```

[Federal Register Volume 78, Number 21 (Thursday, January 31, 2013)]
[Rules and Regulations]
[Pages 7137-7213]
From the Federal Register Online via the Government Printing Office [www.gpo.gov]
[FR Doc No: 2012-31646]

[[Page 7137]]

Vol. 78

Thursday,

No. 21

January 31, 2013

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; Final Rule

Federal Register / Vol. 78 , No. 21 / Thursday, January 31, 2013 / 
Rules and Regulations

[[Page 7138]]

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ENVIRONMENTAL PROTECTION AGENCY

40 CFR Part 63

[EPA-HQ-OAR-2002-0058; FRL-9676-8]
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: Final rule; notice of final action on reconsideration.

-----------------------------------------------------------------------

SUMMARY: In this action the EPA is taking final action on its 
reconsideration of certain issues in the 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, which were issued under section 
112 of the Clean Air Act. As part of this action, the EPA is making 
technical corrections to the final rule to clarify definitions, 
references, applicability and compliance issues raised by petitioners 
and other stakeholders affected by this rule. On March 21, 2011, the 
EPA promulgated national emission standards for this source category. 
On that same day, the EPA also published a notice announcing its intent 
to reconsider certain provisions of the final rule. Following these 
actions, the Administrator received several petitions for 
reconsideration. After consideration of the petitions received, on 
December 23, 2011, the EPA proposed revisions to certain provisions of 
the March 21, 2011, final rule, and requested public comment on several 
provisions of the final rule. The EPA is now taking final action on the 
proposed reconsideration.

DATES: The May 18, 2011 (76 FR28661), delay of the effective date 
revising subpart DDDDD at 76 FR 15451 (March 21, 2011) is lifted 
January 31, 2013. The amendments in this rule to 40 CFR part 63, 
subpart DDDDD are effective as of April 1, 2013.

ADDRESSES: The EPA established a single docket under Docket ID No. EPA-
HQ-OAR-2002-0058 for this action. All documents in the docket are 
listed on the http://www.regulations.gov Web site. Although listed in 
the index, some information is not publicly available, e.g., 
confidential business information or other information whose disclosure 
is restricted by statute. Certain other material, such as copyrighted 
material, is not placed on the Internet and will be publicly available 
only in hard copy form. Publicly available docket materials are 
available either electronically through http://www.regulations.gov or 
in hard copy at the EPA's Docket Center, Public Reading Room, EPA West 
Building, Room 3334, 1301 Constitution Avenue NW., Washington, DC 
20004. This Docket Facility is open from 8:30 a.m. to 4:30 p.m., Monday 
through Friday, excluding legal holidays. The telephone number for the 
Public Reading Room is (202) 566-1744, and the telephone number for the 
Air Docket is (202) 566-1742.

FOR FURTHER INFORMATION CONTACT: Mr. Jim Eddinger, Energy Strategies 
Group, Sector Policies and Programs Division, (D243-01), Office of Air 
Quality Planning and Standards, U.S. Environmental Protection Agency, 
Research Triangle Park, North Carolina 27711; Telephone number: (919) 
541-5426; Fax number (919) 541-5450; Email address: 
eddinger.jim@epa.gov.

SUPPLEMENTARY INFORMATION: 

Executive Summary

Purpose of This Regulatory Action

    The EPA is taking final action on its proposed reconsideration of 
certain provisions of its March 21, 2011, final rule that established 
standards for new and existing industrial, commercial, and 
institutional boilers and process heaters at major sources of hazardous 
air pollutants. Section 112(d) of the CAA requires the EPA to regulate 
HAP from major stationary sources based on the performance of MACT. 
Section 112(h) of the CAA allows the EPA to establish work practice 
standards in lieu of numerical emission limits only in cases where the 
agency determines that it is not feasible to prescribe or enforce an 
emission standard, including circumstances in which the agency 
determines that the application of measurement methodology is not 
practicable due to technological and economic limitations. The EPA is 
revising certain MACT standards established in March 2011 for boilers 
and process heaters, including standards for CO--as a surrogate for 
organic HAP; HCl--as a surrogate for acid gas HAP; Hg; TSM or 
filterable PM--as a surrogate for non-Hg metallic HAP; and dioxin/
furan.
    This final rule amends certain provisions of the final rule issued 
by the EPA on March 21, 2011. The EPA delayed the effective date of the 
2011 rule in a May 18, 2011, notice, but that delay notice was vacated 
by the U.S. District Court for the District of Columbia on January 9, 
2012, and the March 2011 final rule was, therefore, in effect until 
publication of this action.

Summary of Major Reconsideration Provisions

    In general, this final rule requires facilities classified as major 
sources of HAP with affected boilers or process heaters to reduce 
emissions of harmful toxic air emissions from these combustion sources. 
This will improve air quality and protect public health in communities 
where these facilities are located.
    Recognizing the diversity of this source category and the multiple 
sectors of the economy this final rule effects, the EPA is revising 
certain subcategories for boilers and process heaters in this action 
that were established in the March 2011 final rule, based on the design 
of the combustion equipment. These revisions result in 19 subcategories 
for the boilers and process heaters source category. Numerical emission 
limits are established for most of the subcategories for five 
pollutants, CO, HCl, Hg, and PM or TSM. The review of existing data and 
consideration of new data have resulted in changes to some of the 
emission limits contained in the March 2011 final rule. Overall, for 
both new and existing affected units, about 30 percent of the emission 
limits are more stringent, half are less stringent, and 20 percent 
unchanged as compared to the March 2011 final rule. Also, based on its 
review and analysis of new data submissions, the EPA is establishing an 
alternative emission standard for CO, based on CEMS data for several 
subcategories with CO CEMS data available. This alternative standard is 
based on a 30-day rolling average for subcategories for which 
sufficient CEMS data were available for more than a 30-day period, or a 
10-day rolling average for subcategories for which CEMS data were 
available for less than a 30-day period, and provides additional 
compliance flexibility to sources. All of the subcategories are subject 
to periodic tune-up work practices for dioxin/furan emissions.
    The compliance dates for the rule are January 31, 2016, for 
existing sources and, January 31, 2013, or upon startup, whichever is 
later, for new sources. New sources are defined as sources that began 
operation on or after June 4, 2010.

Costs and Benefits

    The final rule affects 1,700 existing major source facilities with 
an estimated 14,136 boilers and process heaters and the EPA projects an 
additional 1,844 new boilers and process heaters to be subject to this 
final rule over the next 3

[[Page 7139]]

years. This final rule affects multiple sectors of the economy 
including small entities. Table 1 summarizes the costs and benefits 
associated with this final rule. A more detailed discussion of the 
costs and benefits of this final rule is provided in section VI of this 
preamble.

       Table 1--Summary of the Monetized Benefits, Social Costs and Net Benefits for the Final Boiler MACT
                                             Reconsideration in 2015
                                             [Millions of 2008$] \1\
----------------------------------------------------------------------------------------------------------------
                                              3 percent discount rate              7 percent discount rate
----------------------------------------------------------------------------------------------------------------
Total Monetized Benefits \2\..........  $27,000 to $67,000.................  $25,000 to $61,000.
Total Social Costs \3\................  $1,400 to $1,600...................  $1,400 to $1,600.
Net Benefits..........................  $26,000 to $65,000.................  $23,000 to $59,000.
----------------------------------------------------------------------------------------------------------------
Non-monetized Benefits................  Health effects from exposure to HAP (39,000 tons of HCl, 500 tons of HF,
                                               3,100 to 5,300 pounds of Hg and 2,500 tons of other metals).
                                         Health effects from exposure to other criteria pollutants (180,000 tons
                                                             of CO and 572,000 tons of SO2).
                                                                   Ecosystem effects.
                                                                 Visibility impairment.
----------------------------------------------------------------------------------------------------------------
\1\ All estimates are for the implementation year (2015), and are rounded to two significant figures.
\2\ The total monetized co-benefits reflect the human health benefits associated with reducing exposure to PM2.5
  through reductions of PM2.5 precursors such as directly emitted particles, SO2, and NOX and reducing exposure
  to ozone through reductions of VOC. It is important to note that the monetized benefits include many but not
  all health effects associated with PM2.5 exposure. Monetized benefits are shown as a range from Pope et al.
  (2002) to Laden et al. (2006). These models assume that all fine particles, regardless of their chemical
  composition, are equally potent in causing premature mortality because the scientific evidence is not yet
  sufficient to support the development of differential effects estimates by particle type. These estimates
  include the energy disbenefits valued at $24 million (using the 3 percent discount rate), which do not change
  the rounded totals. CO2-related disbenefits were calculated using the ``social cost of carbon,'' which is
  discussed further in the RIA.
\3\ The methodology used to estimate social costs for one year in the multimarket model using surplus changes
  results in the same social costs for both discount rates.

    Acronyms and Abbreviations. The following acronyms and 
abbreviations are used in this document.

ACC American Chemistry Council
ACCCI American Coke and Coal Chemicals Institute
AF&PA American Forest and Paper Association
AHFA American Home Furnishings Alliance
AISI American Iron and Steel Institute
AMP American Municipal Power Inc.
AIE Alliance for Industrial Efficiency
APCD air pollution control devices
API American Petroleum Institute
AIF Auto Industry Forum
BFG Blast furnace gas
BLDS Bag leak detection system
BCSE The Business Council for Sustainable Energy
CIBO Council of Industrial Boiler Owners
CO Carbon monoxide
CO2 Carbon dioxide
CEMS Continuous emissions monitoring system
CEG Citizens Energy Group
CAA Clean Air Act
CFR Code of Federal Regulations
CPMS Continuous parameter monitoring system
CMI CraftMaster Manufacturing Inc.
ERT Electronic Reporting Tool
ESP Electrostatic precipitator
EPA Environmental Protection Agency
FBC Fluidized bed combustion
FR Federal Register
FSI Florida Sugar Industry
GPSP Great Plains Synfuels Plant
HAP Hazardous air pollutants
HBES Health-based emissions standard
HF Hydrogen fluoride
Hg Mercury
HCl Hydrogen chloride
kWh Kilowatt hours
ISO International Standards Organization
lb Pounds
LFG Landfill gas
MACT Maximum achievable control technology
MATS Mercury Air Toxics Standards
MSU Michigan State University
MMBtu Million British thermal units
NESHAP National Emission Standards for Hazardous Air Pollutants
NPRA National Petrochemical and Refiners Association
NTTAA National Technology Transfer and Advancement Act
NAICS North American Industry Classification System
NOX Nitrogen oxide
NSR New Source Review
OMB Office of Management and Budget
PM Particulate matter
PSU Penn State University
PS Performance Specification
ppm Parts per million
QA Quality assurance
QC Quality control
RFA Regulatory Flexibility Act
RIA Regulatory Impact Analysis
RPU Rochester Public Utilities
RTC Response to comment
SCR Selective catalytic reduction
SNCR Selective non-catalytic reduction
SO2 Sulfur dioxide
TBtu/yr Trillion British thermal units per year
THC Total hydrocarbon
TSM Total selected metals
TTN Technology Transfer Network
tpy Tons per year
UMRA Unfunded Mandates Reform Act of 1995
U.S. United States
USCHPA US Clean Heat Power Association
US Sugar United States Sugar Corporation
UPL Upper prediction limit
UARG Utility Air Regulatory Group
VCS Voluntary Consensus Standards
VOC Volatile organic compounds
WM Waste Management Inc.
WEPCO Wisconsin Electric Power Company
WWW Worldwide Web

    Organization of this Document. The information presented in this 
preamble is organized as follows:

I. General Information
    A. Does this action apply to me?
    B. Where can I get a copy of this document?
    C. Judicial Review
II. Background Information
    A. Chronological History of Related Actions
III. Summary of This Final Rule
    A. What is an affected source?
    B. What are the subcategories of boilers and process heaters?
    C. What emission limits and work practice standards are being 
finalized?
    D. What are the requirements during periods of startup and 
shutdown?
    E. What are the testing and initial compliance requirements?
    F. What are the continuous compliance requirements?

[[Page 7140]]

    G. What are the compliance dates?
IV. Summary of Significant Changes Since Proposal
    A. Applicability
    B. Subcategories
    C. Performance Test Requirements
    D. Emission Limits
    E. Work Practice Requirement
    F. Averaging Times Definitions
    G. Energy Assessment
    H. Startup and Shutdown Definitions
    I. Fuel Sampling Frequency
    J. Affirmative Defense
V. Other Actions We Are Taking
VI. Impacts of This Final Rule
    A. What are the incremental air impacts?
    B. What are the incremental water and solid waste impacts?
    C. What are the incremental energy impacts?
    D. What are the incremental cost impacts?
    E. What are the economic impacts?
    F. What are the benefits of this final rule?
    G. What are the incremental secondary air impacts?
VII. Statutory and Executive Order Reviews
    A. Executive Order 12866: Regulatory Planning and Review and 
Executive Order 13563: Improving Regulation and Regulatory Review
    B. Paperwork Reduction Act
    C. Regulatory Flexibility Act
    D. Unfunded Mandates Reform Act
    E. Executive Order 13132: Federalism
    F. Executive Order 13175: Consultation and Coordination with 
Indian Tribal Governments
    G. Executive Order 13045: Protection of Children from 
Environmental Health Risks and Safety Risks
    H. Executive Order 13211: Actions Concerning Regulations That 
Significantly Affect Energy Supply, Distribution, or Use
    I. National Technology Transfer and Advancement Act
    J. Executive Order 12898: Federal Actions to Address 
Environmental Justice in Minority Populations and Low-Income 
Populations
    K. Congressional Review Act

I. General Information

A. Does this action apply to me?

    The regulated categories and entities potentially affected by this 
action include:

                          TABLE 2--Potential Regulated Categories and Entities Affected
----------------------------------------------------------------------------------------------------------------
              Category                 NAICS code\1\           Examples of potentially regulated entities
----------------------------------------------------------------------------------------------------------------
Any industry using a boiler or                     211  Extractors of crude petroleum and natural gas.
 process heater as defined in the
 final rule.
                                                   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,  Manufacturers of rubber and miscellaneous plastic
                                                   339   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 this final 
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. Where can I get a copy of this document?

    In addition to being available in the docket, an electronic copy of 
this action will also be available on the WWW through the TTN. 
Following signature, a copy of the action will be posted on the TTN's 
policy and guidance page for newly proposed or promulgated rules at the 
following address: http://www.epa.gov/ttn/oarpg/. The TTN provides 
information and technology exchange in various areas of air pollution 
control.

C. Judicial Review

    Under the CAA section 307(b)(1), judicial review of this final rule 
is available only by filing a petition for review in the U.S. Court of 
Appeals for the District of Columbia Circuit by April 1, 2013. Under 
CAA section 307(d)(7)(B), only an objection to this final rule that was 
raised with reasonable specificity during the period for public comment 
can be raised during judicial review. Note, under CAA section 
307(b)(2), the requirements established by this final rule may not be 
challenged separately in any civil or criminal proceedings brought by 
the EPA to enforce these requirements.

II. Background Information

A. Chronological History of Related Actions

    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 CAA. On the 
same day as the final rule was issued, the EPA 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 March 2011 final rule where additional public 
comment was appropriate. This notice also identified several issues of 
central relevance to the rulemaking where reconsideration was 
appropriate under CAA section 307(d).
    On May 18, 2011, the EPA issued a notice to postpone the effective 
date of the March 21, 2011 final rule. Following promulgation of the 
final rule, the EPA received petitions for reconsideration from the 
following organizations

[[Page 7141]]

(``Petitioners''): AIE, USCHPA, Alyeska Pipeline, ACC, AHFA, AISI, 
ACCCI, AMP, API, NPRA, AIF, Citizens Energy Group (CEG), CIBO, CMI, 
District Energy St. Paul, FSI, GPSP, Hovensa L.L.C., Tesoro Hawaii 
Corp., Industry Coalition (AF&PA et al.), JELD-WEN Inc., MSU, PSU, 
Purdue University, Renovar Energy Corp., RPU, Sierra Club, Southeastern 
Lumber Manufacturers Association, State of Washington Department of 
Ecology, BCSE, UARG, US Sugar, WM and WEPCO. 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 rule. On December 23, 2011, 
the EPA granted the petitions for reconsideration on certain issues, 
and proposed certain revisions to the final rule in response to the 
reconsideration petitions and to address the issues that the EPA 
previously identified as warranting reconsideration. That proposal 
solicited comment on several specific aspects of the rule, including:

     Revising the proposed subcategories.
     Solicitation of new data or corrections to existing data 
to revise emission standards calculations.
     Establishing an alternative TSM limit.
     Appropriateness of an alternative TSM limit for the liquid 
subcategories.
     Establishing work practice standards for dioxin/furan 
emissions.
     Revising the efficiency assumptions for the alternative 
output-based emission standards.
     Accommodating emissions averaging provisions in the 
alternative output-based emission standards.
     Establishing a mercury 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.
     Revisions to the monitoring requirements for oxygen in the 
March 2011 final rule.
     Establishing a full-load stack test requirement for carbon 
monoxide coupled with continuous oxygen (oxygen trim) monitoring.
     Revising PM monitoring requirements from CEMS to CPMS and 
exempting biomass units from PM CPMS requirements.
     Revising mercury monitoring requirements to allow for an 
alternative mercury CEMS.
     Considering use of SO2 CEMS to demonstrate 
compliance with HCl limits.
     Minimum data availability provisions.
     Averaging times for monitored parameters and pollutants.
     Revised methods for computing minimum detection levels.
     Providing an alternative CO emission limit based on CO 
CEMS data.
     Soliciting additional data to set MACT floor emission 
limits for non-continental liquid units.
     Selecting a 99 percent confidence interval for setting the 
CO emission limit.
     Tune-up frequencies, timing of initial tune-ups and 
adjusted tune-up requirements for shutdown units.
     Scope and duration of the energy assessment and deadline 
for completing the assessment.
     Revising work practices during startup and shutdown.
     Revisions to certain exemptions, including units serving 
as control devices, waste heat process heaters, units firing comparable 
fuels and residential units.
     Revisions to reduced testing frequency for emission limits 
that are established at minimum detection levels.
     Removing fuel analysis requirements for gas 1 fuels at co-
fired units.
     Revisions to automating techniques for coal sampling.
     Revisions to emissions averaging across subcategories when 
units opt to switch to natural gas.
     Consideration of a new subcategory for units installed and 
used in place of flares.

    In this action, the EPA is finalizing multiple changes to the March 
2011 final rule after considering public comments on the items under 
reconsideration.

III. Summary of This Final Rule

    As stated above, the December 23, 2011 proposed rule addressed 
specific issues and provisions the EPA identified for reconsideration. 
This summary of the final rule reflects the changes to 40 CFR part 63, 
subpart DDDDD (March 21, 2011 final rule) in regards to those 
provisions identified for reconsideration and on other discrete matters 
identified in response to comments or data received during the comment 
period. Information on other provisions and issues not proposed for 
reconsideration is contained in the notice and record for the 2011 
final rule. [See 76 FR 15608]
    This section summarizes the requirements of this action. Section IV 
below provides a summary of the significant changes to the March 21, 
2011 final rule.

A. What is an affected source?

    This final rule revises the list of exemptions in Sec.  63.7491 to 
include residential boilers that may be located at an industrial, 
commercial or institutional major source. The exemption for boilers or 
process heaters used specifically for research and development has been 
revised to include boilers used for certain testing purposes.

B. What are the subcategories of boilers and process heaters?

    In this final rule, we are finalizing separate subcategories for 
heavy liquid-fired, light liquid-fired and liquid-fired units in non-
continental locations for PM and CO, pollutants that are dependent on 
combustor design. In addition, a new subcategory for coal-fired 
fluidized bed boilers with integrated fluidized bed heat exchangers has 
been included in the final rule for CO which is dependent on boiler 
design. Finally, we are finalizing the subcategory for PM at coal/
fossil solid units across all coal combustor designs.

C. What emission limits and work practice standards are being 
finalized?

    You must meet the emission limits presented in Table 3 of this 
preamble for each subcategory of units listed in the table. This final 
rule includes 19 subcategories, which are based on unit design. New and 
existing units in three of the subcategories are subject to work 
practices standards in lieu of emission limits for all pollutants. 
Numeric emission limits are finalized for new and existing sources in 
each of the other 16 subcategories.
    The changes associated with the emission limits are due to new 
data, corrections to old data, and inventory changes. In summary, for 
existing subcategories, for the HCl emission limits, 10 are more 
stringent, 3 are less stringent and 1 remained the same from the March 
21, 2011 final rule; for the mercury emission limits, 3 are more 
stringent and 11 are less stringent from the March 21, 2011 final rule; 
for the PM emission limits, 2 are more stringent, 7 are less stringent 
and 5 are unchanged from the March 21, 2011 final rule; and for the CO 
emission limits, 4 are more stringent and 10 are less stringent from 
the March 21, 2011 final rule. For new subcategories, for the HCl 
emission limits, 13 are less stringent and 1 is unchanged from the 
March 21, 2011 final rule; for the mercury emission limits, 11 are more

[[Page 7142]]

stringent, 2 are less stringent and 1 is unchanged from the March 21, 
2011 final rule; for the PM emission limits, 9 are less stringent and 5 
are unchanged from the March 21, 2011 final rule; and for the CO 
emission limits, 3 are more stringent and 11 are less stringent from 
the March 21, 2011 final rule.

                                                TABLE 3--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]
--------------------------------------------------------------------------------------------------------------------------------------------------------
                                                                                                                                           Alternate CO
                                            Filterable PM  (or total       HCl  (lb per MMBtu of  Mercury  (lb per MMBtu   CO  (ppm @3%     CEMS limit,
              Subcategory               selected  metals)  (lb per MMBtu      heat input) \a\       of heat input) \a\      oxygen) \a\      (ppm @3%
                                               of heat input) \a\                                                                           oxygen) \b\
--------------------------------------------------------------------------------------------------------------------------------------------------------
Existing--Coal Stoker.................  0.040 (5.3E-05).................  0.022                   5.7E-06                            160             340
Existing--Coal Fluidized Bed..........  0.040 (5.3E-05).................  0.022                   5.7E-06                            130             230
Existing--Coal Fluidized Bed with FB    0.040 (5.3E-05).................  0.022                   5.7E-06                            140             150
 heat exchanger.
Existing--Coal-Burning Pulverized Coal  0.040 (5.3E-05).................  0.022                   5.7E-06                            130             320
Existing--Biomass Wet Stoker/Sloped     0.037 (2.4E-04).................  0.022                   5.7E-06                          1,500             720
 Grate/Other.
Existing--Biomass Kiln-Dried Stoker/    0.32 (4.0E-03)..................  0.022                   5.7E-06                            460              ND
 Sloped Grate/Other.
Existing--Biomass Fluidized Bed.......  0.11 (1.2E-03)..................  0.022                   5.7E-06                            470             310
Existing--Biomass Suspension Burner...  0.051 (6.5E-03).................  0.022                   5.7E-06                          2,400       \c\ 2,000
Existing--Biomass Dutch Ovens/Pile      0.28 (2.0E-03)..................  0.022                   5.7E-06                            770         \c\ 520
 Burners.
Existing--Biomass Fuel Cells..........  0.020 (5.8E-03).................  0.022                   5.7E-06                          1,100              ND
Existing--Biomass Hybrid Suspension     0.44(4.5E-04)...................  0.022                   5.7E-06                          2,800             900
 Grate.
Existing--Heavy Liquid................  0.062 (2.0E-04).................  0.0011                  2.0E-06                            130              ND
Existing--Light Liquid................  0.0079 (6.2E-05)................  0.0011                  2.0E-06                            130              ND
Existing--non-Continental Liquid......  0.27 (8.6E-04)..................  0.0011                  2.0E-06                            130              ND
Existing--Gas 2 (Other Process Gases).  0.0067 (2.1E-04)................  0.0017                  7.9E-06                            130              ND
New--Coal Stoker......................  0.0011 (2.3E-05)................  0.022                   8.0E-07                            130             340
New--Coal Fluidized Bed...............  0.0011 (2.3E-05)................  0.022                   8.0E-07                            130             230
New--Coal Fluidized Bed with FB Heat    0.0011 (2.3E-05)................  0.022                   8.0E-07                            140             150
 Exchanger.
New--Coal-Burning Pulverized Coal.....  0.0011 (2.3E-05)................  0.022                   8.0E-07                            130             320
New--Biomass Wet Stoker/Sloped Grate/   0.030 (2.6E-05).................  0.022                   8.0E-07                            620             390
 Other.
New--Biomass Kiln-Dried Stoker/Sloped   0.030 (4.0E-03).................  0.022                   8.0E-07                            460              ND
 Grate/Other.
New--Biomass Fluidized Bed............  0.0098 (8.3E-05)................  0.022                   8.0E-07                            230             310
New--Biomass Suspension Burner........  0.030 (6.5E-03).................  0.022                   8.0E-07                          2,400       \c\ 2,000
New--Biomass Dutch Ovens/Pile Burners.  0.0032 (3.9E-05)................  0.022                   8.0E-07                            330         \c\ 520
New--Biomass Fuel Cells...............  0.020 (2.9E-05).................  0.022                   8.0E-07                            910              ND
New--Biomass Hybrid Suspension Grate..  0.026 (4.4E-04).................  0.022                   8.0E-07                          1,100             900
New--Heavy Liquid.....................  0.013 (7.5E-05).................  4.4E-04                 4.8E-07                            130              ND
New--Light Liquid.....................  0.0011 (2.9E-05)................  4.4E-04                 4.8E-07                            130              ND
New--Non-Continental Liquid...........  0.023 (8.6E-04).................  4.4E-04                 4.8E-07                            130              ND
New--Gas 2 (Other Process Gases)......  0.0067 (2.1E-04)................  0.0017                  7.9E-06                            130              ND
--------------------------------------------------------------------------------------------------------------------------------------------------------
NA-Not applicable; ND-No data available
\a\ 3-run average, unless otherwise noted.
\b\ 30-day rolling average, unless otherwise noted.
\c\ 10-day rolling average.

    We also are finalizing a work practice standard for dioxin/furan 
emissions from all subcategories.

D. What are the requirements during periods of startup and shutdown?

    We are finalizing revised work practice standards for periods of 
startup and shutdown to better reflect the maximum achievable control 
technology during those periods. In addition, we are finalizing 
definitions of startup and shutdown. We are defining startup as the 
period between the state of first-firing of fuel in the unit after a 
shutdown to the period where the unit first supplies steam. We are 
defining shutdown as the period that begins when no more steam is 
supplied or at the point of no fuel being fired in the unit. For 
periods of startup and shutdown, we are finalizing the following work 
practice standard: You must operate all continuous monitoring systems 
during startup and shutdown. For startup, you must use one or a 
combination of the listed clean fuels. Once you start firing coal/solid 
fossil fuel, biomass/bio-based solids, heavy liquid fuel, or gas 2 
(other) gases, you must engage all of the applicable control devices 
except limestone injection in FBC boilers, dry scrubber, fabric filter, 
SNCR and SCR. You must start your limestone injection in FBC boilers, 
dry scrubber, fabric filter, SNCR and SCR systems as expeditiously as 
possible. During shutdown while firing coal/solid fossil fuel, biomass/
bio-based solids, heavy liquid fuel, or gas 2 (other) gases during 
shutdown, you must operate all applicable control devices, except 
limestone injection in FBC boilers, dry scrubber, fabric filter, SNCR 
and SCR. You must comply with all applicable emissions and operating 
limits at all times the unit is in operation except for periods that 
meet the definitions of startup and shutdown in this subpart, during 
which times you must comply with these work practices. You must keep 
records during periods of startup or shutdown. You must keep records 
concerning the date, duration, and fuel usage during startup and 
shutdown.

E. 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. This final rule adds 
the requirement to 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.

[[Page 7143]]

F. What are the continuous compliance requirements?

    This final rule removes the requirement for units combusting 
biomass with heat input capacities of 250 MMBtu/hr or greater to 
install, certify, maintain and operate a CEMS measuring PM emissions. 
This final rule requires units combusting solid fossil fuel or heavy 
liquid with heat input capacities of 250 MMBtu/hr or greater to 
install, certify, maintain, and operate PM CPMS. Moreover, owners or 
operators of units combusting solid fossil fuel or heavy liquid with 
heat input capacities of 250 MMBtu/hr or greater are allowed to 
install, certify, maintain and operate PM CEMS as an alternative to the 
use of PM CPMS, consistent with regulations for similarly-sized 
commercial and industrial solid waste incinerators units and EGUs 
subject to the MATS. Just as units using PM CPMS will not be required 
to conduct parameter monitoring for PM, units using PM CEMS will not be 
required to conduct parameter monitoring for PM.
    This final rule also includes an alternative method of 
demonstrating continuous compliance with the HCl emission limit. This 
method allows using SO2 emissions as an alternate operating 
limit. This method of demonstrating continuous compliance will be 
allowed only on a unit that utilizes a SO2 CEMS and an acid-
gas control technology including wet scrubber, dry scrubbers and duct 
sorbent injection. Boilers or process heaters subject to an HCl 
emission limit that demonstrate compliance with an SO2 CEMS 
would be required to maintain the 30-day rolling average SO2 
emission rate at or below the highest hourly average SO2 
concentration measured during the most recent HCl performance test.

G. What are the compliance dates?

    For existing sources, the EPA is establishing a compliance date of 
January 31, 2016. New sources must comply by January 31, 2013, or upon 
startup, whichever is later. New sources are defined as sources which 
commenced construction or reconstruction on or after June 4, 2010 
pursuant to section 112(a)(4).
    Commenters have argued that the 3-year compliance deadline the EPA 
is establishing for existing sources to meet the standards does not 
provide them with sufficient time to meet the standards in view of the 
large number of sources that will be competing for the needed resources 
and materials from engineering consultants, permitting authorities, 
equipment vendors, construction contractors, financial institutions, 
and other critical suppliers.
    As an initial matter, we note that many sources subject to the 
emission standards in the final rule should be able to meet the 
standards within three years, even those that need to install pollution 
control technologies to do so. In addition, many sources subject to the 
rule are gas fired units or small boilers (less than 10 MMBtu/hr) and 
will not need to install controls in order to demonstrate compliance, 
as these sources are subject to work practice standards. For these 
sources, the 3-year compliance deadline is highly unlikely to be 
problematic either in general, or with respect to the claims commenters 
have made about the possibility that the demand for resources related 
to control technology will exceed the supply.
    At the same time, the CAA allows title V permitting authorities to 
grant sources, on a case-by-case basis, extensions to the compliance 
time of up to one year if such time is needed for the installation of 
controls. See CAA section 112(i)(4)(i)(A). Permitting authorities are 
already familiar with, and in many cases have experience with, applying 
the 1-year extension authority under section 112(i)(4)(A) since the 
provision applies to all NESHAP. We believe that should the range of 
circumstances that commenters have cited as impeding sources' ability 
to install controls within three years materialize, then it is 
reasonable for permitting authorities to take those circumstances into 
consideration when evaluating a source's request for a 1-year 
extension, and where such applications prove to be well-founded, it is 
also reasonable for permitting authorities to make the 1-year extension 
available to applicants.
    In making a determination as to whether an extension is 
appropriate, we believe it is also reasonable for permitting 
authorities to consider the large number of pollution control retrofit 
projects being undertaken for purposes of complying either with the 
standards in this rule or with those of other rules such as MATS for 
the power sector that may be competing for similar resources.
    Further, commenters have pointed out that in some cases operators 
of existing sources that are subject to these standards and that 
generate energy may opt to meet the standards by terminating operations 
at these sources and building new sources to replace the energy 
generation at the shut-down sources. While the ultimate discretion to 
provide a 1-year extension lies with the permitting authority, the EPA 
believes that it is reasonable for permitting authorities to allow the 
fourth year extension for the installation of replacement sources of 
energy generation at the site of a facility applying for an extension 
for that purpose. Specifically, the EPA believes where an applicant 
demonstrates that it is building replacement sources of energy 
generation for purposes of meeting the requirements of these standards 
such a replacement project could be deemed to constitute the 
``installation of controls'' under section 112(i)(3)(B).
    In a case where pollution controls are being installed or onsite 
replacement energy generation is being constructed to allow for 
retirement of older, under-controlled energy generation units, a 
determination that an extra year is necessary for compliance should be 
relatively straightforward. In order to install controls, companies are 
likely to undertake a number of steps relatively soon after the 
effective date of the rule, including obtaining necessary building and 
environmental permits and hiring contractors to perform the 
construction of the emission controls or replacement energy generation 
units. This should provide sufficient information for a permitting 
authority to determine that emission controls are being installed or 
that replacement energy generation is being constructed. As a result, a 
permitting authority will be in a position to make a determination as 
to whether a source's compliance schedule will exceed 3 years and to 
quickly make a determination as to when an extension is appropriate.
    In sum, the EPA believes that although most, if not all, units will 
be able to fully comply with the standards within 3 years, the fourth 
year that permitting authorities are allowed to grant for installation 
of controls is an important flexibility that will address situations 
where an extra year is necessary. Of course in situations where EPA is 
the permitting authority, we would also consider the above 
circumstances when acting on a permit application.

IV. Summary of Significant Changes Since Proposal

    The EPA has made numerous changes in this final rule from the 
proposal after consideration of the public comments received. Most are 
changes to clarify applicability and implementation issues raised by 
the commenters. The public comments received on the proposed changes 
and the responses to them can be viewed in the memorandum ``Response to 
Comments for Industrial, Commercial, and Institutional Boilers

[[Page 7144]]

and Process Heaters National Emission Standards for Hazardous Air 
Pollutants'' located in the docket.

A. Applicability

    Since proposal, the EPA has made certain changes to the 
applicability of this final rule. We have clarified that the exemption 
for boilers and process heaters used for research and development 
includes boilers used for testing the propulsion systems on military 
vessels. This is consistent with the intent of the exemption in that 
these test boilers do not provide steam for heating, to a process, or 
other non-propulsion related uses but are used exclusively to test the 
propulsion systems of nuclear-powered aircraft carriers that are 
undergoing repair, overhaul, or installation.

B. Subcategories

    As described in the preamble to the proposed reconsideration rule, 
within the basic unit types of boilers and process heaters there are 
different designs and combustion systems that, while having a minor 
effect on fuel-dependent HAP emissions, have a much larger effect on 
pollutants whose emissions depend on the combustion conditions in a 
boiler or process heater. In the case of boilers and process heaters, 
the combustion-related pollutants are the organic HAP. In the proposed 
rule, we identified the following 17 subcategories for organic HAP: (1) 
Pulverized coal units; (2) stokers designed to burn coal; (3) fluidized 
bed units designed to burn coal; (4) stokers designed to burn wet 
biomass; (5) stokers designed to burn kiln-dried biomass; (6) fluidized 
bed units designed to burn biomass; (7) suspension burners designed to 
burn biomass; (8) dutch ovens/pile burners designed to burn biomass; 
(9) fuel cells designed to burn biomass; (10) hybrid suspension grate 
units designed to burn biomass; (11) units designed to burn heavy 
liquid fuel; (12) units designed to burn light liquid fuel; (13) non-
continental liquid units; (14) units designed to burn natural gas/
refinery gas; (15) units designed to burn other gases; (16) metal 
process furnaces; and (17) limited-use units.
    In this final rule, we are also adding a separate subcategory for 
fluidized bed units with a fluidized bed heat exchanger designed to 
burn coal and adjusted the definition of the limited use subcategory.
    Fluidized bed boilers are designed to combust fuel with relatively 
low heating value and high ash compared to other combustor designs. Two 
fuel properties of coal are heating values and ash content. As the 
heating value of the coal decreases, ash content increases. Fluidized 
bed boilers are designed to have large tube surface areas to transfer 
heat from the fuel through the process of conduction and convection, 
but in some cases the amount of tube surface area in the furnace for 
heat transfer is insufficient. In order to overcome insufficient heat 
exchange, certain fluidized bed boilers adopt a fluidized bed heat 
exchanger design to achieve heat transfer. The fluidized bed heat 
exchanger is located at the exit of the cyclone section of the unit. 
This design allows the boiler to combust coal with a lower heating 
value than a coal-fired fluidized bed boiler without a fluidized bed 
heat exchanger. Therefore, because this boiler design does have 
different combustion-related HAP emission characteristics, a new 
subcategory of coal fluidized bed with integrated heat exchanger was 
added to the final rule.
    The EPA is also revising the definition of the limited use 
subcategory. Many affected units operate on standby mode or low loads 
for periods longer than the proposed definition for limited use units, 
which limited operation to 876 hours per year. By converting to a 
capacity-factor approach, we are allowing more flexibility on unit 
operations without increasing emissions or harm to human health and the 
environment. For example, units operating at 10 percent load for 8,760 
hours per year would emit the same amount of emissions as units 
operating at full load for 876 hours per year. Further, it is 
technically infeasible to schedule stack testing for these limited use 
units since these units serve as back up energy sources and their 
operating schedules can be intermittent and unpredictable. The limited 
use subcategory was adjusted to be based on units with a federally 
enforceable operating limit of less than or equal to 10 percent of an 
average annual capacity factor.

C. Performance Test Requirements

    Table 5 of this final rule has been revised to add performance test 
procedures for conducting performance stack tests for demonstrating 
compliance with the alternate TSM emission limits. In the 
reconsideration proposal, we proposed emissions limits for TSM (i.e., 
arsenic, beryllium, cadmium, chromium, lead, manganese, nickel and 
selenium) as an alternative to the proposed PM emission limits for many 
of the subcategories. In the preamble to the proposed rule, we added 
procedures in Table 6 of the rule for conducting fuel analysis for 
total selected metals but we inadvertently failed to add performance 
test requirements for stack sampling of TSM emissions in Table 5 of the 
rule.

D. Emission Limits

    One significant change since proposal is related to the PM emission 
limits for the coal subcategories. Several petitioners disagreed with 
EPA's position to set different PM limits for subcategories of boilers 
and process heaters based on the fuel used, and instead offered 
information to support the position that PM should be considered a 
combustion-based pollutant. The differences in PM particle size, 
fouling characteristics and feasibility of certain control technologies 
on certain unit designs suggested that PM is more appropriately 
classified as a combustion-based pollutant, but only for the coal 
subcategories. After assessing the points raised by the petitioners, 
the EPA agreed that PM emissions are influenced by unit design, and 
fuel type, and proposed to create combustion-based pollutant 
subcategories for coal and solid fuels and create fuel-based 
subcategories for liquid and biomass fuel units. The EPA is finalizing 
a single PM limit for all coal/solid fossil fuel subcategories, and is 
also finalizing emissions limits based on PM as a combustion-based 
pollutant for the biomass and liquid fuel subcategories.
    Another change from proposal is that the alternative TSM emission 
limits are now applicable to the three liquid fuel subcategories. 
Several commenters provided data and comments supporting these 
alternative emission standards for non-mercury metallic HAP. After 
assessing the revised data and the points made by the commenters, the 
EPA agrees that the limited data available for liquid fuel units are 
not unique to this subcategory. Based on the EPA agreeing with the 
commenters, the EPA re-calculated the TSM emission limits for the 
liquid fuel subcategories and included them in the final rule.
    The CO emission limit for several subcategories, both new and 
existing, have been revised to reflect a CO level that is consistent 
with MACT for organic HAP reduction. Several commenters recommended 
that the EPA evaluate a minimum CO standard (i.e., 100 ppm corrected to 
7 percent oxygen) to serve as a lower bound surrogate for organic HAP. 
Commenters also provided data and information to support such a 
standard, and noted that the EPA has taken a similar approach in other 
emission standards under section 112.
