000 ppmv for
                                                       run average; or     average.            Method 10.
                                                       (440 ppm by
                                                       volume on a dry
                                                       basis corrected
                                                       to 3 percent
                                                       oxygen, 10-day
                                                       rolling average).
                                  b. Filterable       0.036 lb per MMBtu  0.050 lb per MMBtu  Collect a minimum
                                   Particulate         of heat input; or   of steam output     of 1 dscm per
                                   Matter (or Total    (4.1E-05 lb per     or 0.51 lb per      run.
                                   Selected Metals).   MMBtu of heat       MWh; or (5.5E-05
                                                       input).             lb per MMBtu of
                                                                           steam output or
                                                                           5.8E-04 lb per
                                                                           MWh).
10. Fuel cell units designed to   a. CO.............  210 ppm by volume   0.29 lb per MMBtu   1 hr minimum
 burn biomass/bio-based solids.                        on a dry basis      of steam output     sampling time,
                                                       corrected to 3      or 2.3 lb per MWh.  use a span value
                                                       percent oxygen.                         of 500 ppmv for
                                                                                               Method 10.
                                  b. Filterable       0.011 lb per MMBtu  0.030 lb per MMBtu  Collect a minimum
                                   Particulate         of heat input; or   of steam output     of 1 dscm per
                                   Matter (or Total    (4.9E-05 \a\ lb     or 0.16 lb per      run.
                                   Selected Metals).   per MMBtu of heat   MWh; or (8.6E-05
                                                       input).             \a\ lb per MMBtu
                                                                           of steam output
                                                                           or 6.9E-04 \a\ lb
                                                                           per MWh).
11. Hybrid suspension grate       a. CO (or CEMS)...  1,500 ppm by        1.80 lb per MMBtu   1 hr minimum
 boiler designed to burn biomass/                      volume on a dry     of steam output     sampling time,
 bio-based solids.                                     basis corrected     or 17 lb per MWh;   use a span value
                                                       to 3 percent        3-run average.      of 3000 ppmv for
                                                       oxygen, 3-run                           Method 10.
                                                       average; or (730
                                                       ppm by volume on
                                                       a dry basis
                                                       corrected to 3
                                                       percent oxygen,
                                                       10-day rolling
                                                       average).
                                  b. Filterable       0.026 lb per MMBtu  0.033 lb per MMBtu  Collect a minimum
                                   Particulate         of heat input; or   of steam output     of 3 dscm per
                                   Matter (or Total    (4.9E-04 \a\ lb     or 0.37 lb per      run.
                                   Selected Metals).   per MMBtu of heat   MWh; or (6.2E-04
                                                       input).             \a\ lb per MMBtu
                                                                           of steam output
                                                                           or 6.9E-03 \a\ lb
                                                                           per MWh).
12. Units designed to burn        a. Hydrogen         0.0012 lb per       0.0013 lb per       For M26A: Collect
 liquid fuel.                      Chloride.           MMBtu of heat       MMBtu of steam      a minimum of 1
                                                       input.              output or 0.017     dscm per run; for
                                                                           lb per MWh.         M26, collect a
                                                                                               minimum of 120
                                                                                               liters per run.
                                  b. Mercury........  4.9E-07 \a\ lb per  5.4E-07 \a\ lb per  For M29, collect a
                                                       MMBtu of heat       MMBtu of steam      minimum of 4 dscm
                                                       input.              output or 6.8E-06   per run; for M30A
                                                                           \a\ lb per MWh.     or M30B, collect
                                                                                               a minimum sample
                                                                                               as specified in
                                                                                               the method; for
                                                                                               ASTM D6784 \b\
                                                                                               collect a minimum
                                                                                               of 4 dscm.

[[Page 80659]]

 
13. Units designed to burn heavy  a. CO (or CEMS)...  10 ppm by volume    0.0091 lb per       1 hr minimum
 liquid fuel.                                          on a dry basis      MMBtu of steam      sampling time,
                                                       corrected to 3      output or 0.11 lb   use a span value
                                                       percent oxygen, 3-  per MWh; 3-run      of 30 ppmv for
                                                       run average; or     average.            Method 10.
                                                       (18 ppm by volume
                                                       on a dry basis
                                                       corrected to 3
                                                       percent oxygen,
                                                       10-day rolling
                                                       average).
                                  b. Filterable       0.013 lb per MMBtu  0.015 lb per MMBtu  Collect a minimum
                                   Particulate         of heat input.      of steam output     of 2 dscm per
                                   Matter.                                 or 0.18 lb per      run.
                                                                           MWh.
14. Units designed to burn light  a. CO (or CEMS)...  3 ppm by volume on  0.0031 lb per       1 hr minimum
 liquid fuel.                                          a dry basis         MMBtu of steam      sampling time,
                                                       corrected to 3      output or 0.033     use a span value
                                                       percent oxygen;     lb per MWh.         of 10 ppmv for
                                                       or (60 ppm by                           Method 10.
                                                       volume on a dry
                                                       basis corrected
                                                       to 3 percent
                                                       oxygen, 1-day
                                                       block average).
                                  b. Filterable       0.0011 \a\ lb per   0.0015 \a\ lb per   Collect a minimum
                                   Particulate         MMBtu of heat       MMBtu of steam      of 3 dscm per
                                   Matter.             input for light     output or 0.016     run.
                                                       liquid.             lb per MWh.
15. Units designed to burn        a. CO.............  18 ppm by volume    0.017 lb per MMBtu  1 hr minimum
 liquid fuel located in non-                           on a dry basis      of steam output     sampling time,
 continental states and                                corrected to 3      or 0.20 lb per      use a span value
 territories.                                          percent oxygen, 3-  MWh; 3-run          of 40 ppmv for
                                                       run average based   average.            Method 10.
                                                       on stack test (91
                                                       ppm by volume on
                                                       a dry basis
                                                       corrected to 3
                                                       percent oxygen, 3-
                                                       hour rolling
                                                       average based on
                                                       CEM).
                                  b. Filterable       0.0080 lb per       0.0087 lb per       Collect a minimum
                                   Particulate         MMBtu of heat       MMBtu of steam      of 4 dscm per
                                   Matter.             input.              output or 0.11 lb   run.
                                                                           per MWh.
16. Units designed to burn gas 2  a. CO.............  4 ppm by volume on  0.005 lb per MMBtu  1 hr minimum
 (other) gases.                                        a dry basis         of steam output     sampling time,
                                                       corrected to 3      or 0.031 lb per     use a span value
                                                       percent oxygen.     MWh.                of 10 ppmv for
                                                                                               Method 10.
                                  b. Hydrogen         0.0017 lb per       0.0029 lb per       For M26A, Collect
                                   Chloride.           MMBtu of heat       MMBtu of steam      a minimum of 1
                                                       input.              output or 0.018     dscm per run; for
                                                                           lb per MWh.         M26, collect a
                                                                                               minimum of 120
                                                                                               liters per run.
                                  c. Mercury........  7.9E-06 lb per      1.4E-05 lb per      For M29, collect a
                                                       MMBtu of heat       MMBtu of steam      minimum of 3 dscm
                                                       input.              output or 8.3E-05   per run; for M30A
                                                                           lb per MWh.         or M30B, collect
                                                                                               a minimum sample
                                                                                               as specified in
                                                                                               the method; for
                                                                                               ASTM D6784 \b\
                                                                                               collect a minimum
                                                                                               of 3 dscm.
                                  d. Filterable       0.0067 lb per       0.012 lb per MMBtu  Collect a minimum
                                   Particulate         MMBtu of heat       of steam output     of 1 dscm per
                                   Matter (or Total    input; or (2.4E-    or 0.070 lb per     run.
                                   Selected Metals).   04 lb per MMBtu     MWh; or (4.0E-04
                                                       of heat input).     lb per MMBtu of
                                                                           steam output or
                                                                           0.0025 lb per
                                                                           MWh).
----------------------------------------------------------------------------------------------------------------
\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 Sec.   63.7515 if all of the other provision of Sec.   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 Sec.   63.14.