    The EPA evaluated whether there is a minimum CO level for boilers 
and

[[Page 7145]]

process heaters below which there is no further benefit in organic HAP 
reduction/destruction. Specifically, we evaluated the relationship 
between CO and formaldehyde using the available data obtained during 
the rulemaking. Formaldehyde was selected as the basis of the organic 
HAP comparison because it is the most prevalent organic HAP in the 
emission database and a large number of paired tests existed for 
boilers and process heaters for CO and formaldehyde. The paired data 
show decreasing formaldehyde emissions with decreasing CO emissions 
down to CO levels around 300 ppm, supporting the selection of CO as a 
surrogate for organic HAP emissions. A slight increase in formaldehyde 
emissions is observed at CO levels below around 200 ppm, suggesting a 
breakdown in the CO-formaldehyde relationship at low CO levels. At 
levels lower than 150 ppm, the mean levels of formaldehyde appear to 
increase, as does the overall maximum value of and variability in 
formaldehyde emissions. However, we are aware of no reason why CO 
concentrations would continue to decrease and formaldehyde 
concentrations would increase as combustion conditions improve. It is 
possible that imprecise formaldehyde measurements at low concentrations 
(i.e., 1-2 ppm) may account for this slight increase in formaldehyde 
emissions observed at CO levels below 100 ppm corrected to 7 percent 
oxygen. Based on this, we do not believe that such measurements are 
sufficiently reliable to use as a basis for establishing an emissions 
limit.
    Therefore, based on the above analysis, we are promulgating a 
minimum MACT floor level for CO of 130 ppm corrected to 3 percent 
oxygen (which is equivalent to 100 ppm corrected to 7 percent oxygen). 
We note this is the same approach used to establish the CO emission 
limit of 100 ppm corrected to 7 percent oxygen for the Burning of 
Hazardous Waste in Boilers and Industrial Furnaces rule. Additional 
discussion of the rationale for this approach can be found in the 
memorandum ``Revised MACT Floor Analysis (August 2012) for Industrial, 
Commercial, Institutional Boilers and Process Heaters National Emission 
Standards for Hazardous Air Pollutants--Major Source.''
    Subcategories where the initial MACT floor 99 percent UPL 
calculations for CO were less than 100 ppm corrected to 7 percent 
oxygen (or equivalently 130 ppm corrected to 3 percent oxygen) are as 
follows:
     New and Existing Subcategories: Coal-FB, Coal-PC, Heavy 
Liquid, Light Liquid, Non-Continental Liquid, Process Gas
     New Subcategories: Coal-Stoker

We believe a CO level of 130 ppm corrected to 3 percent oxygen is an 
appropriate minimum MACT floor level. Although some measurements show 
CO levels below 130 ppm corrected to 3 percent oxygen, it is not 
appropriate to establish a lower floor level because CO is a 
conservative surrogate for organic HAP. In other words, organic HAP 
emissions are extremely low when sources operate under the good 
combustion conditions required to achieve CO levels in the range of 
zero to 100 ppm. As such, lowering the CO floor below 100 ppm will not 
provide reductions in organic HAP emissions. There are myriad factors 
that affect combustion efficiency and, as a function of combustion 
efficiency, CO emissions. As combustion conditions improve and 
hydrocarbon levels decrease, the larger and easier to combust compounds 
are oxidized to form smaller compounds that are, in turn, oxidized to 
form CO and water. As combustion continues, CO is then oxidized to form 
carbon dioxide and water. Because CO is a difficult to destroy 
refractory compound (i.e., oxidation of CO to carbon dioxide is the 
slowest and last step in the oxidation of hydrocarbons), it is a 
conservative surrogate for destruction of hydrocarbons, including 
organic HAP.
    The conservative nature of CO as an indicator of good combustion 
practices is supported by our data. At CO levels less than 100 ppm 
corrected to 7 percent oxygen, our data indicate that there is no 
apparent relationship between CO and organic HAP (i.e., formaldehyde). 
For example, a source with a CO level of 20 ppm may have the same 
measured formaldehyde as a source achieving a CO emission level of 100 
ppm corrected to 7 percent oxygen. Sources are required to establish 
operating requirements based on operating levels that were demonstrated 
during the test. Sources must comply with these operating requirements 
on a continuous basis. Compliance with these requirements adequately 
assures sources will be controlling organic HAP emissions to MACT 
levels.
    As detailed in the docketed memorandum ``Beyond the Floor 
Technology Analysis for Major Source Boilers and Process Heaters 
(Revised August 2012),'' we reviewed the emission limits that are 
becoming less stringent since the March 2011 final rule in order to 
assess whether a beyond the floor option was technically achievable and 
cost effective. As a result of this review, the PM emission limits for 
several new biomass subcategories have been changed to reflect a beyond 
the floor limit of 0.03 lb/MMBtu, based on the limit for new biomass 
boilers in 40 CFR part 60 subparts Db and Dc. Due to the low mercury 
emission limits for new solid fuel boilers, these new biomass units are 
expected to install a fabric filter level of control in order to meet 
the new source mercury limits for the solid fuel subcategory. This 
mercury control has the co-benefit of reducing PM emissions down to 
levels of 0.03 lb/MMBtu so there is no incremental cost to achieve 
these additional reductions in PM for the biomass units that have a 
design heat input capacity between 10 and 30 MMBtu/hr. For units with a 
design heat input capacity of 30 MMBtu/hr or greater, these units are 
already subject to a PM limit of 0.03 lb/MMBtu and adjusting these new 
source limits to this level of control makes the limits consistent 
between both rules, without adding additional costs. We did not 
identify any beyond the floor options for existing source PM limits or 
new and existing limits for other pollutants as technically feasible or 
cost effective.
    The other changes associated with the other emission limits are due 
to new data, corrections to old data, and inventory changes. In 
summary, compared to the December 23, 2011 proposed limits for existing 
units, the final HCl emission limits remained the same; for the final 
mercury emission limits, 3 are more stringent, 10 are less stringent 
and 1 is unchanged; for the final PM emission limits, 3 are more 
stringent, 5 are less stringent and 6 are unchanged; and for the final 
CO emission limits, 3 are more stringent and 11 are less stringent. For 
new units, compared to the proposed emission limits, 3 of the final HCl 
emission limits are more stringent and 11 remained the same; for the 
final mercury emission limits, 10 are more stringent and 4 are 
unchanged; for the final PM emission limits, 5 are more stringent, 2 
are less stringent and 7 are unchanged; and for the final CO emission 
limits, 2 are more stringent, 11 are less stringent and 1 is unchanged.

E. Work Practice Requirement

    In this final rule several changes have been made to the work 
practice requirement to conduct a tune-up. First, the requirement to 
inspect the burner has been revised to allow units that sell 
electricity to schedule the burner inspection, as well as the air-to-
fuel system inspection, at the time of the first outage but not to 
exceed 36 months from the previous inspection. This

[[Page 7146]]

change is being made to this final rule because commenters stated that 
large boilers that serve electricity for sale may not require annual 
outages and would, therefore, need to be taken off-line for the sole 
purpose of an annual tune-up. This frequency is consistent with the 
requirements of the NESHAP for electric utility boilers (40 CFR part 
63, subpart UUUUU).
    Also, for units where entry into a piece of process equipment or 
into a storage vessel is required to complete the tune-up inspections, 
inspections are required only during planned entries into the storage 
vessel or into process equipment. Commenters indicated that some 
process heaters are installed inside tanks and entry into the tank to 
access the heater may not occur within a 5 year period.
    The requirement to optimize total emissions of CO has been revised 
to require that this optimization not only be consistent with the 
manufacturer's specifications but also with any NOX emission 
requirement to which the unit is subject. Some commenters indicated 
that many boilers need different tune-up criteria due to their 
requirement to also comply with low NOX emission limits. We 
are also aware that several states have boiler tune-up requirements to 
minimize NOX emissions first and then optimize CO emissions.
    We have added boilers or process heaters that have a continuous 
oxygen trim system to the types of boilers or process heaters that must 
conduct a tune-up every 5 years. These units do not need to be tuned as 
frequently because the trim system is designed to continuously measure 
and maintain an optimum air to fuel ratio which is the purpose of a 
tune-up.

F. Averaging Times Definitions

    We revised the definitions of ``30-day rolling average'' and 
``daily block average'' to exclude periods of startup and shutdown or 
downtime from the arithmetic mean. Commenters requested that the EPA 
specify how a 30-day rolling average is calculated and whether it 
includes the previous 720 hours of valid operating data and that the 
valid data exclude hours during startup and shutdown as well as unit 
down time. We agree with the commenters that the definitions need 
clarification and that these periods should not be included in 
calculating the 30-day rolling average. Therefore, we have revised the 
definitions accordingly.
    We have also included in the final rule a definition of ``10-day 
rolling average'' that is consistent with the revised definition of 
``30-day rolling average.''

G. Energy Assessment

    In this final rule, we have revised the definition of energy 
assessment per the requirements of Table 3 of this final rule by 
providing duration for performing the energy assessment for large fuel 
use facilities. In numbered paragraph (3) in the definition of ``Energy 
assessment'' in Sec.  63.7575, which is for facilities with units 
having a combined heat input capacity greater than 1 TBtu/yr, we added 
time duration/size ratio and included a cap to the maximum number of 
on-site technical hours that should be used in the energy assessment. 
This addition of a duration for large fuel use facilities is being made 
to be consistent with durations specified for small [paragraph (1) in 
the definition of ``Energy assessment''] and medium [paragraph (2) in 
the definition of ``Energy assessment''] fuel use facilities. The 
energy assessment for facilities with affected boilers and process 
heaters having a combined heat input capacity greater than 1.0 TBtu/yr 
will be up to 24 on-site technical labor hours for the first TBtu/yr 
plus 8 technical labor hours for every additional 1.0 TBtu/yr not to 
exceed 160 technical hours, but may be longer at the discretion of the 
owner or operator.
    The revised definition of energy assessment also clarifies our 
intentions that the scope of assessment is based on energy use by 
discrete segments of a facility and not by a total aggregation of all 
individual energy using elements of a facility. The applicable discrete 
segments of a facility could vary significantly depending on the site 
and its complexity. We have added the following paragraph (4), to the 
energy assessment definition to help resolve current problems in 
identifying the scope of the various energy use systems in a large 
industrial complex and allow for more streamlined assessments:
    ``(4) The on-site energy use systems serving as the basis for the 
percent of affected boiler(s) and process heater(s) energy output in 
(1), (2) and (3) above may be segmented by production area or energy 
use area as most logical and applicable to the specific facility being 
assessed (e.g., product X manufacturing area; product Y drying area; 
Building Z).''
    We have also revised paragraph 4 of Table 3 of the final rule to 
allow a source that is operating under an energy management program 
established through energy management systems compatible with ISO 
50001, which includes the affected units, to satisfy the energy 
assessment requirement. We consider these energy management programs to 
be equivalent to the one-time energy assessment because facilities 
having these programs operate under a set of practices and procedures 
designed to manage energy use on an ongoing basis. These programs 
contain energy performance measurements and tracking plans with 
periodic reviews.
    The definition of ``Energy use system'' has also been revised in 
this final rule to clarify that energy use systems are only those 
systems using energy clearly produced by affected boilers and process 
heaters.

H. Startup and Shutdown Definitions

    A number of commenters indicated that the proposed load 
specifications (i.e., 25 percent load) within the definitions of 
``startup'' and ``shutdown'' were inconsistent with either safe or 
normal (proper) operation of the various types of boilers and process 
heaters encountered within the source category. As the basis for 
defining periods of startup and shutdown, a number of commenters 
suggested alternative load specifications based on the specific 
considerations of their boilers; other commenters suggested the 
achievement of various steady-state conditions.
    We have reviewed these comments and believe adjustments are 
appropriate in the definition of ``startup'' and ``shutdown.'' These 
adjustments are tailored for industrial boilers and are consistent with 
the definitions of ``startup'' and ``shutdown'' contained in the 40 CFR 
part 63, subpart A General Provisions. We believe these revised 
definitions address the comments and are rational based on the fact 
that industrial boilers function to provide steam or, in the case of 
cogeneration units, electricity; therefore, industrial boilers should 
be considered to be operating normally at all times steam of the proper 
pressure, temperature, and flow rate is being supplied to a common 
header system or energy user(s) for use as either process steam or for 
the cogeneration of electricity. The definitions of ``startup'' and 
``shutdown'' have been revised in the final rule as follows:
    ``Startup means either the first-ever firing of fuel in a boiler or 
process heater for the purpose of supplying steam or heat for heating 
and/or producing electricity, or for any other purpose, or the firing 
of fuel in a boiler or process heater after a shutdown event for any 
purpose. Startup ends when any of the steam or heat from the boiler or 
process heater is supplied for heating and/or producing electricity, or 
for any other purpose.''

[[Page 7147]]

    ``Shutdown means the cessation of operation of a boiler or process 
heater for any purpose. Shutdown begins either when none of the steam 
and heat from the boiler or process heater is supplied for heating and/
or producing electricity, or for any other purpose, or at the point of 
no fuel being fired in the boiler or process heater, whichever is 
earlier. Shutdown ends when there is both no steam or heat being 
supplied and no fuel being fired in the boiler or process heater.''
    The EPA is requiring sources to vent emissions to the main stack(s) 
and operate all control devices necessary to meet the normal operating 
standards under this final rule (with the exception of limestone 
injection in FBC boilers, dry scrubber, fabric filter, SNCR and SCR) 
when firing coal/solid fossil fuel, biomass/bio-based solids, heavy 
liquid fuel or gas 2 (other) gases in the boiler or process heater 
during startup or shutdown. It is the responsibility of the operators 
of affected boilers and process heaters to start their limestone 
injection in FBC boilers, dry scrubber, fabric filter, SNCR and SCR 
systems appropriately to comply with relevant standards applicable 
during normal operation. Startup ends and normal operating standards 
apply when heat or steam is supplied for any purpose.
    The EPA carefully considered fuels and potential operational 
constraints of APCD when designing its work practices for periods of 
startup and shutdown. The EPA notes that there is no technical barrier 
to burning clean fuels (e.g., natural gas, distillate oil) for longer 
portions of startup or shutdown periods at a boiler and the HAP 
emission reduction benefits warrant additional utilization of such 
fuels until the temperature and stack emissions pressure is sufficient 
to engage the APCD. The EPA is aware that SNCR and SCR systems with 
ammonia injection need to be operated within a prescribed and 
relatively narrow temperature window to provide NOX 
reductions. Further, the EPA is aware that dry scrubbers also need to 
be operated close to flue gas saturation temperature, and that fabric 
filters need to be operated at temperatures above the acid dew point. 
Because these devices have specific temperature requirements for proper 
operation, the EPA notes in its work practices that it is the 
responsibility of the operators of affected boilers and process heaters 
to start their SNCR, SCR, fabric filter and dry scrubber systems 
appropriately to comply with relevant standards applicable during 
normal operation.

I. Fuel Sampling Frequency

    The sampling frequency for gaseous fuel-fired units that elected to 
demonstrate that the unit meets the specification for mercury for the 
unit designed to burn gas 1 subcategory has been revised in this final 
rule. If the initial mercury constituents in the gaseous fuels are 
measured to be equal to or less than half of the mercury specification, 
no further sampling is required. If the initial mercury constituents 
are greater than half but equal to or less than 75 percent of the 
mercury specification, only semi-annual sampling need to be conducted. 
If the initial mercury constituents are greater than 75 percent of the 
mercury specification, monthly sampling is required.

J. Affirmative Defense

    In the proposal, we used terms such as ``exceedance'' or ``excess 
emissions'' in Sec.  63.7501, which created unnecessary confusion as to 
when the affirmative defense could be used. In the final amended rule, 
we have eliminated those terms and used the word ``violation'' to make 
clear that the affirmative defense to civil penalties is available only 
where an event that causes a violation of the emissions standard meets 
the definition of malfunction under Sec.  63.2.
    We have also eliminated the 2-day notification requirement that was 
included in 40 CFR 63.7501(b) at proposal because we expect to receive 
sufficient notification of malfunction events that result in violations 
in other required compliance reports, such as the malfunction report 
required under 40 CFR 63.7550(c). In addition, we have revised the 45-
day affirmative defense reporting requirement that was included in 40 
CFR 63.7501(b) at proposal to require sources to include the report in 
the first compliance, deviation or excess emission report due after the 
initial occurrence of the violation, unless the compliance, deviation 
or excess emission report is due less than 45 days after the violation. 
In that case, the affirmative defense report may be included in the 
second compliance, deviation or excess emission report due after the 
initial occurrence of the violation. Because the affirmative defense 
report is now included in a subsequent compliance, deviation or excess 
emission report, there is no longer a need for the proposed 30-day 
extension for submitting a stand-alone affirmative defense report. 
Consequently, we are not including this provision in the final amended 
rule. We have also re-evaluated the language concerning the use of off-
shift and overtime labor to the extent practicable and believe that the 
language is not necessary. Thus, we have deleted that phrase from 
section 63.7501(a)(2).

V. Other Actions We Are Taking

    Section 307(d)(7)(B) of the CAA states that ``[o]nly an objection 
to a rule or procedure which was raised with reasonable specificity 
during the period for public comment (including any public hearing) may 
be raised during judicial review. If the person raising an objection 
can demonstrate to the Administrator that it was impracticable to raise 
such objection within such time or if the grounds for such objection 
arose after the period for public comment (but within the time 
specified for judicial review) and if such objection is of central 
relevance to the outcome of the rule, the Administrator shall convene a 
proceeding for reconsideration of the rule and provide the same 
procedural rights as would have been afforded had the information been 
available at the time the rule was proposed. If the Administrator 
refuses to convene such a proceeding, such person may seek review of 
such refusal in the United States court of appeals for the appropriate 
circuit (as provided in subsection (b)).''
    As to the first procedural criterion for reconsideration, a 
petitioner must show why the issue could not have been presented during 
the comment period, either because it was impracticable to raise the 
issue during that time or because the grounds for the issue arose after 
the period for public comment (but within 60 days of publication of the 
final action). The EPA is denying the petitions for reconsideration on 
a number of issues because this criterion has not been met. In many 
cases, the petitions reiterate comments made on the proposed June 2011 
rule during the public comment period for that rule. On those issues, 
the EPA responded to those comments in the final rule and made 
appropriate revisions to the proposed rule after consideration of 
public comments received. It is well-established that an agency may 
refine its proposed approach without providing an additional 
opportunity for public comment. See Community Nutrition Institute v. 
Block, 749 F.2d at 58 and International Fabricare Institute v. EPA, 972 
F.2d 384, 399 (D.C. Cir. 1992) (notice and comment is not intended to 
result in ``interminable back-and-forth[,]'' nor is agency required to 
provide additional opportunity to comment on its response to comments) 
and Small Refiner Lead Phase-Down Task Force v. EPA, 705 F.2d 506, 547 
(D.C. Cir. 1983) (``notice requirement

[[Page 7148]]

should not force an agency endlessly to repropose a rule because of 
minor changes'')
    In the EPA's view, an objection is of central relevance to the 
outcome of the rule only if it provides substantial support for the 
argument that the promulgated regulation should be revised. See Union 
Oil v. EPA, 821 F.2d 768, 683 (D.C. Cir. 1987) (court declined to 
remand rule because petitioners failed to show substantial likelihood 
that final rule would have been changed based on information in 
petition). See also the EPA's Denial of the Petitions to Reconsider the 
Endangerment and Cause or Contribute Findings for Greenhouse Gases 
under Section 202 of the Clean Air Act, 75 FR at 49556, 49561 (August 
13, 2010). See also, 75 FR at 49556, 49560-49563 (August 13, 2010) and 
76 FR at 4780, 4786-4788 (January 26, 2011) for additional discussion 
of the standard for reconsideration under CAA section 307(d)(7)(B).
    We are denying reconsideration on the following 57 issues contained 
in the petitions for reconsideration because they failed to meet the 
standard described above for reconsideration under CAA section 
307(d)(7)(B). Specifically, on these issues, the petitioner has failed 
to show the following: that it was impracticable to raise their 
objections during the comment period or that the grounds for their 
objections arose after the close of the comment period; and/or that 
their concern is of central relevance to the outcome of the rule. 
Therefore, the EPA is denying the petitions for reconsideration on the 
issues for the reasons described below.
    Issue: Delist gas units.
    The petitioners (API, NPRA) requested that the EPA remove gas-fired 
units from the section 112(c) list of source categories for which the 
EPA is required to establish emissions standards under section 112(d). 
The EPA is denying the petition for reconsideration for the following 
reasons. First, the issue is outside the scope of this rulemaking, 
which establishes emissions standards for new and existing units within 
the major source boilers and process heaters source category. The EPA 
did not solicit comment in the proposed rule regarding the scope of the 
subcategory. Further, petitioners provide no information to support 
delisting gas units under section 112(c)(9), which requires the EPA to 
make certain findings before delisting any sources. In addition, the 
petition does not address the D.C. Circuit's decision in NRDC v. EPA, 
489 F.3d 1364 (2007), regarding the EPA's ability to delist 
subcategories of a source category pursuant to section 112(c)(9). For 
these reasons, the petitions do not provide support for the argument 
that the regulation should be changed. For this reason, the petition 
does not demonstrate that the issue is of central relevance to the 
outcome of the final rule and the EPA is denying the request for 
reconsideration.
    Issue: Exempt natural gas hot water heaters with tanks greater than 
120 gallons.
    The petitioner (AIF) requested that the EPA exempt natural gas hot 
water heaters with tanks greater than 120 gallons. While the EPA 
disagrees with the petitioner regarding whether such units should be 
subject to the emissions standards in this rule, the petitioner has not 
demonstrated that it lacked the opportunity to comment on whether such 
units should be required to meet emissions standards. The EPA proposed 
work practice standards for such units in its June 2010 proposal, and 
the petitioner had the opportunity to comment on whether such standards 
should be applied to such units at all. Therefore, the EPA is denying 
the request for reconsideration.
    Issue: Exempt natural gas and distillate oil-fired circulating hot 
water systems with a design capacity of 10 MMBtu/hr or less.
    The petitioner (CIBO) requested that the EPA exempt natural gas and 
distillate oil-fired circulation hot water systems that are not greater 
than 10 MMBtu/hr. While the EPA disagrees with the petitioner regarding 
whether such units should be subject to the emissions standards in this 
rule, the petitioner has not demonstrated that it lacked the 
opportunity to comment on whether such units should be required to meet 
emissions standards. The EPA proposed emissions standards for such 
units, and the petitioner had the opportunity to comment on whether 
such standards should be applied to such units at all. In addition, the 
petition does not provide any information to demonstrate that these 
units should be delisted pursuant to section 112(c)(9). Therefore, the 
EPA is denying the request for reconsideration.
    Issue: Confirm in definitions that open flame heaters (e.g., 
asphalt tank heaters) are not process heaters.
    The petitioners (API, NPRA) requested that the EPA clarify in the 
definition of ``process heater'' that open flame heaters do not meet 
the definition. While the EPA disagrees with the petitioners whether 
clarification is needed in regards to open flame heaters, the 
petitioners have not demonstrated that it lacked the opportunity to 
comment on the proposed definition. The definition that the EPA 
proposed clearly states that process heaters are enclosed devices in 
which the combustion gases do not come into contact with process 
materials, and as such, does not include open flame heaters. Therefore, 
the EPA is denying reconsideration.
    Issue: For blast furnace fuel-fired boiler exemption, compute the 
90 percent BFG by volume threshold to exclude periods of BFG 
curtailment.
    The petitioners (AISI, ACCCI) requested that the EPA revise the 
exemption for BFG fuel-fired boilers to exclude periods of BFG 
curtailment. While the EPA disagrees with the petitioners regarding 
revising the exemption, the petitioners have not demonstrated that it 
lacked the opportunity to comment on the proposed exemption for BFG 
fuel-fired boilers. The EPA proposed the exemption for these boilers, 
and petitioners therefore had the opportunity to comment on whether the 
exemption should apply to periods of BFG curtailment. Therefore, the 
EPA is denying the request for reconsideration.
    Issue: Exempt boilers whose flue gases are used in direct-fired 
process heaters subject to other NESHAP.
    The petitioner (CMI) requested that the EPA exempt from the rule 
boilers whose flue gases are used in direct-fired process heaters that 
are subject to other NESHAP. The final rule does not apply to such 
units if they are subject to another NESHAP. The EPA does not see a 
need for further clarification. Since the final rule does in fact 
exempt these units, the EPA is denying the request for reconsideration.
    Issue: Work practice standards do not meet EPA obligations under 
112(c)(6).
    The petitioner (Sierra Club) requested that the EPA establish 
numeric emissions limits for Gas 1 units rather than work practice 
standards. Specifically, the petitioner alleges that the work practice 
standards do not meet the EPA's obligations under section 112(c)(6) of 
the CAA, and that it was not the case that data were below the 
detection level for all HAP emitted from these units. The EPA is 
denying the request for reconsideration on this issue. While the EPA 
disagrees with the petitioner's arguments regarding the legal authority 
to establish work practice standards for Gas 1 units and the basis for 
such standards, the petitioner has not demonstrated that it lacked the 
opportunity to comment on this issue. The EPA proposed work practice 
standards for Gas 1 units and explained in the proposal its rationale 
for such standards, including the fact that a significant portion of 
the

[[Page 7149]]

emissions data were below the detection level. 75 FR at 32024-25. 
Therefore, the petitioner had the opportunity to comment on this issue, 
and did in fact submit comments regarding the EPA's legal authority to 
establish work practice standards for Gas 1 units. Therefore, the EPA 
is denying reconsideration on this issue.
    Issue: Work practices for small units are not justified by 112(h) 
since small units were not given their own subcategory.
    The petitioner (Sierra Club) requested that the EPA require small 
units, those having a heat input capacity of less than 10 MMBtu/hr, to 
meet numeric emissions limits rather than work practice standards. The 
EPA is denying the request for reconsideration on this issue because 
the petitioner has not demonstrated that it lacked the opportunity to 
comment on this issue. The EPA proposed work practice standards for 
these units and explained in the proposal its rationale for such 
standards. 75 FR at 32024-25. The EPA did in fact receive comments 
regarding the proposed standards, to which it responded in the final 
rule. 76 FR at 15640. Moreover, the EPA notes that nothing in section 
112(h) limits the EPA's discretion to establish work practice standards 
to the establishment of such standards for an entire category or 
subcategory. Therefore, the EPA is denying the request for 
reconsideration.
    Issue: PM is not an adequate surrogate for non-mercury metallic 
HAP.
    The petitioner (Sierra Club) requested that the EPA remove the PM 
standard as a surrogate for non-mercury metallic HAP and instead adopt 
a numeric limit for non-mercury metallic HAP because PM is not an 
appropriate surrogate. The EPA is denying the request for 
reconsideration on this issue. While the EPA disagrees with the 
petitioner's argument regarding the suitability of PM as a surrogate 
for non-mercury metallic HAP, the petitioner has not demonstrated that 
it lacked the opportunity to comment on this issue. The EPA proposed PM 
standards as a surrogate for non-mercury metallic HAP and explained in 
the proposal the agency's basis for concluding that PM was an 
appropriate surrogate. 75 FR at 32018. Therefore, the EPA is denying 
the request for reconsideration.
    Issue: Establish direct limits on organics or select a surrogate 
besides CO.
    The petitioner (Sierra Club) requested that the EPA remove the CO 
standard as a surrogate for organic HAP and instead adopt a numeric 
limit for these HAP, because CO is not an appropriate surrogate. The 
EPA is denying the request for reconsideration on this issue. While the 
EPA disagrees with the petitioner's argument regarding the suitability 
of CO as a surrogate for organic HAP, the petitioner has not 
demonstrated that it lacked the opportunity to comment on this issue. 
The EPA proposed CO standards as a surrogate for organic HAP and 
explained in the proposal the agency's basis for concluding that CO was 
an appropriate surrogate. 75 FR at 32018. The EPA received comments on 
this issue, including comments stating that CO is not an appropriate 
surrogate for organic HAP. Therefore, the EPA is denying the request 
for reconsideration.
    Issue: Adopt an alternative THC emission standard.
    The petitioner (CIBO) requested that the EPA adopt a THC emissions 
standard as an alternative to the CO standard. The EPA is denying the 
request for reconsideration on this issue. While the EPA disagrees with 
the petitioner's argument regarding whether a THC alternative standard 
is appropriate as a surrogate for non-dioxin organic HAP, the 
petitioner has not demonstrated that it lacked the opportunity to 
comment on this issue. The EPA raised in the proposal the possibility 
of THC as a surrogate for non-dioxin organic HAP, and explained why the 
use of CO as a surrogate was preferable. 75 FR at 32018. In addition, 
the EPA did not receive any comments or data during the public comment 
period on the proposed rule that would have enabled the agency to 
establish a THC alternative standard, including THC emissions data, nor 
did the petitioner provide any such data. Therefore, the petition does 
not provide substantial support for its argument that the final rule 
should be changed. For these reasons, the EPA is denying the petition 
for reconsideration on this issue.
    Issue: Regulation of Total dioxin/furans exceeds statutory 
authority as only 2 compounds are in 112(b)(1).
    The petitioners (AISI, ACCCI, AF&PA) alleged that the EPA lacks 
statutory authority to regulate total dioxin/furans under CAA section 
112, and that the EPA's response in the final rule explaining why it is 
issuing a total dioxin/furan standard was not a logical outgrowth of 
the proposed rule. The EPA is denying the request for reconsideration 
on this issue. First, the EPA disagrees that the final rule is not a 
logical outgrowth of the proposal. The EPA proposed emissions standards 
for total dioxin/furans and adopted a final emissions standard for the 
same pollutant. Therefore, the commenter had the opportunity to provide 
its views during the public comment period regarding the EPA's proposed 
emissions standard, including its views regarding the EPA's authority 
to regulate the pollutant at issue. The fact that the EPA responded to 
those comments does not mean that the petitioner lacked the opportunity 
to comment--in fact, the petitioner did provide such comments. 76 FR at 
15640. For this reason, the EPA is denying the petition for 
reconsideration.
    Issue: HCl is an inadequate surrogate for all acid gases.
    The petitioner (Sierra Club) requested that the EPA remove the HCl 
standard as a surrogate for acid gases and instead adopt a numeric 
limit for these HAP, because HCl is not an appropriate surrogate. The 
EPA is denying the request for reconsideration on this issue. While the 
EPA disagrees with the petitioner's argument regarding the suitability 
of HCl as a surrogate for acid gases, the petitioner has not 
demonstrated that it lacked the opportunity to comment on this issue. 
The EPA proposed HCl standards as a surrogate for acid gases and 
explained in the proposal the agency's basis for concluding that HCl 
was an appropriate surrogate. 75 FR at 32018. While the EPA had 
emission data for HCl from hundreds of affected units upon which to 
establish standards, the EPA did not have sufficient data on the other 
acid gases to do so (hydrogen fluoride, hydrogen cyanide and chlorine). 
The petitioner did not refer to any such data and, therefore, the issue 
is not of central relevance to the outcome of the final rule. 
Therefore, the EPA is denying the request for reconsideration.
    Issue: Establish work practice for other organic HAP instead of 
using CO as a surrogate.
    The petitioners (AMP, JELD-WEN) requested that the EPA adopt a work 
practice standard for organic HAP rather than a numeric emissions limit 
based on CO as a surrogate for organic HAP. The EPA is denying the 
request for reconsideration on this issue. While the EPA disagrees that 
a work practice standard is appropriate for such HAP for the 
subcategories for which the EPA adopted a numeric CO limit in the final 
rule, the petitioners have not demonstrated that they lacked the 
opportunity to comment on this issue. The EPA proposed numeric CO 
limits rather than a work practice, and the petitioners had the 
opportunity to provide their views during the public comment period on 
the proposed rule regarding why it believed a work practice standard 
should instead be

[[Page 7150]]

finalized. Therefore, the EPA is denying the petition for 
reconsideration.
    Issue: Allow health based compliance alternatives for HCl, other 
acid gases and manganese.
    The petitioners (AMP, AF&PA, AHFA, AISI, ACCCI, RPU, CIBO) 
requested that the EPA adopt a HBES for HCl and other acid gases as 
well as for manganese, pursuant to section 112(d)(4). The petitioners 
also requested that the EPA grant reconsideration on this issue to 
better address the comments and data submitted during the public 
comment period for the proposed rule. The EPA is denying the request 
for reconsideration of this issue. The EPA did not propose a HBES for 
any pollutants, but did solicit public comment on such standards, 
explaining its concerns regarding health-based standards, including the 
lack of available data on which to base such standards. 75 FR at 32030. 
The EPA received comments addressing those concerns and responded to 
them in the final rule. 76 FR at 15642. Therefore, the petitioners have 
not demonstrated that it lacked the opportunity to comment on this 
issue. Further, the EPA received no data during the public comment 
period for the proposed rule on which it could base a HBES for HCl, 
other acid gases or manganese. Therefore, the petitions do not provide 
substantial support to demonstrate that the final rule should be 
changed. For these reasons, the EPA is denying the petition for 
reconsideration.
    Issue: Provide additional compliance alternatives according to 
Executive Order 13563 (additional subcategories and HBES).
    The petitioner (AHFA) requested that the EPA provide additional 
compliance alternatives in the final rule pursuant to Executive Order 
13563 (Improving Regulation and Regulatory Review), including HBES. The 
EPA is denying the request for reconsideration on this issue because it 
is not of central relevance. First, nothing in Executive Order 13563 
affects the EPA's discretion to establish HBES under the CAA. 
Additionally, the petition does not provide any information to address 
our concerns regarding HBES or data to establish such standards.
    Issue: Remove energy assessment requirements.
    The petitioners (AHFA, AISI, ACCCI, API, NPRA, AIF, CIBO, AF&PA, 
U.S. Sugar) requested that the EPA remove from the final rule the 
requirement that existing sources conduct an energy assessment. The EPA 
is denying the request for reconsideration on this issue. The EPA 
proposed an energy assessment requirement as a beyond-the-floor 
standard, and petitioners commented on that proposal. The EPA addressed 
those comments in the final rule, and petitioners have not demonstrated 
that they lacked the opportunity to comment on whether the EPA should 
require an energy assessment, including the EPA's legal authority to do 
so. 76 FR at 15631. Therefore, the EPA is denying the petition for 
reconsideration. The EPA continues to believe that an energy assessment 
is not only authorized by the CAA but required as a cost-effective 
beyond-the-floor standard in accordance with section 112(d)(2).
    Issue: Require energy assessment to be conducted every 5 years.
    The petitioner (Washington Dept. of Ecology) requested that the EPA 
require more frequent energy assessments. The EPA proposed a one-time 
assessment (75 FR at p. 32036) and the petitioner has not demonstrated 
it lacked the opportunity to comment on the frequency of the assessment 
requirement. Therefore, the EPA is denying the petition.
    Issue: Modify cost analysis to include potential fuel savings from 
implementing assessment findings.
    The petitioners (AIE, USCHPA) requested that the EPA modify its 
cost impacts analysis to include potential fuel savings from 
implementing energy assessment findings. The EPA is denying the 
petition. The impacts analysis, including specific mention of how cost 
savings for energy assessments were handled quantitatively, was 
explained in the proposal (see 75 FR 32026), and the petitioner 
therefore had the opportunity to comment on this issue. For this 
reason, the EPA is denying the petition for reconsideration on this 
issue.
    Issue: Reconsider definition of ``cost effective.''
    The petitioners (AIE, USCHPA) requested that the EPA reconsider the 
definition of ``cost-effective'' in the final rule. The EPA is denying 
the request for reconsideration on this issue. The EPA proposed to 
define cost-effective energy conservation measures as any measure with 
return of investment period of two years or less. 75 FR at 32036. The 
petitioners have not demonstrated it lacked the opportunity to comment 
on the proposed definition. Therefore, the EPA is denying the petition 
for reconsideration.
    Issue: Establish work practice for other organic HAP instead of 
using CO surrogate.
    The petitioners (AMP, JELD-WEN) requested that the EPA establish 
work practice standards for controlling organic HAP instead of using CO 
as a surrogate for organic HAP and establishing CO emission limits. The 
EPA is denying the request for reconsideration on this issue. Use of CO 
as a surrogate for organic HAP was subject to notice and comment. (75 
FR 32018, 75 FR 32041). Responses to comment on this topic were 
provided in RTC document, Volume 2, EPA-HQ-OAR-2002-0058-3289, see 
section ``Choice of Regulated Pollutants: THC vs. CO vs. Other Organic 
HAP''.
    Issue: Provide alternative format for units of measure for CO 
emission limits to allow sources to use their existing monitoring 
equipment.
    The petitioners (UARG, CIBO) requested that the EPA provide an 
alternative format (ppm at X percent CO2) for units of 
measure for CO emissions in addition to ppm at 3 percent oxygen. The 
EPA is denying the petition because the petitioners do not demonstrate 
that it was impracticable to comment on this issue. The format for 
units of measure for the limits was provided in the proposed rule, and 
petitioners could have commented on whether the proposed units were 
appropriate.
    Issue: New source emission limits are unachievable and the EPA 
should collect additional fuel variability data from top performing 
units to adjust the limits.
    The petitioner (AF&PA) requested that the EPA adjust the emissions 
limits for new sources by collecting additional data from the best 
performing units that they believed would result in increased 
variability. The petitioners have not demonstrated that they lacked the 
opportunity to comment. We proposed standards based on the data we had, 
including data collected during the ICR process in which petitioners 
participated, and that data were available for public review. 
Therefore, petitioners could have commented on this issue. Second, the 
CAA requires that we base the standards on the sources for which we 
have emissions information. Petitioners are always free to provide more 
information to us and the EPA specifically requested new data at each 
stage of the rulemaking to support the development of emission limits 
for each subcategory. (75 FR 32041, 76 FR 28663, 76 FR 80612). The EPA 
has incorporated revised data corrections or new data submittals in its 
analysis for the final rule. The EPA is denying the request for 
reconsideration.
    Issue: Adjust the methodology for computing MACT floors to address 
statistical errors and variability concerns.
    The petitioners (AISI, ACCCI, AF&PA) requested that the EPA adjust 
the

[[Page 7151]]

methodology for computing MACT floors to address statistical errors and 
variability concerns, including: (1) Dataset reflects the ``best of the 
best'' units; (2) misapplication of statistical formulae to address 
distribution, confidence limits, and variability; and (3) failure to 
address variability in emissions from one unit over time. The methods 
used to compute the MACT floors were subject to notice and comment. 
Where new data or data corrections have been submitted that might alter 
data distributions, identifying best performers or application of fuel 
variability factors, these changes have been made in the final rule, 
but the general methodology remains the same. See Solite Corp. v. EPA, 
952 F.2d 473, 485 (D.C. Cir. 1991) (public had sufficient notice of 
final rule threshold calculations where methodology did not change 
significantly from proposed rule). The EPA explained the MACT floor 
methodology in the proposed rule, and addressed comments received on 
the proposed methodology in the final rule (75 FR 32019-26, 32027-29, 
76 15621-30, 76 FR 80614). Therefore, the EPA is denying the request 
for reconsideration.
    Issue: Modify the basis for ranking the top performing units.
    The petitioner (WEPCO) requested that the EPA modify the basis for 
ranking the top performing units, especially for new units, according 
to the average performance of the unit. The EPA is denying the 
petition. The methods used to rank units to establish the MACT floors 
were subject to notice and comment. The EPA explained its methodology 
in the proposed rule and addressed comments received on the ranking of 
data for computing the MACT floor in the final rule (75 FR 32019-26, 
32027-29, 76 FR 15627).
    Issue: Do not use a pollutant-by-pollutant approach to establish 
MACT floors.