[[Page 80660]]

    As stated in Sec.  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]
----------------------------------------------------------------------------------------------------------------
                                                      The emissions must
                                                        not exceed the    The emissions must
If your boiler or process heater                      following emission    not exceed the        Using this
  is in this subcategory . . .     For the following    limits, except         following      specified sampling
                                   pollutants . . .    during periods of  alternative output- volume or test run
                                                          startup and     based limits . . .    duration . . .
                                                        shutdown . . .
----------------------------------------------------------------------------------------------------------------
1. Units in all subcategories     a. Hydrogen         0.022 lb per MMBtu  0.025 lb per MMBtu  For M26A, Collect
 designed to burn solid fuel.      Chloride.           of heat input.      of steam output     a minimum of 1
                                                                           or 0.28 lb per      dscm per run; for
                                                                           MWh.                M26, collect a
                                                                                               minimum of 120
                                                                                               liters per run.
                                  b. Mercury........  3.1E-06 lb per      3.5E-06 lb per      For M29, collect a
                                                       MMBtu of heat       MMBtu of steam      minimum of 3 dscm
                                                       input.              output or 4.0E-05   per run; for M30A
                                                                           lb per MWh.         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        a. CO (or CEMS)...  41 ppm by volume    0.035 lb per MMBtu  1 hr minimum
 designed to burn coal/solid                           on a dry basis      of steam output     sampling time,
 fossil fuel.                                          corrected to 3      or 0.42 lb per      use a span value
                                                       percent oxygen, 3-  MWh; 3-run          of 100 ppmv for
                                                       run average; or     average.            Method 10.
                                                       (28 ppm by volume
                                                       on a dry basis
                                                       corrected to 3
                                                       percent oxygen,
                                                       10-day rolling
                                                       average).
                                  b. Filterable       0.044 lb per MMBtu  0.045 lb per MMBtu  Collect a minimum
                                   Particulate         of heat input; or   of steam output     of 1 dscm per
                                   Matter (or Total    (5.9E-05 lb per     or 0.54 lb per      run.
                                   Selected Metals).   MMBtu of heat       MWh; or (6.0E-05
                                                       input).             lb per MMBtu of
                                                                           steam output or
                                                                           7.3E-04 lb per
                                                                           MWh).
3. Stokers designed to burn coal/ a. CO (or CEMS)...  220 ppm by volume   0.20 lb per MMBtu   1 hr minimum
 solid fossil fuel.                                    on a dry basis      of steam output     sampling time,
                                                       corrected to 3      or 2.3 lb per       use a span value
                                                       percent oxygen, 3-  MWh; 3-run          of 400 ppmv for
                                                       run average; or     average.            Method 10.
                                                       (34 ppm by volume
                                                       on a dry basis
                                                       corrected to 3
                                                       percent oxygen,
                                                       10-day rolling
                                                       average).
                                  b. Filterable       0.028 lb per MMBtu  0.030 lb per MMBtu  Collect a minimum
                                   Particulate         of heat input; or   of steam output     of 2 dscm per
                                   Matter (or Total    (8.3E-05 lb per     or 0.35 lb per      run.
                                   Selected Metals).   MMBtu of heat       MWh; or (8.8E-05
                                                       input).             lb per MMBtu of
                                                                           steam output or
                                                                           0.0011 lb per
                                                                           MWh).
4. Fluidized bed units designed   a. CO (or CEMS)...  56 ppm by volume    0.049 lb per MMBtu  1 hr minimum
 to burn coal/solid fossil fuel.                       on a dry basis      of steam output     sampling time,
                                                       corrected to 3      or 0.57 lb per      use a span value
                                                       percent oxygen, 3-  MWh; 3-run          of 100 ppmv for
                                                       run average; or     average.            Method 10.
                                                       (59 ppm by volume
                                                       on a dry basis
                                                       corrected to 3
                                                       percent oxygen,
                                                       10-day rolling
                                                       average).
                                  b. Filterable       0.088 lb per MMBtu  0.092 lb per MMBtu  Collect a minimum
                                   Particulate         of heat input; or   of steam output     of 1 dscm per
                                   Matter (or Total    (1.7E-05 lb per     or 1.1 lb per       run.
                                   Selected Metals).   MMBtu of heat       MWh; or (1.8E-05
                                                       input).             lb per MMBtu of
                                                                           steam output or
                                                                           2.1E-04 lb per
                                                                           MWh).

[[Page 80661]]

 
5. Stokers/sloped grate/others    a. CO (or CEMS)...  790 ppm by volume   0.72 lb per MMBtu   1 hr minimum
 designed to burn wet biomass                          on a dry basis      of steam output     sampling time,
 fuel.                                                 corrected to 3      or 8.7 lb per       use a span value
                                                       percent oxygen, 3-  MWh; 3-run          of 1000 ppmv for
                                                       run average; or     average.            Method 10.
                                                       (410 ppm by
                                                       volume on a dry
                                                       basis corrected
                                                       to 3 percent
                                                       oxygen, 10-day
                                                       rolling average).
                                  b. Filterable       0.029 lb per MMBtu  0.034 lb per MMBtu  Collect a minimum
                                   Particulate         of heat input; or   of steam output     of 2 dscm per
                                   Matter (or Total    (5.7E-05 lb per     or 0.41 lb per      run.
                                   Selected Metals).   MMBtu of heat       MWh; or (6.6E-05
                                                       input).             lb per MMBtu of
                                                                           steam output or
                                                                           8.0E-04 lb per
                                                                           MWh).
6. Stokers/sloped grate/others    a. CO.............  250 ppm by volume   0.23 lb per MMBtu   1 hr minimum
 designed to burn kiln-dried                           on a dry basis      of steam output     sampling time,
 biomass fuel.                                         corrected to 3      or 2.8 lb per MWh.  use a span value
                                                       percent oxygen.                         of 500 ppmv for
                                                                                               Method 10.
                                  b. Filterable       0.32 lb per MMBtu   0.37 lb per MMBtu   Collect a minimum
                                   Particulate         of heat input; or   of steam output     of 1 dscm per
                                   Matter (or Total    (4.0E-03 lb per     or 4.5 lb per       run.
                                   Selected Metals).   MMBtu of heat       MWh; or (0.0046
                                                       input).             lb per MMBtu of
                                                                           steam output or
                                                                           0.056 lb per MWh).
7. Fluidized bed units designed   a. CO (or CEMS)...  370 ppm by volume   0.36 lb per MMBtu   1 hr minimum
 to burn biomass/bio-based solid.                      on a dry basis      of steam output     sampling time,
                                                       corrected to 3      or 4.1 lb per       use a span value
                                                       percent oxygen, 3-  MWh; 3-run          of 500 ppmv for
                                                       run average; or     average.            Method 10.
                                                       (180 ppm by
                                                       volume on a dry
                                                       basis corrected
                                                       to 3 percent
                                                       oxygen, 10-day
                                                       rolling average).
                                  b. Filterable       0.11 lb per MMBtu   0.14 lb per MMBtu   Collect a minimum
                                   Particulate         of heat input; or   of steam output     of 1 dscm per
                                   Matter (or Total    (0.0012 lb per      or 1.6 lb per       run.
                                   Selected Metals).   MMBtu of heat       MWh; or (0.0015
                                                       input).             lb per MMBtu of
                                                                           steam output or
                                                                           0.017 lb per MWh).
8. Suspension burners designed    a. CO (or CEMS)...  58 ppm by volume    0.046 lb per MMBtu  1 hr minimum
 to burn biomass/bio-based solid.                      on a dry basis      of steam output     sampling time,
                                                       corrected to 3      or 0.64 lb per      use a span value
                                                       percent oxygen, 3-  MWh; 3-run          of 100ppmv for
                                                       run average; or     average.            Method 10.
                                                       (1,400 ppm by
                                                       volume on a dry
                                                       basis corrected
                                                       to 3 percent
                                                       oxygen, 10-day
                                                       rolling average).
                                  b. Filterable       0.051 lb per MMBtu  0.052 lb per MMBtu  Collect a minimum
                                   Particulate         of heat input; or   of steam output     of 1 dscm per
                                   Matter (or Total    (0.0011 lb per      or 0.71 lb per      run.
                                   Selected Metals).   MMBtu of heat       MWh; or (0.0012
                                                       input).             lb per MMBtu of
                                                                           steam output or
                                                                           0.016 lb per MWh).
9. Dutch Ovens/Pile burners       a. CO (or CEMS)...  810 ppm by volume   0.89 lb per MMBtu   1 hr minimum
 designed to burn biomass/bio-                         on a dry basis      of steam output     sampling time,
 based solid.                                          corrected to 3      or 8.9 lb per       use a span value
                                                       percent oxygen, 3-  MWh; 3-run          of 1000 ppmv for
                                                       run average; or     average.            Method 10.
                                                       (440 ppm by
                                                       volume on a dry
                                                       basis corrected
                                                       to 3 percent
                                                       oxygen, 10-day
                                                       rolling average).

[[Page 80662]]