    The petitioners (AISI, ACCCI, AF&PA) requested that the EPA not use 
a pollutant-by-pollutant approach to establish MACT floors. The 
petitioners stated that this method is not a reasonable interpretation 
of Section 112(d)(3) of the CAA and that MACT floors should reflect 
levels achieved in practice, not aspirational controls. The EPA is 
denying the petition for reconsideration on this issue because it does 
not demonstrate that it was impracticable to comment on the issue. The 
EPA proposed MACT floors based on the pollutant-by-pollutant 
methodology, and therefore petitioners could, and in fact did, provide 
comments opposing this approach. See 75 FR 32021, 32029. The EPA 
addressed comments received on this approach in the final rule (76 FR 
15621-23). Therefore, the EPA is denying the petition.
    Issue: Revise approach to establish MACT floors where there is non-
detect data.
    The petitioner (Sierra Club) requested that the EPA not use the 
approach it used in the final rule based on the representative 
detection level (RDL) to establish MACT floors because it does not 
reflect actual emissions of any source within the subcategory. Further, 
the petitioner questioned the basis of the selected detection level, 
and whether or not other variability adjustments (e.g., UPL analysis) 
sufficiently account for measurement imprecision. The EPA is denying 
the petition. The three times representative detection level approach 
was subject to notice and comment. The EPA explained its rationale for 
this approach in the proposed rule (75 FR 32021) and responded to 
comments received in the final rule (76 FR 15623, 76 FR 80611).
    Issue: The approach used to set MACT floor limits for dioxin/furan 
emissions is flawed and the EPA should establish an isomer-specific 
approach.
    The petitioner (WEPCO) requested that the EPA establish an isomer-
specific approach for dioxin/furan emissions because the three times 
detection level approach for dioxin/furan emissions is flawed. The EPA 
is denying the petition. This approach was subject to notice and 
comment. Rationale and responses to comments on this approach were 
provided at (75 FR 32021, 32041, 76 FR 15623). Further, the methods for 
establishing a representative detection level for dioxin/furan have 
been revised to account for the sensitivity of individual isomers, see 
rationale provided at (76 FR 80606).
    Issue: Incorporate a fuel variability factor for PM based on the 
ash content of the fuel used by best performing units.
    The petitioners (WEPCO, CIBO) requested that the EPA incorporate a 
fuel variability factor for PM based on the ash content of the fuel 
used by best performing units. The MACT floor methodology was explained 
in the June 4, 2010 proposal which included fuel variability factors 
that did not reflect the ash content of the fuel. Therefore, the 
petitioner could have commented recommending that the EPA do so, and, 
in fact, comments were provided on this issue. The EPA is denying the 
petition for reconsideration on this issue because it does not 
demonstrate that it was impracticable to comment on the issue. 
Responses to comment on this topic were provided in RTC document, 
Volume 1, EPA-HQ-OAR-2002-0058-3289, see section ``MACT Floor 
Methodology: Fuel Analysis Variability''.
    Issue: Allow energy assessors to determine the time needed to 
conduct assessment.
    The petitioner (Washington Dept. of Ecology) requested that the EPA 
allow the energy assessor to determine the time needed to conduct the 
energy assessment. The EPA is denying the petition. The duration of 
energy assessments was subject to notice and comment and the duration 
remains up to the affected source. Specific concerns with maximum 
duration requirements included in the March 21, 2011 final rule were 
clarified in the December 23, 2011 proposed notice of reconsideration. 
(76 FR 80615)
    Issue: The unit designed to burn gas 1 subcategory should allow for 
limited use of liquid fuels.
    The petitioners (ACC, CEG, API, NPRA) requested that the EPA allow 
units in the Gas 1 subcategory for limited use of liquid fuels; for 
example, units with a federally enforceable permit on back up fuels or 
units burning 10 percent or less of its heat input from liquid fuels 
should qualify as gas 1 units. The EPA is denying the petition because 
it does not demonstrate that it was impracticable to comment on the 
issue. The EPA proposed definitions of the various subcategories, and 
petitioners had the opportunity to comment on those definitions, 
including the proposed definition of the Gas 1 subcategory which did 
allow for the limited use of liquid fuels. The EPA addressed comments 
received on this issue in the final rule (76 FR 15620).
    Issue: The unit designed to burn gas 1 subcategory should 
automatically include other gaseous fuels such as petrochemical process 
gas and landfill gas.
    The petitioners (ACC, AIF, WM) requested that the EPA redefine the 
unit designed to burn gas 1 subcategory to automatically include other 
gaseous fuels such as petrochemical process gas and LFG, especially 
when the LFG is routed to a treatment system prior to use or sale. The 
EPA proposed definitions of units designed to burn gas 1 and units 
designed to burn gas 2 (other), and therefore the petitioner had the 
opportunity to comment on these definitions and to recommend that other 
gases be included in the definition of the Gas 1 subcategory (75 FR 
32017, 32065). The EPA addressed comments received on this issue in the 
final rule (76 FR 15638). Therefore, the EPA is denying the petition.

[[Page 7152]]

    Issue: Reconsider the emission standards established for the unit 
designed to burn gas 2 subcategory.
    Petitioners (AIF, CIBO, WM, CEG) requested that the EPA reconsider 
the emission standards for the unit designed to burn gas 2 subcategory 
in light of what they feel was a limited dataset and lack of data from 
a diverse set of fuel types. The EPA is denying the petition. The MACT 
floor methodology was open to notice and comment in the June 4, 2010 
proposal. The EPA proposed emissions standards for this subcategory and 
the petitioners had an opportunity to comment on the proposed standards 
and the data on which the standards were based. The EPA further notes 
that the CAA requires that the MACT standards be based on the best 
performing sources for which the Administrator has emissions 
information.
    Issue: Adjust the ``metal process furnaces'' subcategory definition 
to include any gas-fired process furnace.
    The petitioners (AISI, ACCCI) requested that the EPA adjust the 
``metal process furnaces'' subcategory definition to include any gas-
fired process furnace. The EPA is denying the petition. The definition 
of the subcategory for metal process furnaces was subject to notice and 
comment. (75 FR 32064, 76 FR 15620).
    Issue: The designed to burn rationale for subcategorization is 
arbitrary.
    The petitioner (Sierra Club) alleged that the designed to burn 
rationale for subcategorization is arbitrary, especially considering 
the large number of co-fired units in the inventory. The EPA proposed 
subcategories based on boiler design, and the petitioner has not 
demonstrated that it was impracticable to comment on the issue. In 
fact, the petitioner did submit comments on the proposed rule opposing 
the EPA's proposed subcategorization approach. Therefore, the EPA is 
denying the petition.
    Issue: The EPA should consider exempting units from NSR.
    The petitioners (MSU, PSU, Purdue, Citizens Thermal Energy) 
requested that the EPA consider exempting units from NSR who switch 
fuels, install pollution controls, or construct energy efficiency 
projects to meet the requirements of this rule because complying with 
the rule requirements will trigger NSR. The EPA is denying the 
petition. The applicability of NSR is outside the scope of this 
rulemaking. Moreover, it was not impracticable to comment on this issue 
during the 2011 rulemaking, in fact, comments were submitted on this 
issue, to which the EPA responded. See RTC document, Volume 2, EPA-HQ-
OAR-2002-0058-3289, DCN EPA-HQ-OAR-2002-0058-2729.1, excerpt 17.
    Issue: Remove the 10 percent penalty for sources opting to use the 
emission averaging compliance alternative.
    The petitioners (AMP, MSU, PSU, Purdue, RPU, U.S. Sugar, Citizens 
Thermal Energy) requested that the EPA remove the 10 percent penalty 
for sources opting to use the emission averaging compliance 
alternative. The EPA is denying the petition. The EPA proposed an 
emissions averaging approach that included the 10 percent adjustment 
factor. (75 FR 32035) Therefore, the petition does not demonstrate that 
it was impracticable to comment on this issue. Responses to comment on 
this topic were provided in RTC document, Volume 2, EPA-HQ-OAR-2002-
0058-3289, see section ``Emissions Averaging.''
    Issue: Allow emissions averaging across subcategories.
    The petitioners (MSU, PSU, Purdue, RPU, Citizens Thermal Energy) 
requested that the EPA allow emissions averaging across subcategories. 
The EPA is denying the petition. The EPA proposed an emissions 
averaging approach that did not allow averaging across subcategories, 
and petitioners therefore had the opportunity to comment recommending 
that the EPA allow such averaging. Responses to comment on this topic 
were provided in RTC document, Volume 2, EPA-HQ-OAR-2002-0058-3289, DCN 
EPA-HQ-OAR-2002-0058-3213.1, excerpt 175.
    Issue: Allow a source's actual heat input instead of the maximum 
design heat input to be used in the emissions averaging provisions.
    The petitioner (CIBO) requested that the EPA allow a source's 
actual heat input instead of the maximum design heat input to be used 
in the emissions averaging provisions of the final rule. The EPA 
proposed an emissions averaging approach that was based on the maximum 
rated heat input capacity, and petitioners therefore had the 
opportunity to comment recommending that the EPA base the averaging on 
actual heat input. Therefore, the EPA is denying the petition.
    Issue: Reduce stack testing frequency to once every five years to 
reduce burden on facilities.
    The petitioners (ACC, CIBO, JELD-WEN) requested that the EPA reduce 
stack testing frequency to once every 5 years and rely on the extensive 
set of continuous parameter monitoring in order to reduce burden on 
facilities. The EPA is denying the petition. The EPA proposed to 
require stack testing every year. The petition does not demonstrate 
that it was impracticable to comment on this issue, and the petitioners 
could have submitted comments requesting less frequent stack testing.
    Issue: Incorporate detailed fuel sampling procedures using 
incorporation by reference mechanisms instead of detailing sampling 
procedures in the regulatory language.
    The petitioner (CIBO) requested that the EPA incorporate detailed 
fuel sampling procedures using incorporation by reference mechanisms 
and citing credible literature (e.g., American Society for Testing and 
Materials) instead of detailing sampling procedures in the regulatory 
language since sampling procedures are subject to change over time. The 
EPA is denying the petition because the petitioner has not demonstrated 
that it was impracticable to comment on this issue. The EPA proposed 
fuel sampling procedures in the regulatory text in the June 4, 2010 
proposal, and the petitioner therefore had the opportunity to comment 
recommending its preferred approach.
    Issue: Remove the advanced submittal requirement for site-specific 
fuel monitoring plans before each analysis.
    The petitioner (UARG) requested that the EPA remove the advanced 
submittal requirement for site-specific fuel monitoring plans before 
each analysis, especially if monthly frequency is maintained. If the 
fuel monitoring plan requirement remains, the petitioner requests that 
the EPA remove the requirement to report things that might change, such 
as unanticipated fuel use (based on unanticipated fuel changes). The 
EPA is denying the petition and disagrees with the commenter. First, 
the EPA proposed a fuel monitoring plan, and petitioners had the 
opportunity to comment on the plan requirement. The final rule requires 
submittal of a fuel monitoring plan 60 days before demonstrating 
initial compliance. The rule does not require re-submittal of this plan 
before each monthly analysis, see 40 CFR section 63.7521(b)(1).
    Issue: Allow EPA Method 5B to demonstrate compliance with PM 
emission limits.
    The petitioner (UARG) requested that the EPA allow EPA Method 5B to 
demonstrate compliance with PM emission limits. The EPA is denying the 
petition because it does not demonstrate that it was impracticable to 
comment on this issue. The EPA proposed methods to demonstrate 
compliance in the June 4, 2010 proposal and did not propose to allow 
Method 5B for PM compliance demonstrations. Therefore, the petitioner 
had the opportunity to submit comments recommending that the EPA allow 
the use of this method. For this

[[Page 7153]]

reason, the EPA is denying the petition on this issue.
    Issue: Remove or make references to Methods 2, 2F, 2G and 4 
optional.
    The petitioner (UARG) requested that the EPA remove or make 
references to EPA Methods 2, 2F, 2G and 4 optional. The EPA is denying 
the petition because it does not demonstrate that it was impracticable 
to comment on this issue. The EPA proposed methods to demonstrate 
compliance in the June 4, 2010 proposal and did not propose to make EPA 
Methods 2, 2F, 2G and 4 optional. Therefore, the petitioner had the 
opportunity to submit comments recommending that the EPA make the use 
of these methods optional. For this reason, the EPA is denying the 
petition on this issue.
    Issue: Allow sources to petition for alternative PM monitoring 
requirements based on source-specific limitations.
    The petitioner (CEG) requested that the EPA allow sources to 
petition for alternative PM monitoring requirements based on source-
specific limitations (e.g., common stacks with more than one 
subcategory). The EPA is denying this petition because it is not of 
central relevance to this rulemaking. The General Provisions at 40 CFR 
63.8 allow sources to petition the EPA for alternative monitoring 
plans. Therefore, no such provision is needed in this final rule.
    Issue: Allow sources with overlapping CEMS regulations to comply 
with existing QA/QC plans or 40 CFR part 75 Appendices A and B.
    The petitioners (CIBO, CMI) requested that the EPA allow sources 
with overlapping CEMS regulations to comply with existing QA/QC plans 
or 40 CFR part 75 Appendices A and B. The EPA is denying this petition 
because it is not of central relevance to this rulemaking.
    Issue: No justification or discussion was provided on why the EPA 
selected 12 hours as the averaging time period and also why the EPA 
selected block averages instead of rolling averages.
    The petitioner (Sierra Club) alleges that the EPA provided no 
justification or discussion explaining why the EPA selected 12 hours as 
the averaging time period and why the EPA selected block averages 
instead of rolling averages for parameter monitor. The petitioner 
requested that the EPA clarify that the averaging times for continuous 
parameter monitoring should be the same as the averaging times during 
the most recent performance test. Averaging times were open to notice 
and comment in the June 4, 2010 proposal. In the June 2010 proposal, we 
required that parameters be set based on 4-hour block averages during 
the compliance test, and that continuous compliance be demonstrated by 
monitoring 12-hour block average values for most parameters. We 
selected this averaging period to reflect operating conditions during 
the performance test to ensure the control system is continuously 
operating at the same or better level as during a performance test 
demonstrating compliance with the emission limits. Therefore, the EPA 
is denying the petition.
    Issue: The EPA position regarding treatment of ``out-of-control'' 
and ``maintenance'' periods as deviations is not supported or 
explained.
    The petitioner (UARG) alleges that the EPA position regarding 
treatment of ``out-of-control'' and ``maintenance'' periods as 
deviations is not supported or explained. The petitioner requested that 
the EPA revise the definition of ``deviation'' to be consistent with 
how deviation is treated with respect to CO CEMS and CPMS. The EPA is 
denying the petition. The definition of deviations was open to notice 
and comment in the June 4, 2010 proposal.
    Issue: Require checks of pressure monitoring taps only if reading 
is abnormal.
    The petitioner (CMI) requested that the EPA require checks of 
pressure monitoring taps only if reading is abnormal. The requirement 
to check pressure tap pluggage daily was open to notice and comment in 
the June 2010 proposal. In addition, the EPA is denying this petition 
because it is not of central relevance to this rulemaking.
    Issue: The EPA has not sufficiently correlated emission limits to 
operating parameters and should not set enforceable limits on maximum 
and minimum control device operating parameters.
    The petitioners (UARG, AMP, CIBO) alleges that the EPA has not 
sufficiently correlated emission limits to operating parameters and 
requested the EPA not to set enforceable limits on maximum and minimum 
control device operating parameters. One petitioner (CIBO) requested 
that the rule should allow sources to set their own ESP secondary 
voltage requirement based on load and coal quality since power 
consumption by an ESP is influenced by factors other than operating 
load, including ESP design, amount of PM collected, and resistivity of 
the PM. Other petitioners (UARG and AMP) also indicate that the limits 
set on control devices inhibit the flexibility to operate control 
devices with a margin of safety. The EPA is denying the petition. 
Operating limits were open to notice and comment in the June 4, 2010 
proposal.
    Issue: The EPA should delay incorporating PS 17 in this rule until 
the revisions for PS 17 are completed.
    The petitioner (UARG) requested that the EPA delay incorporating PS 
17 in this rule, which outlines how to select and install CPMS, until 
the revisions for PS 17 are completed.
    The EPA is denying this petition. The final rule did not 
incorporate PS 17, or any other PS, in the provision regarding 
selection and installation of CPMS and ongoing quality assurance of 
data from CPMS. Comments related to revising PS 17 are outside the 
scope of this rulemaking. (RTC document, Chapter 11, EPA-HQ-OAR-2002-
0058-3289, DCN EPA-HQ-OAR-2002-0058-2960.1, excerpt 150).
    Issue: The EPA should not set an enforceable operating limit on 
opacity.
    The petitioner (UARG) alleged that there is insufficient 
correlation between opacity and PM emissions and requested that the EPA 
not set an enforceable operating limit on opacity. The EPA is denying 
the petition. The EPA proposed opacity limits in the June 4, 2010 
proposal and the petitioner therefore had the opportunity to comment on 
the proposed limits, including comments requesting that no limit be 
established.
    Issue: Update outdated BLDS Guidance.
    The petitioner (UARG) requested that the EPA update the outdated 
BLDS Guidance that is currently incorporated by reference. The EPA is 
denying this petition. The current guidance document is the most recent 
guidance available and comments related to revising the guidance 
document are outside the scope of this rulemaking. (RTC document, 
Chapter 11, EPA-HQ-OAR-2002-0058-3289, DCN EPA-HQ-OAR-2002-0058-2997.1, 
excerpt 10).
    Issue: The EPA should reconsider emission limits for HCl on coal-
fired boilers using a hot-side ESP for particulate control.
    The petitioners (MSU, PSU, Purdue, Citizens Thermal Energy) 
requested that the EPA reconsider emission limits for HCl on coal-fired 
boilers using a hot-side ESP for particulate control. The petitioners 
are unaware of any HCl control devices that are compatible with a hot-
side ESP. The EPA is denying the petition. The basis for 
subcategorization was subject to notice and comment. The EPA did not 
propose a separate subcategory for such units, and the petitioner could 
have commented recommending that the agency do so. (75 FR 32012, 76 FR 
15617-18, 76 FR 80607) Further, the EPA disagrees with the petitioner 
that the subcategories

[[Page 7154]]

could be based on the level of controls installed on the unit.
    Issue: The EPA should change electronic reporting requirements to 
avoid WebFIRE and ERT shortcomings.
    The petitioner (UARG) requested that the EPA change the electronic 
reporting requirements to avoid WebFIRE and ERT shortcomings. The 
petitioner requested that to meet the EPA's obligations under the 
Paperwork Reduction Act the EPA specify each individual data item 
requested in the ERT. The petitioner also requests that the EPA explain 
how the ERT electronic signature mechanisms will meet the requirements 
of the Cross-Media Electronic Reporting Rule.
    The EPA is denying the petition because it does not demonstrate 
that it was impracticable to comment on this issue. The EPA proposed to 
require the use of the ERT and WebFIRE, and the petitioner therefore 
had the opportunity to comment on any concerns with the proposed 
approach.
    Issue: Eliminate gas curtailment notification requirements or 
adjust the frequency of these notifications to be consistent with the 
reporting requirements in the Title V program.
    The petitioner (AIF) requested that the EPA eliminate the gas 
curtailment notification requirements or adjust the frequency of these 
notifications to be consistent with the semi-annual reporting 
requirements in the Title V program. The EPA is denying the petition. 
Reporting requirements were open to notice and comment in the June 4, 
2010 proposal.
    Issue: Allow facilities to become area or synthetic minor sources 
instead of installing controls.
    The petitioner (GPSP) requested that the EPA allow facilities to 
become area or synthetic minor sources instead of installing controls. 
The EPA is denying the petition. Whether or not sources elect to become 
area or synthetic minor sources is not of central relevance to this 
rulemaking, as nothing in this rule affects whether or how a source can 
become a synthetic minor source (RTC document, EPA-HQ-OAR-2002-0058-
3289, Volume 1, DCN EPA-HQ-OAR-2002-0058-3176.2, excerpt 4).

VI. Impacts of This Final Rule

A. What are the incremental air impacts?

    Table 4 of this preamble illustrates, for each basic fuel 
subcategory, the total emissions reductions achieved by the final 
amended rule (i.e., the difference in emissions between a boiler or 
process heater controlled to the amended 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, 
mercury, metals, and VOC) will be reduced by 44,300 tpy. This is an 
incremental increase of 4,000 tpy in HAP reductions compared to the 
estimates in the March 2011 final rule. This increase is due mainly to 
changes in the inventory (336 units were added since the March 2011 
inventory). Excluding the changes in the inventory, the amendments to 
the regulatory provisions themselves resulted in a decrease of 1,100 
tpy of estimated reductions, part of this incremental reduction in HAP 
is contributed to edits to the baseline emission data received since 
the March 2011 final rule, as well as changes to the subcategories and 
emission limits as a result of this amended rule. The amendments to the 
final rule are expected to result in an additional 4,600 tpy of 
reductions in HCl emissions. The amendments are also expected to have a 
modest effect on mercury, estimated to range from a slight decrease of 
0.12 tpy up to a slight increase of 0.96 tpy in emission reductions as 
a result of the changes to the regulatory requirements. Reductions in 
emissions of filterable PM will decrease by 18,500 tpy due to the final 
amended rule. Reductions in emissions of non-mercury metals (i.e., 
antimony, arsenic, beryllium, cadmium, chromium, cobalt, lead, 
manganese, nickel, and selenium) will decrease by 260 tpy. In addition, 
the amendments are estimated to result in an additional 50,100 tpy of 
reductions in SO2 emissions. A discussion of the methodology 
used to estimate emissions, emissions reductions, and incremental 
emission reductions is presented in ``Revised (August 2012) Methodology 
for Estimating Cost and Emission Impacts for Industrial, Commercial, 
and Institutional Boilers and Process Heaters NESHAP--Major Source'' in 
the docket.

                    Table 4--Summary of Total Emissions Reductions for the Final Amended Rule
                                                    [tons/yr]
----------------------------------------------------------------------------------------------------------------
                                                                            Non
                                                                          mercury
            Source                 Subcategory        HCl         PM       metals      Mercury \b\        VOC
                                                                            \a\
----------------------------------------------------------------------------------------------------------------
Existing Units................  Limited Use......          1          2       0.42  2.1E-04..........       0.48
                                Solid units......     36,737     21,367        147   0.4 to 1.5......      1,619
                                Liquid units.....      2,143      9,434      2,315  0.9 to 1.........        620
                                Non-Continental           35          3          1  0.01 to 0.02.....         23
                                 Liquid units.
                                Gas 1 (NG/RG)             20        117        0.3  0.01.............         88
                                 units.
                                Gas 1                    0.4          3       0.02  0.001............         27
                                 Metallurgical
                                 Furnaces.
                                Gas 2 (other)              4          8       0.06   3.8E-03 to 4.6E-         40
                                 units.                                              03.
New Units.....................  Solid units......          0        351          5  0.02.............          0
                                Liquid units.....          0          0          0  0................          0
                                Gas 1 units......          0          0          0  0................          0
                                Gas 1                      0          0          0  0................          0
                                 Metallurgical
                                 Furnaces.
                                Gas 2 (other)              0          0          0  0................          0
                                 units.
----------------------------------------------------------------------------------------------------------------
\a\ Includes antimony, arsenic, beryllium, cadmium, chromium, cobalt, lead, manganese, nickel, and selenium.
\b\ Mercury reductions are presented as a range due to adjustments on reported fractions and limits of
  detection. See memorandum entitled ``Revised (March 2012) 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 mercury
  reductions.

[[Page 7155]]

B. What are the incremental water and solid waste impacts?

    The EPA estimated the additional water usage that would result from 
installing wet scrubbers to meet the amended emission limits for HCl 
would be 556 million gallons per year for existing sources compared to 
the current baseline. In addition to the increased water usage, an 
additional 160 million gallons per year of wastewater would be produced 
for existing sources. Only half of these incremental changes are due to 
changes in the regulatory provisions. The other half is due to changes 
in the number of identified existing units and projected new units. The 
annual costs of treating the additional wastewater are $1.2 million. 
These additional costs are accounted for in the incremental control 
cost estimates.
    The EPA estimated the additional solid waste that would result due 
to the amendments to be 138,000 tpy, with nearly all due to changes in 
the regulatory provisions. Solid waste is generated from flyash and 
dust captured in PM and mercury 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 $5.8 
million. These costs are also accounted for in the incremental control 
costs estimates.
    A discussion of the methodology used to estimate incremental 
impacts is presented in ``Revised (August 2012) 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 incremental energy impacts?

    The EPA estimated that the March 2011 final rule would result in an 
increase of about 1.4 billion kWh/yr in national energy usage 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 final rule. The amendments are expected to 
decrease energy usage by a net 143 million kWh/yr compared to the March 
2011 rule. These reductions are driven by the regulatory provisions of 
these amendments. Additionally, the EPA expects these amendments will 
result in a decrease of 4.4 million MMBtu/yr in fuel savings, compared 
with the estimates in the March 2011 final rule.

D. What are the incremental cost impacts?

    For these final amendments, we estimated the incremental difference 
between the national costs impacts for the final amended rule and the 
March 2011 final rule. First, we determined the control measures, work 
practices, and monitoring and testing requirements that would be 
required by boilers and process heaters located at major source 
facilities to comply with the final amended rule. To estimate the 
national cost impacts of the final amended rule for existing sources, 
we used the identical methodology used to estimate the cost impacts for 
the March 2011 final rule with one exception. In this revised analysis, 
it was assumed that several liquid fuel units that reported natural gas 
firing capability would switch to natural gas as a compliance option 
instead of installing add-on controls to demonstrate compliance with 
the emission limits. Thus, the only costs to these units would be the 
tune-up work practice costs. A discussion of the methodology used to 
estimate cost impacts is presented in ``Revised (August 2012) 
Methodology for Estimating Cost and Emission Impacts for Industrial, 
Commercial, and Institutional Boilers and Process Heaters NESHAP--Major 
Source'' in the docket.
    The resulting total national cost impact of the final amended rule 
is $4.7 billion in capital expenditures and $1.5 billion per year in 
total annual costs, considering fuel savings. The total capital 
expenditures are slightly lower than estimated for the March 2011 final 
rule, but the total annual costs are slightly higher than estimated for 
the March 2011 final rule. See 76 FR 15651. The total capital and 
annual costs include costs for control devices, work practices, testing 
and monitoring.
    In order to determine the incremental cost impacts of the amended 
requirements and emission limits, we first estimated the cost impacts 
of the additional existing boilers and process heaters added to the 
Boiler MACT inventory database since promulgation of the March 2011 
final rule and the revised number of new boilers and process heaters 
that could be potentially constructed. Since the March 2011 final rule, 
we became aware of 72 major source facilities that were not previously 
in the Boiler MACT inventory database. Adding the boilers and process 
heaters located at these newly identified major source facilities 
resulted in 73 additional coal-fired units, 32 additional biomass-fired 
units, 82 additional oil-fired units, and 149 additional gas-fired 
units. Our revised number of new boilers and process heaters included 
82 additional biomass units, 1,728 additional gas 1 units and 13 fewer 
liquid units.
    The resulting cost impact for these additional existing and new 
boilers and process heaters is $1.0 billion in capital expenditures and 
$0.31 billion per year in total annual costs, considering fuel savings.
    Therefore, discounting the added costs for the additional boilers 
and process heaters included in the costs analysis, the estimated 
incremental cost impacts for these amended requirements on existing and 
new boilers and process heaters are $1.0 billion in capital 
expenditures and $0.13 billion per year in total annual costs less than 
the costs estimated in the March 2011 rule.
    Table 5 of this preamble shows the total capital and annual cost 
impacts of the final amended rule for each subcategory. Costs include 
testing and monitoring costs, but not recordkeeping and reporting 
costs.

                       Table 5--Summary of Total Capital and Annual Costs for New and Existing Sources for the Final Amended Rule
--------------------------------------------------------------------------------------------------------------------------------------------------------
                                                                                                                          Testing and
                                                                                                                           monitoring    Annualized cost
                  Source                            Subcategory          Estimated/projected number of   Capital costs     annualized      (10\6\ $/yr)
                                                                                 affected units            (10\6\ $)    costs  (10\6\ $/   (considering
                                                                                                                              yr)         fuel savings)
--------------------------------------------------------------------------------------------------------------------------------------------------------
Existing Units...........................  Coal units..................  621..........................           2,554             46               904
                                           Biomass units...............  502..........................             405             29               109
                                           Heavy Liquid units..........  319..........................             761              5.4             221
                                           Light Liquid units..........  615..........................             712              4.2             166
                                           Non-Continental Liquid units  21...........................              62              0.8              17
                                           Gas 1 (NG/RG) units.........  11,929.......................              77              0.9            (295)

[[Page 7156]]

 
                                           Gas 2 (other) units.........  129..........................             138              2.3              58
Energy Assessment........................  ALL.........................  1,700 (Facilities)...........             N/A            N/A                28
New Units................................  Coal units..................  0............................               0              0                 0
                                           Biomass units...............  82...........................             381              5.6          \a\ 99
                                           Liquid units................  0............................               0              0                 0
                                           Gas 1 (NG/RG) units.........  1,762........................              11              0           \a\ 5.1
                                           Gas 2 (other) units.........  0............................               0              0                 0
--------------------------------------------------------------------------------------------------------------------------------------------------------
\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.

    Potential control device cost savings and increased recordkeeping 
and reporting costs associated with the emissions averaging provisions 
in the final 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 (August 2012) 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 final amended rule 
using the methodology that was discussed in the March 2011 final rule 
RIA and in the preamble to the March 2011 final rule. See FR 76 15651. 
The market impact results are very similar to the results presented in 
the March 2011 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 
results for sales tests for small businesses were somewhat reduced than 
those calculated for the March 2011 final rule. 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 3 percent for 
this final amended rule and the median was 0.2 percent for the RIA and 
also 0.2 percent for this final amended rule. The number of parent 
companies with sales tests exceeding 3 percent dropped from 8 in the 
RIA to 5 for this final amended 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 final amended rule is minimal. In the RIA for 
the March 2011 final rule, we estimated employment changes ranging 
between -3,100 to +6,500 employees, with a central estimate of +1,700. 
For this final amended rule we estimate employment changes ranging 
between -2,600 to +5,400 employees, with a central estimate of +1,400. 
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).

F. What are the benefits of this final 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 final 
rule into the analysis. We were unable to estimate the benefits from 
reducing exposure to HAP and ozone, ecosystem impairment and visibility 
impairment, including reducing 180,000 tons of carbon monoxide, 39,000 
tons of HCl, 500 tons of HF, 2,500 tons of other metals and 3,100 to 
5,300 pounds of mercury. Please refer to the full description of the 
unquantified benefits as well as technical details of the analysis and 
its limitations and uncertainties in the final Boiler RIA (March 2011). 
These monetized benefits are approximately 23 percent higher than the 
March 2011 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 final regulatory action to be $27 billion to $67 
billion at a 3 percent discount rate and $25 to $61 billion at a 7 
percent discount rate. All estimates are for the implementation year 
(2015) in 2008$. A summary 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$] a b
----------------------------------------------------------------------------------------------------------------
                                           Emissions
                Pollutant                  reductions    Total monetized benefits      Total monetized benefits
                                             (tons)        (at 3% discount rate)        (at 7% discount rate)
----------------------------------------------------------------------------------------------------------------
PM2.5-related benefits
----------------------------------------------------------------------------------------------------------------
Direct PM2.5............................       14,139  $1,200 to $2,900............  $1,100 to $ $2,700
SO2.....................................      572,000  $26,000 to $64,000..........  $24,000 to $61,000
-----------------------------------------

[[Page 7157]]

 
    Total...............................  ...........  $27,000 to $67,000..........  $25,000 to $61,000.
----------------------------------------------------------------------------------------------------------------
\a\ 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 because the
  scientific evidence is not yet sufficient to allow differentiation of effect estimates by particle type.
  Benefits from reducing hazardous air pollutants (HAP) are not included. These estimates do not include energy
  disbenefits valued at $24 million (using a 3 percent discount rate). These benefits reflect existing boilers
  and new boilers anticipated to come online by 2015.
\b\ There are some slight differences in the emission reductions used in the RIA and those used in the air
  impacts section of this preamble due to some late changes in the data that were received after the RIA was
  completed. Refer to the memoranda ``Revised (August 2012) Methodology for Estimating Cost and Emission Impacts
  for Industrial, Commercial, and Institutional Boilers and Process Heaters NESHAP--Major Source'' for a
  discussion of the differences.

 Table 7--Summary of the Avoided Health Incidences for the Final Boiler
                                 MACT a
------------------------------------------------------------------------
                                                          Avoided health
                                                            incidences
------------------------------------------------------------------------
Premature Mortality.....................................     3,000-7,900
Morbidity...............................................  ..............
Chronic Bronchitis......................................           2,000
Acute Myocardial Infarction.............................           5,000
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
------------------------------------------------------------------------
\a\ 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 because the scientific evidence is not
  yet sufficient to allow differentiation of effect estimates by
  particle type. 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 incremental secondary air impacts?

    For units adding controls to meet the amended 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 NOX, CO, PM and SO2 and 
an increase in CO2 emissions. Since NOX and 
SO2 are covered by capped emissions trading programs and 
methodological limitations prevent us from quantifying the change in CO 
and PM, we do not estimate an increase in secondary air impacts for 
this final rule from additional electricity demand. We do estimate 
greenhouse gas impacts, which result from increased electricity 
consumption, to be 859,200 tpy from existing units and 79,700 tpy from 
new units. This is 19,200 tpy less than the estimated greenhouse gas 
impacts associated with the March 2011 final rule.

VII. 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 OMB for review under Executive Orders 12866 and 13563 (76 
FR 3821, January 21, 2011) and any changes made in response to the OMB 
recommendations have been documented in the docket for this action.
    The EPA did prepare a new RIA for this action. The EPA prepared an 
assessment of the changes in the costs and benefits of this final 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 previous final rule, 
although the distribution is somewhat different and the number of 
affected units in the inventory has increased by about 302 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 
previous final rule. The benefits are projected to increase by about 20 
percent because of the increase in the estimated SO2 
reductions. A summary of the costs and benefits of the previous final 
rule is provided in the preamble to the previous final rule (see 76 FR 
15658) and the detailed analysis for the previous final rule is 
provided in the RIA for the previous final rule. In addition, memoranda 
are provided in the docket to document the changes in costs, economic 
impacts, and benefits associated with this final rule, shown in Table 
8.

    Table 8--Summary of the Monetized Benefits, Social Costs and Net
       Benefits for the Final Boiler MACT Reconsideration in 2015
                         [Millions of 2008$] \1\
------------------------------------------------------------------------
                                  3 percent discount  7 percent discount
                                         rate                rate
------------------------------------------------------------------------
Total Monetized Benefits \2\...  $27,000 to $67,000.  $24,000 to
                                                       $61,000.
Total Social Costs \3\.........  $1,400 to $1,600...  $1,400 to $1,600.
Net Benefits...................  $26,000 to $65,000.  $23,200 to
                                                       $59,000.
------------------------------------------------------------------------

[[Page 7158]]

 
Non-monetized Benefits.........    Health effects from exposure to HAP
                                   (39,000 tons of HCl, 500 tons of HF,
                                   3,100 to 5,300 pounds of mercury, and
                                       2,500 tons of other metals).
                                  Health effects from exposure to other
                                   criteria pollutants (180,000 tons of
                                       CO and 572,000 tons of SO2).
                                            Ecosystem effects.
                                          Visibility impairment.
------------------------------------------------------------------------
\1\ All estimates are for the implementation year (2015), and are
  rounded to two significant figures.
\2\ The total monetized co-benefits reflect the human health benefits
  associated with reducing exposure to PM2.5 through reductions of PM2.5
  precursors such as directly emitted particles, SO2, and NOX and
  reducing exposure to ozone through reductions of VOC. It is important
  to note that the monetized benefits include many but not all health
  effects associated with PM2.5 exposure. Monetized benefits are shown
  as a range from Pope et al. (2002) to Laden et al. (2006). These
  models assume that all fine particles, regardless of their chemical
  composition, are equally potent in causing premature mortality because
  the scientific evidence is not yet sufficient to support the
  development of differential effects estimates by particle type. These
  estimates include the energy disbenefits valued at $24 million (using
  the 3 percent discount rate), which do not change the rounded totals.
  CO2-related disbenefits were calculated using the ``social cost of
  carbon'', which is discussed further in the RIA.
\3\ The methodology used to estimate social costs for one year in the
  multimarket model using surplus changes results in the same social
  costs for both discount rates.

B. Paperwork Reduction Act

    The OMB has approved the information collection requirements 
contained in the March 21, 2011 final rule under the provisions of the 
Paperwork Reduction Act, 44 U.S.C. 3501 et seq. and has assigned OMB 
control number 2060-0551. The EPA has updated the supporting statement 
to reflect the final inventory and burden estimates associated with 
this action since some of the monitoring, recordkeeping and reporting 
requirements have changed since the March 21, 2011 final rule. These 
revised estimates have been sent to OMB for review and approval.
    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 final rule will require maintenance inspections of the control 
devices but will 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 revised 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 $95.3 million which 
is about the same as estimated for the March 2011 final rule. This 
includes 323,130 labor hours per year at a total labor cost of $30.6 
million per year, and total non-labor capital costs of $64.7 million 
per year. This estimate includes initial and annual performance test, 
conducting and 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 VI.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 100,608 hours per year at a 
total labor cost of $5.3 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. In addition, 
the EPA is amending the table in 40 CFR part 9 of currently approved 
OMB control numbers for various regulations to list the regulatory 
citations for the information requirements contained in this final 
rule.

C. Regulatory Flexibility Act

    The 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.\1\ 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. Sec.  605(c). This final rule is closely related to the final 
major source rule, which the EPA signed on February 21, 2011. The EPA 
prepared a final regulatory flexibility analyses in connection with the 
major source rule. Therefore,

[[Page 7159]]

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

    \1\ 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 
final 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 final action would 
decrease capital and annualized costs on small entities by about 3 
percent and 10 percent, respectively, relative to the closely related 
final rule.

D. Unfunded Mandates Reform Act

    Title II of the UMRA of 1995, 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. Federal agencies must also develop a plan to provide 
notice to small governments that might be significantly or uniquely 
affected by any regulatory requirements. The plan must enable officials 
of affected small governments to have meaningful and timely input in 
the development of the EPA regulatory proposals with significant 
Federal intergovernmental mandates and must inform, educate, and advise 
small governments on compliance with the regulatory requirements.
    Both this rule and the March 21, 2011 final rule contain 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. This final rule 
also contains 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. The discussion below 
has been updated to reflect the changes.
1. Statutory Authority
    As discussed in the March 21, 2011, final rule, the statutory 
authority for this final 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 boilers and 
process heaters located at major sources of HAP emissions.
2. Social Costs and Benefits
    The regulatory impact analysis prepared for the March 21, 2011 
final rule, which we have revised for this final 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)'' and in the ``Regulatory Impact Results 
for the Reconsideration Final Rule for National Emission Standards for 
Hazardous Air Pollutants for Industrial, Commercial, and Institutional 
Boilers and Process Heaters at Major Sources'' in the docket. Based on 
estimated compliance costs associated with this final rule and the 
predicted change in prices and production in the affected industries, 
the estimated social costs of this rule are $1.4 to 1.6 billion (2008 
dollars).