 
                                  b. Filterable       0.036 lb per MMBtu  0.050 lb per MMBtu  Collect a minimum
                                   Particulate         of heat input; or   of steam output     of 1 dscm per
                                   Matter (or Total    (2.4E-04 lb per     or 0.51 lb per      run.
                                   Selected Metals).   MMBtu of heat       MWh; or (3.4E-04
                                                       input).             lb per MMBtu of
                                                                           steam output or
                                                                           0.0034 lb per
                                                                           MWh).
10. Fuel cell units designed to   a. CO.............  1,500 ppm by        3.2 lb per MMBtu    1 hr minimum
 burn biomass/bio-based solid.                         volume on a dry     of steam output     sampling time,
                                                       basis corrected     or 17 lb per MWh.   use a span value
                                                       to 3 percent                            of 2000 ppmv for
                                                       oxygen.                                 Method 10.
                                  b. Filterable       0.033 lb per MMBtu  0.090 lb per MMBtu  Collect a minimum
                                   Particulate         of heat input; or   of steam output     of 1 dscm per
                                   Matter (or Total    (4.9E-05 lb per     or 0.46 lb per      run.
                                   Selected Metals).   MMBtu of heat       MWh; or (1.4E-04
                                                       input).             lb per MMBtu of
                                                                           steam output or
                                                                           6.9E-04 lb per
                                                                           MWh).
11. Hybrid suspension grate       a. CO (or CEMS)...  3,900 ppm by        3.9 lb per MMBtu    1 hr minimum
 units designed to burn biomass/                       volume on a dry     of steam output     sampling time,
 bio-based solid.                                      basis corrected     or 43 lb per MWh;   use a span value
                                                       to 3 percent        3-run average.      of 5000 ppmv for
                                                       oxygen, 3-run                           Method 10.
                                                       average; or (730
                                                       ppm by volume on
                                                       a dry basis
                                                       corrected to 3
                                                       percent oxygen,
                                                       10-day rolling
                                                       average).
                                  b. Filterable       0.44 lb per MMBtu   0.55 lb per MMBtu   Collect a minimum
                                   Particulate         of heat input; or   of steam output     of 1 dscm per
                                   Matter (or Total    (4.9E-04\a\ lb      or 6.2 lb per       run.
                                   Selected Metals).   per MMBtu of heat   MWh; or (6.2E-
                                                       input).             04\a\ lb per
                                                                           MMBtu of steam
                                                                           output or 6.9E-
                                                                           03\a\ lb per MWh).
12. Units designed to burn        a. Hydrogen         0.0012 lb per       0.0015 lb per       For M26A, collect
 liquid fuel.                      Chloride.           MMBtu of heat       MMBtu of steam      a minimum of 1
                                                       input.              output or 0.017     dscm per run; for
                                                                           lb per MWh.         M26, collect a
                                                                                               minimum of 120
                                                                                               liters per run.
                                  b. Mercury........  2.6E-05 lb per      3.3E-05 lb per      For M29, collect a
                                                       MMBtu of heat       MMBtu of steam      minimum of 2 dscm
                                                       input.              output or 3.6E-04   per run; for M30A
                                                                           lb per MWh.         or M30B collect a
                                                                                               minimum sample as
                                                                                               specified in the
                                                                                               method, for ASTM
                                                                                               D6784\b\ collect
                                                                                               a minimum of 2
                                                                                               dscm.
13. Units designed to burn heavy  a. CO (or CEMS)...  10 ppm by volume    0.0091 lb per       1 hr minimum
 liquid fuel.                                          on a dry basis      MMBtu of steam      sampling time,
                                                       corrected to 3      output or 0.11 lb   use a span value
                                                       percent oxygen, 3-  per MWh; 3-run      of 20 ppmv for
                                                       run average; or     average.            Method 10.
                                                       (18 ppm by volume
                                                       on a dry basis
                                                       corrected to 3
                                                       percent oxygen,
                                                       10-day rolling
                                                       average).
                                  b. Filterable       0.062 lb per MMBtu  0.075 lb per MMBtu  Collect a minimum
                                   Particulate         of heat input.      of steam output     of 1 dscm per
                                   Matter.                                 or 0.86 lb per      run.
                                                                           MWh.
14. Units designed to burn light  a. CO (or CEMS)...  7 ppm by volume on  0.0071 lb per       1 hr minimum
 liquid fuel.                                          a dry basis         MMBtu of steam      sampling time,
                                                       corrected to 3      output or 0.076     use a span value
                                                       percent oxygen;     lb per MWh.         of 10 ppmv for
                                                       or (60 ppm by                           Method 10.
                                                       volume on a dry
                                                       basis corrected
                                                       to 3 percent
                                                       oxygen, 1-day
                                                       block average).
                                  b. Filterable       0.0034 lb per       0.0045 lb per       Collect a minimum
                                   Particulate         MMBtu of heat       MMBtu of steam      of 3 dscm per
                                   Matter.             input.              output or 0.047     run.
                                                                           lb per MWh.

[[Page 80663]]

 
15. Units designed to burn        a. CO (or CEMS)...  18 ppm by volume    0.017 lb per MMBtu  1 hr minimum
 liquid fuel located in non-                           on a dry basis      of steam output     sampling time,
 continental states and                                corrected to 3      or 0.20 lb per      use a span value
 territories.                                          percent oxygen, 3-  MWh; 3-run          of 40 ppmv for
                                                       run average based   average.            Method 10.
                                                       on stack test (91
                                                       ppm by volume on
                                                       a dry basis
                                                       corrected to 3
                                                       percent oxygen, 3-
                                                       hour rolling
                                                       average based on
                                                       CEM).
                                  b. Filterable       0.0080 lb per       0.0097 lb per       Collect a minimum
                                   Particulate         MMBtu of heat       MMBtu of steam      of 2 dscm per
                                   Matter.             input.              output or 0.11 lb   run.
                                                                           per MWh.
16. Units designed to burn gas 2  a. CO.............  4 ppm by volume on  0.0050 lb per       1 hr minimum
 (other) gases.                                        a dry basis         MMBtu of steam      sampling time,
                                                       corrected to 3      output or 0.031     use a span value
                                                       percent oxygen.     lb per MWh.         of 10 ppmv for
                                                                                               Method 10.
                                  b. Hydrogen         0.0017 lb per       0.0029 lb per       For M26A, collect
                                   Chloride.           MMBtu of heat       MMBtu of steam      a minimum of 1
                                                       input.              output or 0.018     dscm per run; for
                                                                           lb per MWh.         M26, collect a
                                                                                               minimum of 120
                                                                                               liters per run.
                                  c. Mercury........  7.9E-06 lb per      1.4E-05 lb per      For M29, collect a
                                                       MMBtu of heat       MMBtu of steam      minimum of 2 dscm
                                                       input.              output or 8.3E-05   per run; for M30A
                                                                           lb per MWh.         or M30B, collect
                                                                                               a minimum sample
                                                                                               as specified in
                                                                                               the method; for
                                                                                               ASTM D6784 \b\
                                                                                               collect a minimum
                                                                                               of 2 dscm.
                                  d. Filterable       0.0067 lb per       0.012 lb per MMBtu  Collect a minimum
                                   Particulate         MMBtu of heat       of steam output     of 1 dscm per
                                   Matter (or Total    input or (2.4E-04   or 0.070 lb per     run.
                                   Selected Metals).   lb per MMBtu of     MWh; or (4.0E-04
                                                       heat input).        lb per MMBtu of
                                                                           steam output or
                                                                           0.0025 lb per
                                                                           MWh).
----------------------------------------------------------------------------------------------------------------
\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 Sec.   63.7515 if all of the other provisions of Sec.   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 Sec.   63.14.

    As stated in Sec.  63.7500, you must comply with the following 
applicable work practice standards:

      Table 3--to Subpart DDDDD of Part 63--Work Practice Standards
------------------------------------------------------------------------
                                         You must meet the following . .
         If your unit is . . .                          .
------------------------------------------------------------------------
1. A new or existing boiler or process   Conduct a tune-up of the boiler
 heater with heat input capacity of       or process heater every 5
 less than 5 million Btu per hour in      years as specified in Sec.
 any of the following subcategories:      63.7540.
 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.
2. A limited use boiler or process       Conduct a tune-up of the boiler
 heater; or a new or existing boiler or   or process heater biennially
 process heater with heat input           as specified in Sec.
 capacity of less than 10 million Btu     63.7540.
 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.

[[Page 80664]]

 
3. A new or existing boiler or process   Conduct a tune-up of the boiler
 heater with heat input capacity of 10    or process heater annually as
 million Btu per hour or greater.         specified in Sec.   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  Must have a one-time energy
 located at a major source facility.      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    You must employ good combustion
 emission limits in Tables 1 or 2 to      practices and demonstrate that
 this subpart.                            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 Sec.  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   You must meet these operating limits . .
         using . . .                               .
------------------------------------------------------------------------
1. Wet PM scrubber control on  Maintain the 30-day rolling average
 a boiler not using a PM CPMS.  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 Sec.
                                63.7530(b) and Table 7 to this subpart.
2. Wet acid gas (HCl)          Maintain the 30-day rolling average
 scrubber control on a boiler   effluent pH at or above the lowest one-
 not using a hydrogen           hour average pH and the 30-day rolling
 chloride CEMS.                 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 Sec.
                                63.7530(b) and Table 7 to this subpart.
3. Fabric filter control on    a. Maintain opacity to less than or equal
 units not using a PM CPMS.     to 10 percent opacity (daily block
                                average); or
                               b. Install and operate a bag leak
                                detection system according to Sec.
                                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  a. This option is for boilers and process
 control on units not using a   heaters that operate dry control systems
 PM CPMS.                       (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 Sec.
                                63.7530(b) and Table 7 to this subpart.

[[Page 80665]]

 
5. Dry scrubber or carbon      Maintain the minimum sorbent or carbon
 injection control on a         injection rate as defined in Sec.
 boiler not using a mercury     63.7575 of this subpart.
 CEMS.
6. Any other add-on air        This option is for boilers and process
 pollution control type on      heaters that operate dry control
 units not using a PM CPMS.     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 Sec.
                                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 Sec.
                                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 Sec.  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          Method 1 at 40 CFR
                                 sampling ports     part 60, appendix A-
                                 location and the   1 of this chapter.
                                 number of
                                 traverse points.
                                b. Determine       Method 2, 2F, or 2G
                                 velocity and       at 40 CFR part 60,
                                 volumetric flow-   appendix A-1 or A-2
                                 rate of the        to part 60 of this
                                 stack gas.         chapter.
                                c. Determine       Method 3A or 3B at 40
                                 oxygen or carbon   CFR part 60,
                                 dioxide            appendix A-2 to part
                                 concentration of   60 of this chapter,
                                 the stack gas.     or ANSI/ASME PTC
                                                    19.10-1981.\a\
                                d. Measure the     Method 4 at 40 CFR
                                 moisture content   part 60, appendix A-
                                 of the stack gas.  3 of this chapter.
                                e. Measure the     Method 5 or 17
                                 particulate        (positive pressure
                                 matter emission    fabric filters must
                                 concentration.     use Method 5D) at 40
                                                    CFR part 60,
                                                    appendix A-3 or A-6
                                                    of this chapter.
                                f. Convert         Method 19 F-factor
                                 emissions          methodology at 40
                                 concentration to   CFR part 60,
                                 lb per MMBtu       appendix A-7 of this
                                 emission rates.    chapter.
2. Hydrogen chloride..........  a. Select          Method 1 at 40 CFR
                                 sampling ports     part 60, appendix A-
                                 location and the   1 of this chapter.
                                 number of
                                 traverse points.
                                b. Determine       Method 2, 2F, or 2G
                                 velocity and       at 40 CFR part 60,
                                 volumetric flow-   appendix A-2 of this
                                 rate of the        chapter.
                                 stack gas.
                                c. Determine       Method 3A or 3B at 40
                                 oxygen or carbon   CFR part 60,
                                 dioxide            appendix A-2 of this
                                 concentration of   chapter, or ANSI/
                                 the stack gas.     ASME PTC 19.10-
                                                    1981.\a\
                                d. Measure the     Method 4 at 40 CFR
                                 moisture content   part 60, appendix A-
                                 of the stack gas.  3 of this chapter.
                                e. Measure the     Method 26 or 26A (M26
                                 hydrogen           or M26A) at 40 CFR
                                 chloride           part 60, appendix A-
                                 emission           8 of this chapter.
                                 concentration.
                                f. Convert         Method 19 F-factor
                                 emissions          methodology at 40
                                 concentration to   CFR part 60,
                                 lb per MMBtu       appendix A-7 of this
                                 emission rates.    chapter.
3. Mercury....................  a. Select          Method 1 at 40 CFR
                                 sampling ports     part 60, appendix A-
                                 location and the   1 of this chapter.
                                 number of
                                 traverse points.
                                b. Determine       Method 2, 2F, or 2G
                                 velocity and       at 40 CFR part 60,
                                 volumetric flow-   appendix A-1 or A-2
                                 rate of the        of this chapter.
                                 stack gas.
                                c. Determine       Method 3A or 3B at 40
                                 oxygen or carbon   CFR part 60,
                                 dioxide            appendix A-1 of this
                                 concentration of   chapter, or ANSI/
                                 the stack gas.     ASME PTC 19.10-
                                                    1981.\a\
                                d. Measure the     Method 4 at 40 CFR
                                 moisture content   part 60, appendix A-
                                 of the stack gas.  3 of this chapter.
                                e. Measure the     Method 29, 30A, or
                                 mercury emission   30B (M29, M30A, or
                                 concentration.     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         Method 19 F-factor
                                 emissions          methodology at 40
                                 concentration to   CFR part 60,
                                 lb per MMBtu       appendix A-7 of this
                                 emission rates.    chapter.
4. CO.........................  a. Select the      Method 1 at 40 CFR
                                 sampling ports     part 60, appendix A-
                                 location and the   1 of this chapter.
                                 number of
                                 traverse points.
                                b. Determine       Method 3A or 3B at 40
                                 oxygen             CFR part 60,
                                 concentration of   appendix A-3 of this
                                 the stack gas.     chapter, or ASTM
                                                    D6522-00 (Reapproved
                                                    2005), or ANSI/ASME
                                                    PTC 19.10-1981.\a\
                                c. Measure the     Method 4 at 40 CFR
                                 moisture content   part 60, appendix A-
                                 of the stack gas.  3 of this chapter.

[[Page 80666]]

 
                                d. Measure the CO  Method 10 at 40 CFR
                                 emission           part 60, appendix A-
                                 concentration.     4 of this chapter.
                                                    Use a span value of
                                                    2 times the
                                                    concentration of the
                                                    applicable emission
                                                    limit.
------------------------------------------------------------------------
\a\ Incorporated by reference, see Sec.   63.14.