    It is estimated that 3 years after implementation of this final 
rule, HAP would be reduced by 45,000 tpy, including reductions in HCl, 
hydrogen fluoride, metallic HAP including mercury, 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 thousand tons of 
PM2.5 and 558 thousand tons of SO2. These 
reductions occur within 3 years after the implementation of the final 
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) are 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 final regulatory action 
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 final rule 
and any 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 final 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 final 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 final rule is presented in 
the

[[Page 7160]]

``Regulatory Impact Analysis for the Final Industrial Boilers and 
Process Heaters MACT (2011)'' and a memoranda that are included in the 
docket, entitled ``Regulatory Impact Results for the Reconsideration 
Final Rule 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 final 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 final 
rule. We consulted with state and local air pollution control officials 
during the development of the final rule. We have also held meetings on 
this final 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 
final 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 final rule, the impacts are not 
expected to be significant. Therefore, this final 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 final 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.

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.

G. Executive Order 13045: Protection of Children From Environmental 
Health Risks and Safety Risks

    The EPA interprets Executive Order 13045 (62 FR 19885, April 23, 
1997) as applying to those regulatory actions that concern health or 
safety risks, such that the analysis required under section 5-501 of 
the Order has the potential to influence the regulation. This action is 
not subject to EO 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 recreate the RIA for this final 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 previous final 
rule. Therefore, we conclude that this final 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 NTTAA, Public Law 104-113, 12(d) (15 U.S.C. 
272 note) directs the EPA to use VCS in its regulatory activities 
unless to do so would be inconsistent with applicable law or otherwise 
impractical. VCS are technical standards (e.g., materials 
specifications, test methods, sampling procedures, and business 
practices) that are developed or adopted by VCS bodies. NTTAA directs 
the EPA to provide Congress, through the OMB, explanations when the 
agency decides not to use available and applicable VCS.
    This action does not involve any new technical standards from those 
contained in the March 21, 2011 final rule. Therefore, the EPA did not 
consider the use of any VCS. See 76 FR 15660-15662 for the NTTAA 
discussion in the March 21, 2011 final rule.

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 the rule 
would not have disproportionately high and adverse human health or 
environmental effects on minority or low-income populations because it 
increases the

[[Page 7161]]

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 previous final rule, while the 
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 previous final rule are still valid. 
Therefore, the EPA has determined this final rule will not have 
disproportionately high and adverse human or environmental effects on 
minority or low-income populations.

K. Congressional Review Act

    The Congressional Review Act, 5 U.S.C. 801 et seq., as added by the 
Small Business Regulatory Enforcement Fairness Act of 1996, generally 
provides that before a rule may take effect, the agency promulgating 
the rule must submit a rule report, which includes a copy of the rule, 
to each House of the Congress and to the Comptroller General of the 
United States. EPA will submit a report containing this final rule and 
other required information to the U.S. Senate, the U.S. House of 
Representatives, and the Comptroller General of the United States prior 
to publication of the rule in the Federal Register. A major rule cannot 
take effect until 60 days after it is published in the Federal 
Register. This action is a ``major rule'' as defined by 5 U.S.C. 
804(2). With the exception of the May 18, 2011 (76 FR 28661), delay of 
the effective date revising subpart DDDDD at 76 FR 15451 (March 21, 
2011) being lifted January 31, 2013, this rule will be effective April 
1, 2013.

List of Subjects in 40 CFR Part 63

    Environmental protection, Administrative practice and procedure, 
Air pollution control, Hazardous substances, Incorporation by 
reference, Intergovernmental relations, Reporting and Recordkeeping 
requirements.

    Dated: December 20, 2012
Lisa P. Jackson,
Administrator.
    For the reasons cited in the preamble, title 40, chapter I, part 63 
of the Code of Federal Regulations is amended as follows:

PART 63--[AMENDED]

0
1. The authority for part 63 continues to read as follows:

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

0
2. Effective January 31, 2013, the May 18, 2011 (76 FR 28661), delay of 
the effective date revising subpart DDDDD at 76 FR 15451 (March 21, 
2011) is lifted.

Subpart A--[Amended]

0
3. Section 63.14 is amended by:
0
a. Revising paragraphs (b)(19), (b)(23), (b)(35), (b)(40), (b)(69), and 
(b)(70).
0
b. Removing and reserving paragraph (b)(53).
0
c. Adding paragraphs (b)(46), (b)(55), and (b)(76) through (83).
0
d. Adding paragraphs (p)(12) through (20).
0
e. Adding paragraph (r).
    The revisions and additions read as follows:

Sec.  63.14  Incorporations by reference.

* * * * *
    (b) * * *
    (19) ASTM D95-05 (Reapproved 2010), Standard Test Method for Water 
in Petroleum Products and Bituminous Materials by Distillation, 
approved May 1, 2010, IBR approved for Sec.  63.10005(i) and table 6 to 
subpart DDDDD.
* * * * *
    (23) ASTM D4006-11, Standard Test Method for Water in Crude Oil by 
Distillation, including Annex A1 and Appendix X1, approved June 1, 
2011, IBR approved for Sec.  63.10005(i) and table 6 to subpart DDDDD.
* * * * *
    (35) ASTM D6784-02 (Reapproved 2008) Standard Test Method for 
Elemental, Oxidized, Particle-Bound and Total Mercury in Flue Gas 
Generated from Coal-Fired Stationary Sources (Ontario Hydro Method), 
approved April 1, 2008, IBR approved for table 1 to subpart DDDDD of 
this part, table 2 to subpart DDDDD of this part, table 5 to subpart 
DDDDD, table 11 to subpart DDDDD of this part, table 12 to subpart 
DDDDD of this part, table 13 to subpart DDDDD of this part, and table 4 
to subpart JJJJJJ of this part.
* * * * *
    (40) ASTM D396-10 Standard Specification for Fuel Oils, approved 
October 1, 2010, IBR approved for Sec.  63.7575 and Sec.  63.11237.
* * * * *
    (46) ASTM D4606-03 (2007), Standard Test Method for Determination 
of Arsenic and Selenium in Coal by the Hydride Generation/Atomic 
Absorption Method, approved October 1, 2007, IBR approved for table 6 
to subpart DDDDD.
* * * * *
    (55) ASTM D6357-11, Test Methods for Determination of Trace 
Elements in Coal, Coke, and Combustion Residues from Coal Utilization 
Processes by Inductively Coupled Plasma Atomic Emission Spectrometry, 
approved April 1, 2011, IBR approved for table 6 to subpart DDDDD.
* * * * *
    (69) ASTM D4057-06 (Reapproved 2011), Standard Practice for Manual 
Sampling of Petroleum and Petroleum Products, including Annex A1, 
approved June 1, 2011, IBR approved for Sec.  63.10005(i) and table 6 
to subpart DDDDD.
    (70) ASTM D4177-95 (Reapproved 2010), Standard Practice for 
Automatic Sampling of Petroleum and Petroleum Products, including 
Annexes A1 through A6 and Appendices X1 and X2, approved May 1, 2010, 
IBR approved for Sec.  63.10005(i) and table 6 to subpart DDDDD.
* * * * *
    (76) ASTM D6751-11b, Standard Specification for Biodiesel Fuel 
Blend Stock (B100) for Middle Distillate Fuels, approved July 15, 2011, 
IBR approved for Sec.  63.7575 and Sec.  63.11237.
    (77) ASTM D975-11b, Standard Specification for Diesel Fuel Oils, 
approved December 1, 2011, IBR approved for Sec.  63.7575.
    (78) ASTM D5864-11 Standard Test Method for Determining Aerobic 
Aquatic Biodegradation of Lubricants or Their Components, approved 
March 1, 2011, IBR approved for table 6 to subpart DDDDD.
    (79) ASTM D240-09 Standard Test Method for Heat of Combustion of 
Liquid Hydrocarbon Fuels by Bomb Calorimeter, approved July 1, 2009, 
IBR approved for table 6 to subpart DDDDD.
    (80) ASTM D4208-02 (2007) Standard Test Method for Total Chlorine 
in Coal by the Oxygen Bomb Combustion/Ion Selective Electrode Method, 
approved May 1, 2007, IBR approved for table 6 to subpart DDDDD.
    (81) ASTM D5192-09 Standard Practice for Collection of Coal Samples 
from Core, approved June 1, 2009, IBR approved for table 6 to subpart 
DDDDD.
    (82) ASTM D7430-11ae1, Standard Practice for Mechanical Sampling of 
Coal, approved October 1, 2011, IBR approved for table 6 to subpart 
DDDDD.
    (83) ASTM D6883-04, Standard Practice for Manual Sampling of 
Stationary Coal from Railroad Cars, Barges, Trucks, or Stockpiles, 
approved June 1, 2004, IBR approved for table 6 to subpart DDDDD.
* * * * *
    (p) * * *
    (12) Method 5050 (SW-846-5050), Bomb Preparation Method for Solid 
Waste, Revision 0, September 1994, in

[[Page 7162]]

EPA Publication No. SW-846, Test Methods for Evaluating Solid Waste, 
Physical/Chemical Methods, Third Edition IBR approved for table 6 to 
subpart DDDDD.
    (13) Method 9056 (SW-846-9056), Determination of Inorganic Anions 
by Ion Chromatography, Revision 1, February 2007, in EPA Publication 
No. SW-846, Test Methods for Evaluating Solid Waste, Physical/Chemical 
Methods, Third Edition, IBR approved for table 6 to subpart DDDDD.
    (14) Method 9076 (SW-846-9076), Test Method for Total Chlorine in 
New and Used Petroleum Products by Oxidative Combustion and 
Microcoulometry, Revision 0, September 1994, in EPA Publication No. SW-
846, Test Methods for Evaluating Solid Waste, Physical/Chemical 
Methods, Third Edition, IBR approved for table 6 to subpart DDDDD.
    (15) Method 1631 Revision E, Mercury in Water by Oxidation, Purge 
and Trap, and Cold Vapor Atomic Absorption Fluorescence Spectrometry, 
Revision E, EPA-821-R-02-019, August 2002, IBR approved for table 6 to 
subpart DDDDD.
    (16) Method 200.8, Determination of Trace Elements in Waters and 
Wastes by Inductively Coupled Plasma--Mass Spectrometry, Revision 5.4, 
1994, IBR approved for table 6 to subpart DDDDD.
    (17) Method 6020A (SW-846-6020A), Inductively Coupled Plasma-Mass 
Spectrometry, Revision 1, February 2007, in EPA Publication No. SW-846, 
Test Methods for Evaluating Solid Waste, Physical/Chemical Methods, 
Third Edition, IBR approved for table 6 to subpart DDDDD.
    (18) Method 6010C (SW-846-6010C), Inductively Coupled Plasma-Atomic 
Emission Spectrometry, Revision 3, February 2007, in EPA Publication 
No. SW-846, Test Methods for Evaluating Solid Waste, Physical/Chemical 
Methods, Third Edition, IBR approved for table 6 to subpart DDDDD.
    (19) Method 7060A (SW-846-7060A), Arsenic (Atomic Absorption, 
Furnace Technique), Revision 1, September 1994, in EPA Publication No. 
SW-846, Test Methods for Evaluating Solid Waste, Physical/Chemical 
Methods, Third Edition, IBR approved for table 6 to subpart DDDDD.
    (20) Method 7740 (SW-846-7740), Selenium (Atomic Absorption, 
Furnace Technique), Revision 0, September 1986, in EPA Publication No. 
SW-846, Test Methods for Evaluating Solid Waste, Physical/Chemical 
Methods, Third Edition, IBR approved for table 6 to subpart DDDDD.
* * * * *
    (r) The following material is available for purchase from the 
Technical Association of the Pulp and Paper Industry (TAPPI), 15 
Technology Parkway South, Norcross, GA 30092, (800) 332-8686, http://www.tappi.org.
    (1) TAPPI T 266, Determination of Sodium, Calcium, Copper, Iron, 
and Manganese in Pulp and Paper by Atomic Absorption Spectroscopy 
(Reaffirmation of T 266 om-02), Draft No. 2, July 2006, IBR approved 
for table 6 to subpart DDDDD.
    (2) [Reserved]

Subpart DDDDD--[Amended]

0
4. Section 63.7485 is revised to read as follows:

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 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.  63.7575.
0
5. Section 63.7490 is amended by adding paragraph (e) to read as 
follows:

Sec.  63.7490  What is the affected source of this subpart?

* * * * *
    (e) An existing electric utility steam generating unit (EGU) that 
meets the applicability requirements of this subpart after the 
effective date of this final rule due to a change (e.g., fuel switch) 
is considered to be an existing source under this subpart.

0
6. Section 63.7491 is amended by:
0
a. Revising the introductory text.
0
b. Revising paragraph (a).
0
c. Revising paragraph (c).
0
d. Revising paragraph (h)
0
e. Revising paragraph (i).
0
f. Revising paragraph (m).
0
g. Revising paragraph (n).
    The revisions read as follows:

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 (EGU) covered by 
subpart UUUUU of this part.
* * * * *
    (c) A boiler or process heater that is used specifically for 
research and development, including test steam boilers used to provide 
steam for testing the propulsion systems on military vessels. This does 
not include units that provide heat or steam to a process at a research 
and development facility.
* * * * *
    (h) Any boiler or process heater that is part of the affected 
source subject to another subpart of this part, such as boilers and 
process heaters used as control devices to comply with subparts JJJ, 
OOO, PPP, and U of this part.
    (i) Any boiler or process heater that is used as a control device 
to comply with another subpart of this part, or part 60, part 61, or 
part 65 of this chapter provided that at least 50 percent of the 
average annual heat input during any 3 consecutive calendar years to 
the boiler or process heater is provided by regulated gas streams that 
are subject to another standard.
* * * * *
    (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.
* * * * *

0
7. Section 63.7495 is amended by:
0
a. Revising paragraph (a).
0
b. Revising paragraph (b).
0
c. Adding paragraphs (e), (f), and (g).
    The revisions and additions read as follows:

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 January 31, 2013, 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 January 31, 2016, except as 
provided in Sec.  63.6(i).
* * * * *
    (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 and are no longer subject to part 60, 
subparts CCCC or DDDD beginning on the effective date of the switch as 
identified under the provisions of Sec.  60.2145(a)(2) and (3) or Sec.  
60.2710(a)(2) and (3).
    (f) If you own or operate an existing EGU that becomes subject to 
this subpart after January 31, 2013, you must

[[Page 7163]]

be in compliance with the applicable existing source provisions of this 
subpart on the effective date such unit becomes subject to this 
subpart.
    (g) If you own or operate an existing industrial, commercial, or 
institutional boiler or process heater and would be subject to this 
subpart except for a exemption in Sec.  63.7491(i) that becomes subject 
to this subpart after January 31, 2013, you must be in compliance with 
the applicable existing source provisions of this subpart within 3 
years after such unit becomes subject to this subpart.

0
8.Section 63.7499 is amended by revising paragraphs (d) and (f) through 
(l) and adding paragraphs (p) through (u) to read as follows:

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

* * * * *
    (d) Stokers/sloped grate/other units designed to burn kiln dried 
biomass/bio-based solid.
* * * * *
    (f) Suspension burners designed to burn biomass/bio-based solid.
    (g) Fuel cells designed to burn biomass/bio-based solid.
    (h) Hybrid suspension/grate burners designed to burn wet biomass/
bio-based solid.
    (i) Stokers/sloped grate/other units designed to burn wet biomass/
bio-based solid.
    (j) Dutch ovens/pile burners designed to burn biomass/bio-based 
solid.
    (k) Units designed to burn liquid fuel that are non-continental 
units.
    (l) Units designed to burn gas 1 fuels.
* * * * *
    (p) Units designed to burn solid fuel.
    (q) Units designed to burn liquid fuel.
    (r) Units designed to burn coal/solid fossil fuel.
    (s) Fluidized bed units with an integrated fluidized bed heat 
exchanger designed to burn coal/solid fossil fuel.
    (t) Units designed to burn heavy liquid fuel.
    (u) Units designed to burn light liquid fuel.

0
9. Section 63.7500 is amended by:
0
a. Revising paragraph (a).
0
b. Revising paragraph (c).
0
c. Adding paragraph (d).
0
d. Adding paragraph (e).
0
e. Adding paragraph (f).

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), through (e) of 
this section. You must meet these requirements at all times the 
affected unit is operating, except as provided in paragraph (f) of this 
section.
    (1) You must meet each emission limit and work practice standard in 
Tables 1 through 3, and 11 through 13 to this subpart that applies to 
your boiler or process heater, for each boiler or process heater at 
your source, except as provided under Sec.  63.7522. The output-based 
emission limits, in units of pounds per million Btu of steam output, in 
Tables 1 or 2 to this subpart are an alternative applicable only to 
boilers and process heaters that generate steam. The output-based 
emission limits, in units of pounds per megawatt-hour, in Tables 1 or 2 
to this subpart are an alternative applicable only to boilers that 
generate electricity. If you operate a new boiler or process heater, 
you can choose to comply with alternative limits as discussed in 
paragraphs (a)(1)(i) through (a)(1)(iii) of this section, but on or 
after January 31, 2016, you must comply with the emission limits in 
Table 1 to this subpart.
    (i) If your boiler or process heater commenced construction or 
reconstruction after June 4, 2010 and before May 20, 2011, you may 
comply with the emission limits in Table 1 or 11 to this subpart until 
January 31, 2016.
    (ii) If your boiler or process heater commenced construction or 
reconstruction after May 20, 2011 and before December 23, 2011, you may 
comply with the emission limits in Table 1 or 12 to this subpart until 
January 31, 2016.
    (iii) If your boiler or process heater commenced construction or 
reconstruction after December 23, 2011 and before January 31, 2013, you 
may comply with the emission limits in Table 1 or 13 to this subpart 
until January 31, 2016.
    (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 or an alternative monitoring parameter, 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 
(as defined in Sec.  63.7490), 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.
* * * * *
    (c) Limited-use boilers and process heaters must complete a tune-up 
every 5 years as specified in Sec.  63.7540. They are not subject to 
the emission limits in Tables 1 and 2 or 11 through 13 to this subpart, 
the annual tune-up, or the energy assessment requirements in Table 3 to 
this subpart, or the operating limits in Table 4 to this subpart.
    (d) Boilers and process heaters with a heat input capacity of less 
than or equal to 5 million Btu per hour in the 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) Boilers and process heaters in the units designed to burn gas 1 
fuels subcategory with a heat input capacity of less than or equal to 5 
million Btu per hour must complete a tune-up every 5 years as specified 
in Sec.  63.7540. Boilers and process heaters in the units designed to 
burn gas 1 fuels subcategory with a heat input capacity greater than 5 
million Btu per hour and less than 10 million Btu per hour must 
complete a tune-up every 2 years as specified in Sec.  63.7540. Boilers 
and process heaters in the units designed to burn gas 1 fuels 
subcategory are not subject to the emission limits in Tables 1 and 2 or 
11 through 13 to this subpart, or the operating limits in Table 4 to 
this subpart.
    (f) These standards apply at all times the affected unit is 
operating, except during periods of startup and shutdown during which 
time you must comply only with Table 3 to this subpart.

0
10. Section 63.7501 is revised to read as follows:

Sec.  63.7501  Affirmative Defense for Violation of Emission Standards 
During Malfunction.

    In response to an action to enforce the standards set forth in 
Sec.  63.7500 you may assert an affirmative defense to a claim for 
civil penalties for violations of such standards that are caused by 
malfunction, as defined at Sec.  63.2. Appropriate penalties may be 
assessed 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) Assertion of affirmative defense. To establish the affirmative 
defense in

[[Page 7164]]

any action to enforce such a standard, you must timely meet the 
reporting requirements in paragraph (b) of this section, and must prove 
by a preponderance of evidence that:
    (1) The violation:
    (i) Was caused by a sudden, infrequent, and unavoidable failure of 
air pollution control 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) Was not part of a recurring pattern indicative of inadequate 
design, operation, or maintenance; and
    (2) Repairs were made as expeditiously as possible when a violation 
occurred; and
    (3) The frequency, amount, and duration of the violation (including 
any bypass) were minimized to the maximum extent practicable; and
    (4) If the violation 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 
violation 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 violation were documented 
by properly signed, contemporaneous operating logs; and
    (8) At all times, the affected source 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 violation resulting from the malfunction event at 
issue. The analysis shall also specify, using best monitoring methods 
and engineering judgment, the amount of any emissions that were the 
result of the malfunction.
    (b) Report. The owner or operator seeking to assert an affirmative 
defense shall submit a written report to the Administrator with all 
necessary supporting documentation, that it has met the requirements 
set forth in Sec.  63.7500 of this section. This affirmative defense 
report shall be included in the first periodic compliance, deviation 
report or excess emission report otherwise required after the initial 
occurrence of the violation of the relevant standard (which may be the 
end of any applicable averaging period). If such compliance, deviation 
report or excess emission report is due less than 45 days after the 
initial occurrence of the violation, the affirmative defense report may 
be included in the second compliance, deviation report or excess 
emission report due after the initial occurrence of the violation of 
the relevant standard.

0
11. Section 63.7505 is amended by:
0
a. Revising paragraph (a).
0
b. Revising paragraph (c).
0
c. Revising paragraphs (d) introductory text, (d)(1) introductory text, 
and (d)(1)(iii).

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 the affected unit is operating except for the 
periods noted in Sec.  63.7500(f).
* * * * *
    (c) You must demonstrate compliance with all applicable emission 
limits using performance stack testing, fuel analysis, or continuous 
monitoring systems (CMS), including a continuous emission monitoring 
system (CEMS), continuous opacity monitoring system (COMS), continuous 
parameter monitoring system (CPMS), or particulate matter continuous 
parameter monitoring system (PM CPMS), where applicable. You may 
demonstrate compliance with the applicable emission limit for hydrogen 
chloride (HCl), mercury, or total selected metals (TSM) using fuel 
analysis if the emission rate calculated according to Sec.  63.7530(c) 
is less than the applicable emission limit. (For gaseous fuels, you may 
not use fuel analyses to comply with the TSM alternative standard or 
the HCl standard.) Otherwise, you must demonstrate compliance for HCl, 
mercury, or TSM using performance testing, if subject to an applicable 
emission limit listed in Tables 1, 2, or 11 through 13 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 Administrator 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 CEMS or COMS operated according to the 
performance specifications 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.
* * * * *
    (iii) Performance evaluation procedures and acceptance criteria 
(e.g., calibrations, accuracy audits, analytical drift).
* * * * *

0
12. Section 63.7510 is revised to read as follows:

Sec.  63.7510  What are my initial compliance requirements and by what 
date must I conduct them?

    (a) For each boiler or process heater that is required or that you 
elect to demonstrate compliance with any of the applicable emission 
limits in Tables 1 or 2 or 11 through 13 of this subpart through 
performance 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 each boiler or process heater that burns 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

[[Page 7165]]

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 units 
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, or 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, part 60, part 61, or part 65, 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 conduct a fuel analysis for mercury on 
gaseous fuels unless the fuel is exempted in paragraphs (a)(2)(i) and 
(ii) 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 each boiler or process heater that you elect to demonstrate 
compliance with the applicable emission limits in Tables 1 or 2 or 11 
through 13 to this subpart for HCl, mercury, or TSM 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) and (ii) of this 
section are exempt from these fuel analysis and operating limit 
requirements. The fuels described in paragraph (a)(2)(ii) of this 
section are exempt from the chloride fuel analysis and operating limit 
requirements. Boilers and process heaters that use a CEMS for mercury 
or HCl are exempt from the performance testing and operating limit 
requirements specified in paragraph (a) of this section for the HAP for 
which CEMS are used.
    (c) If your boiler or process heater is subject to a carbon 
monoxide (CO) limit, your initial compliance demonstration for CO is to 
conduct a performance test for CO according to Table 5 to this subpart 
or conduct a performance evaluation of your continuous CO monitor, if 
applicable, according to Sec.  63.7525(a). Boilers and process heaters 
that use a CO CEMS to comply with the applicable alternative CO CEMS 
emission standard listed in Tables 12, or 11 through 13 to this 
subpart, as specified in Sec.  63.7525(a), are exempt from the initial 
CO performance testing and oxygen concentration operating limit 
requirements specified in paragraph (a) of this section.
    (d) If your boiler or process heater is subject to a PM limit, your 
initial compliance demonstration for PM is to conduct a performance 
test in accordance with Sec.  63.7520 and Table 5 to this subpart.
    (e) For existing affected sources (as defined in Sec.  63.7490), 
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, except as specified in paragraph 
(j) of this section. You must complete an initial tune-up by following 
the procedures described in Sec.  63.7540(a)(10)(i) through (vi) no 
later than the compliance date specified in Sec.  63.7495, except as 
specified in paragraph (j) of this section. You must complete the one-
time energy assessment specified in Table 3 to this subpart no later 
than the compliance date specified in Sec.  63.7495, except as 
specified in paragraph (j) of this section.
    (f) For new or reconstructed affected sources (as defined in Sec.  
63.7490), you must complete the initial compliance demonstration with 
the emission limits no later than July 30, 2013 or within 180 days 
after startup of the source, whichever is later. If you are 
demonstrating compliance with an emission limit in Tables 11 through 13 
to this subpart that is less stringent (that is, higher) than the 
applicable emission limit in Table 1 to this subpart, you must 
demonstrate compliance with the applicable emission limit in Table 1 no 
later than July 29, 2016.
    (g) For new or reconstructed affected sources (as defined in Sec.  
63.7490), you must demonstrate initial compliance with the applicable 
work practice standards in Table 3 to this subpart within the 
applicable annual, biennial, or 5-year schedule as specified in Sec.  
63.7540(a) following the initial compliance date specified in Sec.  
63.7495(a). 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 (as defined in Sec.  63.7490) that ceased 
burning solid waste consistent with Sec.  63.7495(e) and for which the 
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.
    (i) For an existing EGU that becomes subject after January 31, 
2013, you must demonstrate compliance within 180 days after becoming an 
affected source.
    (j) For existing affected sources (as defined in Sec.  63.7490) 
that have not operated between the effective date of the rule and the 
compliance date that is specified for your source in Sec.  63.7495, you 
must complete the initial compliance demonstration, if subject to the 
emission limits in Table 2 to this subpart, as specified in paragraphs 
(a) through (d) of this section, no later than 180 days after the re-
start of the affected source 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) no later than 30 days after the 
re-start of the affected source and, if applicable, complete the one-
time energy assessment specified in Table 3 to this subpart, no later 
than the compliance date specified in Sec.  63.7495.

0
13. Section 63.7515 is revised to read as follows:

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), (g), and (h) 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), (g), and (h) 
of this section.
    (b) If your performance tests for a given 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 or 11 through 13 to this subpart, at or below the emission 
limit) for the pollutant, and if there are no changes in the operation 
of the individual boiler or process heater or air pollution control 
equipment that could increase emissions, you may choose to conduct 
performance tests for the pollutant every third year. Each such 
performance test must be conducted no more than 37 months after the 
previous performance test. If you elect to

[[Page 7166]]

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 HCl. 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 TSM input level is waived 
unless the stack test is conducted for TSM.
    (c) If a performance test shows emissions exceeded the emission 
limit or 75 percent of the emission limit (as specified in Tables 1 and 
2 or 11 through 13 to this subpart) 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 (at or below 
75 percent of the emission limit, as specified in Tables 1 and 2 or 11 
through 13 to this subpart).
    (d) If you are required to meet an applicable tune-up work practice 
standard, you must conduct an annual, biennial, or 5-year performance 
tune-up according to 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 (as 
defined in Sec.  63.7490), the first annual, biennial, or 5-year tune-
up must be no later than 13 months, 25 months, or 61 months, 
respectively, after the initial startup of the new or reconstructed 
affected source.
    (e) If you demonstrate compliance with the mercury, HCl, or TSM 
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 Tables 1, 2, or 11 through 13 to this subpart. 
You may comply with this monthly requirement by completing the fuel 
analysis any time within the calendar month as long as the analysis is 
separated from the previous analysis by at least 14 calendar days. 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 each of 12 consecutive monthly fuel analyses demonstrates 
75 percent or less of the compliance level, you may decrease the fuel 
analysis frequency to quarterly for that fuel. If any quarterly sample 
exceeds 75 percent of the compliance level or you begin burning a new 
type of fuel, you must return to monthly monitoring for that fuel, 
until 12 months of fuel analyses are again less than 75 percent of the 
compliance level.
    (f) You must report the results of performance tests and the 
associated fuel analyses within 60 days after the completion of the 
performance tests. This report must also verify that the operating 
limits for each boiler or process heater 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.
    (g) For affected sources (as defined in Sec.  63.7490) that have 
not operated since the previous compliance demonstration and more than 
one year has passed since the previous compliance demonstration, you 
must complete the subsequent compliance demonstration, if subject to 
the emission limits in Tables 1, 2, or 11 through 13 to this subpart, 
no later than 180 days after the re-start of the affected source and 
according to the applicable provisions in Sec.  63.7(a)(2) as cited in 
Table 10 to this subpart. You must complete a subsequent tune-up by 
following the procedures described in Sec.  63.7540(a)(10)(i) through 
(vi) and the schedule described in Sec.  63.7540(a)(13) for units that 
are not operating at the time of their scheduled tune-up.
    (h) If your affected boiler or process heater is in the unit 
designed to burn light liquid subcategory and you combust ultra low 
sulfur liquid fuel, you do not need to conduct further performance 
tests if the pollutants measured during the initial compliance 
performance tests meet the emission limits in Tables 1 or 2 of this 
subpart providing you demonstrate ongoing compliance with the emissions 
limits by monitoring and recording the type of fuel combusted on a 
monthly basis. If you intend to use a fuel other than ultra low sulfur 
liquid fuel, natural gas, refinery gas, or other gas 1 fuel, you must 
conduct new performance tests within 60 days of burning the new fuel 
type.
    (i) If you operate a CO CEMS that meets the Performance 
Specifications outlined in Sec.  63.7525(a)(3) of this subpart to 
demonstrate compliance with the applicable alternative CO CEMS emission 
standard listed in Tables 1, 2, or 11 through 13 to this subpart, you 
are not required to conduct CO performance tests and are not subject to 
the oxygen concentration operating limit requirement specified in Sec.  
63.7510(a).

0
14. Section Sec.  63.7520 is amended by revising paragraphs (a), (c), 
(d), and (e) and adding paragraph (f) to read as follows:

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 the representative performance 
of each boiler or process heater 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.
* * * * *
    (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 TSM if you are opting to comply 
with the TSM 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 a minimum of 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 or 11 through 13 
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 (PM) concentrations, the measured HCl 
concentrations, the measured mercury concentrations, and the measured 
TSM concentrations that result from the performance test to pounds per 
million Btu heat input emission rates.

[[Page 7167]]

    (f) Except for a 30-day rolling average based on CEMS (or sorbent 
trap monitoring system) data, if measurement results for any pollutant 
are reported as below the method detection level (e.g., laboratory 
analytical results for one or more sample components are below the 
method defined analytical detection level), you must use the method 
detection level as the measured emissions level for that pollutant in 
calculating compliance. The measured result for a multiple component 
analysis (e.g., analytical values for multiple Method 29 fractions both 
for individual HAP metals and for total HAP metals) may include a 
combination of method detection level data and analytical data reported 
above the method detection level.

0
15. Section 63.7521 is revised to read as follows:

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 and liquid fuels, you must also conduct fuel analyses 
for TSM if you are opting to comply with the TSM alternative standard. 
For gas 2 (other) fuels, you must conduct fuel analyses for mercury 
according to the procedures in paragraphs (b) through (e) of this 
section and Table 6 to this subpart, as applicable. (For gaseous fuels, 
you may not use fuel analyses to comply with the TSM alternative 
standard or the HCl standard.) For purposes of complying with this 
section, a fuel gas system that consists of multiple gaseous fuels 
collected and mixed with each other is considered a single fuel type 
and sampling and analysis is only required on the combined fuel gas 
system that will feed the boiler or process heater. Sampling and 
analysis of the individual gaseous streams prior to combining is not 
required. You are not required to conduct fuel analyses for fuels used 
for only startup, unit shutdown, and transient flame stability 
purposes. You are required to conduct fuel analyses only for fuels and 
units that are subject to emission limits for mercury, HCl, or TSM in 
Tables 1 and 2 or 11 through 13 to this subpart. Gaseous and liquid 
fuels are exempt from the sampling requirements in paragraphs (c) and 
(d) of this section and Table 6 to this subpart.
    (b) You must develop a site-specific fuel monitoring plan 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) If you intend to use an alternative analytical method other 
than those required by Table 6 to this subpart, you must submit the 
fuel analysis plan to the Administrator for review and approval 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 the methods listed in Table 6 to this subpart, 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.
    (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 TSM) in units of pounds per million Btu 
of each composite sample for each fuel type according to the procedures 
in

[[Page 7168]]

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 (4) 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, part 60, part 61, or part 
65.
    (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.
    (4) You are not required to conduct the fuel specification analyses 
in paragraphs (g) through (i) of this section for gas streams directly 
derived from natural gas at natural gas production sites or natural gas 
plants.
    (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) If you intend to use an alternative analytical method other 
than those required by Table 6 to this subpart, you must submit the 
fuel analysis plan to the Administrator for review and approval 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 
other gas 1 fuel type according to the procedures in Table 6 to this 
subpart.

0
16. Section Sec.  63.7522 is revised by:
0
a. Revising paragraphs (a) through (d).
0
b. Revising paragraphs (e)(1) and (2).
0
c. Revising paragraphs (f) introductory text and (f)(1) and (2).
0
d. Revising paragraphs (g) introductory text, (g)(2)(i), (g)(2)(iv), 
(g)(2)(vi)(B), (g)(3) introductory text, (g)(4) introductory text, and 
(g)(4)(ii).
0
e. Revising paragraph (h).
0
f. Revising paragraph (i).
0
g. Revising paragraph (j)(1).
0
h. Revising paragraph (k).
    The revisions read as follows:

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 PM (or TSM), HCl, or mercury on a boiler or process heater-specific 
basis, if you have more than one existing boiler or process heater in 
any subcategories 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 PM (or TSM), HCl, 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 average units using a CEMS or PM CPMS for demonstrating 
compliance.
    (2) For mercury 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 units designed to burn liquid, 
units designed to burn solid fuel, and units designed to burn gas 2 
(other) subcategories.
    (3) For PM (or TSM), averaging is only allowed between units within 
each of the following subcategories and you may not average across 
subcategories:
    (i) Units designed to burn coal/solid fossil fuel.
    (ii) Stokers/sloped grate/other units designed to burn kiln dried 
biomass/bio-based solids.
    (iii) Stokers/sloped grate/other units designed to burn wet 
biomass/bio-based solids.
    (iv) Fluidized bed units designed to burn biomass/bio-based solid.
    (v) Suspension burners designed to burn biomass/bio-based solid.
    (vi) Dutch ovens/pile burners designed to burn biomass/bio-based 
solid.
    (vii) Fuel Cells designed to burn biomass/bio-based solid.
    (viii) Hybrid suspension/grate burners designed to burn wet 
biomass/bio-based solid.
    (ix) Units designed to burn heavy liquid fuel.
    (x) Units designed to burn light liquid fuel.
    (xi) Units designed to burn liquid fuel that are non-continental 
units.
    (xii) 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 compliance test 
for the HAP being averaged must not exceed the emission level that was 
being achieved on

[[Page 7169]]

January 31, 2013 or the control technology employed during the initial 
compliance test must not be less effective for the HAP being averaged 
than the control technology employed on January 31, 2013.
    (d) The averaged emissions rate from the existing boilers and 
process heaters participating in the emissions averaging option must 
not exceed 90 percent of the limits in Table 2 to this subpart at all 
times the affected units are operating following the compliance date 
specified in Sec.  63.7495.
    (e) * * *
    (1) You must use Equation 1a or 1b or 1c of this section to 
demonstrate that the PM (or TSM), HCl, 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, use Equation 1b if you are complying with the emission 
limits on a steam generation (output) basis, and use Equation 1c if you 
are complying with the emission limits on a electric generation 
(output) basis.
[GRAPHIC] [TIFF OMITTED] TR31JA13.004

Where:
AveWeightedEmissions = Average weighted emissions for PM (or TSM), 
HCl, or mercury, in units of pounds per million Btu of heat input.
Er = Emission rate (as determined during the initial compliance 
demonstration) of PM (or TSM), HCl, or mercury from unit, i, in 
units of pounds per million Btu of heat input. Determine the 
emission rate for PM (or TSM), HCl, or mercury by performance 
testing according to Table 5 to this subpart, or by fuel analysis 
for HCl or mercury or TSM 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] TR31JA13.005

Where:
AveWeightedEmissions = Average weighted emissions for PM (or TSM), 
HCl, or mercury, in units of pounds per million Btu of steam output.
Er = Emission rate (as determined during the initial compliance 
demonstration) of PM (or TSM), HCl, or mercury from unit, i, in 
units of pounds per million Btu of steam output. Determine the 
emission rate for PM (or TSM), HCl, or mercury by performance 
testing according to Table 5 to this subpart, or by fuel analysis 
for HCl or mercury or TSM 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.
[GRAPHIC] [TIFF OMITTED] TR31JA13.006

Where:
AveWeightedEmissions = Average weighted emissions for PM (or TSM), 
HCl, or mercury, in units of pounds per megawatt hour.
Er = Emission rate (as determined during the initial compliance 
demonstration) of PM (or TSM), HCl, or mercury from unit, i, in 
units of pounds per megawatt hour. Determine the emission rate for 
PM (or TSM), HCl, or mercury by performance testing according to 
Table 5 to this subpart, or by fuel analysis for HCl or mercury or 
TSM 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.
Eo = Maximum electric generating output capacity of unit, i, in 
units of megawatt 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 PM (or TSM), HCl, 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] TR31JA13.007

Where:
AveWeightedEmissions = Average weighted emission level for PM (or 
TSM), HCl, or mercury, in units of pounds per million Btu of heat 
input.
Er = Emission rate (as determined during the most recent compliance 
demonstration) of PM (or TSM), HCl, or mercury from unit, i, in 
units of pounds per million Btu of heat input. Determine the 
emission rate for PM (or TSM), HCl, or mercury by performance 
testing according to Table 5 to this subpart, or by fuel analysis 
for HCl or mercury or TSM using the applicable equation in Sec.  
63.7530(c).

[[Page 7170]]

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. If the affected source elects to collect monthly data for up 
the 11 months preceding the first monthly period, these additional data 
points can be used to compute the 12-month rolling average in paragraph 
(f)(3) of this section.
    (1) For each calendar month, you must use Equation 3a or 3b or 3c 
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 are 
complying with the emission limits on a steam generation (output) 
basis. Use Equation 3c and the actual steam generation for the month if 
you are complying with the emission limits on a electrical generation 
(output) basis.
[GRAPHIC] [TIFF OMITTED] TR31JA13.008

Where:
AveWeightedEmissions = Average weighted emission level for PM (or 
TSM), HCl, 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 PM (or TSM), HCl, or mercury from unit, i, in 
units of pounds per million Btu of heat input. Determine the 
emission rate for PM (or TSM), HCl, or mercury by performance 
testing according to Table 5 to this subpart, or by fuel analysis 
for HCl or mercury or TSM according to Table 6 to this subpart.
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] TR31JA13.009

Where:
AveWeightedEmissions = Average weighted emission level for PM (or 
TSM), HCl, 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 PM (or TSM), HCl, or mercury from unit, i, in 
units of pounds per million Btu of steam output. Determine the 
emission rate for PM (or TSM), HCl, or mercury by performance 
testing according to Table 5 to this subpart, or by fuel analysis 
for HCl or mercury or TSM according to Table 6 to this subpart. 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.
[GRAPHIC] [TIFF OMITTED] TR31JA13.010

Where:
AveWeightedEmissions = Average weighted emission level for PM (or 
TSM), HCl, or mercury, in units of pounds per megawatt hour, for 
that calendar month.