    As stated in Sec.  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 Sec.  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       Procedure in Sec.
                               samples.              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     Procedure in Sec.
                               samples.              63.7521(d) or
                                                     equivalent.
                              c. Prepare            EPA SW-846-3050B \a\
                               composited fuel       (for solid
                               samples.              samples), EPA SW-
                                                     846-3020A \a\ (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     ASTM D5865 \a\ (for
                               content of the fuel   coal) or ASTM E711
                               type.                 \a\ (for biomass),
                                                     or ASTM D5864 for
                                                     liquids and other
                                                     solids, or ASTM
                                                     D240 or equivalent.
                              e. Determine          ASTM D3173 \a\, ASTM
                               moisture content of   E871 \a\, or ASTM
                               the fuel type.        D5864, or ASTM D240
                                                     or equivalent.
                              f. Measure mercury    ASTM D6722 \a\ (for
                               concentration in      coal), EPA SW-846-
                               fuel sample.          7471B \a\ (for
                                                     solid samples), or
                                                     EPA SW-846-7470A
                                                     \a\ (for liquid
                                                     samples), or
                                                     equivalent.
                              g. Convert            Equation 8 in Sec.
                               concentration into    63.7530.
                               units of pounds of
                               mercury per MMBtu
                               of heat content.
                              h. Calculate the      Equations 10 and 12
                               mercury emission      in Sec.   63.7530.
                               rate from the
                               boiler or process
                               heater in units of
                               pounds per million
                               Btu.
2. Hydrogen Chloride........  a. Collect fuel       Procedure in Sec.
                               samples.              63.7521(c) or ASTM
                                                     D2234/D2234M \a\
                                                     (for coal) or ASTM
                                                     D6323 \a\ (for coal
                                                     or biomass), or
                                                     equivalent.
                              b. Composite fuel     Procedure in Sec.
                               samples.              63.7521(d) or
                                                     equivalent.
                              c. Prepare            EPA SW-846-3050B \a\
                               composited fuel       (for solid
                               samples.              samples), EPA SW-
                                                     846-3020A \a\ (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     ASTM D5865 \a\ (for
                               content of the fuel   coal) or ASTM E711
                               type.                 \a\ (for biomass),
                                                     ASTM D5864, ASTM
                                                     D240 or equivalent.
                              e. Determine          ASTM D3173 \a\ or
                               moisture content of   ASTM E871 \a\, or
                               the fuel type.        D5864, or ASTM D240
                                                     or equivalent.
                              f. Measure chlorine   EPA SW-846-9250 \a\,
                               concentration in      ASTM D6721 \a\,
                               fuel sample.          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            Equation 7 in Sec.
                               concentrations into   63.7530.
                               units of pounds of
                               hydrogen chloride
                               per MMBtu of heat
                               content.
                              h. Calculate the      Equations 10 and 11
                               hydrogen chloride     in Sec.   63.7530.
                               emission rate from
                               the boiler or
                               process heater in
                               units of pounds per
                               million Btu.
3. Mercury Fuel               a. Measure mercury    ASTM D5954 \a\, ASTM
 Specification for other gas   concentration in      D6350 \a\, ISO 6978-
 1 fuels.                      the fuel sample and   1:2003(E) \a\, or
                               convert to units of   ISO 6978-2:2003(E)
                               micrograms per        \a\, or equivalent.
                               cubic meter.
4. Total Selected Metals for  a. Collect fuel       Procedure in Sec.
 solid fuels.                  samples.              63.7521(c) or ASTM
                                                     D2234/D2234M \a\
                                                     (for coal) or ASTM
                                                     D6323 \a\ (for coal
                                                     or biomass), or
                                                     equivalent.
                              b. Composite fuel     Procedure in Sec.
                               samples.              63.7521(d) or
                                                     equivalent.

[[Page 80667]]

 
                              c. Prepare            EPA SW-846-3050B \a\
                               composited fuel       (for solid
                               samples.              samples), EPA SW-
                                                     846-3020A \a\ (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     ASTM D5865 \a\ (for
                               content of the fuel   coal) or ASTM E711
                               type.                 \a\ (for biomass),
                                                     or ASTM D5864 for
                                                     liquids and other
                                                     solids, or ASTM
                                                     D240 or equivalent.
                              e. Determine          ASTM D3173 \a\ or
                               moisture content of   ASTM E871 \a\, or
                               the fuel type.        D5864, or ASTM D240
                                                     or equivalent.
                              f. Measure total      ASTM D3683, or ASTM
                               selected metals       D4606, or ASTM
                               concentration in      D6357 or EPA 200.8
                               fuel sample.          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            Equations 9 in Sec.
                               concentrations into    63.7530.
                               units of pounds of
                               total selected
                               metals per MMBtu of
                               heat content.
                              h. Calculate the      Equations 10 and 13
                               total selected        in Sec.   63.7530.
                               metals emission
                               rate from the
                               boiler or process
                               heater in units of
                               pounds per million
                               Btu.
------------------------------------------------------------------------
 \a\ Incorporated by reference, see Sec.   63.14.

    As stated in Sec.  63.7520, you must comply with the following 
requirements for establishing operating limits:

                       Table 7--to Subpart DDDDD of Part 63--Establishing Operating Limits
----------------------------------------------------------------------------------------------------------------
                                  And your operating                                           According to the
    If you have an applicable      limits are based     You must . . .        Using . . .          following
    emission limit for . . .           on . . .                                               requirements . . .
----------------------------------------------------------------------------------------------------------------
1. Particulate matter, total      a. Wet scrubber     i. Establish a      (1) Data from the   (a) You must
 selected metals, or mercury.      operating           site-specific       scrubber pressure   collect scrubber
                                   parameters.         minimum scrubber    drop and liquid     pressure drop and
                                                       pressure drop and   flow rate           liquid flow rate
                                                       minimum flow rate   monitors and the    data every 15
                                                       operating limit     particulate         minutes during
                                                       according to Sec.   matter or mercury   the entire period
                                                         63.7530(b).       performance test.   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    i. Establish a      (1) Data from the   (a) You must
                                   precipitator        site-specific       voltage and         collect secondary
                                   operating           minimum total       secondary           voltage and
                                   parameters          secondary           amperage monitors   secondary
                                   (option only for    electric power      during the          amperage for each
                                   units that          input according     particulate         ESP cell and
                                   operate wet         to Sec.             matter or mercury   calculate total
                                   scrubbers).         63.7530(b).         performance test.   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     i. Establish site-  (1) Data from the   (a) You must
                                   operating           specific minimum    pressure drop,      collect pH and
                                   parameters.         pressure drop,      pH, and liquid      liquid flow-rate
                                                       effluent pH, and    flow-rate           data every 15
                                                       flow rate           monitors and the    minutes during
                                                       operating limits    hydrogen chloride   the entire period
                                                       according to Sec.   performance test.   of the
                                                         63.7530(b).                           performance
                                                                                               tests.