Er = Emission rate (as determined during the most recent compliance 
demonstration) of PM (or TSM), HCl, or mercury from unit, i, in 
units of pounds per megawatt hour. Determine the emission rate for 
PM (or TSM), HCl, or mercury by performance testing according to 
Table 5 to this subpart, or by fuel analysis for HCl or mercury or 
TSM according to Table 6 to this subpart. 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.
Eo = The electric generating output for that calendar month from 
unit, i, in units of megawatt 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 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] TR31JA13.011

Where:
AveWeightedEmissions = average weighted emission level for PM (or 
TSM), HCl, or mercury, in units of pounds per million

[[Page 7171]]

Btu of heat input for that calendar month.
Er = Emission rate (as determined during the most recent compliance 
demonstration of PM (or TSM), HCl, or mercury from unit, i, in units 
of pounds per million Btu of heat input. Determine the emission rate 
for PM (or TSM), HCl, or mercury by performance testing according to 
Table 5 to this subpart, or by fuel analysis for HCl or mercury or 
TSM according to Table 6 to this subpart.
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.

* * * * *
    (g) You must develop, and submit upon request to the applicable 
Administrator 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.
* * * * *
    (2) * * *
    (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 January 31, 
2013 and the date on which you are requesting emission averaging to 
commence;
* * * * *
    (iv) The test plan for the measurement of PM (or TSM), HCl, or 
mercury emissions in accordance with the requirements in Sec.  63.7520;
* * * * *
    (vi) * * *
    (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 Administrator, that the proposed monitoring frequency is sufficient 
to represent control device operating conditions; and
* * * * *
    (3) The Administrator shall review and approve or disapprove the 
plan according to the following criteria:
* * * * *
    (4) The applicable Administrator shall not approve an emission 
averaging implementation plan containing any of the following 
provisions:
* * * * *
    (ii) The inclusion of any emission source other than an existing 
unit in the same subcategories.
* * * * *
    (h) For a group of two or more existing affected units, each of 
which vents through a single common stack, you may average PM (or TSM), 
HCl, 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 
subcategories, each of which vents through a common emissions control 
system to a common stack, that does not receive emissions from units in 
other subcategories or categories, you may treat such averaging group 
as a single existing unit for purposes of this subpart and comply with 
the requirements of this subpart as if the group were a single unit.
    (j) * * *
    (1) Conduct performance tests according to procedures specified in 
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] TR31JA13.012

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.
* * * * *
    (k) The common stack of a group of two or more existing boilers or 
process heaters in the same subcategories 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.

0
17. Section 63.7525 is amended by:
0
a. Revising paragraph (a)
0
b. Revising paragraph (b).
0
c. Revising paragraph (c) introductory text.
0
d. Revising paragraphs (d) introductory text and paragraphs (d)(1) 
through (d)(4).
0
e. Revising paragraph (e)(2).
0
f. Revising paragraph (e)(3).
0
g. Revising paragraph (f)(2).
0
h. Revising paragraph (j).
0
i. Revising paragraph (k).
0
j. Adding paragraph (l).
0
k. Adding paragraph (m).
    The revisions and additions read as follows:

Sec.  63.7525  What are my monitoring, installation, operation, and 
maintenance requirements?

    (a) If your boiler or process heater is subject to a CO emission 
limit in Tables 1, 2, or 11 through 13 to this subpart, you must 
install, operate, and maintain an oxygen analyzer system, as defined in 
Sec.  63.7575, or install, certify, operate and maintain continuous 
emission monitoring systems for CO and oxygen according to the 
procedures in paragraphs (a)(1) through (7) of this section.
    (1) Install the CO CEMS and oxygen analyzer by the compliance date 
specified in Sec.  63.7495. The CO and oxygen levels shall be monitored 
at the same location at the outlet of the boiler or process heater.
    (2) To demonstrate compliance with the applicable alternative CO 
CEMS emission standard listed in Tables 1, 2, or 11 through 13 to this 
subpart, you must install, certify, operate, and maintain a CO CEMS and 
an oxygen analyzer according to the applicable procedures under 
Performance Specification 4, 4A, or 4B at 40 CFR part 60, appendix B, 
the site-specific monitoring plan developed according to Sec.  
63.7505(d), and the requirements in Sec.  63.7540(a)(8) and paragraph 
(a) of this section. Any boiler or process heater that has a CO CEMS 
that is compliant with Performance Specification 4, 4A, or 4B at 40 CFR 
part 60, appendix B, a site-specific monitoring plan developed 
according to Sec.  63.7505(d), and the requirements in Sec.  
63.7540(a)(8) and paragraph (a) of this section must use the CO CEMS to 
comply with the applicable alternative CO CEMS emission standard listed 
in Tables 1, 2, or 11 through 13 to this subpart.
    (i) You must conduct a performance evaluation of each CO CEMS 
according to the requirements in Sec.  63.8(e) and

[[Page 7172]]

according to Performance Specification 4, 4A, or 4B at 40 CFR part 60, 
appendix B.
    (ii) During each relative accuracy test run of the CO CEMS, you 
must be collect emission data for CO 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.
    (iii) 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 measurement span value of the 
CO CEMS must be two times the applicable CO emission limit, expressed 
as a concentration.
    (iv) Any CO CEMS that does not comply with Sec.  63.7525(a) cannot 
be used to meet any requirement in this subpart to demonstrate 
compliance with a CO emission limit listed in Tables 1, 2, or 11 
through 13 to this subpart.
    (v) For a new unit, complete the initial performance evaluation no 
later than July 30, 2013, or 180 days after the date of initial 
startup, whichever is later. For an existing unit, complete the initial 
performance evaluation no later than July 29, 2016.
    (3) Complete a minimum of one cycle of CO and oxygen CEMS operation 
(sampling, analyzing, and data recording) for each successive 15-minute 
period. Collect CO and oxygen data concurrently. Collect at least four 
CO and oxygen 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.
    (4) Reduce the CO CEMS data as specified in Sec.  63.8(g)(2).
    (5) Calculate one-hour arithmetic averages, corrected to 3 percent 
oxygen from each hour of CO CEMS data in parts per million CO 
concentration. The one-hour arithmetic averages required shall be used 
to calculate the 30-day or 10-day rolling average emissions. Use 
Equation 19-19 in section 12.4.1 of Method 19 of 40 CFR part 60, 
appendix A-7 for calculating the average CO concentration from the 
hourly values.
    (6) For purposes of collecting CO data, 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).
    (7) Operate an oxygen trim system with the oxygen level set no 
lower than the lowest hourly average oxygen concentration measured 
during the most recent CO performance test as the operating limit for 
oxygen according to Table 7 to this subpart.
    (b) If your boiler or process heater is in the unit designed to 
burn coal/solid fossil fuel subcategory or the unit designed to burn 
heavy liquid subcategory and has an average annual heat input rate 
greater than 250 MMBtu per hour from solid fossil fuel and/or heavy 
liquid, and you demonstrate compliance with the PM limit instead of the 
alternative TSM limit, you must install, 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. As an alternative to use of a PM CPMS to demonstrate 
compliance with the PM limit, you may choose to use a PM CEMS. If you 
choose to use a PM CEMS to demonstrate compliance with the PM limit 
instead of the alternative TSM limit, you must install, certify, 
maintain, and operate a PM CEMS monitoring emissions discharged to the 
atmosphere and record the output of the system as specified in 
paragraph (b)(5) through (8) of this section. For other boilers or 
process heaters, you may elect to use a PM CPMS or PM CEMS operated in 
accordance with this section in lieu of using other CMS for monitoring 
PM compliance (e.g., bag leak detectors, ESP secondary power, PM 
scrubber pressure). Owners of boilers and process heaters who elect to 
comply with the alternative TSM limit are not required to install a PM 
CPMS.
    (1) Install, 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 paragraphs (b)(1)(i) through (iii) of this 
section.
    (i) The operating principle of the PM CPMS must be based on in-
stack or extractive light scatter, light scintillation, beta 
attenuation, or mass accumulation detection of PM in the exhaust gas or 
representative exhaust gas sample. The reportable measurement output 
from the PM CPMS must be expressed as milliamps.
    (ii) The PM CPMS must have a cycle time (i.e., period required to 
complete sampling, measurement, and reporting for each measurement) no 
longer than 60 minutes.
    (iii) The PM CPMS must be capable of detecting and responding to PM 
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 July 30, 2013, or 180 days after the date of initial 
startup, whichever is later. For an existing unit, complete the initial 
performance evaluation no later than July 29, 2016.
    (3) Collect PM CPMS hourly average output data for all boiler or 
process heater operating hours except as indicated in Sec.  63.7535(a) 
through (d). Express the PM CPMS output as milliamps.
    (4) Calculate the arithmetic 30-day rolling average of all of the 
hourly average PM CPMS output data collected during all boiler or 
process heater operating hours (milliamps).
    (5) Install, certify, operate, and maintain your PM CEMS 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 paragraphs (b)(5)(i) through (iv) of this 
section.
    (i) You shall conduct a performance evaluation of the PM CEMS 
according to the applicable requirements of Sec.  60.8(e), and 
Performance Specification 11 at 40 CFR part 60, appendix B of this 
chapter.
    (ii) During each PM correlation testing run of the CEMS required by 
Performance Specification 11 at 40 CFR part 60, appendix B of this 
chapter, you shall collect PM and oxygen (or carbon dioxide) data 
concurrently (or within a 30-to 60-minute period) by both the CEMS and 
conducting performance tests using Method 5 at 40 CFR part 60, appendix 
A-3 or Method 17 at 40 CFR part 60, appendix A-6 of this chapter.
    (iii) You shall perform quarterly accuracy determinations and daily 
calibration drift tests in accordance with Procedure 2 at 40 CFR part 
60, appendix F of this chapter. You must perform Relative Response 
Audits annually and perform Response Correlation Audits every 3 years.
    (iv) Within 60 days after the date of completing each CEMS relative 
accuracy test audit or performance test conducted to demonstrate 
compliance with this subpart, you must submit the relative accuracy 
test audit data and performance test data to the EPA by successfully 
submitting the data electronically into the EPA's Central Data Exchange 
by using the Electronic Reporting Tool (see http://www.epa.gov/ttn/chief/ert/erttool.html/).
    (6) For a new unit, complete the initial performance evaluation no 
later than July 30, 2013, or 180 days after the date of initial 
startup, whichever is later. For an existing unit, complete the

[[Page 7173]]

initial performance evaluation no later than July 29, 2016.
    (7) Collect PM CEMS hourly average output data for all boiler or 
process heater operating hours except as indicated in Sec.  63.7535(a) 
through (d).
    (8) Calculate the arithmetic 30-day rolling average of all of the 
hourly average PM CEMS output data collected during all boiler or 
process heater operating hours.
    (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, PM CEMS, 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.
* * * * *
    (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 paragraphs (d)(1) through (5) 
of this section by the compliance date specified in Sec.  63.7495.
    (1) The CPMS must complete a minimum of one cycle of operation 
every 15-minutes. You must have a minimum of four successive cycles of 
operation, one representing each of the four 15-minute periods in an 
hour, 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 Sec.  63.7535(c).
* * * * *
    (e) * * *
    (2) You must use a flow sensor with a measurement sensitivity of no 
greater than 2 percent of the design flow rate.
    (3) You must minimize, consistent with good engineering practices, 
the effects of swirling flow or abnormal velocity distributions due to 
upstream and downstream disturbances.
* * * * *
    (f) * * *
    (2) Minimize or eliminate pulsating pressure, vibration, and 
internal and external corrosion consistent with good engineering 
practices.
* * * * *
    (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 PM 
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 PM 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 plant operating personnel when an increase in relative PM 
emissions over a preset level is detected. The alert must easily 
recognizable (e.g., heard or seen) by plant operating personnel.
    (6) Where multiple bag leak detectors are required, the system's 
instrumentation and alert may be shared among detectors.
    (k) For each unit that meets the definition of limited-use boiler 
or process heater, you must keep fuel use records for the days the 
boiler or process heater was operating.
    (l) For each unit for which you decide to demonstrate compliance 
with the mercury or HCl emissions limits in Tables 1 or 2 or 11 through 
13 of this subpart by use of a CEMS for mercury or HCl, 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 HCl, 
this option for an affected unit takes effect on the date a final 
performance specification for a HCl 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 HCl 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 July 30, 2013.
    (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 July 29, 2016.
    (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 HCl 
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 30-day and 10-day 
rolling average emissions.
    (8) You are allowed to substitute the use of the PM, mercury or HCl 
CEMS for the applicable fuel analysis, annual performance test, and 
operating limits specified in Table 4 to this subpart to demonstrate 
compliance with the PM, mercury or HCl emissions limit, and if you are 
using an acid gas wet scrubber or dry sorbent injection control 
technology to comply with the HCl emission limit, you are allowed to 
substitute the use of a sulfur dioxide

[[Page 7174]]

(SO2) CEMS for the applicable fuel analysis, annual 
performance test, and operating limits specified in Table 4 to this 
subpart to demonstrate compliance with HCl emissions limit.
    (m) If your unit is subject to a HCl emission limit in Tables 1, 2, 
or 11 through 13 of this subpart and you have an acid gas wet scrubber 
or dry sorbent injection control technology and you use an 
SO2 CEMS, you must install the monitor at the outlet of the 
boiler or process heater, downstream of all emission control devices, 
and you must install, certify, operate, and maintain the CEMS according 
to part 75 of this chapter.
    (1) The SO2 CEMS must be installed by the compliance 
date specified in Sec.  63.7495.
    (2) For on-going quality assurance (QA), the SO2 CEMS 
must meet the applicable daily, quarterly, and semiannual or annual 
requirements in sections 2.1 through 2.3 of appendix B to part 75 of 
this chapter, with the following addition: You must perform the 
linearity checks required in section 2.2 of appendix B to part 75 of 
this chapter if the SO2 CEMS has a span value of 30 ppm or 
less.
    (3) For a new unit, the initial performance evaluation shall be 
completed no later than July 30, 2013, or 180 days after the date of 
initial startup, whichever is later. For an existing unit, the initial 
performance evaluation shall be completed no later than July 29, 2016.
    (4) For purposes of collecting SO2 data, you must 
operate the SO2 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 SO2 data 
are unavailable may constitute monitoring deviations as specified in 
Sec.  63.7535(d).
    (5) Collect CEMS hourly averages for all operating hours on a 30-
day rolling average basis.
    (6) Use only unadjusted, quality-assured SO2 
concentration values in the emissions calculations; do not apply bias 
adjustment factors to the part 75 SO2 data and do not use 
part 75 substitute data values.

0
18. Section 63.7530 is amended by:
0
a. Revising paragraph (a).
0
b. Revising paragraph (b) introductory text.
0
c. Redesignating paragraph (b)(3) as paragraph (b)(4) and adding new 
paragraph (b)(3).
0
d. Revising newly designated paragraph (b)(4).
0
e. Revising paragraph (c), (c)(2) through (4).
0
f. Adding paragraph (c)(5).
0
g. Revising paragraphs (d), (e), (g), and (h).
0
h. Adding paragraph (i).
    The revisions and additions read as follows:

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. The requirement to conduct a fuel 
analysis is not applicable for units that burn a single type of fuel, 
as specified by Sec.  63.7510(a)(2)(i). If applicable, you must also 
install, operate, and maintain all applicable CMS (including CEMS, 
COMS, and CPMS) 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 TSM input into the unit through the 
results of fuel analysis, then you must repeat the performance test to 
demonstrate compliance while burning the new fuel(s).
* * * * *
    (3) If you opt to comply with the alternative TSM limit, you must 
establish the maximum TSM fuel input (TSMinput) for solid or liquid 
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 
TSM.
    (ii) During the fuel analysis for TSM, 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 TSM, and the 
average TSM concentration of each fuel type burned (TSMi).
    (iii) You must establish a maximum TSM input level using Equation 9 
of this section.
[GRAPHIC] [TIFF OMITTED] TR31JA13.013

Where:

TSMinput = Maximum amount of TSM entering the boiler or process 
heater through fuels burned in units of pounds per million Btu.
TSMi = Arithmetic average concentration of TSM in fuel type, i, 
analyzed according to 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 TSM. 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 TSM.

    (4) You must establish parameter operating limits according to 
paragraphs (b)(4)(i) through (ix) 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 performance test during which you 
demonstrate compliance with your applicable limit. If you use a wet 
scrubber and you conduct separate performance tests for HCl and mercury 
emissions, you must establish one set of minimum scrubber effluent pH, 
liquid flow rate, and

[[Page 7175]]

pressure drop operating limits. The minimum scrubber effluent pH 
operating limit must be established during the HCl performance test. If 
you conduct multiple performance tests, you must set the minimum liquid 
flow rate 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 PM CPMS operating limit and determine compliance with it 
according to paragraphs (b)(4)(ii)(A) through (F) of this section.
    (A) Determine your operating limit as the average PM CPMS output 
value recorded during the most recent performance test run 
demonstrating compliance with the filterable PM emission limit or at 
the PM CPMS output value corresponding to 75 percent of the emission 
limit if your PM performance test demonstrates compliance below 75 
percent of the emission limit. You must verify an existing or establish 
a new operating limit after each repeated performance test. You must 
repeat the performance test annually and reassess and adjust the site-
specific operating limit in accordance with the results of the 
performance test.
    (1) Your PM CPMS must provide a 4-20 milliamp output and the 
establishment of its relationship to manual reference method 
measurements must be determined in units of milliamps.
    (2) Your PM CPMS operating range must be capable of reading PM 
concentrations from zero to a level equivalent to at least two times 
your allowable emission limit. If your PM CPMS is an auto-ranging 
instrument capable of multiple scales, the primary range of the 
instrument must be capable of reading PM concentration from zero to a 
level equivalent to two times your allowable emission limit.
    (3) During the initial performance test or any such subsequent 
performance test that demonstrates compliance with the PM limit, record 
and average all milliamp output values from the PM CPMS for the periods 
corresponding to the compliance test runs (e.g., average all your PM 
CPMS output values for three corresponding 2-hour Method 5I test runs).
    (B) If the average of your three PM performance test runs are below 
75 percent of your PM emission limit, you must calculate an operating 
limit by establishing a relationship of PM CPMS signal to PM 
concentration using the PM CPMS instrument zero, the average PM CPMS 
values corresponding to the three compliance test runs, and the average 
PM concentration from the Method 5 or performance test with the 
procedures in paragraphs (b)(4)(ii)(B)(1) through (4) of this section.
    (1) Determine your instrument zero output with one of the following 
procedures:
    (i) Zero point data for in-situ instruments should be obtained by 
removing the instrument from the stack and monitoring ambient air on a 
test bench.
    (ii) Zero point data for extractive instruments should be obtained 
by removing the extractive probe from the stack and drawing in clean 
ambient air.
    (iii) The zero point may also be established by performing manual 
reference method measurements when the flue gas is free of PM emissions 
or contains very low PM concentrations (e.g., when your process is not 
operating, but the fans are operating or your source is combusting only 
natural gas) and plotting these with the compliance data to find the 
zero intercept.
    (iv) If none of the steps in paragraphs (b)(4)(ii)(B)(1)(i) through 
(iii) of this section are possible, you must use a zero output value 
provided by the manufacturer.
    (2) Determine your PM CPMS instrument average in milliamps, and the 
average of your corresponding three PM compliance test runs, using 
equation 10.
[GRAPHIC] [TIFF OMITTED] TR31JA13.014

Where:

X1 = the PM CPMS data points for the three runs 
constituting the performance test,
Y1 = the PM concentration value for the three runs 
constituting the performance test, and
n = the number of data points.

    (3) With your instrument zero expressed in milliamps, your three 
run average PM CPMS milliamp value, and your three run average PM 
concentration from your three compliance tests, determine a 
relationship of lb/MMBtu per milliamp with equation 11.
[GRAPHIC] [TIFF OMITTED] TR31JA13.015

Where:

R = the relative lb/MMBtu per milliamp for your PM CPMS,
Y1 = the three run average lb/MMBtu PM concentration,
X1 = the three run average milliamp output from you PM 
CPMS, and
z = the milliamp equivalent of your instrument zero determined from 
(B)(i).

    (4) Determine your source specific 30-day rolling average operating 
limit using the lb/MMBtu per milliamp value from Equation 11 in 
equation 12, below. This sets your operating limit at the PM CPMS 
output value corresponding to 75 percent of your emission limit.
[GRAPHIC] [TIFF OMITTED] TR31JA13.016

Where:

Ol = the operating limit for your PM CPMS on a 30-day 
rolling average, in milliamps.
L = your source emission limit expressed in lb/MMBtu,
z = your instrument zero in milliamps, determined from (B)(i), and
R = the relative lb/MMBtu per milliamp for your PM CPMS, from 
Equation 11.

    (C) If the average of your three PM compliance test runs is at or 
above 75 percent of your PM emission limit you must determine your 30-
day rolling average operating limit by averaging the PM CPMS milliamp 
output corresponding to your three PM performance test runs that 
demonstrate compliance with the emission limit using equation 13 and 
you must submit all compliance test and PM CPMS data according to the 
reporting requirements in paragraph (b)(4)(ii)(F) of this section.
[GRAPHIC] [TIFF OMITTED] TR31JA13.017

Where:

X1 = the PM CPMS data points for all runs i,
n = the number of data points, and
Oh = your site specific operating limit, in milliamps.

    (D) To determine continuous compliance, you must record the PM

[[Page 7176]]

CPMS output data for all periods when the process is operating and the 
PM CPMS is not out-of-control. You must demonstrate continuous 
compliance by using all quality-assured hourly average data collected 
by the PM CPMS for all operating hours to calculate the arithmetic 
average operating parameter in units of the operating limit (milliamps) 
on a 30-day rolling average basis, updated at the end of each new 
operating hour. Use Equation 14 to determine the 30-day rolling 
average.
[GRAPHIC] [TIFF OMITTED] TR31JA13.018

Where:

30-day = 30-day average.
Hpvi = is the hourly parameter value for hour i
n = is the number of valid hourly parameter values collected over 
the previous 720 operating hours.

    (E) Use EPA Method 5 of appendix A to part 60 of this chapter to 
determine PM emissions. For each performance test, conduct three 
separate runs under the conditions that exist when the affected source 
is operating at the highest load or capacity level reasonably expected 
to occur. Conduct each test run to collect a minimum sample volume 
specified in Tables 1, 2, or 11 through 13 to this subpart, as 
applicable, for determining compliance with a new source limit or an 
existing source limit. Calculate the average of the results from three 
runs to determine compliance. You need not determine the PM collected 
in the impingers (``back half'') of the Method 5 particulate sampling 
train to demonstrate compliance with the PM standards of this subpart. 
This shall not preclude the permitting authority from requiring a 
determination of the ``back half'' for other purposes.
    (F) For PM performance test reports used to set a PM CPMS operating 
limit, the electronic submission of the test report must also include 
the make and model of the PM CPMS instrument, serial number of the 
instrument, analytical principle of the instrument (e.g. beta 
attenuation), span of the instruments primary analytical range, 
milliamp value equivalent to the instrument zero output, technique by 
which this zero value was determined, and the average milliamp signals 
corresponding to each PM compliance test run. (iii) For a particulate 
wet scrubber, you must establish the minimum pressure drop and liquid 
flow rate as defined in 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 PM and TSM emissions, you must establish 
one set of minimum scrubber liquid flow rate and pressure drop 
operating limits. The minimum scrubber effluent pH operating limit must 
be established during the HCl performance test. If you conduct multiple 
performance tests, you must set the minimum liquid flow rate and 
pressure drop operating limits at the higher of the minimum values 
established during the performance tests.
    (iii) For an electrostatic precipitator (ESP) operated with a wet 
scrubber, you must establish the minimum total secondary electric power 
input, 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. (These operating limits do not apply to ESP that 
are operated as dry controls without a wet scrubber.)
    (iv) 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.
    (v) 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.
    (vi) 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 alert 
is not activated more than 5 percent of the operating time during a 6-
month period.
    (vii) For a minimum oxygen level, if you conduct multiple 
performance tests, you must set the minimum oxygen level at the lower 
of the minimum values established during the performance tests.
    (viii) The operating limit for boilers or process heaters that 
demonstrate continuous compliance with the HCl emission limit using a 
SO2 CEMS is to install and operate the SO2 
according to the requirements in Sec.  63.7525(m) establish a maximum 
SO2 emission rate equal to the highest hourly average 
SO2 measurement during the most recent three-run performance 
test for HCl.
    (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.
* * * * *
    (2) You must determine the 90th percentile confidence level fuel 
pollutant concentration of the composite samples analyzed for each fuel 
type using the one-sided t-statistic test described in Equation 15 of 
this section.
[GRAPHIC] [TIFF OMITTED] TR31JA13.019

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 mean of pollutant concentration in 
the fuel samples analyzed according to Sec.  63.7521, in units of 
pounds per million Btu. SD is calculated as the sample standard

[[Page 7177]]

deviation divided by the square root of the number of samples.
t = t distribution critical value for 90th percentile 
(t0.1) probability for the appropriate degrees of freedom 
(number of samples minus one) as obtained from a t-Distribution 
Critical Value Table.

    (3) To demonstrate compliance with the applicable emission limit 
for HCl, the HCl emission rate that you calculate for your boiler or 
process heater using Equation 16 of this section must not exceed the 
applicable emission limit for HCl.
[GRAPHIC] [TIFF OMITTED] TR31JA13.020

Where:

HCl = HCl emission rate from the boiler or process heater in units 
of pounds per million Btu.
Ci90 = 90th percentile confidence level concentration of chlorine in 
fuel type, i, in units of pounds per million Btu as calculated 
according to Equation 11 of this section.
Qi = Fraction of total heat input from fuel type, i, based on the 
fuel mixture that has the highest content of chlorine. If you do not 
burn multiple fuel types, it is not necessary to determine the value 
of this term. Insert a value of ``1'' for Qi.
n = Number of different fuel types burned in your boiler or process 
heater for the mixture that has the highest content of chlorine.
1.028 = Molecular weight ratio of HCl to chlorine.

    (4) To demonstrate compliance with the applicable emission limit 
for mercury, the mercury emission rate that you calculate for your 
boiler or process heater using Equation 17 of this section must not 
exceed the applicable emission limit for mercury.
[GRAPHIC] [TIFF OMITTED] TR31JA13.021

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 11 of this section.
Qi = Fraction of total heat input from fuel type, i, based on the 
fuel mixture that has the highest mercury content. If you do not 
burn multiple fuel types, it is not necessary to determine the value 
of this term. Insert a value of ``1'' for Qi.
n = Number of different fuel types burned in your boiler or process 
heater for the mixture that has the highest mercury content.

    (5) To demonstrate compliance with the applicable emission limit 
for TSM for solid or liquid fuels, the TSM emission rate that you 
calculate for your boiler or process heater from solid fuels using 
Equation 18 of this section must not exceed the applicable emission 
limit for TSM.
[GRAPHIC] [TIFF OMITTED] TR31JA13.022

Where:

Metals = TSM emission rate from the boiler or process heater in 
units of pounds per million Btu.
TSMi90 = 90th percentile confidence level concentration of TSM in 
fuel, i, in units of pounds per million Btu as calculated according 
to Equation 11 of this section.
Qi = Fraction of total heat input from fuel type, i, based on the 
fuel mixture that has the highest TSM content. If you do not burn 
multiple fuel types, it is not necessary to determine the value of 
this term. Insert a value of ``1'' for Qi.
n = Number of different fuel types burned in your boiler or process 
heater for the mixture that has the highest TSM content.

    (d) If you own or operate an existing unit with a heat input 
capacity of less than 10 million Btu per hour or a unit in the unit 
designed to burn gas 1 subcategory, 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 at the time of the assessment.
* * * * *
    (g) If you elect to demonstrate that a gaseous fuel meets the 
specifications of another 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) and according to the frequency listed in Sec.  
63.7540(c) and maintain records of the results of the testing as 
outlined in Sec.  63.7555(g). For samples where the initial mercury 
specification has not been exceeded, 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.
    (h) If you own or operate a unit subject to emission limits in 
Tables 1 or 2 or 11 through 13 to this subpart, you must meet the work 
practice standard according to Table 3 of this subpart. During startup 
and shutdown, you must only follow the work practice standards 
according to item 5 of Table 3 of this subpart.
    (i) If you opt to comply with the alternative SO2 CEMS 
operating limit in Tables 4 and 8 to this subpart, you may do so only 
if your affected boiler or process heater:
    (1) Has a system using wet scrubber or dry sorbent injection and 
SO2 CEMS installed on the unit; and
    (2) At all times, you operate the wet scrubber or dry sorbent 
injection for acid gas control on the unit consistent with Sec.  
63.7500(a)(3); and
    (3) You establish a unit-specific maximum SO2 operating 
limit by

[[Page 7178]]

collecting the minimum hourly SO2 emission rate on the 
SO2 CEMS during the paired 3-run test for HCl. The maximum 
SO2 operating limit is equal to the highest hourly average 
SO2 concentration measured during the most recent HCl 
performance test.

0
19. Section 63.7533 is amended by:
0
a. Revising the section heading.
0
b. Revising paragraph (a).
0
c. Revising paragraphs (b)(1) and (4).
0
d. Revising paragraphs (c) introductory text, (c)(1)(i) and (ii), 
(c)(2)(i), and (c)(3).
0
e. Revising paragraph (d) through (f).
0
f. Adding paragraph (g).
    The revisions and addition read as follows:

Sec.  63.7533  Can I use efficiency credits earned from implementation 
of energy conservation measures to comply with this subpart?

    (a) If you elect to comply with the alternative equivalent 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 efficiency 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 
efficiency credits, develop an Implementation Plan, comply with the 
general reporting requirements, and apply the efficiency 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. Additional guidance from the Department 
of Energy on efficiency credits is available at: http://www.epa.gov/ttn/atw/boiler/boilerpg.html.
    (b) * * *
    (1) The benchmark from which efficiency 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.
* * * * *
    (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) Efficiency 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 
efficiency 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) Efficiency credits on shut-down boilers. Boilers that are shut 
down cannot be used to generate credits unless the facility provides 
documentation linking the permanent shutdown to energy conservation 
measures identified in the energy assessment. In this case, the bench 
established for the affected boiler to which the credits from the 
shutdown will be applied must be revised to include the benchmark 
established for the shutdown boiler.
    (2) * * *
    (i) Calculate annual credits for all energy demand points. Use 
Equation 19 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 19 of this 
section as follows:
    (i) The overall equation for calculating credits is:
    [GRAPHIC] [TIFF OMITTED] TR31JA13.023
    
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 
efficiency credit for the affected boiler.

    (ii) [Reserved]
    (d) The owner or operator shall develop, and submit for approval 
upon request by the Administrator, an Implementation Plan containing 
all of the information required in this paragraph for all boilers to be 
included in an efficiency credit approach. The Implementation Plan 
shall identify all existing affected boilers to be included in applying 
the efficiency 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. If requested, you must 
submit the implementation plan for efficiency credits to the 
Administrator for review and approval no later than 180 days before the 
date on which the facility intends to demonstrate compliance using the 
efficiency credit approach.
    (e) The emissions rate as calculated using Equation 20 of this 
section from each existing boiler participating in the efficiency 
credit option must be in compliance with the limits in Table 2 to this 
subpart at all times the affected unit is operating, following the 
compliance date specified in Sec.  63.7495.
    (f) You must use Equation 20 of this section to demonstrate initial 
compliance by demonstrating that the emissions from the affected boiler 
participating in the efficiency credit compliance approach do not 
exceed the emission limits in Table 2 to this subpart.

[[Page 7179]]

[GRAPHIC] [TIFF OMITTED] TR31JA13.024

Where:

Eadj = Emission level adjusted by applying the efficiency 
credits earned, lb per million Btu steam output (or lb per MWh) for 
the affected boiler.
Em = Emissions measured during the performance test, lb 
per million Btu steam output (or lb per MWh) for the affected 
boiler.
ECredits = Efficiency credits from Equation 19 for the affected 
boiler.

    (g) As part of each compliance report submitted as required under 
Sec.  63.7550, you must include documentation that the energy 
conservation measures implemented continue to generate the credit for 
use in demonstrating compliance with the emission limits.

0
20. Section 63.7535 is amended by revising the section heading and 
paragraphs (b), (c), and (d) to read as follows:

Sec.  63.7535  Is there a minimum amount of monitoring data I must 
obtain?

* * * * *
    (b) You must operate the monitoring system and collect data at all 
required intervals at all times that each boiler or process heater 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. In calculating monitoring 
results, do not use any data collected during periods when the 
monitoring system is out of control as specified in your site-specific 
monitoring plan, while conducting repairs associated with periods when 
the monitoring system is out of control, or while conducting required 
monitoring system quality assurance or quality control activities. You 
must calculate monitoring results using all other monitoring data 
collected while the process is operating. You must report all periods 
when the monitoring system is out of control in your annual report.

0
21. Section 63.7540 is revised to read as follows:

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 or 11 through 13 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 (19) 
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 HCl, mercury, and TSM than the applicable 
emission limit for each pollutant, if you demonstrate compliance 
through fuel analysis.
    (ii) Lower fuel input of chlorine, mercury, and TSM 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 HCl emission 
limit through fuel analysis for a solid or liquid fuel and you plan to 
burn a new type of solid or liquid fuel, you must recalculate the HCl 
emission rate using Equation 12 of Sec.  63.7530 according to 
paragraphs (a)(3)(i) through (iii) of this section. You are not 
required to conduct fuel analyses for the fuels described in 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 HCl 
emission rate.
    (i) You must determine the chlorine concentration for any new fuel 
type in units of pounds per million Btu, based on supplier data or your 
own fuel analysis, according to the provisions in your site-specific 
fuel analysis plan developed according to Sec.  63.7521(b).
    (ii) You must determine the new mixture of fuels that will have the 
highest content of chlorine.
    (iii) Recalculate the HCl emission rate from your boiler or process 
heater under these new conditions using Equation 12 of Sec.  63.7530. 
The recalculated HCl emission rate must be less than the applicable 
emission limit.
    (4) If you demonstrate compliance with an applicable HCl 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

[[Page 7180]]

procedures in Sec.  63.7520 to demonstrate that the HCl 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 conduct 
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 
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 
conduct 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 13 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 conduct 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 alert and complete corrective actions as soon as 
practical, and operate and maintain the fabric filter system such that 
the periods which would cause an alert are no 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 alert, the time corrective 
action was initiated and completed, and a brief description of the 
cause of the alert and the corrective action taken. You must also 
record the percent of the operating time during each 6-month period 
that the conditions exist for an alert. In calculating this operating 
time percentage, if inspection of the fabric filter demonstrates that 
no corrective action is required, no alert time is counted. If 
corrective action is required, each alert shall be counted as a minimum 
of 1 hour. If you take longer than 1 hour to initiate corrective 
action, the alert time shall be counted as the actual amount of time 
taken to initiate corrective action.
    (8) To demonstrate compliance with the applicable alternative CO 
CEMS emission limit listed in Tables 1, 2, or 11 through 13 to this 
subpart, you must meet the requirements in paragraphs (a)(8)(i) through 
(iv) 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 or 11 through 13 to 
this subpart at all times the affected unit is operating.
    (iii) Keep records of CO levels according to Sec.  63.7555(b).
    (iv) You must record and make available upon request results of CO 
CEMS performance audits, dates and duration of periods when the CO CEMS 
is out of control to completion of the corrective actions necessary to 
return the CO CEMS to operation consistent with your site-specific 
monitoring plan.
    (9) The owner or operator of a boiler or process heater using a PM 
CPMS or a PM CEMS to meet requirements of this subpart shall install, 
certify, operate, and maintain the PM CPMS or PM CEMS in accordance 
with your site-specific monitoring plan as required in Sec.  
63.7505(d).
    (10) If your boiler or process heater has a heat input capacity of 
10 million Btu per hour or greater, you must conduct an annual tune-up 
of the boiler or process heater to demonstrate continuous compliance as 
specified in paragraphs (a)(10)(i) through (vi) of this section. This 
frequency does not apply to limited-use boilers and process heaters, as 
defined in Sec.  63.7575, or units with continuous oxygen trim systems 
that maintain an optimum air to fuel ratio.
    (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 unit shutdown). Units that produce 
electricity for sale may delay the burner inspection until the first 
outage, not to exceed 36 months from the previous inspection. At units 
where entry into a piece of process equipment or into a storage vessel 
is required to complete the tune-up inspections, inspections are 
required only during planned entries into the storage vessel or process 
equipment;
    (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 (you may delay the inspection until the next scheduled unit 
shutdown). Units that produce electricity for sale may delay the 
inspection until the first outage, not to exceed 36 months from the 
previous inspection;
    (iv) Optimize total emissions of CO. This optimization should be 
consistent with the manufacturer's specifications, if available, and 
with any NOX requirement to which the unit is subject;
    (v) Measure the concentrations in the effluent stream of CO 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). Measurements may be taken using a portable CO 
analyzer; 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 CO in the effluent stream in parts per 
million by volume, and oxygen in volume percent, measured at high fire 
or typical operating load, before and after the tune-up of the boiler 
or process heater;
    (B) A description of any corrective actions taken as a part of the 
tune-up; and

[[Page 7181]]

    (C) The type and amount of fuel used over the 12 months prior to 
the tune-up, 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), you must conduct a biennial tune-up of the 
boiler or process heater as specified in paragraphs (a)(10)(i) through 
(vi) of this section to demonstrate continuous compliance.
    (12) If your boiler or process heater has a continuous oxygen trim 
system that maintains an optimum air to fuel ratio, or a heat input 
capacity of less than or equal to 5 million Btu per hour and the unit 
is in the units designed to burn gas 1; units designed to burn gas 2 
(other); or units designed to burn light liquid subcategories, or meets 
the definition of limited-use boiler or process heater in Sec.  
63.7575, 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 30 calendar days 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 
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 the maximum of 30 unit operating days or 720 
hours. For each day 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 HCl emissions to meet 
requirements of this subpart, you must install, certify, operate, and 
maintain the HCl 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 an HCl 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 the 
maximum of 30 unit operating days or 720 hours. For each day in which 
the unit operates, you must obtain hourly HCl concentration data, and 
stack gas volumetric flow rate data.
    (ii) If you are using a HCl CEMS, you must install, operate, 
calibrate, and maintain an instrument for continuously measuring and 
recording the HCl 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 TSM 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 TSM 
input using Equation 9 of Sec.  63.7530. If the results of 
recalculating the maximum TSM 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 TSM 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 conduct 
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 TSM emission rate.
    (17) If you demonstrate compliance with an applicable TSM emission 
limit through fuel analysis for solid or liquid fuels, and you plan to 
burn a new type of fuel, you must recalculate the TSM emission rate 
using Equation 14 of Sec.  63.7530 according to the procedures 
specified in paragraphs (a)(5)(i) through (iii) of this section. You 
are not required to conduct fuel analyses for the fuels described in 
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 TSM emission rate.
    (i) You must determine the TSM concentration for any new fuel type 
in units of pounds per million Btu, based on supplier data or your own 
fuel analysis, according to the provisions in your site-specific fuel 
analysis plan developed according to Sec.  63.7521(b).
    (ii) You must determine the new mixture of fuels that will have the 
highest content of TSM.
    (iii) Recalculate the TSM emission rate from your boiler or process 
heater under these new conditions using Equation 14 of Sec.  63.7530. 
The recalculated TSM emission rate must be less than the applicable 
emission limit.
    (18) If you demonstrate continuous PM emissions compliance with a 
PM CPMS you will use a PM CPMS to establish a site-specific operating 
limit corresponding to the results of the performance test 
demonstrating compliance with the PM limit. You will conduct your 
performance test using the test method criteria in Table 5 of this 
subpart. You will use the PM CPMS to demonstrate continuous compliance 
with this operating limit. You must repeat the performance test 
annually and reassess and adjust the site-specific operating limit in 
accordance with the results of the performance test.
    (i) To determine continuous compliance, you must record the PM CPMS 
output data for all periods when the process is operating and the PM 
CPMS is not out-of-control. You must demonstrate continuous compliance 
by using all quality-assured hourly average data collected by the PM 
CPMS for all operating hours to calculate the arithmetic average 
operating parameter in units of the operating limit (milliamps) on a 
30-day rolling average basis, updated at the end of each new boiler or 
process heater operating hour.
    (ii) For any deviation of the 30-day rolling PM CPMS average value 
from the established operating parameter limit, you must:
    (A) Within 48 hours of the deviation, visually inspect the air 
pollution control device (APCD);
    (B) If inspection of the APCD identifies the cause of the 
deviation, take corrective action as soon as possible and return the PM 
CPMS measurement to within the established value; and

[[Page 7182]]

    (C) Within 30 days of the deviation or at the time of the annual 
compliance test, whichever comes first, conduct a PM emissions 
compliance test to determine compliance with the PM emissions limit and 
to verify or re-establish the CPMS operating limit. You are not 
required to conduct additional testing for any deviations that occur 
between the time of the original deviation and the PM emissions 
compliance test required under this paragraph.
    (iii) PM CPMS deviations from the operating limit leading to more 
than four required performance tests in a 12-month operating period 
constitute a separate violation of this subpart.
    (19) If you choose to comply with the PM filterable emissions limit 
by using PM CEMS you must install, certify, operate, and maintain a PM 
CEMS and record the output of the PM CEMS as specified in paragraphs 
(a)(19)(i) through (vii) of this section. The compliance limit will be 
expressed as a 30-day rolling average of the numerical emissions limit 
value applicable for your unit in Tables 1 or 2 or 11 through 13 of 
this subpart.
    (i) Install and certify your PM CEMS according to the procedures 
and requirements in Performance Specification 11--Specifications and 
Test Procedures for Particulate Matter Continuous Emission Monitoring 
Systems at Stationary Sources in Appendix B to part 60 of this chapter, 
using test criteria outlined in Table V of this rule. The reportable 
measurement output from the PM CEMS must be expressed in units of the 
applicable emissions limit (e.g., lb/MMBtu, lb/MWh).
    (ii) Operate and maintain your PM CEMS according to the procedures 
and requirements in Procedure 2-- Quality Assurance Requirements for 
Particulate Matter Continuous Emission Monitoring Systems at Stationary 
Sources in Appendix F to part 60 of this chapter.
    (A) You must conduct the relative response audit (RRA) for your PM 
CEMS at least once annually.
    (B) You must conduct the relative correlation audit (RCA) for your 
PM CEMS at least once every 3 years.
    (iii) Collect PM CEMS hourly average output data for all boiler 
operating hours except as indicated in paragraph (i) of this section.
    (iv) Calculate the arithmetic 30-day rolling average of all of the 
hourly average PM CEMS output data collected during all nonexempt 
boiler or process heater operating hours.
    (v) You must collect data using the PM CEMS at all times the unit 
is operating and at the intervals specified this paragraph (a), except 
for periods of monitoring system malfunctions, repairs associated with 
monitoring system malfunctions, and required monitoring system quality 
assurance or quality control activities.
    (vi) You must use all the data collected during all boiler or 
process heater operating hours in assessing the compliance with your 
operating limit except:
    (A) Any data collected during monitoring system malfunctions, 
repairs associated with monitoring system malfunctions, or required 
monitoring system quality assurance or control activities conducted 
during monitoring system malfunctions in calculations and report any 
such periods in your annual deviation report;
    (B) Any data collected during periods when the monitoring system is 
out of control as specified in your site-specific monitoring plan, 
repairs associated with periods when the monitoring system is out of 
control, or required monitoring system quality assurance or control 
activities conducted during out of control periods in calculations used 
to report emissions or operating levels and report any such periods in 
your annual deviation report;
    (C) Any data recorded during periods of startup or shutdown.
    (vii) You must record and make available upon request results of PM 
CEMS system performance audits, dates and duration of periods when the 
PM CEMS is out of control to completion of the corrective actions 
necessary to return the PM CEMS to operation consistent with your site-
specific monitoring plan.
    (b) You must report each instance in which you did not meet each 
emission limit and operating limit in Tables 1 through 4 or 11 through 
13 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 unit designed to burn gas 1 
subcategory, you must follow the sampling frequency specified in 
paragraphs (c)(1) through (4) of this section and conduct this sampling 
according to the procedures in Sec.  63.7521(f) through (i).
    (1) If the initial mercury constituents in the gaseous fuels are 
measured to be equal to or less than half of the mercury specification 
as defined in Sec.  63.7575, you do not need to conduct further 
sampling.
    (2) If the initial mercury constituents are greater than half but 
equal to or less than 75 percent of the mercury specification as 
defined in Sec.  63.7575, you will conduct semi-annual sampling. If 6 
consecutive semi-annual fuel analyses demonstrate 50 percent or less of 
the mercury specification, you do not need to conduct further sampling. 
If any semi-annual sample exceeds 75 percent of the mercury 
specification, you must return to monthly sampling for that fuel, until 
12 months of fuel analyses again are less than 75 percent of the 
compliance level.
    (3) If the initial mercury constituents are greater than 75 percent 
of the mercury specification as defined in Sec.  63.7575, you will 
conduct monthly sampling. If 12 consecutive monthly fuel analyses 
demonstrate 75 percent or less of the mercury specification, you may 
decrease the fuel analysis frequency to semi-annual for that fuel.
    (4) If the initial sample exceeds the mercury specification as 
defined in Sec.  63.7575, each affected boiler or process heater 
combusting this fuel is not part of the unit designed to burn gas 1 
subcategory and must be in compliance with the emission and operating 
limits for the appropriate subcategory. You may elect to conduct 
additional monthly sampling while complying with these emissions and 
operating limits to demonstrate that the fuel qualifies as another gas 
1 fuel. If 12 consecutive monthly fuel analyses samples are at or below 
the mercury specification as defined in Sec.  63.7575, each affected 
boiler or process heater combusting the fuel can elect to switch back 
into the unit designed to burn gas 1 subcategory until the mercury 
specification is exceeded.
    (d) For startup and shutdown, you must meet the work practice 
standards according to item 5 of Table 3 of this subpart.

0
22. Section 63.7541 is amended by revising paragraphs (a)(3) and (4) to 
read as follows:

Sec.  63.7541  How do I demonstrate continuous compliance under the 
emissions averaging provision?

* * * * *
    (a) * * *
    (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 above 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 parameter, maintain 
the 30-day rolling

[[Page 7183]]

average parameter values consistent with the approved monitoring plan.
* * * * *

0
23. Section 63.7545 is amended by:
0
a. Revising paragraphs (a) through (c).
0
b. Revising paragraphs (e) introductory text, (e)(1), (e)(2), (e)(3), 
(e)(4), (e)(5) introductory text, and (e)(5)(i).
0
c. Adding paragraph (e)(5)(ii).
0
d. Revising paragraphs (e)(8)(i) and (iii).
0
e. Revising paragraph (f) introductory text.
0
f. Revising paragraphs (g)(1) and (2).
0
g. Revising paragraphs (h) introductory text and (h)(1) and (3).
0
h. Removing paragraph (h)(4).
    The revisions and addition read as follows:

Sec.  63.7545  What notifications must I submit and when?

    (a) You must submit to the Administrator all of the notifications 
in Sec. Sec.  63.7(b) and (c), 63.8(e), (f)(4) and (6), and 63.9(b) 
through (h) that apply to you by the dates specified.
    (b) As specified in Sec.  63.9(b)(2), if you startup your affected 
source before January 31, 2013, you must submit an Initial Notification 
not later than 120 days after January 31, 2013.
    (c) As specified in Sec.  63.9(b)(4) and (5), if you startup your 
new or reconstructed affected source on or after January 31, 2013, you 
must submit an Initial Notification not later than 15 days after the 
actual date of startup of the affected source.
* * * * *
    (e) If you are required to conduct an initial compliance 
demonstration as specified in Sec.  63.7530, you must submit a 
Notification of Compliance Status according to Sec.  63.9(h)(2)(ii). 
For the initial compliance demonstration for each boiler or process 
heater, 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 all 
boiler or process heaters at the facility 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. If you are not required to conduct an initial compliance 
demonstration as specified in Sec.  63.7530(a), the Notification of 
Compliance Status must only contain the information specified in 
paragraphs (e)(1) and (8).
    (1) A description of the affected unit(s) including identification 
of which subcategories the unit is in, the design heat input capacity 
of the unit, a description of the add-on controls used on the unit to 
comply with this subpart, description of the fuel(s) burned, including 
whether the fuel(s) were a secondary material determined by you or the 
EPA through a petition process to be a non-waste under Sec.  241.3 of 
this chapter, whether the fuel(s) were a secondary material processed 
from discarded non-hazardous secondary materials within the meaning of 
Sec.  241.3 of this chapter, 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, and including:
    (i) Identification of whether you are complying with the PM 
emission limit or the alternative TSM emission limit.
    (ii) Identification of whether you are complying with the output-
based emission limits or the heat input-based (i.e., lb/MMBtu or ppm) 
emission limits,
    (3) A summary of the maximum CO emission levels recorded during the 
performance test to show that you have met any applicable emission 
standard in Tables 1, 2, or 11 through 13 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 efficiency 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 January 31, 2013.
    (ii) [Reserved]
* * * * *
    (8) * * *
    (i) ``This facility complies with the required initial tune-up 
according to the procedures in Sec.  63.7540(a)(10)(i) through (vi).''
* * * * *
    (iii) Except for units that burn only natural gas, refinery gas, or 
other gas 1 fuel, or 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, part 60, 61, or 65, 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.
* * * * *
    (g) * * *
    (1) The name of the owner or operator of the affected source, as 
defined in Sec.  63.7490, 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 subcategories under this subpart.
* * * * *
    (h) If you have switched fuels or made a physical change to the 
boiler and the fuel switch or physical change resulted in the 
applicability of a different subcategory, you must provide notice of 
the date upon which you switched fuels or made the physical change 
within 30 days of the switch/change. The notification must identify:
    (1) The name of the owner or operator of the affected source, as 
defined in Sec.  63.7490, the location of the source, the boiler(s) and 
process heater(s) that have switched fuels, were physically changed, 
and the date of the notice.
* * * * *
    (3) The date upon which the fuel switch or physical change 
occurred.

0
24. Section 63.7550 is revised to read as follows:

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, according to paragraph (h) of this section, by the date in 
Table 9 to this subpart and according to the requirements in paragraphs 
(b)(1) through (4) of this section. For units that are subject only to 
a requirement to conduct an annual, biennial, or 5-year tune-up 
according to Sec.  63.7540(a)(10), (11), or (12), respectively, and not 
subject to emission

[[Page 7184]]

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 (4) 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 each boiler or process heater 
in Sec.  63.7495 and ending on July 31 or January 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 submitted no 
later than July 31 or January 31, whichever date is the first date 
following the end of the first calendar half after the compliance date 
that is specified for each boiler or process heater in Sec.  63.7495. 
The first annual, biennial, or 5-year compliance report must be 
postmarked or submitted 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 
submitted no later than July 31 or January 31, whichever date is the 
first date following the end of the semiannual reporting period. 
Annual, biennial, and 5-year compliance reports must be postmarked or 
submitted no later than January 31.
    (c) A compliance report must contain the following information 
depending on how the facility chooses to comply with the limits set in 
this rule.
    (1) If the facility is subject to a the requirements of a tune up 
they must submit a compliance report with the information in paragraphs 
(c)(5)(i) through (iv) and (xiv) of this section.
    (2) If a facility is complying with the fuel analysis they must 
submit a compliance report with the information in paragraphs (c)(5)(i) 
through (iv), (vi), (x), (xi), (xiii), (xv) and paragraph (d) of this 
section.
    (3) If a facility is complying with the applicable emissions limit 
with performance testing they must submit a compliance report with the 
information in (c)(5)(i) through (iv), (vi), (vii), (ix), (xi), (xiii), 
(xv) and paragraph (d) of this section.
    (4) If a facility is complying with an emissions limit using a CMS 
the compliance report must contain the information required in 
paragraphs (c)(5)(i) through (vi), (xi), (xiii), (xv) through (xvii), 
and paragraph (e) of this section.
    (5)(i) Company and Facility name and address.
    (ii) Process unit information, emissions limitations, and operating 
parameter limitations.
    (iii) Date of report and beginning and ending dates of the 
reporting period.
    (iv) The total operating time during the reporting period.
    (v) If you use a CMS, including CEMS, COMS, or CPMS, you must 
include the monitoring equipment manufacturer(s) and model numbers and 
the date of the last CMS certification or audit.
    (vi) The total fuel use by each individual boiler or process heater 
subject to an emission limit within the reporting period, including, 
but not limited to, a description of the fuel, whether the fuel has 
received a non-waste determination by the EPA or your basis for 
concluding that the fuel is not a waste, and the total fuel usage 
amount with units of measure.
    (vii) If you are conducting performance tests once every 3 years 
consistent with Sec.  63.7515(b) or (c), the date of the last 2 
performance tests and a statement as to whether there have been any 
operational changes since the last performance test that could increase 
emissions.
    (viii) A statement indicating that you burned no new types of fuel 
in an individual boiler or process heater subject to an emission limit. 
Or, if you did burn a new type of fuel and are subject to a HCl 
emission limit, you must submit the calculation of chlorine input, 
using Equation 7 of 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 HCl 
emission rate using Equation 12 of Sec.  63.7530 that demonstrates that 
your source is still meeting the emission limit for HCl emissions (for 
boilers or process heaters that demonstrate compliance through fuel 
analysis). If you burned a new type of fuel and are subject to a 
mercury emission limit, you must submit the calculation of mercury 
input, using Equation 8 of 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 13 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 TSM emission limit, you must submit the calculation of 
TSM input, using Equation 9 of Sec.  63.7530, that demonstrates that 
your source is still within its maximum TSM input level established 
during the previous performance testing (for sources that demonstrate 
compliance through performance testing), or you must submit the 
calculation of TSM emission rate, using Equation 14 of Sec.  63.7530, 
that demonstrates that your source is still meeting the emission limit 
for TSM emissions (for boilers or process heaters that demonstrate 
compliance through fuel analysis).
    (ix) If you wish to burn a new type of fuel in an individual boiler 
or process heater subject to an emission limit and you cannot 
demonstrate compliance with the maximum chlorine input operating limit 
using Equation 7 of Sec.  63.7530 or the maximum mercury input 
operating limit using Equation 8 of Sec.  63.7530, or the maximum TSM 
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.
    (x) A summary of any monthly fuel analyses conducted to demonstrate 
compliance according to Sec. Sec.  63.7521 and 63.7530 for individual 
boilers or process heaters subject to emission limits, and any fuel 
specification analyses conducted according to Sec. Sec.  63.7521(f) and 
63.7530(g).
    (xi) If there are no deviations from any emission limits or 
operating limits in this subpart that apply to you, a statement that 
there were no deviations from the emission limits or operating limits 
during the reporting period.
    (xii) If there were no deviations from the monitoring requirements 
including no periods during which the CMSs, including CEMS, COMS, and 
CPMS, were out of control as specified in 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.
    (xiii) 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

[[Page 7185]]

may have caused any applicable emission limitation to be exceeded. The 
report must also include a description of actions taken by you during a 
malfunction of a boiler, process heater, or associated air pollution 
control device or CMS to minimize emissions in accordance with Sec.  
63.7500(a)(3), including actions taken to correct the malfunction.
    (xiv) Include the date of the most recent tune-up for each unit 
subject to only the requirement to conduct an annual, biennial, or 5-
year tune-up according to 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.
    (xv) If you plan to demonstrate compliance by emission averaging, 
certify the emission level achieved or the control technology employed 
is no less stringent than the level or control technology contained in 
the notification of compliance status in Sec.  63.7545(e)(5)(i).
    (xvi) For each reporting period, the compliance reports must 
include all of the calculated 30 day rolling average values based on 
the daily CEMS (CO and mercury) and CPMS (PM CPMS output, scrubber pH, 
scrubber liquid flow rate, scrubber pressure drop) data.
    (xvii) Statement by a responsible official with that official's 
name, title, and signature, certifying the truth, accuracy, and 
completeness of the content of the report.
    (d) For each deviation from an emission limit or operating limit in 
this subpart that occurs at an individual boiler or process heater 
where you are not using a CMS to comply with that emission limit or 
operating limit, the compliance report must additionally contain the 
information required in paragraphs (d)(1) through (3) of this section.
    (1) A description of the deviation and which emission limit or 
operating limit from which you deviated.
    (2) Information on the number, duration, and cause of deviations 
(including unknown cause), as applicable, and the corrective action 
taken.
    (3) If the deviation occurred during an annual performance test, 
provide the date the annual performance test was completed.
    (e) For each deviation from an emission limit, operating limit, and 
monitoring requirement in this subpart occurring at an individual 
boiler or process heater where you are using a CMS to comply with that 
emission limit or operating limit, the compliance report must 
additionally contain the information required in paragraphs (e)(1) 
through (9) 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) A characterization 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) A brief description of the source for which there was a 
deviation.
    (9) 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) [Reserved]
    (g) [Reserved]
    (h) You must submit the reports according to the procedures 
specified in paragraphs (h)(1) through (3) of this section.
    (1) Within 60 days after the date of completing each performance 
test (defined in Sec.  63.2) as required by this subpart you must 
submit the results of the performance tests, including any associated 
fuel analyses, required by this subpart and the compliance reports 
required in Sec.  63.7550(b) to the EPA's WebFIRE database by using the 
Compliance and Emissions Data Reporting Interface (CEDRI) that is 
accessed through the EPA's Central Data Exchange (CDX) (www.epa.gov/cdx). Performance test data must be submitted in the file format 
generated through use of the 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 the EPA via CDX as described earlier in this paragraph. At 
the discretion of the Administrator, you must also submit these 
reports, including the confidential business information, to the 
Administrator in the format specified by the Administrator. For any 
performance test conducted using test methods that are not listed on 
the ERT Web site, the owner or operator shall submit the results of the 
performance test in paper submissions to the Administrator.
    (2) Within 60 days after the date of completing each CEMS 
performance evaluation test (defined in 63.2) you must submit the 
relative accuracy test audit (RATA) data to the EPA's Central Data 
Exchange by using CEDRI as mentioned in paragraph (h)(1) of this 
section. Only RATA pollutants that can be documented with the ERT (as 
listed on the ERT Web site) are subject to this requirement. For any 
performance evaluations with no corresponding RATA pollutants listed on 
the ERT Web site, the owner or operator shall submit the results of the 
performance evaluation in paper submissions to the Administrator.
    (3) You must submit all reports required by Table 9 of this subpart 
electronically using CEDRI that is accessed through the EPA's Central 
Data Exchange (CDX) (www.epa.gov/cdx). However, if the reporting form 
specific to this subpart is not available in CEDRI at the time that the 
report is due the report you must submit the report to the 
Administrator at the appropriate address listed in Sec.  63.13. At the 
discretion of the Administrator, you must also submit these reports, to 
the Administrator in the format specified by the Administrator.

0
25. Section 63.7555 is amended by:
0
a. Revising paragraphs (d) introductory text and (d)(2) through (6).
0
b. Adding paragraphs (d)(9) through (11).
0
c. Revising paragraphs (f) through (h).
0
d. Adding paragraphs (i) and (j).

[[Page 7186]]

    The revisions and additions read as follows:

Sec.  63.7555  What records must I keep?

* * * * *
    (d) For each boiler or process heater subject to an emission limit 
in Tables 1, 2, or 11 through 13 to this subpart, you must also keep 
the applicable records in paragraphs (d)(1) through (11) of this 
section.
* * * * *
    (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) 
of this chapter, you must keep a record that documents how the 
secondary material meets each of the legitimacy criteria under Sec.  
241.3(d)(1) of this chapter. If you combust a fuel that has been 
processed from a discarded non-hazardous secondary material pursuant to 
Sec.  241.3(b)(4) of this chapter, you must keep records as to how the 
operations that produced the fuel satisfy the definition of processing 
in Sec.  241.2 of this chapter. If the fuel received a non-waste 
determination pursuant to the petition process submitted under Sec.  
241.3(c) of this chapter, you must keep a record that documents how the 
fuel satisfies the requirements of the petition process. For operating 
units that combust non-hazardous secondary materials as fuel per Sec.  
241.4 of this chapter, you must keep records documenting that the 
material is listed as a non-waste under Sec.  241.4(a) of this chapter. 
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) For units in the limited use subcategory, you must keep a copy 
of the federally enforceable permit that limits the annual capacity 
factor to less than or equal to 10 percent and fuel use records for the 
days the boiler or process heater was operating.
    (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 HCl emission 
limit, for sources that demonstrate compliance through performance 
testing. For sources that demonstrate compliance through fuel analysis, 
a copy of all calculations and supporting documentation of HCl emission 
rates, using Equation 12 of Sec.  63.7530, that were done to 
demonstrate compliance with the HCl emission limit. Supporting 
documentation should include results of any fuel analyses and basis for 
the estimates of maximum chlorine fuel input or HCl emission rates. You 
can use the results from one fuel analysis for multiple boilers and 
process heaters provided they are all burning the same fuel type. 
However, you must calculate chlorine fuel input, or HCl emission rate, 
for each boiler and process heater.
    (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 13 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), you choose to stack test 
less frequently than annually, you must keep a record that documents 
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 or 11 through 13 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.
* * * * *
    (9) A copy of all calculations and supporting documentation of 
maximum TSM fuel input, using Equation 9 of Sec.  63.7530, that were 
done to demonstrate continuous compliance with the TSM emission limit 
for sources that demonstrate compliance through performance testing. 
For sources that demonstrate compliance through fuel analysis, a copy 
of all calculations and supporting documentation of TSM emission rates, 
using Equation 14 of Sec.  63.7530, that were done to demonstrate 
compliance with the TSM emission limit. Supporting documentation should 
include results of any fuel analyses and basis for the estimates of 
maximum TSM fuel input or TSM emission rates. You can use the results 
from one fuel analysis for multiple boilers and process heaters 
provided they are all burning the same fuel type. However, you must 
calculate TSM fuel input, or TSM emission rates, for each boiler and 
process heater.
    (10) You must maintain records of the calendar date, time, 
occurrence and duration of each startup and shutdown.
    (11) You must maintain records of the type(s) and amount(s) of 
fuels used during each startup and shutdown.
* * * * *
    (f) If you elect to use efficiency 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 unit designed to burn gas 1 
subcategory, you must maintain monthly records (or at the frequency 
required by Sec.  63.7540(c)) of the calculations and results of the 
fuel specification for mercury in Table 6.
    (h) If you operate a unit in the unit designed to burn gas 1 
subcategory 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, other gas 1 fuel, or gaseous fuel 
subject to another subpart of this part or part 60, 61, or 65, you must 
keep records of the total hours per calendar year that alternative fuel 
is burned and the total hours per calendar year that the unit operated 
during periods of gas curtailment or gas supply emergencies.
    (i) You must maintain records of the calendar date, time, 
occurrence and duration of each startup and shutdown.
    (j) You must maintain records of the type(s) and amount(s) of fuels 
used during each startup and shutdown.

0
26. Section 63.7570 is amended by revising paragraph (a) and paragraph 
(b) introductory text to read as follows:

Sec.  63.7570  Who implements and enforces this subpart?

    (a) This subpart can be implemented and enforced by the EPA, or an 
Administrator 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 the EPA) has the authority to 
implement and enforce this subpart. You should contact your EPA 
Regional Office to find out if this

[[Page 7187]]

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, the EPA 
retains oversight of this subpart and can take enforcement actions, as 
appropriate.
* * * * *

0
27. Section 63.7575 is amended by:
0
a. Adding in alphabetical order definitions for ``10-day rolling 
average,'' ``30-day rolling average,'' ``Annual capacity factor,'' 
``Average annual heat input rate,'' ``Benchmark,'' ``Biodiesel,'' 
``Daily block average,'' ``Efficiency credit,'' ``Energy management 
program,'' ``Fluidized bed boiler with an integrated fluidized bed heat 
exchanger,'' ``Heavy liquid,'' ``Light liquid,'' '' ``Major source for 
oil and natural gas production facilities,'' ``Minimum oxygen level,'' 
``Other combustor'', ``Oxygen analyzer system'', ``Oxygen trim 
system'', ``Pile burner'', ``Regulated gas stream'', ``Residential 
boiler,'' ``Residual oil'', ``Secondary material,'' ``Shutdown'', 
``Sloped grate'', ``Startup'', ``Stoker/sloped grate/other unit 
designed to burn kiln dried biomass,'' Stoker/sloped grate/other unit 
designed to burn wet biomass,'' ``Suspension burner,'' ``Total selected 
metals (TSM),'' ``Traditional fuel,'' ``Ultra low sulfur liquid fuel,'' 
``Unit designed to burn heavy liquid subcategory,'' ``Unit designed to 
burn light liquid subcategory,'' and ``Vegetable oil.''
0
b. Revising the definitions for ``Boiler,'' ``Boiler system,'' 
``Coal,'' Commercial/institutional boiler,'' ``Deviation,'' 
``Distillate oil,'' ``Dry scrubber,'' ``Dutch oven,'' ``Electric 
utility steam generating unit,'' ``Energy assessment,'' ``Energy use 
system,'' ``Equivalent,'' ``Federally enforceable,'' ``Fluidized bed 
boiler'', ``Fuel cell,'' ``Fuel type,'' ``Gaseous fuel,'' ``Heat 
input,'' ``Hot water heater,'' ``Hybrid suspension grate boiler,'' 
``Industrial boiler,'' ``Limited-use boiler or process heater,'' 
``Liquid fuel,'' ``Load fraction,'' ``Metal process furnaces,'' 
``Minimum activated carbon injection rate,'' ``Minimum scrubber liquid 
flow rate,'' ``Minimum sorbent injection rate,'' ``Natural gas,'' 
``Other gas 1 fuel,'' ``Period of natural gas curtailment or supply 
interruption,'' ``Process heater,'' ``Qualified energy assessor,'' 
``Residual oil,'' ``Solid fossil fuel,'' ``Steam output,'' ``Stoker,'' 
``Temporary boiler,'' ``Tune-up,'' ``Unit designed to burn gas 1 
subcategory,'' ``Unit designed to burn gas 2 (other) subcategory,'' 
``Unit designed to burn liquid subcategory,'' ``Unit designed to burn 
liquid fuel that is a non-continental unit,'' ``Unit designed to burn 
solid fuel,'' ``Waste heat boiler,'' ``Waste heat process heater.''
0
c. Removing the definitions for ``Benchmarking,'' ``Emission credit,'' 
``Liquid fuel subcategory,'' and ``Suspension boiler.''
    The revisions read as follows:

Sec.  63.7575  What definitions apply to this subpart?

* * * * *
    10-day rolling average means the arithmetic mean of the previous 
240 hours of valid operating data. Valid data excludes hours during 
startup and shutdown, data collected during periods when the monitoring 
system is out of control as specified in your site-specific monitoring 
plan, while conducting repairs associated with periods when the 
monitoring system is out of control, or while conducting required 
monitoring system quality assurance or quality control activities, and 
periods when this unit is not operating. The 240 hours should be 
consecutive, but not necessarily continuous if operations were 
intermittent.
    30-day rolling average means the arithmetic mean of the previous 
720 hours of valid operating data. Valid data excludes hours during 
startup and shutdown, data collected during periods when the monitoring 
system is out of control as specified in your site-specific monitoring 
plan, while conducting repairs associated with periods when the 
monitoring system is out of control, or while conducting required 
monitoring system quality assurance or quality control activities, and 
periods when this unit is not operating. The 720 hours should be 
consecutive, but not necessarily continuous if operations were 
intermittent.
* * * * *
    Annual capacity factor means the ratio between the actual heat 
input to a boiler or process heater from the fuels burned during a 
calendar year and the potential heat input to the boiler or process 
heater had it been operated for 8,760 hours during a year at the 
maximum steady state design heat input capacity.
    Average annual heat input rate means total heat input divided by 
the hours of operation for the 12 months preceding the compliance 
demonstration.
* * * * *
    Benchmark means the fuel heat input for a boiler or process heater 
for the 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.
    Biodiesel means a mono-alkyl ester derived from biomass and 
conforming to ASTM D6751-11b, Standard Specification for Biodiesel Fuel 
Blend Stock (B100) for Middle Distillate Fuels (incorporated by 
reference, see Sec.  63.14).
* * * * *
    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 of this chapter, 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 
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 control systems, steam 
systems, and condensate return systems.
* * * * *
    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, including but not limited to, solvent-refined coal, coal-oil 
mixtures, and coal-water mixtures. Coal derived gases are excluded from 
this definition.
* * * * *
    Commercial/institutional boiler means a boiler used in commercial 
establishments or institutional establishments such as medical centers, 
nursing homes, research centers, institutions of higher education, 
elementary and secondary schools, libraries, religious establishments, 
governmental buildings, hotels, restaurants, and laundries to provide 
electricity, steam, and/or hot water.
* * * * *
    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), except for periods of startup and shutdown or downtime.

[[Page 7188]]

    Deviation.
    (1) Deviation 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 applicable 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.
* * * * *
    Distillate oil means fuel oils that contain 0.05 weight percent 
nitrogen or less and comply with the specifications for fuel oil 
numbers 1 and 2, as defined by the American Society of Testing and 
Materials in ASTM D396 (incorporated by reference, see Sec.  63.14) or 
diesel fuel oil numbers 1 and 2, as defined by the American Society for 
Testing and Materials in ASTM D975 (incorporated by reference, see 
Sec.  63.14), kerosene, and biodiesel as defined by the American 
Society of Testing and Materials in ASTM D6751-11b (incorporated by 
reference, see Sec.  60.14).
    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 
used as control devices 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 (EGU) means a fossil fuel-
fired combustion unit of more than 25 megawatts electric (MWe) 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 MWe 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 April 16, 2012.
* * * * *
    Efficiency credit means emission reductions above those required by 
this subpart. Efficiency 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. Boilers 
that are shut down cannot be used to generate credits unless the 
facility provides documentation linking the permanent shutdown to 
implementation of the energy conservation measures identified in the 
energy assessment.
    Energy assessment means the following for the emission units 
covered by this subpart:
    (1) The energy assessment for facilities with affected boilers and 
process heaters with a combined heat input capacity of less than 0.3 
trillion Btu (TBtu) per year will be 8 on-site technical labor hours in 
length maximum, but may be longer at the discretion of the owner or 
operator of the affected source. The boiler system(s) and any on-site 
energy use system(s) accounting for at least 50 percent of the affected 
boiler(s) energy (e.g., steam, hot water, process heat, or electricity) 
production, as applicable, will be evaluated to identify energy savings 
opportunities, within the limit of performing an 8-hour on-site energy 
assessment.
    (2) The energy assessment for facilities with affected boilers and 
process heaters with a combined heat input capacity of 0.3 to 1.0 TBtu/
year will be 24 on-site technical labor hours in length maximum, but 
may be longer at the discretion of the owner or operator of the 
affected source. The boiler system(s) and any on-site energy use 
system(s) accounting for at least 33 percent of the energy (e.g., 
steam, hot water, process heat, or electricity) production, as 
applicable, will be evaluated to identify energy savings opportunities, 
within the limit of performing a 24-hour on-site energy assessment.
    (3) The energy assessment for facilities with affected boilers and 
process heaters with a combined heat input capacity greater than 1.0 
TBtu/year will be up to 24 on-site technical labor hours in length for 
the first TBtu/yr plus 8 on-site technical labor hours for every 
additional 1.0 TBtu/yr not to exceed 160 on-site technical hours, but 
may be longer at the discretion of the owner or operator of the 
affected source. The boiler system(s), process heater(s), and any on-
site energy use system(s) accounting for at least 20 percent of the 
energy (e.g., steam, process heat, hot water, or electricity) 
production, as applicable, will be evaluated to identify energy savings 
opportunities.
    (4) The on-site energy use systems serving as the basis for the 
percent of affected boiler(s) and process heater(s) energy production 
in paragraphs (1), (2), and (3) of this definition may be segmented by 
production area or energy use area as most logical and applicable to 
the specific facility being assessed (e.g., product X manufacturing 
area; product Y drying area; Building Z).
* * * * *
    Energy management program means a program that includes a 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. Facilities may establish their 
program through energy management systems compatible with ISO 50001.
    Energy use system includes the following systems located on-site 
that use energy (steam, hot water, or electricity) provided by the 
affected boiler or process heater: 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; or other systems that use steam, hot 
water, process heat, or electricity provided by the affected boiler or 
process heater. Energy use systems are only those systems using energy 
clearly produced by affected boilers and process heaters.
    Equivalent means the following only as this term is used in Table 6 
to this subpart:
    (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

[[Page 7189]]

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, HCl) 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.
* * * * *
    Federally enforceable means all limitations and conditions that are 
enforceable by the EPA Administrator, including, but not limited to, 
the requirements of 40 CFR parts 60, 61, 63, and 65, 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 boiler with an integrated fluidized bed heat 
exchanger means a boiler utilizing a fluidized bed combustion where the 
entire tube surface area is located outside of the furnace section at 
the exit of the cyclone section and exposed to the flue gas stream for 
conductive heat transfer. This design applies only to boilers in the 
unit designed to burn coal/solid fossil fuel subcategory that fire coal 
refuse.
* * * * *
    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, distillate 
oil, 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 and process gases that are regulated under another subpart 
of this part, or part 60, part 61, or part 65 of this chapter, are 
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, returned condensate, 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.
* * * * *
    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, liquid, or biomass/bio-based solid fuel and is withdrawn for 
use external to the vessel. Hot water boilers (i.e., not generating 
steam) combusting gaseous, liquid, or biomass fuel with a heat input 
capacity of less than 1.6 million Btu per hour are included in this 
definition. The 120 U.S. gallon capacity threshold to be considered a 
hot water heater is independent of the 1.6 MMBtu/hr heat input capacity 
threshold for hot water boilers. 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 biomass fuel combusted in 
these units exceeds a moisture content of 40 percent on an as-fired 
annual heat input 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, hot water, 
and/or electricity.
    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 and has 
a federally enforceable average annual capacity factor of no more than 
10 percent.
    Liquid fuel includes, but is not limited to, light liquid, heavy 
liquid, any form of liquid fuel derived from petroleum, used oil, 
liquid biofuels, biodiesel, vegetable oil, and comparable fuels as 
defined under 40 CFR 261.38.
    Load fraction means the actual heat input of a boiler or process 
heater divided by heat input during the performance test that 
established the minimum sorbent injection rate or minimum activated 
carbon injection rate, expressed as a fraction (e.g., for 50 percent 
load the load fraction is 0.5).
    Major source for oil and natural gas production facilities, as used 
in this subpart, shall have the same meaning as in Sec.  63.2, except 
that:
    (1) Emissions from any oil or gas exploration or production well 
(with its associated equipment, as defined in this section), and 
emissions from any pipeline compressor station or pump station shall 
not be aggregated with emissions from other similar units to determine 
whether such emission points or stations are major sources, even when 
emission points are in a contiguous area or under common control;
    (2) Emissions from processes, operations, or equipment that are not 
part of the same facility, as defined in this section, shall not be 
aggregated; and
    (3) For facilities that are production field facilities, only HAP 
emissions from glycol dehydration units and storage vessels with the 
potential for flash emissions shall be aggregated for a major source 
determination. For facilities that are not production field facilities, 
HAP emissions from all HAP emission units shall be aggregated for a 
major source determination.

[[Page 7190]]

    Metal process furnaces are a subcategory of process heaters, as 
defined in this subpart, which include natural gas-fired annealing 
furnaces, preheat furnaces, reheat furnaces, aging furnaces, heat treat 
furnaces, and homogenizing furnaces.
* * * * *
    Minimum activated carbon injection rate means load fraction 
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 
limit.
    Minimum oxygen level means the lowest hourly average oxygen level 
measured according to Table 7 to this subpart during the most recent 
performance test demonstrating compliance with the applicable emission 
limit.
* * * * *
    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 stack test demonstrating compliance with the applicable 
emission limit.
* * * * *
    Minimum sorbent injection rate means:
    (1) The load fraction 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; or
    (2) For fluidized bed combustion, the lowest average ratio of 
sorbent to sulfur measured during the most recent performance test.
* * * * *
    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) Liquefied 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 35 and 41 megajoules (MJ) per dry standard cubic meter (950 and 
1,100 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.
* * * * *
    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 a 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 or process heater flue gas, boiler or process heater, firebox, 
or other appropriate location. 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 CO monitor that 
automatically provides a feedback signal to the combustion air 
controller.
* * * * *
    Period of gas curtailment or supply interruption means a period of 
time during which the supply of gaseous fuel to an affected boiler or 
process heater is restricted or 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 (e.g., 
glycol or a mixture of glycol and water) for use in a process unit, 
instead of generating steam. Process heaters are devices in which the 
combustion gases do not come into direct contact with process 
materials. A device combusting solid waste, as defined in Sec.  241.3 
of this chapter, 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 are excluded 
from this definition.
* * * * *
    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 
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.

[[Page 7191]]

    (vi) Industry specific steam end-use systems.
* * * * *
    Regulated gas stream means an offgas stream that is routed to a 
boiler or process heater for the purpose of achieving compliance with a 
standard under another subpart of this part or part 60, part 61, or 
part 65 of this chapter.
    Residential boiler means a boiler used to provide heat and/or hot 
water and/or as part of a residential combined heat and power system. 
This definition includes boilers located at an institutional facility 
(e.g., university campus, military base, church grounds) or commercial/
industrial facility (e.g., farm) used primarily to provide heat and/or 
hot water for:
    (1) A dwelling containing four or fewer families; or
    (2) A single unit residence dwelling that has since been converted 
or subdivided into condominiums or apartments.
    Residual oil means crude oil, fuel oil that does not comply with 
the specifications under the definition of distillate oil, and all fuel 
oil numbers 4, 5, and 6, as defined by the American Society of Testing 
and Materials in ASTM D396-10 (incorporated by reference, see Sec.  
63.14(b)).
* * * * *
    Secondary material means the material as defined in Sec.  241.2 of 
this chapter.
    Shutdown means the cessation of operation of a boiler or process 
heater for any purpose. Shutdown begins either when none of the steam 
from the boiler is supplied for heating and/or producing electricity, 
or for any other purpose, or at the point of no fuel being fired in the 
boiler or process heater, whichever is earlier. Shutdown ends when 
there is no steam and no heat being supplied and no fuel being fired in 
the boiler or process heater.
    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.
* * * * *
    Startup means either the first-ever firing of fuel in a boiler or 
process heater for the purpose of supplying steam or heat for heating 
and/or producing electricity, or for any other purpose, or the firing 
of fuel in a boiler after a shutdown event for any purpose. Startup 
ends when any of the steam or heat from the boiler or process heater is 
supplied for heating, and/or producing electricity, or for any other 
purpose.
    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 21 
through 25 of this section, as appropriate:
    (i) For emission limits for boilers in the unit designed to burn 
solid fuel subcategory use Equation 21 of this section:
[GRAPHIC] [TIFF OMITTED] TR31JA13.025

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 22 of this 
section:
[GRAPHIC] [TIFF OMITTED] TR31JA13.026

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 23 of this 
section:
[GRAPHIC] [TIFF OMITTED] TR31JA13.027

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 one of the subcategories of 
units designed to burn liquid fuels use Equation 24 of this section:
[GRAPHIC] [TIFF OMITTED] TR31JA13.028

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 unit designed to burn 
gas 2 (other)

[[Page 7192]]

subcategory, use Equation 25 of this section:
[GRAPHIC] [TIFF OMITTED] TR31JA13.029

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 on an annual heat input basis.