[[Page 80668]]

 
                                                                                              (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     i. Establish a      (1) Data from the   (a) You must
                                   operating           site-specific       sorbent injection   collect sorbent
                                   parameters.         minimum sorbent     rate monitors and   injection rate
                                                       injection rate      hydrogen chloride   data every 15
                                                       operating limit     or mercury          minutes during
                                                       according to Sec.   performance test.   the entire period
                                                         63.7530(b) If                         of the
                                                       different acid                          performance
                                                       gas sorbents are                        tests.
                                                       used during the
                                                       hydrogen chloride
                                                       performance test,
                                                       the average value
                                                       for each sorbent
                                                       becomes the site-
                                                       specific
                                                       operating limit
                                                       for that sorbent.
                                                                                              (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        i. Establish a      (1) Data from the   (a) You must
                                   carbon injection.   site-specific       activated carbon    collect activated
                                                       minimum activated   rate monitors and   carbon injection
                                                       carbon injection    mercury             rate data every
                                                       rate operating      performance test.   15 minutes during
                                                       limit according                         the entire period
                                                       to Sec.                                 of the
                                                       63.7530(b).                             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.

[[Page 80669]]

 
                                                                                              (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      (1) Data from the   (a) You must
                                                       unit-specific       oxygen analyzer     collect oxygen
                                                       limit for minimum   system specified    data every 15
                                                       oxygen level        in Sec.             minutes during
                                                       according to Sec.   63.7525(a).         the entire period
                                                         63.7520.                              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        a. Boiler or        i. Establish a      (1) Data from the   (a) You must
 compliance is demonstrated by a   process heater      unit specific       operating load      collect operating
 performance test.                 operating load.     limit for maximum   monitors or from    load or steam
                                                       operating load      steam generation    generation data
                                                       according to Sec.   monitors.           every 15 minutes
                                                         63.7520(c).                           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 Sec.  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       You must demonstrate continuous
work practice standards . . .             compliance by . . .
------------------------------------------------------------------------
1. Opacity...................  a. Collecting the opacity monitoring
                                system data according to Sec.
                                63.7525(c) and Sec.   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 Sec.   63.7525;

[[Page 80670]]

 
                               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 Sec.
                                63.7530.
3. Fabric Filter Bag Leak      Installing and operating a bag leak
 Detection Operation.           detection system according to Sec.
                                63.7525 and operating the fabric filter
                                such that the requirements in Sec.
                                63.7540(a)(9) are met.
4. Wet Scrubber Pressure Drop  a. Collecting the pressure drop and
 and Liquid Flow-rate.          liquid flow rate monitoring system data
                                according to Sec.  Sec.   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
                                Sec.   63.7530(b).
5. Wet Scrubber pH...........  a. Collecting the pH monitoring system
                                data according to Sec.  Sec.   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 Sec.   63.7530(b).
6. Dry Scrubber Sorbent or     a. Collecting the sorbent or carbon
 Carbon Injection Rate.         injection rate monitoring system data
                                for the dry scrubber according to Sec.
                                Sec.   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 Sec.
                                63.7575.
7. Electrostatic Precipitator  a. Collecting the total secondary
 Total Secondary Electric       electric power input monitoring system
 Power Input.                   data for the electrostatic precipitator
                                according to Sec.  Sec.   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 Sec.   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 Sec.   63.7530(b) or (c) as
                                applicable; and
                               b. Keeping monthly records of fuel use
                                according to Sec.   63.7540(a).
9. Oxygen content............  a. Continuously monitor the oxygen
                                content using an oxygen trim system
                                according to Sec.   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 Sec.   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 non-
                                continental 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   a. Collecting operating load data or
 operating load.                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 Sec.   63.7520(c).
------------------------------------------------------------------------

    As stated in Sec.  63.7550, you must comply with the following 
requirements for reports:

      Table 9--to Subpart DDDDD of Part 63--Reporting Requirements
------------------------------------------------------------------------
                                    The report must      You must submit
     You must submit a(n)            contain . . .      the report . . .
------------------------------------------------------------------------
1. Compliance report..........  a. Information          Semiannually,
                                 required in Sec.        annually,
                                 63.7550(c)(1) through   biennially, or
                                 (12); and.              every 5 years
                                                         according to
                                                         the
                                                         requirements in
                                                         Sec.
                                                         63.7550(b).

[[Page 80671]]

 
                                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 Sec.   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
                                 Sec.   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 Sec.   63.8(c)(7),
                                 or otherwise not
                                 operating, the report
                                 must contain the
                                 information in Sec.
                                 63.7550(e).
------------------------------------------------------------------------