    Suspension burner means a unit designed to fire dry biomass/
biobased solid particles in suspension that are conveyed in an 
airstream to the furnace like pulverized coal. The combustion of the 
fuel material is completed on a grate or floor below. The biomass/
biobased fuel combusted in the unit shall not exceed 20 percent 
moisture on an annual heat input basis. 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 within the 
facility and performs the same or similar function for more than 12 
consecutive months, unless the regulatory agency approves an extension. 
An extension may be granted by the regulating agency upon petition by 
the owner or operator of a unit specifying the basis for such a 
request. Any temporary boiler that replaces a temporary boiler at a 
location and performs the same or similar function will be included in 
calculating the consecutive time period.
    (3) The equipment is located at a seasonal facility and operates 
during the full annual operating period of the seasonal facility, 
remains at the facility for at least 2 years, and operates at that 
facility for at least 3 months each year.
    (4) The equipment is moved from one location to another within the 
facility but continues to perform the same or similar function and 
serve the same electricity, steam, and/or hot water system in an 
attempt to circumvent the residence time requirements of this 
definition.
    Total selected metals (TSM) means the sum of the following metallic 
hazardous air pollutants: arsenic, beryllium, cadmium, chromium, lead, 
manganese, nickel and selenium.
    Traditional fuel means the fuel as defined in Sec.  241.2 of this 
chapter.
    Tune-up means adjustments made to a boiler or process heater in 
accordance with the procedures outlined in Sec.  63.7540(a)(10).
* * * * *
    Ultra low sulfur liquid fuel means a distillate oil that has less 
than or equal to 15 ppm sulfur.
* * * * *
    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. 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, are included in this definition. Gaseous fuel boilers 
and process heaters that burn liquid fuel during periods of gas 
curtailment or gas supply interruptions of any duration are also 
included in this definition.
    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, and less than 10 
percent biomass/bio-based solid fuel on an annual heat input basis, and 
no liquid fuels. Gaseous fuel boilers and process heaters that are not 
in the unit designed to burn gas 1 subcategory and 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, are included in this definition. Gaseous fuel boilers 
and process heaters that are not in the unit designed to burn gas 1 
subcategory and that burn liquid fuel during periods of gas curtailment 
or gas supply interruption of any duration are also included in this 
definition.
    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. Units in the unit design to burn gas 1 or unit designed 
to burn gas 2 (other) subcategories 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 are not 
included in this definition. Units in the unit design to burn gas 1 or 
unit designed to burn gas 2 (other) subcategories during periods of gas 
curtailment or gas supply interruption 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 meeting the definition of the unit designed to burn

[[Page 7193]]

liquid subcategory 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.
* * * * *
    Waste heat boiler means a device that recovers normally unused 
energy (i.e., hot exhaust gas) and converts it to usable heat. Waste 
heat boilers are also referred to as heat recovery steam generators. 
Waste heat boilers are heat exchangers generating steam from incoming 
hot exhaust gas from an industrial (e.g., thermal oxidizer, kiln, 
furnace) or power (e.g., combustion turbine, engine) equipment. Duct 
burners are sometimes used to increase the temperature of the incoming 
hot exhaust gas.
    Waste heat process heater means an enclosed device that recovers 
normally unused energy (i.e., hot exhaust gas) 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.
* * * * *

0
28. Table 1 to subpart DDDDD of part 63 is revised to read as follows:
    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]
----------------------------------------------------------------------------------------------------------------
                                                                           Or the emissions
                                                      The emissions must    must not exceed
                                                        not exceed the       the following        Using this
If your boiler or process heater   For the following  following emission  alternative output- specified sampling
  is in this subcategory . . .     pollutants . . .     limits, except       based limits,    volume or test run
                                                      during startup and     except during      duration . . .
                                                        shutdown . . .        startup and
                                                                            shutdown . . .
----------------------------------------------------------------------------------------------------------------
1. Units in all subcategories     a. HCl............  2.2E-02 lb per      2.5E-02 lb per      For M26A, collect
 designed to burn solid fuel.                          MMBtu of heat       MMBtu of steam      a minimum of 1
                                                       input.              output or 0.28 lb   dscm per run; for
                                                                           per MWh.            M26 collect a
                                                                                               minimum of 120
                                                                                               liters per run.
                                  b. Mercury........  8.0E-07 \a\ lb per  8.7E-07 \a\ lb per  For M29, collect a
                                                       MMBtu of heat       MMBtu of steam      minimum of 4 dscm
                                                       input.              output or 1.1E-05   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.
2. Units designed to burn coal/   a. Filterable PM    1.1E-03 lb per      1.1E-03 lb per      Collect a minimum
 solid fossil fuel.                (or TSM).           MMBtu of heat       MMBtu of steam      of 3 dscm per
                                                       input; or (2.3E-    output or 1.4E-02   run.
                                                       05 lb per MMBtu     lb per MWh; or
                                                       of heat input).     (2.7E-05 lb per
                                                                           MMBtu of steam
                                                                           output or 2.9E-04
                                                                           lb per MWh).
3. Pulverized coal boilers        a. Carbon monoxide  130 ppm by volume   0.11 lb per MMBtu   1 hr minimum
 designed to burn coal/solid       (CO) (or CEMS).     on a dry basis      of steam output     sampling time.
 fossil fuel.                                          corrected to 3      or 1.4 lb per
                                                       percent oxygen, 3-  MWh; 3-run
                                                       run average; or     average.
                                                       (320 ppm by
                                                       volume on a dry
                                                       basis corrected
                                                       to 3 percent
                                                       oxygen, 30-day
                                                       rolling average).
4. Stokers designed to burn coal/ a. CO (or CEMS)...  130 ppm by volume   0.12 lb per MMBtu   1 hr minimum
 solid fossil fuel.                                    on a dry basis      of steam output     sampling time.
                                                       corrected to 3      or 1.4 lb per
                                                       percent oxygen, 3-  MWh; 3-run
                                                       run average; or     average.
                                                       (340 ppm by
                                                       volume on a dry
                                                       basis corrected
                                                       to 3 percent
                                                       oxygen, 30-day
                                                       rolling average).
5. Fluidized bed units designed   a. CO (or CEMS)...  130 ppm by volume   0.11 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 1.4 lb per
                                                       percent oxygen, 3-  MWh; 3-run
                                                       run average; or     average.
                                                       (230 ppm by
                                                       volume on a dry
                                                       basis corrected
                                                       to 3 percent
                                                       oxygen, 30-day
                                                       rolling average).
6. Fluidized bed units with an    a. CO (or CEMS)...  140 ppm by volume   1.2E-01 lb per      1 hr minimum
 integrated heat exchanger                             on a dry basis      MMBtu of steam      sampling time.
 designed to burn coal/solid                           corrected to 3      output or 1.5 lb
 fossil fuel.                                          percent oxygen, 3-  per MWh; 3-run
                                                       run average; or     average.
                                                       (150 ppm by
                                                       volume on a dry
                                                       basis corrected
                                                       to 3 percent
                                                       oxygen, 30-day
                                                       rolling average).
7. Stokers/sloped grate/others    a. CO (or CEMS)...  620 ppm by volume   5.8E-01 lb per      1 hr minimum
 designed to burn wet biomass                          on a dry basis      MMBtu of steam      sampling time.
 fuel.                                                 corrected to 3      output or 6.8 lb
                                                       percent oxygen, 3-  per MWh; 3-run
                                                       run average; or     average.
                                                       (390 ppm by
                                                       volume on a dry
                                                       basis corrected
                                                       to 3 percent
                                                       oxygen, 30-day
                                                       rolling average).
                                  b. Filterable PM    3.0E-02 lb per      3.5E-02 lb per      Collect a minimum
                                   (or TSM).           MMBtu of heat       MMBtu of steam      of 2 dscm per
                                                       input; or (2.6E-    output or 4.2E-01   run.
                                                       05 lb per MMBtu     lb per MWh; or
                                                       of heat input).     (2.7E-05 lb per
                                                                           MMBtu of steam
                                                                           output or 3.7E-04
                                                                           lb per MWh).

[[Page 7194]]

 
8. Stokers/sloped grate/others    a. CO.............  460 ppm by volume   4.2E-01 lb per      1 hr minimum
 designed to burn kiln-dried                           on a dry basis      MMBtu of steam      sampling time.
 biomass fuel.                                         corrected to 3      output or 5.1 lb
                                                       percent oxygen.     per MWh.
                                  b. Filterable PM    3.0E-02 lb per      3.5E-02 lb per      Collect a minimum
                                   (or TSM).           MMBtu of heat       MMBtu of steam      of 2 dscm per
                                                       input; or (4.0E-    output or 4.2E-01   run.
                                                       03 lb per MMBtu     lb per MWh; or
                                                       of heat input).     (4.2E-03 lb per
                                                                           MMBtu of steam
                                                                           output or 5.6E-02
                                                                           lb per MWh).
9. Fluidized bed units designed   a. CO (or CEMS)...  230 ppm by volume   2.2E-01 lb per      1 hr minimum
 to burn biomass/bio-based                             on a dry basis      MMBtu of steam      sampling time.
 solids.                                               corrected to 3      output or 2.6 lb
                                                       percent oxygen, 3-  per MWh; 3-run
                                                       run average; or     average.
                                                       (310 ppm by
                                                       volume on a dry
                                                       basis corrected
                                                       to 3 percent
                                                       oxygen, 30-day
                                                       rolling average).
                                  b. Filterable PM    9.8E-03 lb per      1.2E-02 lb per      Collect a minimum
                                   (or TSM).           MMBtu of heat       MMBtu of steam      of 3 dscm per
                                                       input; or (8.3E-    output or 0.14 lb   run.
                                                       05 \a\ lb per       per MWh; or (1.1E-
                                                       MMBtu of heat       04 \a\ lb per
                                                       input).             MMBtu of steam
                                                                           output or 1.2E-03
                                                                           \a\ lb per MWh).
10. Suspension burners designed   a. CO (or CEMS)...  2,400 ppm by        1.9 lb per MMBtu    1 hr minimum
 to burn biomass/bio-based                             volume on a dry     of steam output     sampling time.
 solids.                                               basis corrected     or 27 lb per MWh;
                                                       to 3 percent        3-run average.
                                                       oxygen, 3-run
                                                       average; or
                                                       (2,000 ppm by
                                                       volume on a dry
                                                       basis corrected
                                                       to 3 percent
                                                       oxygen, 10-day
                                                       rolling average).
                                  b. Filterable PM    3.0E-02 lb per      3.1E-02 lb per      Collect a minimum
                                   (or TSM).           MMBtu of heat       MMBtu of steam      of 2 dscm per
                                                       input; or (6.5E-    output or 4.2E-01   run.
                                                       03 lb per MMBtu     lb per MWh; or
                                                       of heat input).     (6.6E-03 lb per
                                                                           MMBtu of steam
                                                                           output or 9.1E-02
                                                                           lb per MWh).
11. Dutch Ovens/Pile burners      a. CO (or CEMS)...  330 ppm by volume   3.5E-01 lb per      1 hr minimum
 designed to burn biomass/bio-                         on a dry basis      MMBtu of steam      sampling time.
 based solids.                                         corrected to 3      output or 3.6 lb
                                                       percent oxygen, 3-  per MWh; 3-run
                                                       run average; or     average.
                                                       (520 ppm by
                                                       volume on a dry
                                                       basis corrected
                                                       to 3 percent
                                                       oxygen, 10-day
                                                       rolling average).
                                  b. Filterable PM    3.2E-03 lb per      4.3E-03 lb per      Collect a minimum
                                   (or TSM).           MMBtu of heat       MMBtu of steam      of 3 dscm per
                                                       input; or (3.9E-    output or 4.5E-02   run.
                                                       05 lb per MMBtu     lb per MWh; or
                                                       of heat input).     (5.2E-05 lb per
                                                                           MMBtu of steam
                                                                           output or 5.5E-04
                                                                           lb per MWh).
12. Fuel cell units designed to   a. CO.............  910 ppm by volume   1.1 lb per MMBtu    1 hr minimum
 burn biomass/bio-based solids.                        on a dry basis      of steam output     sampling time.
                                                       corrected to 3      or 1.0E+01 lb per
                                                       percent oxygen.     MWh.
                                  b. Filterable PM    2.0E-02 lb per      3.0E-02 lb per      Collect a minimum
                                   (or TSM).           MMBtu of heat       MMBtu of steam      of 2 dscm per
                                                       input; or (2.9E-    output or 2.8E-01   run.
                                                       05 \a\ lb per       lb per MWh; or
                                                       MMBtu of heat       (5.1E-05 lb per
                                                       input).             MMBtu of steam
                                                                           output or 4.1E-04
                                                                           lb per MWh).
13. Hybrid suspension grate       a. CO (or CEMS)...  1,100 ppm by        1.4 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 12 lb per MWh;
                                                       to 3 percent        3-run average.
                                                       oxygen, 3-run
                                                       average; or (900
                                                       ppm by volume on
                                                       a dry basis
                                                       corrected to 3
                                                       percent oxygen,
                                                       30-day rolling
                                                       average).
                                  b. Filterable PM    2.6E-02 lb per      3.3E-02 lb per      Collect a minimum
                                   (or TSM).           MMBtu of heat       MMBtu of steam      of 3 dscm per
                                                       input; or (4.4E-    output or 3.7E-01   run.
                                                       04 lb per MMBtu     lb per MWh; or
                                                       of heat input).     (5.5E-04 lb per
                                                                           MMBtu of steam
                                                                           output or 6.2E-03
                                                                           lb per MWh).
14. Units designed to burn        a. HCl............  4.4E-04 lb per      4.8E-04 lb per      For M26A: Collect
 liquid fuel.                                          MMBtu of heat       MMBtu of steam      a minimum of 2
                                                       input.              output or 6.1E-03   dscm per run; for
                                                                           lb per MWh.         M26, collect a
                                                                                               minimum of 240
                                                                                               liters per run.
                                  b. Mercury........  4.8E-07 \a\ lb per  5.3E-07 \a\ lb per  For M29, collect a
                                                       MMBtu of heat       MMBtu of steam      minimum of 4 dscm
                                                       input.              output or 6.7E-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 7195]]

 
15. Units designed to burn heavy  a. CO.............  130 ppm by volume   0.13 lb per MMBtu   1 hr minimum
 liquid fuel.                                          on a dry basis      of steam output     sampling time.
                                                       corrected to 3      or 1.4 lb per
                                                       percent oxygen, 3-  MWh; 3-run
                                                       run average.        average.
                                  b. Filterable PM    1.3E-02 lb per      1.5E-02 lb per      Collect a minimum
                                   (or TSM).           MMBtu of heat       MMBtu of steam      of 3 dscm per
                                                       input; or (7.5E-    output or 1.8E-01   run.
                                                       05 lb per MMBtu     lb per MWh; or
                                                       of heat input).     (8.2E-05 lb per
                                                                           MMBtu of steam
                                                                           output or 1.1E-03
                                                                           lb per MWh).
16. Units designed to burn light  a. CO.............  130 ppm by volume   0.13 lb per MMBtu   1 hr minimum
 liquid fuel.                                          on a dry basis      of steam output     sampling time.
                                                       corrected to 3      or 1.4 lb per MWh.
                                                       percent oxygen.
                                  b. Filterable PM    1.1E-03 \a\ lb per  1.2E-03 \a\ lb per  Collect a minimum
                                   (or TSM).           MMBtu of heat       MMBtu of steam      of 3 dscm per
                                                       input; or (2.9E-    output or 1.6E-02   run.
                                                       05 lb per MMBtu     \a\ lb per MWh;
                                                       of heat input).     or (3.2E-05 lb
                                                                           per MMBtu of
                                                                           steam output or
                                                                           4.0E-04 lb per
                                                                           MWh).
17. Units designed to burn        a. CO.............  130 ppm by volume   0.13 lb per MMBtu   1 hr minimum
 liquid fuel that are non-                             on a dry basis      of steam output     sampling time.
 continental units.                                    corrected to 3      or 1.4 lb per
                                                       percent oxygen, 3-  MWh; 3-run
                                                       run average based   average.
                                                       on stack test.
                                  b. Filterable PM    2.3E-02 lb per      2.5E-02 lb per      Collect a minimum
                                   (or TSM).           MMBtu of heat       MMBtu of steam      of 4 dscm per
                                                       input; or (8.6E-    output or 3.2E-01   run.
                                                       04 lb per MMBtu     lb per MWh; or
                                                       of heat input).     (9.4E-04 lb per
                                                                           MMBtu of steam
                                                                           output or 1.2E-02
                                                                           lb per MWh).
18. Units designed to burn gas 2  a. CO.............  130 ppm by volume   0.16 lb per MMBtu   1 hr minimum
 (other) gases.                                        on a dry basis      of steam output     sampling time.
                                                       corrected to 3      or 1.0 lb per MWh.
                                                       percent oxygen.
                                  b. HCl............  1.7E-03 lb per      2.9E-03 lb per      For M26A, Collect
                                                       MMBtu of heat       MMBtu of steam      a minimum of 2
                                                       input.              output or 1.8E-02   dscm per run; for
                                                                           lb per MWh.         M26, collect a
                                                                                               minimum of 240
                                                                                               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 PM    6.7E-03 lb per      1.2E-02 lb per      Collect a minimum
                                   (or TSM).           MMBtu of heat       MMBtu of steam      of 3 dscm per
                                                       input; or (2.1E-    output or 7.0E-02   run.
                                                       04 lb per MMBtu     lb per MWh; or
                                                       of heat input).     (3.5E-04 lb per
                                                                           MMBtu of steam
                                                                           output or 2.2E-03
                                                                           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 below 75 percent of this limit in order to qualify for skip
  testing.
\b\ Incorporated by reference, see Sec.   63.14.
\c\ If your affected source is a new or reconstructed affected source that commenced construction or
  reconstruction after June 4, 2010, and before January 31, 2013, you may comply with the emission limits in
  Tables 11, 12 or 13 to this subpart until January 31, 2016. On and after January 31, 2016, you must comply
  with the emission limits in Table 1 to this subpart.

0
29. Table 2 to subpart DDDDD of part 63 is revised to read as follows:
    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
                                                      The emissions must    not exceed the
                                                        not exceed the         following          Using this
If your boiler or process heater   For the following  following emission  alternative output- specified sampling
  is in this subcategory . . .     pollutants . . .     limits, except       based limits,    volume or test run
                                                      during startup and     except during      duration . . .
                                                        shutdown . . .        startup and
                                                                            shutdown . . .
----------------------------------------------------------------------------------------------------------------
1. Units in all subcategories     a. HCl............  2.2E-02 lb per      2.5E-02 lb per      For M26A, Collect
 designed to burn solid fuel.                          MMBtu of heat       MMBtu of steam      a minimum of 1
                                                       input.              output or 0.27 lb   dscm per run; for
                                                                           per MWh.            M26, collect a
                                                                                               minimum of 120
                                                                                               liters per run.

[[Page 7196]]

 
                                  b. Mercury........  5.7E-06 lb per      6.4E-06 lb per      For M29, collect a
                                                       MMBtu of heat       MMBtu of steam      minimum of 3 dscm
                                                       input.              output or 7.3E-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.
2. Units design to burn coal/     a. Filterable PM    4.0E-02 lb per      4.2E-02 lb per      Collect a minimum
 solid fossil fuel.                (or TSM).           MMBtu of heat       MMBtu of steam      of 2 dscm per
                                                       input; or (5.3E-    output or 4.9E-01   run.
                                                       05 lb per MMBtu     lb per MWh; or
                                                       of heat input).     (5.6E-05 lb per
                                                                           MMBtu of steam
                                                                           output or 6.5E-04
                                                                           lb per MWh).
3. Pulverized coal boilers        a. CO (or CEMS)...  130 ppm by volume   0.11 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 1.4 lb per
                                                       percent oxygen, 3-  MWh; 3-run
                                                       run average; or     average.
                                                       (320 ppm by
                                                       volume on a dry
                                                       basis corrected
                                                       to 3 percent
                                                       oxygen, 30-day
                                                       rolling average).
4. Stokers designed to burn coal/ a. CO (or CEMS)...  160 ppm by volume   0.14 lb per MMBtu   1 hr minimum
 solid fossil fuel.                                    on a dry basis      of steam output     sampling time.
                                                       corrected to 3      or 1.7 lb per
                                                       percent oxygen, 3-  MWh; 3-run
                                                       run average; or     average.
                                                       (340 ppm by
                                                       volume on a dry
                                                       basis corrected
                                                       to 3 percent
                                                       oxygen, 30-day
                                                       rolling average).
5. Fluidized bed units designed   a. CO (or CEMS)...  130 ppm by volume   0.12 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 1.4 lb per
                                                       percent oxygen, 3-  MWh; 3-run
                                                       run average; or     average.
                                                       (230 ppm by
                                                       volume on a dry
                                                       basis corrected
                                                       to 3 percent
                                                       oxygen, 30-day
                                                       rolling average).
6. Fluidized bed units with an    a. CO (or CEMS)...  140 ppm by volume   1.3E-01 lb per      1 hr minimum
 integrated heat exchanger                             on a dry basis      MMBtu of steam      sampling time.
 designed to burn coal/solid                           corrected to 3      output or 1.5 lb
 fossil fuel.                                          percent oxygen, 3-  per MWh; 3-run
                                                       run average; or     average.
                                                       (150 ppm by
                                                       volume on a dry
                                                       basis corrected
                                                       to 3 percent
                                                       oxygen, 30-day
                                                       rolling average).
7. Stokers/sloped grate/others    a. CO (or CEMS)...  1,500 ppm by        1.4 lb per MMBtu    1 hr minimum
 designed to burn wet biomass                          volume on a dry     of steam output     sampling time.
 fuel.                                                 basis corrected     or 17 lb per MWh;
                                                       to 3 percent        3-run average.
                                                       oxygen, 3-run
                                                       average; or (720
                                                       ppm by volume on
                                                       a dry basis
                                                       corrected to 3
                                                       percent oxygen,
                                                       30-day rolling
                                                       average).
                                  b. Filterable PM    3.7E-02 lb per      4.3E-02 lb per      Collect a minimum
                                   (or TSM).           MMBtu of heat       MMBtu of steam      of 2 dscm per
                                                       input; or (2.4E-    output or 5.2E-01   run.
                                                       04 lb per MMBtu     lb per MWh; or
                                                       of heat input).     (2.8E-04 lb per
                                                                           MMBtu of steam
                                                                           output or 3.4E-04
                                                                           lb per MWh).
8. Stokers/sloped grate/others    a. CO.............  460 ppm by volume   4.2E-01 lb per      1 hr minimum
 designed to burn kiln-dried                           on a dry basis      MMBtu of steam      sampling time.
 biomass fuel.                                         corrected to 3      output or 5.1 lb
                                                       percent oxygen.     per MWh.
                                  b. Filterable PM    3.2E-01 lb per      3.7E-01 lb per      Collect a minimum
                                   (or TSM).           MMBtu of heat       MMBtu of steam      of 1 dscm per
                                                       input; or (4.0E-    output or 4.5 lb    run.
                                                       03 lb per MMBtu     per MWh; or (4.6E-
                                                       of heat input).     03 lb per MMBtu
                                                                           of steam output
                                                                           or 5.6E-02 lb per
                                                                           MWh).
9. Fluidized bed units designed   a. CO (or CEMS)...  470 ppm by volume   4.6E-01 lb per      1 hr minimum
 to burn biomass/bio-based solid.                      on a dry basis      MMBtu of steam      sampling time.
                                                       corrected to 3      output or 5.2 lb
                                                       percent oxygen, 3-  per MWh; 3-run
                                                       run average; or     average.
                                                       (310 ppm by
                                                       volume on a dry
                                                       basis corrected
                                                       to 3 percent
                                                       oxygen, 30-day
                                                       rolling average).
                                  b. Filterable PM    1.1E-01 lb per      1.4E-01 lb per      Collect a minimum
                                   (or TSM).           MMBtu of heat       MMBtu of steam      of 1 dscm per
                                                       input; or (1.2E-    output or 1.6 lb    run.
                                                       03 lb per MMBtu     per MWh; or (1.5E-
                                                       of heat input).     03 lb per MMBtu
                                                                           of steam output
                                                                           or 1.7E-02 lb per
                                                                           MWh).

[[Page 7197]]

 
10. Suspension burners designed   a. CO (or CEMS)...  2,400 ppm by        1.9 lb per MMBtu    1 hr minimum
 to burn biomass/bio-based solid.                      volume on a dry     of steam output     sampling time.
                                                       basis corrected     or 27 lb per MWh;
                                                       to 3 percent        3-run average.
                                                       oxygen, 3-run
                                                       average; or
                                                       (2,000 ppm by
                                                       volume on a dry
                                                       basis corrected
                                                       to 3 percent
                                                       oxygen, 10-day
                                                       rolling average).
                                  b. Filterable PM    5.1E-02 lb per      5.2E-02 lb per      Collect a minimum
                                   (or TSM).           MMBtu of heat       MMBtu of steam      of 2 dscm per
                                                       input; or (6.5E-    output or 7.1E-01   run.
                                                       03 lb per MMBtu     lb per MWh; or
                                                       of heat input).     (6.6E-03 lb per
                                                                           MMBtu of steam
                                                                           output or 9.1E-02
                                                                           lb per MWh).
11. Dutch Ovens/Pile burners      a. CO (or CEMS)...  770 ppm by volume   8.4E-01 lb per      1 hr minimum
 designed to burn biomass/bio-                         on a dry basis      MMBtu of steam      sampling time.
 based solid.                                          corrected to 3      output or 8.4 lb
                                                       percent oxygen, 3-  per MWh; 3-run
                                                       run average; or     average.
                                                       (520 ppm by
                                                       volume on a dry
                                                       basis corrected
                                                       to 3 percent
                                                       oxygen, 10-day
                                                       rolling average).
                                  b. Filterable PM    2.8E-01 lb per      3.9E-01 lb per      Collect a minimum
                                   (or TSM).           MMBtu of heat       MMBtu of steam      of 1 dscm per
                                                       input; or (2.0E-    output or 3.9 lb    run.
                                                       03 lb per MMBtu     per MWh; or (2.8E-
                                                       of heat input).     03 lb per MMBtu
                                                                           of steam output
                                                                           or 2.8E-02 lb per
                                                                           MWh).
12. Fuel cell units designed to   a. CO.............  1,100 ppm by        2.4 lb per MMBtu    1 hr minimum
 burn biomass/bio-based solid.                         volume on a dry     of steam output     sampling time.
                                                       basis corrected     or 12 lb per MWh.
                                                       to 3 percent
                                                       oxygen.
                                  b. Filterable PM    2.0E-02 lb per      5.5E-02 lb per      Collect a minimum
                                   (or TSM).           MMBtu of heat       MMBtu of steam      of 2 dscm per
                                                       input; or (5.8E-    output or 2.8E-01   run.
                                                       03 lb per MMBtu     lb per MWh; or
                                                       of heat input).     (1.6E-02 lb per
                                                                           MMBtu of steam
                                                                           output or 8.1E-02
                                                                           lb per MWh).
13. Hybrid suspension grate       a. CO (or CEMS)...  2,800 ppm by        2.8 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 31 lb per MWh;
                                                       to 3 percent        3-run average.
                                                       oxygen, 3-run
                                                       average; or (900
                                                       ppm by volume on
                                                       a dry basis
                                                       corrected to 3
                                                       percent oxygen,
                                                       30-day rolling
                                                       average).
                                  b. Filterable PM    4.4E-01 lb per      5.5E-01 lb per      Collect a minimum
                                   (or TSM).           MMBtu of heat       MMBtu of steam      of 1 dscm per
                                                       input; or (4.5E-    output or 6.2 lb    run.
                                                       04 lb per MMBtu     per MWh; or (5.7E-
                                                       of heat input).     04 lb per MMBtu
                                                                           of steam output
                                                                           or 6.3E-03 lb per
                                                                           MWh).
14. Units designed to burn        a. HCl............  1.1E-03 lb per      1.4E-03 lb per      For M26A, collect
 liquid fuel.                                          MMBtu of heat       MMBtu of steam      a minimum of 2
                                                       input.              output or 1.6E-02   dscm per run; for
                                                                           lb per MWh.         M26, collect a
                                                                                               minimum of 240
                                                                                               liters per run.
                                  b. Mercury........  2.0E-06 lb per      2.5E-06 lb per      For M29, collect a
                                                       MMBtu of heat       MMBtu of steam      minimum of 3 dscm
                                                       input.              output or 2.8E-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.
15. Units designed to burn heavy  a. CO.............  130 ppm by volume   0.13 lb per MMBtu   1 hr minimum
 liquid fuel.                                          on a dry basis      of steam output     sampling time.
                                                       corrected to 3      or 1.4 lb per
                                                       percent oxygen, 3-  MWh; 3-run
                                                       run average.        average.
                                  b. Filterable PM    6.2E-02 lb per      7.5E-02 lb per      Collect a minimum
                                   (or TSM).           MMBtu of heat       MMBtu of steam      of 1 dscm per
                                                       input; or (2.0E-    output or 8.6E-01   run.
                                                       04 lb per MMBtu     lb per MWh; or
                                                       of heat input).     (2.5E-04 lb per
                                                                           MMBtu of steam
                                                                           output or 2.8E-03
                                                                           lb per MWh).
16. Units designed to burn light  a. CO.............  130 ppm by volume   0.13 lb per MMBtu   1 hr minimum
 liquid fuel.                                          on a dry basis      of steam output     sampling time.
                                                       corrected to 3      or 1.4 lb per MWh.
                                                       percent oxygen.
                                  b. Filterable PM    7.9E-03 lb per      9.6E-03 lb per      Collect a minimum
                                   (or TSM).           MMBtu of heat       MMBtu of steam      of 3 dscm per
                                                       input; or (6.2E-    output or 1.1E-01   run.
                                                       05 lb per MMBtu     lb per MWh; or
                                                       of heat input).     (7.5E-05 lb per
                                                                           MMBtu of steam
                                                                           output or 8.6E-04
                                                                           lb per MWh).
17. Units designed to burn        a. CO.............  130 ppm by volume   0.13 lb per MMBtu   1 hr minimum
 liquid fuel that are non-                             on a dry basis      of steam output     sampling time.
 continental units.                                    corrected to 3      or 1.4 lb per
                                                       percent oxygen, 3-  MWh; 3-run
                                                       run average based   average.
                                                       on stack test.

[[Page 7198]]

 
                                  b. Filterable PM    2.7E-01 lb per      3.3E-01 lb per      Collect a minimum
                                   (or TSM).           MMBtu of heat       MMBtu of steam      of 2 dscm per
                                                       input; or (8.6E-    output or 3.8 lb    run.
                                                       04 lb per MMBtu     per MWh; or (1.1E-
                                                       of heat input).     03 lb per MMBtu
                                                                           of steam output
                                                                           or 1.2E-02 lb per
                                                                           MWh).
18. Units designed to burn gas 2  a. CO.............  130 ppm by volume   0.16 lb per MMBtu   1 hr minimum
 (other) gases.                                        on a dry basis      of steam output     sampling time.
                                                       corrected to 3      or 1.0 lb per MWh.
                                                       percent oxygen.
                                  b. HCl............  1.7E-03 lb per      2.9E-03 lb per      For M26A, collect
                                                       MMBtu of heat       MMBtu of steam      a minimum of 2
                                                       input.              output or 1.8E-02   dscm per run; for
                                                                           lb per MWh.         M26, collect a
                                                                                               minimum of 240
                                                                                               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 2 dscm.
                                  d. Filterable PM    6.7E-03 lb per      1.2E-02 lb per      Collect a minimum
                                   (or TSM).           MMBtu of heat       MMBtu of steam      of 3 dscm per
                                                       input or (2.1E-04   output or 7.0E-02   run.
                                                       lb per MMBtu of     lb per MWh; or
                                                       heat input).        (3.5E-04 lb per
                                                                           MMBtu of steam
                                                                           output or 2.2E-03
                                                                           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 below 75 percent of this limit in order to qualify for skip testing.
\b\ Incorporated by reference, see Sec.   63.14.

0
30. Table 3 to subpart DDDDD of part 63 is revised to read as follows:
    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 a continuous oxygen trim     or process heater every 5
 system that maintains an optimum air     years as specified in Sec.
 to fuel ratio, or a heat input           63.7540.
 capacity of less than or equal to 5
 million Btu per hour in any of the
 following subcategories: unit designed
 to burn gas 1; unit designed to burn
 gas 2 (other); or unit designed to
 burn light liquid, or a limited use
 boiler or process heater.
2. A new or existing boiler or process   Conduct a tune-up of the boiler
 heater without a continuous oxygen       or process heater biennially
 trim system and 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 greater than
 5 million Btu per hour, in any of the
 following subcategories: unit designed
 to burn gas 1; unit designed to burn
 gas 2 (other); or unit designed to
 burn light liquid.
3. A new or existing boiler or process   Conduct a tune-up of the boiler
 heater without a continuous oxygen       or process heater annually as
 trim system and with heat input          specified in Sec.   63.7540.
 capacity of 10 million Btu per hour or   Units in either the Gas 1 or
 greater.                                 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 by a
 not including limited use units.         qualified energy assessor. An
                                          energy assessment completed on
                                          or after January 1, 2008, that
                                          meets or is amended to meet
                                          the energy assessment
                                          requirements in this table,
                                          satisfies the energy
                                          assessment requirement. A
                                          facility that operates under
                                          an energy management program
                                          compatible with ISO 50001 that
                                          includes the affected units
                                          also satisfies the energy
                                          assessment requirement. The
                                          energy assessment must include
                                          the following with extent of
                                          the evaluation for items a. to
                                          e. appropriate for the on-site
                                          technical hours listed in Sec.
                                            63.7575:
                                         a. A visual inspection of the
                                          boiler or process heater
                                          system.

[[Page 7199]]

 
                                         b. An evaluation of operating
                                          characteristics of the boiler
                                          or process heater systems,
                                          specifications of energy using
                                          systems, operating and
                                          maintenance procedures, and
                                          unusual operating constraints.
                                         c. An inventory of major energy
                                          use systems consuming energy
                                          from affected boilers and
                                          process heaters and which are
                                          under the control of the
                                          boiler/process heater owner/
                                          operator.
                                         d. A review of available
                                          architectural and engineering
                                          plans, facility operation and
                                          maintenance procedures and
                                          logs, and fuel usage.
                                         e. A review of the facility's
                                          energy management practices
                                          and provide recommendations
                                          for improvements consistent
                                          with the definition of energy
                                          management practices, if
                                          identified.
                                         f. A list of cost-effective
                                          energy conservation measures
                                          that are within the facility's
                                          control.
                                         g. A list of the energy savings
                                          potential of the energy
                                          conservation measures
                                          identified.
                                         h. A comprehensive report
                                          detailing the ways to improve
                                          efficiency, the cost of
                                          specific improvements,
                                          benefits, and the time frame
                                          for recouping those
                                          investments.
5. An existing or new boiler or process  You must operate all CMS during
 heater subject to emission limits in     startup.
 Table 1 or 2 or 11 through 13 to this   For startup of a boiler or
 subpart during startup.                  process heater, you must use
                                          one or a combination of the
                                          following clean fuels: natural
                                          gas, synthetic natural gas,
                                          propane, distillate oil,
                                          syngas, ultra-low sulfur
                                          diesel, fuel oil-soaked rags,
                                          kerosene, hydrogen, paper,
                                          cardboard, refinery gas, and
                                          liquefied petroleum gas.
                                         If you start firing coal/solid
                                          fossil fuel, biomass/bio-based
                                          solids, heavy liquid fuel, or
                                          gas 2 (other) gases, you must
                                          vent emissions to the main
                                          stack(s) and engage all of the
                                          applicable control devices
                                          except limestone injection in
                                          fluidized bed combustion (FBC)
                                          boilers, dry scrubber, fabric
                                          filter, selective non-
                                          catalytic reduction (SNCR),
                                          and selective catalytic
                                          reduction (SCR). You must
                                          start your limestone injection
                                          in FBC boilers, dry scrubber,
                                          fabric filter, SNCR, and SCR
                                          systems as expeditiously as
                                          possible. Startup ends when
                                          steam or heat is supplied for
                                          any purpose.
                                         You must comply with all
                                          applicable emission limits at
                                          all times except for startup
                                          or shutdown periods conforming
                                          with this work practice. You
                                          must collect monitoring data
                                          during periods of startup, as
                                          specified in Sec.
                                          63.7535(b). You must keep
                                          records during periods of
                                          startup. You must provide
                                          reports concerning activities
                                          and periods of startup, as
                                          specified in Sec.   63.7555.
6. An existing or new boiler or process  You must operate all CMS during
 heater subject to emission limits in     shutdown.
 Tables 1 or 2 or 11 through 13 to this  While firing coal/solid fossil
 subpart during shutdown.                 fuel, biomass/bio-based
                                          solids, heavy liquid fuel, or
                                          gas 2 (other) gases during
                                          shutdown, you must vent
                                          emissions to the main stack(s)
                                          and operate all applicable
                                          control devices, except
                                          limestone injection in FBC
                                          boilers, dry scrubber, fabric
                                          filter, SNCR, and SCR.
                                         You must comply with all
                                          applicable emissions limits at
                                          all times except for startup
                                          or shutdown periods conforming
                                          with this work practice. You
                                          must collect monitoring data
                                          during periods of shutdown, as
                                          specified in Sec.
                                          63.7535(b). You must keep
                                          records during periods of
                                          shutdown. You must provide
                                          reports concerning activities
                                          and periods of shutdown, as
                                          specified in Sec.   63.7555.
------------------------------------------------------------------------

0
31. Table 4 to subpart DDDDD of part 63 is revised to read as follows:
    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
------------------------------------------------------------------------
 When complying with a Table
1, 2, 11, 12, or 13 numerical   You must meet these operating limits . .
  emission limit 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.

[[Page 7200]]

 
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 HCl CEMS.          hour average pH and the 30-day rolling
                                average liquid flow rate at or above the
                                lowest one-hour average liquid flow rate
                                measured during the most recent
                                performance test demonstrating
                                compliance with the HCl emission
                                limitation according to 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
                                alert is not activated 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.
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 highest hourly
                                average operating load recorded during
                                the most recent performance test.
9. Oxygen analyzer system....  For boilers and process heaters subject
                                to a CO emission limit that demonstrate
                                compliance with an O2 analyzer system as
                                specified in Sec.   63.7525(a), maintain
                                the 30-day rolling average oxygen
                                content at or above the lowest hourly
                                average oxygen concentration measured
                                during the most recent CO performance
                                test, as specified in Table 8. This
                                requirement does not apply to units that
                                install an oxygen trim system since
                                these units will set the trim system to
                                the level specified in Sec.
                                63.7525(a).
10. SO2 CEMS.................  For boilers or process heaters subject to
                                an HCl emission limit that demonstrate
                                compliance with an SO2 CEMS, maintain
                                the 30-day rolling average SO2 emission
                                rate at or below the highest hourly
                                average SO2 concentration measured
                                during the most recent HCl performance
                                test, as specified in Table 8.
------------------------------------------------------------------------

0
32. Table 5 to subpart DDDDD of part 63 is amended by:
0
a. Revising the entry for ``1. Particulate matter.''
0
b. Remove the entry for ``5. Dioxins/Furans''.
0
c. Redesignating the entries for ``2. Hydrogen chloride,'' ``3. 
Mercury,'' and ``4. CO'' as ``3. Hydrogen chloride,'' ``4. Mercury,'' 
and ``5. CO,'' respectively.
0
d. Revising the newly redesignated entries for ``4. Mercury'' and ``5. 