    As stated in Sec.  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
------------------------------------------------------------------------
                                                      Applies to subpart
            Citation                    Subject              DDDDD
------------------------------------------------------------------------
Sec.   63.1.....................  Applicability.....  Yes.
Sec.   63.2.....................  Definitions.......  Yes. Additional
                                                       terms defined in
                                                       Sec.   63.7575.
Sec.   63.3.....................  Units and           Yes.
                                   Abbreviations.
Sec.   63.4.....................  Prohibited          Yes.
                                   Activities and
                                   Circumvention.
Sec.   63.5.....................  Preconstruction     Yes.
                                   Review and
                                   Notification
                                   Requirements.
Sec.   63.6(a), (b)(1)-(b)(5),    Compliance with     Yes.
 (b)(7), (c).                      Standards and
                                   Maintenance
                                   Requirements.
Sec.   63.6(e)(1)(i)............  General duty to     No. See Sec.
                                   minimize            63.7500(a)(3) for
                                   emissions..         the general duty
                                                       requirement.
Sec.   63.6(e)(1)(ii)...........  Requirement to      No.
                                   correct
                                   malfunctions as
                                   soon as
                                   practicable.
Sec.   63.6(e)(3)...............  Startup, shutdown,  No.
                                   and malfunction
                                   plan requirements.
Sec.   63.6(f)(1)...............  Startup, shutdown,  No.
                                   and malfunction
                                   exemptions for
                                   compliance with
                                   non-opacity
                                   emission
                                   standards.
Sec.   63.6(f)(2) and (3).......  Compliance with     Yes.
                                   non-opacity
                                   emission
                                   standards.
Sec.   63.6(g)..................  Use of alternative  Yes.
                                   standards.
Sec.   63.6(h)(1)...............  Startup, shutdown,  No. See Sec.
                                   and malfunction     63.7500(a).
                                   exemptions to
                                   opacity standards.
Sec.   63.6(h)(2) to (h)(9).....  Determining         Yes.
                                   compliance with
                                   opacity emission
                                   standards.
Sec.   63.6(i)..................  Extension of        Yes. Facilities
                                   compliance.         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.
Sec.   63.6(j)..................  Presidential        Yes.
                                   exemption.
Sec.   63.7(a), (b), (c), and     Performance         Yes.
 (d).                              Testing
                                   Requirements.
Sec.   63.7(e)(1)...............  Conditions for      No. Subpart DDDDD
                                   conducting          specifies
                                   performance         conditions for
                                   tests..             conducting
                                                       performance tests
                                                       at Sec.
                                                       63.7520(a) to
                                                       (c).
Sec.   63.7(e)(2)-(e)(9), (f),    Performance         Yes.
 (g), and (h).                     Testing
                                   Requirements.
Sec.   63.8(a) and (b)..........  Applicability and   Yes.
                                   Conduct of
                                   Monitoring.
Sec.   63.8(c)(1)...............  Operation and       Yes.
                                   maintenance of
                                   CMS.
Sec.   63.8(c)(1)(i)............  General duty to     No. See Sec.
                                   minimize            63.7500(a)(3).
                                   emissions and CMS
                                   operation.
Sec.   63.8(c)(1)(ii)...........  Operation and       Yes.
                                   maintenance of
                                   CMS.
Sec.   63.8(c)(1)(iii)..........  Startup, shutdown,  No.
                                   and malfunction
                                   plans for CMS.
Sec.   63.8(c)(2) to (c)(9).....  Operation and       Yes.
                                   maintenance of
                                   CMS.

[[Page 80672]]

 
Sec.   63.8(d)(1) and (2).......  Monitoring          Yes.
                                   Requirements,
                                   Quality Control
                                   Program.
Sec.   63.8(d)(3)...............  Written procedures  Yes, except for
                                   for CMS.            the last
                                                       sentence, which
                                                       refers to a
                                                       startup,
                                                       shutdown, and
                                                       malfunction plan.
                                                       Startup,
                                                       shutdown, and
                                                       malfunction plans
                                                       are not required.
Sec.   63.8(e)..................  Performance         Yes.
                                   evaluation of a
                                   CMS.
Sec.   63.8(f)..................  Use of an           Yes.
                                   alternative
                                   monitoring method.
Sec.   63.8(g)..................  Reduction of        Yes.
                                   monitoring data.
Sec.   63.9.....................  Notification        Yes.
                                   Requirements.
Sec.   63.10(a), (b)(1).........  Recordkeeping and   Yes.
                                   Reporting
                                   Requirements.
Sec.   63.10(b)(2)(i)...........  Recordkeeping of    Yes.
                                   occurrence and
                                   duration of
                                   startups or
                                   shutdowns.
Sec.   63.10(b)(2)(ii)..........  Recordkeeping of    No. See Sec.
                                   malfunctions.       63.7555(d)(7) for
                                                       recordkeeping of
                                                       occurrence and
                                                       duration and Sec.
                                                         63.7555(d)(8)
                                                       for actions taken
                                                       during
                                                       malfunctions.
Sec.   63.10(b)(2)(iii).........  Maintenance         Yes.
                                   records.
Sec.   63.10(b)(2)(iv) and (v)..  Actions taken to    No.
                                   minimize
                                   emissions during
                                   startup,
                                   shutdown, or
                                   malfunction.
Sec.   63.10(b)(2)(vi)..........  Recordkeeping for   Yes.
                                   CMS malfunctions.
Sec.   63.10(b)(2)(vii) to (xiv)  Other CMS           Yes.
                                   requirements.
Sec.   63.10(b)(3)..............  Recordkeeping       No.
                                   requirements for
                                   applicability
                                   determinations.
Sec.   63.10(c)(1) to (9).......  Recordkeeping for   Yes.
                                   sources with CMS.
Sec.   63.10(c)(10) and (11)....  Recording nature    No. See Sec.
                                   and cause of        63.7555(d)(7) for
                                   malfunctions, and   recordkeeping of
                                   corrective          occurrence and
                                   actions.            duration and Sec.
                                                         63.7555(d)(8)
                                                       for actions taken
                                                       during
                                                       malfunctions.
Sec.   63.10(c)(12) and (13)....  Recordkeeping for   Yes.
                                   sources with CMS.
Sec.   63.10(c)(15).............  Use of startup,     No.
                                   shutdown, and
                                   malfunction plan.
Sec.   63.10(d)(1) and (2)......  General reporting   Yes.
                                   requirements.
Sec.   63.10(d)(3)..............  Reporting opacity   No.
                                   or visible
                                   emission
                                   observation
                                   results.
Sec.   63.10(d)(4)..............  Progress reports    Yes.
                                   under an
                                   extension of
                                   compliance.
Sec.   63.10(d)(5)..............  Startup, shutdown,  No. See Sec.
                                   and malfunction     63.7550(c)(11)
                                   reports.            for malfunction
                                                       reporting
                                                       requirements.
Sec.   63.10(e).................  Additional          Yes.
                                   reporting
                                   requirements for
                                   sources with CMS.
Sec.   63.10(f).................  Waiver of           Yes.
                                   recordkeeping or
                                   reporting
                                   requirements.
Sec.   63.11....................  Control Device      No.
                                   Requirements.
Sec.   63.12....................  State Authority     Yes.
                                   and Delegation.
Sec.   63.13-63.16..............  Addresses,          Yes.
                                   Incorporation by
                                   Reference,
                                   Availability of
                                   Information,
                                   Performance Track
                                   Provisions.
Sec.   63.1(a)(5),(a)(7)-(a)(9),  Reserved..........  No.
 (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).
------------------------------------------------------------------------

[FR Doc. 2011-31667 Filed 12-22-11; 8:45 am]
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