CO.''
0
e. Add entry for ``2. Total selected metals.''
    The revisions and addition read as follows:
    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. Filterable PM..............  a. Select sampling   Method 1 at 40 CFR
                                 ports location and   part 60, appendix
                                 the number of        A-1 of this
                                 traverse points.     chapter.
                                b. Determine         Method 2, 2F, or 2G
                                 velocity and         at 40 CFR part 60,
                                 volumetric flow-     appendix A-1 or A-
                                 rate of the stack    2 to part 60 of
                                 gas.                 this chapter.
                                c. Determine oxygen  Method 3A or 3B at
                                 or carbon dioxide    40 CFR part 60,
                                 concentration of     appendix A-2 to
                                 the stack gas.       part 60 of this
                                                      chapter, or ANSI/
                                                      ASME PTC 19.10-
                                                      1981.\a\
                                d. Measure the       Method 4 at 40 CFR
                                 moisture content     part 60, appendix
                                 of the stack gas.    A-3 of this
                                                      chapter.
                                e. Measure the PM    Method 5 or 17
                                 emission             (positive pressure
                                 concentration.       fabric filters
                                                      must 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
                                 emission rates.      this chapter.
2. TSM........................  a. Select sampling   Method 1 at 40 CFR
                                 ports location and   part 60, appendix
                                 the number of        A-1 of this
                                 traverse points.     chapter.

[[Page 7201]]

 
                                b. Determine         Method 2, 2F, or 2G
                                 velocity and         at 40 CFR part 60,
                                 volumetric flow-     appendix A-1 or A-
                                 rate of the stack    2 of this chapter.
                                 gas.
                                c. Determine oxygen  Method 3A or 3B at
                                 or carbon dioxide    40 CFR part 60,
                                 concentration of     appendix A-1 of
                                 the stack gas.       this chapter, or
                                                      ANSI/ASME PTC
                                                      19.10-1981.\a\
                                d. Measure the       Method 4 at 40 CFR
                                 moisture content     part 60, appendix
                                 of the stack gas.    A-3 of this
                                                      chapter.
                                e. Measure the TSM   Method 29 at 40 CFR
                                 emission             part 60, appendix
                                 concentration.       A-8 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
                                 emission rates.      this chapter.
3. HCl........................  a. Select sampling   Method 1 at 40 CFR
                                 ports location and   part 60, appendix
                                 the number of        A-1 of this
                                 traverse points.     chapter.
                                b. Determine         Method 2, 2F, or 2G
                                 velocity and         at 40 CFR part 60,
                                 volumetric flow-     appendix A-2 of
                                 rate of the stack    this chapter.
                                 gas.
                                c. Determine oxygen  Method 3A or 3B at
                                 or carbon dioxide    40 CFR part 60,
                                 concentration of     appendix A-2 of
                                 the stack gas.       this chapter, or
                                                      ANSI/ASME PTC
                                                      19.10-1981.\a\
                                d. Measure the       Method 4 at 40 CFR
                                 moisture content     part 60, appendix
                                 of the stack gas.    A-3 of this
                                                      chapter.
                                e. Measure the HCl   Method 26 or 26A
                                 emission             (M26 or M26A) at
                                 concentration.       40 CFR part 60,
                                                      appendix A-8 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
                                 emission rates.      this chapter.
4. Mercury....................  a. Select sampling   Method 1 at 40 CFR
                                 ports location and   part 60, appendix
                                 the number of        A-1 of this
                                 traverse points.     chapter.
                                b. Determine         Method 2, 2F, or 2G
                                 velocity and         at 40 CFR part 60,
                                 volumetric flow-     appendix A-1 or A-
                                 rate of the stack    2 of this chapter.
                                 gas.
                                c. Determine oxygen  Method 3A or 3B at
                                 or carbon dioxide    40 CFR part 60,
                                 concentration of     appendix A-1 of
                                 the stack gas.       this chapter, or
                                                      ANSI/ASME PTC
                                                      19.10-1981.\a\
                                d. Measure the       Method 4 at 40 CFR
                                 moisture content     part 60, appendix
                                 of the stack gas.    A-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 61, 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
                                 emission rates.      this chapter.
5. CO.........................  a. Select the        Method 1 at 40 CFR
                                 sampling ports       part 60, appendix
                                 location and the     A-1 of this
                                 number of traverse   chapter.
                                 points.
                                b. Determine oxygen  Method 3A or 3B at
                                 concentration of     40 CFR part 60,
                                 the stack gas.       appendix A-3 of
                                                      this 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
                                 of the stack gas.    A-3 of this
                                                      chapter.
                                d. Measure the CO    Method 10 at 40 CFR
                                 emission             part 60, appendix
                                 concentration.       A-4 of this
                                                      chapter. Use a
                                                      measurement span
                                                      value of 2 times
                                                      the concentration
                                                      of the applicable
                                                      emission limit.
------------------------------------------------------------------------

* * * * *

0
33. Table 6 to subpart DDDDD of part 63 is revised to read as follows:
    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
                                                      D5192 \a\, or ASTM
                                                      D7430 \a\, or ASTM
                                                      D6883 \a\, or ASTM
                                                      D2234/D2234M
                                                      \a\(for coal) or
                                                      EPA 1631 or EPA
                                                      1631E or ASTM
                                                      D6323 \a\ (for
                                                      solid), or EPA 821-
                                                      R-01-013 (for
                                                      liquid or solid),
                                                      or ASTM D4177 \a\
                                                      (for liquid), or
                                                      ASTM D4057 \a\
                                                      (for liquid), or
                                                      equivalent.
                                b. Composite fuel    Procedure in Sec.
                                 samples.             63.7521(d) or
                                                      equivalent.
                                c. Prepare           EPA SW-846-3050B
                                 composited fuel      \a\ (for solid
                                 samples.             samples), EPA SW-
                                                      846-3020A \a\ (for
                                                      liquid samples),
                                                      ASTM D2013/D2013M
                                                      \a\ (for coal),
                                                      ASTM D5198 \a\
                                                      (for biomass), or
                                                      EPA 3050 \a\ (for
                                                      solid fuel), or
                                                      EPA 821-R-01-013
                                                      \a\ (for liquid or
                                                      solid), or
                                                      equivalent.

[[Page 7202]]

 
                                d. Determine heat    ASTM D5865 \a\ (for
                                 content of the       coal) or ASTM E711
                                 fuel type.           \a\ (for biomass),
                                                      or ASTM D5864 \a\
                                                      for liquids and
                                                      other solids, or
                                                      ASTM D240 \a\ or
                                                      equivalent.
                                e. Determine         ASTM D3173 \a\,
                                 moisture content     ASTM E871 \a\, or
                                 of the fuel type.    ASTM D5864 \a\, or
                                                      ASTM D240, or ASTM
                                                      D95 \a\ (for
                                                      liquid fuels), or
                                                      ASTM D4006 \a\
                                                      (for liquid
                                                      fuels), or ASTM
                                                      D4177 \a\ (for
                                                      liquid fuels) or
                                                      ASTM D4057 \a\
                                                      (for liquid
                                                      fuels), or
                                                      equivalent.
                                f. Measure mercury   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. HCl........................  a. Collect fuel      Procedure in Sec.
                                 samples.             63.7521(c) or ASTM
                                                      D5192 \a\, or ASTM
                                                      D7430 \a\, or ASTM
                                                      D6883 \a\, or ASTM
                                                      D2234/D2234M \a\
                                                      (for coal) or ASTM
                                                      D6323 \a\ (for
                                                      coal or biomass),
                                                      ASTM D4177 \a\
                                                      (for liquid fuels)
                                                      or ASTM D4057 \a\
                                                      (for liquid
                                                      fuels), or
                                                      equivalent.
                                b. Composite fuel    Procedure in Sec.
                                 samples.             63.7521(d) or
                                                      equivalent.
                                c. Prepare           EPA SW-846-3050B
                                 composited fuel      \a\ (for solid
                                 samples.             samples), EPA SW-
                                                      846-3020A \a\ (for
                                                      liquid samples),
                                                      ASTM D2013/
                                                      D2013MSec.  \a\
                                                      (for coal), or
                                                      ASTM D5198Sec.
                                                      \a\ (for biomass),
                                                      or EPA 3050 \a\ or
                                                      equivalent.
                                d. Determine heat    ASTM D5865 \a\ (for
                                 content of the       coal) or ASTM E711
                                 fuel type.           \a\ (for biomass),
                                                      ASTM D5864, ASTM
                                                      D240 \a\ or
                                                      equivalent.
                                e. Determine         ASTM D3173 \a\ or
                                 moisture content     ASTM E871 \a\, or
                                 of the fuel type.    D5864 \a\, or ASTM
                                                      D240 \a\, or ASTM
                                                      D95\a\ (for liquid
                                                      fuels), or ASTM
                                                      D4006 \a\ (for
                                                      liquid fuels), or
                                                      ASTM D4177 \a\
                                                      (for liquid fuels)
                                                      or ASTM D4057 \a\
                                                      (for liquid fuels)
                                                      or equivalent.
                                f. Measure chlorine  EPA SW-846-9250
                                 concentration in     \a\, ASTM D6721
                                 fuel sample.         \a\, ASTM D4208
                                                      \a\ (for coal), or
                                                      EPA SW-846-5050
                                                      \a\ or ASTM E776
                                                      \a\ (for solid
                                                      fuel), or EPA SW-
                                                      846-9056 \a\ or SW-
                                                      846-9076 \a\ (for
                                                      solids or liquids)
                                                      or equivalent.
                                g. Convert           Equation 7 in Sec.
                                 concentrations        63.7530.
                                 into units of
                                 pounds of HCl per
                                 MMBtu of heat
                                 content.
                                h. Calculate the     Equations 10 and 11
                                 HCl emission rate    in Sec.   63.7530.
                                 from the boiler or
                                 process heater in
                                 units of pounds
                                 per million Btu.
3. Mercury Fuel Specification   a. Measure mercury   Method 30B (M30B)
 for other gas 1 fuels.          concentration in     at 40 CFR part 60,
                                 the fuel sample      appendix A-8 of
                                 and convert to       this chapter or
                                 units of             ASTM D5954 \a\,
                                 micrograms per       ASTM D6350 \a\,
                                 cubic meter.         ISO 6978-1:2003(E)
                                                      \a\, or ISO 6978-
                                                      2:2003(E) \a\, or
                                                      EPA-1631 \a\ or
                                                      equivalent.
                                b. Measure mercury   Method 29, 30A, or
                                 concentration in     30B (M29, M30A, or
                                 the exhaust gas      M30B) at 40 CFR
                                 when firing only     part 60, appendix
                                 the other gas 1      A-8 of this
                                 fuel is fired in     chapter or Method
                                 the boiler or        101A or Method 102
                                 process heater.      at 40 CFR part 61,
                                                      appendix B of this
                                                      chapter, or ASTM
                                                      Method D6784 \a\
                                                      or equivalent.
4. TSM for solid fuels........  a. Collect fuel      Procedure in Sec.
                                 samples.             63.7521(c) or ASTM
                                                      D5192 \a\, or ASTM
                                                      D7430 \a\, or ASTM
                                                      D6883 \a\, or ASTM
                                                      D2234/D2234M \a\
                                                      (for coal) or ASTM
                                                      D6323 \a\ (for
                                                      coal or biomass),
                                                      or ASTM D4177
                                                      \a\,(for liquid
                                                      fuels)or ASTM
                                                      D4057 \a\ (for
                                                      liquid fuels),or
                                                      equivalent.
                                b. Composite fuel    Procedure in Sec.
                                 samples.             63.7521(d) or
                                                      equivalent.
                                c. Prepare           EPA SW-846-3050B
                                 composited fuel      \a\ (for solid
                                 samples.             samples), EPA SW-
                                                      846-3020A \a\ (for
                                                      liquid samples),
                                                      ASTM D2013/D2013M
                                                      \a\ (for coal),
                                                      ASTM D5198 \a\ or
                                                      TAPPI T266 \a\
                                                      (for biomass), or
                                                      EPA 3050 \a\ or
                                                      equivalent.
                                d. Determine heat    ASTM D5865 \a\ (for
                                 content of the       coal) or ASTM E711
                                 fuel type.           \a\ (for biomass),
                                                      or ASTM D5864 \a\
                                                      for liquids and
                                                      other solids, or
                                                      ASTM D240 \a\ or
                                                      equivalent.
                                e. Determine         ASTM D3173 \a\ or
                                 moisture content     ASTM E871 \a\, or
                                 of the fuel type.    D5864, or ASTM
                                                      D240 \a\, or ASTM
                                                      D95 \a\ (for
                                                      liquid fuels), or
                                                      ASTM D4006\a\ (for
                                                      liquid fuels), or
                                                      ASTM D4177 \a\
                                                      (for liquid fuels)
                                                      or ASTM D4057 \a\
                                                      (for liquid
                                                      fuels), or
                                                      equivalent.
                                f. Measure TSM       ASTM D3683 \a\, or
                                 concentration in     ASTM D4606 \ a\,
                                 fuel sample.         or ASTM D6357 \a\
                                                      or EPA 200.8 \a\
                                                      or EPA SW-846-6020
                                                      \a\, or EPA SW-846-
                                                      6020A \a\, or EPA
                                                      SW-846-6010C \a\,
                                                      EPA 7060 \a\ or
                                                      EPA 7060A \a\ (for
                                                      arsenic only), or
                                                      EPA SW-846-7740
                                                      \a\ (for selenium
                                                      only).
                                g. Convert           Equation 9 in Sec.
                                 concentrations        63.7530.
                                 into units of
                                 pounds of TSM per
                                 MMBtu of heat
                                 content.
                                h. Calculate the     Equations 10 and 13
                                 TSM emission rate    in Sec.   63.7530.
                                 from the boiler or
                                 process heater in
                                 units of pounds
                                 per million Btu.
------------------------------------------------------------------------
\a\ Incorporated by reference, see Sec.   63.14.

[[Page 7203]]

0
34. Table 7 to subpart DDDDD of part 63 is amended by:
0
a. Revising the entry for ``1. Particulate matter or mercury,''.
0
b. Revising the entry for ``2. Hydrogen Chloride,''.
0
c. Revising the entry for ``3. Mercury,''.
0
d. Revising the entry for ``4. Carbon monoxide''.
    The revisions read as follows:
    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. PM, TSM, or mercury..........  a. Wet scrubber     i. Establish a      (1) Data from the   (a) You must
                                   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     PM or mercury       minutes during
                                                       according to Sec.   performance test.   the entire period
                                                         63.7530(b).                           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 PM or    amperage for each
                                   units that          input according     mercury             ESP cell and
                                   operate wet         to Sec.             performance test.   calculate total
                                   scrubbers).         63.7530(b).                             secondary
                                                                                               electric power
                                                                                               input data every
                                                                                               15 minutes during
                                                                                               the entire period
                                                                                               of the
                                                                                               performance
                                                                                               tests.
                                                                                              (b) Determine the
                                                                                               average total
                                                                                               secondary
                                                                                               electric power
                                                                                               input by
                                                                                               computing the
                                                                                               hourly averages
                                                                                               using all of the
                                                                                               15-minute
                                                                                               readings taken
                                                                                               during each
                                                                                               performance test.
2. HCl..........................  a. Wet scrubber     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    HCl performance     the entire period
                                                       according to Sec.   test.               of the
                                                         63.7530(b).                           performance
                                                                                               tests.
                                                                                              (b) Determine the
                                                                                               hourly average pH
                                                                                               and liquid flow
                                                                                               rate by computing
                                                                                               the hourly
                                                                                               averages using
                                                                                               all of the 15-
                                                                                               minute readings
                                                                                               taken during each
                                                                                               performance test.
                                  b. Dry scrubber     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      HCl or mercury      data every 15
                                                       operating limit     performance test.   minutes during
                                                       according to Sec.                       the entire period
                                                         63.7530(b). If                        of the
                                                       different acid                          performance
                                                       gas sorbents are                        tests.
                                                       used during the
                                                       HCl 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.
                                  c. Alternative      i. Establish a      (1) Data from SO2   (a) You must
                                   Maximum SO2         site-specific       CEMS and the HCl    collect the SO2
                                   emission rate.      maximum SO2         performance test.   emissions data
                                                       emission rate                           according to Sec.
                                                       operating limit                           63.7525(m)
                                                       according to Sec.                       during the most
                                                         63.7530(b).                           recent HCl
                                                                                               performance
                                                                                               tests.

[[Page 7204]]

 
                                                                                              (b) The maximum
                                                                                               SO2 emission rate
                                                                                               is equal to the
                                                                                               lowest hourly
                                                                                               average SO2
                                                                                               emission rate
                                                                                               measured during
                                                                                               the most recent
                                                                                               HCl performance
                                                                                               tests.
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.
                                                                                              (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.
 
                                                  * * * * * * *
----------------------------------------------------------------------------------------------------------------

0
35. Table 8 to subpart DDDDD of part 63 is revised to read as follows:
    As stated in Sec.  63.7540, you must show continuous compliance 
with the emission limitations for each boiler or process heater 
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;
                               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(b)(4).
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

[[Page 7205]]

 
                               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. Emission limits using fuel  a. Conduct monthly fuel analysis for HCl
 analysis.                      or mercury or TSM according to Table 6
                                to this subpart; and
                               b. Reduce the data to 12-month rolling
                                averages; and
                               c. Maintain the 12-month rolling average
                                at or below the applicable emission
                                limit for HCl or mercury or TSM in
                                Tables 1 and 2 or 11 through 13 to this
                                subpart.
9. Oxygen content............  a. Continuously monitor the oxygen
                                content using an oxygen analyzer system
                                according to Sec.   63.7525(a). This
                                requirement does not apply to units that
                                install an oxygen trim system since
                                these units will set the trim system to
                                the level specified in Sec.
                                63.7525(a)(2).
                               b. Reducing the data to 30-day rolling
                                averages; and
                               c. Maintain the 30-day rolling average
                                oxygen content at or above the lowest
                                hourly average oxygen level measured
                                during the most recent CO performance
                                test.
10. Boiler or process heater   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 highest hourly average operating
                                load recorded during the most recent
                                performance test according to Sec.
                                63.7520(c).
11. SO2 emissions using SO2    a. Collecting the SO2 CEMS output data
 CEMS.                          according to Sec.   63.7525;
                               b. Reducing the data to 30-day rolling
                                averages; and
                               c. Maintaining the 30-day rolling average
                                SO2 CEMS emission rate to a level at or
                                below the minimum hourly SO2 rate
                                measured during the most recent HCl
                                performance test according to Sec.
                                63.7530.
------------------------------------------------------------------------

0
36. Table 9 to subpart DDDDD of part 63 is amended by revising the 
entry for ``1. Compliance report'' to read as follows:
    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)      biennially, or
                                   through (5); and    every 5 years
                                                       according to the
                                                       requirements in
                                                       Sec.
                                                       63.7550(b).
 
                              * * * * * * *
------------------------------------------------------------------------

0
37. Table 10 to subpart DDDDD of part 63 is amended by:
0
a. Revising the entry for ``Sec.  63.6(i)''.
0
b. Revising the entry for ``Sec.  63.7(e)(1)''.
0
c. Revising the entry for ``63.8(g)''.
0
d. Revising the entry for ``Sec.  63.10(e) and (f)''.
0
e. Adding an entry for ``Sec.  63.10(e)''.
    The revisions and addition read as follows.
    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.   63.6(i)................  Extension of         Yes. Note:
                                 compliance.          Facilities may
                                                      also request
                                                      extensions of
                                                      compliance for the
                                                      installation of
                                                      combined heat and
                                                      power, waste heat
                                                      recovery, or gas
                                                      pipeline or fuel
                                                      feeding
                                                      infrastructure as
                                                      a means of
                                                      complying with
                                                      this subpart.
 

[[Page 7206]]

 
                              * * * * * * *
Sec.   63.7(e)(1).............  Conditions for       No. Subpart DDDDD
                                 conducting           specifies
                                 performance tests.   conditions for
                                                      conducting
                                                      performance tests
                                                      at Sec.
                                                      63.7520(a) to (c).
 
                              * * * * * * *
Sec.   63.8(g)................  Reduction of         Yes.
                                 monitoring data.
 
                              * * * * * * *
Sec.   63.10(e)...............  Additional           Yes.
                                 reporting
                                 requirements for
                                 sources with CMS.
Sec.   63.10(f)...............  Waiver of            Yes.
                                 recordkeeping or
                                 reporting
                                 requirements.
 
                              * * * * * * *
------------------------------------------------------------------------

0
38. Add Table 11 to subpart DDDDD of part 63 to read as follows:

 Table 11 to Subpart DDDDD of Part 63--Alternative Emission Limits for New or Reconstructed Boilers and Process
        Heaters That Commenced Construction or Reconstruction After June 4, 2010, and Before May 20, 2011
----------------------------------------------------------------------------------------------------------------
                                                                       The emissions must
                                                                         not exceed the
                                                                       following emission   Using this specified
 If your boiler or process heater   For the following pollutants . .     limits, except      sampling volume or
   is in this subcategory . . .                     .                   during periods of    test run duration .
                                                                      startup and shutdown           . .
                                                                              . . .
----------------------------------------------------------------------------------------------------------------
1. Units in all subcategories       a. HCl..........................  0.022 lb per MMBtu    For M26A, collect a
 designed to burn solid fuel.                                          of heat input.        minimum of 1 dscm
                                                                                             per run; for M26
                                                                                             collect a minimum
                                                                                             of 120 liters per
                                                                                             run.
2. Units in all subcategories       a. Mercury......................  8.0E-07 \a\ lb per    For M29, collect a
 designed to burn solid fuel that                                      MMBtu of heat input.  minimum of 4 dscm
 combust at least 10 percent                                                                 per run; for M30A
 biomass/bio-based solids on an                                                              or M30B, collect a
 annual heat input basis and less                                                            minimum sample as
 than 10 percent coal/solid fossil                                                           specified in the
 fuels on an annual heat input                                                               method; for ASTM
 basis.                                                                                      D6784 \b\ collect a
                                                                                             minimum of 4 dscm.
3. Units in all subcategories       a. Mercury......................  2.0E-06 lb per MMBtu  For M29, collect a
 designed to burn solid fuel that                                      of heat input.        minimum of 4 dscm
 combust at least 10 percent coal/                                                           per run; for M30A
 solid fossil fuels on an annual                                                             or M30B, collect a
 heat input basis and less than 10                                                           minimum sample as
 percent biomass/bio-based solids                                                            specified in the
 on an annual heat input basis.                                                              method; for ASTM
                                                                                             D6784 \b\ collect a
                                                                                             minimum of 4 dscm.
4. Units designed to burn coal/     a. Filterable PM (or TSM).......  1.1E-03 lb per MMBtu  Collect a minimum of
 solid fossil fuel.                                                    of heat input; or     3 dscm per run.
                                                                       (2.3E-05 lb per
                                                                       MMBtu of heat
                                                                       input).
5. Pulverized coal boilers          a. Carbon monoxide (CO) (or       130 ppm by volume on  1 hr minimum
 designed to burn coal/solid         CEMS).                            a dry basis           sampling time.
 fossil fuel.                                                          corrected to 3
                                                                       percent oxygen, 3-
                                                                       run average; or
                                                                       (320 ppm by volume
                                                                       on a dry basis
                                                                       corrected to 3
                                                                       percent oxygen, 30-
                                                                       day rolling
                                                                       average).
6. Stokers designed to burn coal/   a. CO (or CEMS).................  130 ppm by volume on  1 hr minimum
 solid fossil fuel.                                                    a dry basis           sampling time.
                                                                       corrected to 3
                                                                       percent oxygen, 3-
                                                                       run average; or
                                                                       (340 ppm by volume
                                                                       on a dry basis
                                                                       corrected to 3
                                                                       percent oxygen, 10-
                                                                       day rolling
                                                                       average).
7. Fluidized bed units designed to  a. CO (or CEMS).................  130 ppm by volume on  1 hr minimum
 burn coal/solid fossil fuel.                                          a dry basis           sampling time.
                                                                       corrected to 3
                                                                       percent oxygen, 3-
                                                                       run average; or
                                                                       (230 ppm by volume
                                                                       on a dry basis
                                                                       corrected to 3
                                                                       percent oxygen, 30-
                                                                       day rolling
                                                                       average).

[[Page 7207]]

 
8. Fluidized bed units with an      a. CO (or CEMS).................  140 ppm by volume on  1 hr minimum
 integrated heat exchanger                                             a dry basis           sampling time.
 designed to burn coal/solid                                           corrected to 3
 fossil fuel.                                                          percent oxygen, 3-
                                                                       run average; or
                                                                       (150 ppm by volume
                                                                       on a dry basis
                                                                       corrected to 3
                                                                       percent oxygen, 30-
                                                                       day rolling
                                                                       average).
9. Stokers/sloped grate/others      a. CO (or CEMS).................  620 ppm by volume on  1 hr minimum
 designed to burn wet biomass fuel.                                    a dry basis           sampling time.
                                                                       corrected to 3
                                                                       percent oxygen, 3-
                                                                       run average; or
                                                                       (390 ppm by volume
                                                                       on a dry basis
                                                                       corrected to 3
                                                                       percent oxygen, 30-
                                                                       day rolling
                                                                       average).
                                    b. Filterable PM (or TSM).......  3.0E-02 lb per MMBtu  Collect a minimum of
                                                                       of heat input; or     2 dscm per run.
                                                                       (2.6E-05 lb per
                                                                       MMBtu of heat
                                                                       input).
10. Stokers/sloped grate/others     a. CO...........................  560 ppm by volume on  1 hr minimum
 designed to burn kiln-dried                                           a dry basis           sampling time.
 biomass fuel.                                                         corrected to 3
                                                                       percent oxygen.
                                    b. Filterable PM (or TSM).......  3.0E-02 lb per MMBtu  Collect a minimum of
                                                                       of heat input; or     2 dscm per run.
                                                                       (4.0E-03 lb per
                                                                       MMBtu of heat
                                                                       input).
11. Fluidized bed units designed    a. CO (or CEMS).................  230 ppm by volume on  1 hr minimum
 to burn biomass/bio-based solids.                                     a dry basis           sampling time.
                                                                       corrected to 3
                                                                       percent oxygen, 3-
                                                                       run average; or
                                                                       (310 ppm by volume
                                                                       on a dry basis
                                                                       corrected to 3
                                                                       percent oxygen, 30-
                                                                       day rolling
                                                                       average).
                                    b. Filterable PM (or TSM).......  9.8E-03 lb per MMBtu  Collect a minimum of
                                                                       of heat input; or     3 dscm per run
                                                                       (8.3E-05 \a\ lb per
                                                                       MMBtu of heat
                                                                       input).
12. Suspension burners designed to  a. CO (or CEMS).................  2,400 ppm by volume   1 hr minimum
 burn biomass/bio-based solids.                                        on a dry basis        sampling time.
                                                                       corrected to 3
                                                                       percent oxygen, 3-
                                                                       run average; or
                                                                       (2,000 ppm by
                                                                       volume on a dry
                                                                       basis corrected to
                                                                       3 percent oxygen,
                                                                       10-day rolling
                                                                       average).
                                    b. Filterable PM (or TSM).......  3.0E-02 lb per MMBtu  Collect a minimum of
                                                                       of heat input; or     2 dscm per run.
                                                                       (6.5E-03 lb per
                                                                       MMBtu of heat
                                                                       input).
13. Dutch Ovens/Pile burners        a. CO (or CEMS).................  1,010 ppm by volume   1 hr minimum
 designed to burn biomass/bio-                                         on a dry basis        sampling time.
 based solids.                                                         corrected to 3
                                                                       percent oxygen, 3-
                                                                       run average; or
                                                                       (520 ppm by volume
                                                                       on a dry basis
                                                                       corrected to 3
                                                                       percent oxygen, 10-
                                                                       day rolling
                                                                       average).
                                    b. Filterable PM (or TSM).......  8.0E-03 lb per MMBtu  Collect a minimum of
                                                                       of heat input; or     3 dscm per run.
                                                                       (3.9E-05 lb per
                                                                       MMBtu of heat
                                                                       input).
14. Fuel cell units designed to     a. CO...........................  910 ppm by volume on  1 hr minimum
 burn biomass/bio-based solids.                                        a dry basis           sampling time.
                                                                       corrected to 3
                                                                       percent oxygen.
                                    b. Filterable PM (or TSM).......  2.0E-02 lb per MMBtu  Collect a minimum of
                                                                       of heat input; or     2 dscm per run.
                                                                       (2.9E-05 lb per
                                                                       MMBtu of heat
                                                                       input).
15. Hybrid suspension grate boiler  a. CO (or CEMS).................  1,100 ppm by volume   1 hr minimum
 designed to burn biomass/bio-                                         on a dry basis        sampling time.
 based solids.                                                         corrected to 3
                                                                       percent oxygen, 3-
                                                                       run average; or
                                                                       (900 ppm by volume
                                                                       on a dry basis
                                                                       corrected to 3
                                                                       percent oxygen, 30-
                                                                       day rolling
                                                                       average).
                                    b. Filterable PM (or TSM).......  2.6E-02 lb per MMBtu  Collect a minimum of
                                                                       of heat input; or     3 dscm per run.
                                                                       (4.4E-04 lb per
                                                                       MMBtu of heat
                                                                       input).
16. Units designed to burn liquid   a. HCl..........................  4.4E-04 lb per MMBtu  For M26A: Collect a
 fuel.                                                                 of heat input.        minimum of 2 dscm
                                                                                             per run; for M26,
                                                                                             collect a minimum
                                                                                             of 240 liters per
                                                                                             run.

[[Page 7208]]

 
                                    b. Mercury......................  4.8E-07 \a\ lb per    For M29, collect a
                                                                       MMBtu of heat input.  minimum of 4 dscm
                                                                                             per run; for M30A
                                                                                             or M30B, collect a
                                                                                             minimum sample as
                                                                                             specified in the
                                                                                             method; for ASTM
                                                                                             D6784 \b\ collect a
                                                                                             minimum of 4 dscm.
17. Units designed to burn heavy    a. CO...........................  130 ppm by volume on  1 hr minimum
 liquid fuel.                                                          a dry basis           sampling time.
                                                                       corrected to 3
                                                                       percent oxygen, 3-
                                                                       run average.
                                    b. Filterable PM (or TSM).......  1.3E-02 lb per MMBtu  Collect a minimum of
                                                                       of heat input; or     3 dscm per run.
                                                                       (7.5E-05 lb per
                                                                       MMBtu of heat
                                                                       input).
18. Units designed to burn light    a. CO...........................  130 ppm by volume on  1 hr minimum
 liquid fuel.                                                          a dry basis           sampling time.
                                                                       corrected to 3
                                                                       percent oxygen.
                                    b. Filterable PM (or TSM).......  2.0E-03 \a\ lb per    Collect a minimum of
                                                                       MMBtu of heat         3 dscm per run
                                                                       input; or (2.9E-05
                                                                       lb per MMBtu of
                                                                       heat input).
19. Units designed to burn liquid   a. CO...........................  130 ppm by volume on  1 hr minimum
 fuel that are non-continental                                         a dry basis           sampling time.
 units.                                                                corrected to 3
                                                                       percent oxygen, 3-
                                                                       run average based
                                                                       on stack test.
                                    b. Filterable PM (or TSM).......  2.3E-02 lb per MMBtu  Collect a minimum of
                                                                       of heat input; or     4 dscm per run
                                                                       (8.6E-04 lb per
                                                                       MMBtu of heat
                                                                       input).
20. Units designed to burn gas 2    a. CO...........................  130 ppm by volume on  1 hr minimum
 (other) gases.                                                        a dry basis           sampling time.
                                                                       corrected to 3
                                                                       percent oxygen.
                                    b. HCl..........................  1.7E-03 lb per MMBtu  For M26A, collect a
                                                                       of heat input.        minimum of 2 dscm
                                                                                             per run; for M26,
                                                                                             collect a minimum
                                                                                             of 240 liters per
                                                                                             run.
                                    c. Mercury......................  7.9E-06 lb per MMBtu  For M29, collect a
                                                                       of heat input.        minimum of 3 dscm
                                                                                             per run; for M30A
                                                                                             or M30B, collect a
                                                                                             minimum sample as
                                                                                             specified in the
                                                                                             method; for ASTM
                                                                                             D6784 \b\ collect a
                                                                                             minimum of 3 dscm.
                                    d. Filterable PM (or TSM).......  6.7E-03 lb per MMBtu  Collect a minimum of
                                                                       of heat input; or     3 dscm per run
                                                                       (2.1E-04 lb per
                                                                       MMBtu of heat
                                                                       input).
----------------------------------------------------------------------------------------------------------------
\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 below 75 percent of this limit in order to qualify for skip
  testing.
\b\ Incorporated by reference, see Sec.   63.14.

0
39. Add Table 12 to subpart DDDDD of part 63 to read as follows:

 Table 12 to Subpart DDDDD of Part 63--Alternative Emission Limits for New or Reconstructed Boilers and Process
     Heaters that Commenced Construction or Reconstruction after May 20, 2011, and Before December 23, 2011
----------------------------------------------------------------------------------------------------------------
                                                                       The emissions must
                                                                         not exceed the
                                                                       following emission   Using this specified
 If your boiler or process heater   For the following pollutants . .     limits, except      sampling volume or
   is in this subcategory . . .                     .                   during periods of    test run duration .
                                                                      startup and shutdown           . .
                                                                              . . .
----------------------------------------------------------------------------------------------------------------
1. Units in all subcategories       a. HCl..........................  0.022 lb per MMBtu    For M26A, collect a
 designed to burn solid fuel.                                          of heat input.        minimum of 1 dscm
                                                                                             per run; for M26
                                                                                             collect a minimum
                                                                                             of 120 liters per
                                                                                             run.
                                    b. Mercury......................  3.5E-06 \a\ lb per    For M29, collect a
                                                                       MMBtu of heat input.  minimum of 3 dscm
                                                                                             per run; for M30A
                                                                                             or M30B, collect a
                                                                                             minimum sample as
                                                                                             specified in the
                                                                                             method; for ASTM
                                                                                             D6784 \b\ collect a
                                                                                             minimum of 3 dscm.
2. Units design to burn coal/solid  a. Filterable PM (or TSM).......  1.1E-03 lb per MMBtu  Collect a minimum of
 fossil fuel.                                                          of heat input; or     3 dscm per run.
                                                                       (2.3E-05 lb per
                                                                       MMBtu of heat
                                                                       input).

[[Page 7209]]

 
3. Pulverized coal boilers          a. Carbon monoxide (CO) (or       130 ppm by volume on  1 hr minimum
 designed to burn coal/solid         CEMS).                            a dry basis           sampling time.
 fossil fuel.                                                          corrected to 3
                                                                       percent oxygen, 3-
                                                                       run average; or
                                                                       (320 ppm by volume
                                                                       on a dry basis
                                                                       corrected to 3
                                                                       percent oxygen, 30-
                                                                       day rolling
                                                                       average).
4. Stokers designed to burn coal/   a. CO (or CEMS).................  130 ppm by volume on  1 hr minimum
 solid fossil fuel.                                                    a dry basis           sampling time.
                                                                       corrected to 3
                                                                       percent oxygen, 3-
                                                                       run average; or
                                                                       (340 ppm by volume
                                                                       on a dry basis
                                                                       corrected to 3
                                                                       percent oxygen, 10-
                                                                       day rolling
                                                                       average).
5. Fluidized bed units designed to  a. CO (or CEMS).................  130 ppm by volume on  1 hr minimum
 burn coal/solid fossil fuel.                                          a dry basis           sampling time.
                                                                       corrected to 3
                                                                       percent oxygen, 3-
                                                                       run average; or
                                                                       (230 ppm by volume
                                                                       on a dry basis
                                                                       corrected to 3
                                                                       percent oxygen, 30-
                                                                       day rolling
                                                                       average).
6. Fluidized bed units with an      a. CO (or CEMS).................  140 ppm by volume on  1 hr minimum
 integrated heat exchanger                                             a dry basis           sampling time.
 designed to burn coal/solid                                           corrected to 3
 fossil fuel.                                                          percent oxygen, 3-
                                                                       run average; or
                                                                       (150 ppm by volume
                                                                       on a dry basis
                                                                       corrected to 3
                                                                       percent oxygen, 30-
                                                                       day rolling
                                                                       average).
7. Stokers/sloped grate/others      a. CO (or CEMS).................  620 ppm by volume on  1 hr minimum
 designed to burn wet biomass fuel.                                    a dry basis           sampling time.
                                                                       corrected to 3
                                                                       percent oxygen, 3-
                                                                       run average; or
                                                                       (390 ppm by volume
                                                                       on a dry basis
                                                                       corrected to 3
                                                                       percent oxygen, 30-
                                                                       day rolling
                                                                       average).
                                    b. Filterable PM (or TSM).......  3.0E-02 lb per MMBtu  Collect a minimum of
                                                                       of heat input; or     2 dscm per run.
                                                                       (2.6E-05 lb per
                                                                       MMBtu of heat
                                                                       input).
8. Stokers/sloped grate/others      a. CO...........................  460 ppm by volume on  1 hr minimum
 designed to burn kiln-dried                                           a dry basis           sampling time.
 biomass fuel.                                                         corrected to 3
                                                                       percent oxygen.
                                    b. Filterable PM (or TSM).......  3.0E-02 lb per MMBtu  Collect a minimum of
                                                                       of heat input; or     2 dscm per run.
                                                                       (4.0E-03 lb per
                                                                       MMBtu of heat
                                                                       input).
9. Fluidized bed units designed to  a. CO (or CEMS).................  260 ppm by volume on  1 hr minimum
 burn biomass/bio-based solids.                                        a dry basis           sampling time.
                                                                       corrected to 3
                                                                       percent oxygen, 3-
                                                                       run average; or
                                                                       (310 ppm by volume
                                                                       on a dry basis
                                                                       corrected to 3
                                                                       percent oxygen, 30-
                                                                       day rolling
                                                                       average).
                                    b. Filterable PM (or TSM).......  9.8E-03 lb per MMBtu  Collect a minimum of
                                                                       of heat input; or     3 dscm per run.
                                                                       (8.3E-05 \a\ lb per
                                                                       MMBtu of heat
                                                                       input).
10. Suspension burners designed to  a. CO (or CEMS).................  2,400 ppm by volume   1 hr minimum
 burn biomass/bio-based solids.                                        on a dry basis        sampling time.
                                                                       corrected to 3
                                                                       percent oxygen, 3-
                                                                       run average; or
                                                                       (2,000 ppm by
                                                                       volume on a dry
                                                                       basis corrected to
                                                                       3 percent oxygen,
                                                                       10-day rolling
                                                                       average).
                                    b. Filterable PM (or TSM).......  3.0E-02 lb per MMBtu  Collect a minimum of
                                                                       of heat input; or     2 dscm per run.
                                                                       (6.5E-03 lb per
                                                                       MMBtu of heat
                                                                       input).
11. Dutch Ovens/Pile burners        a. CO (or CEMS).................  470 ppm by volume on  1 hr minimum
 designed to burn biomass/bio-                                         a dry basis           sampling time.
 based solids.                                                         corrected to 3
                                                                       percent oxygen, 3-
                                                                       run average; or
                                                                       (520 ppm by volume
                                                                       on a dry basis
                                                                       corrected to 3
                                                                       percent oxygen, 10-
                                                                       day rolling
                                                                       average).
                                    b. Filterable PM (or TSM).......  3.2E-03 lb per MMBtu  Collect a minimum of
                                                                       of heat input; or     3 dscm per run.
                                                                       (3.9E-05 lb per
                                                                       MMBtu of heat
                                                                       input).

[[Page 7210]]

 
12. Fuel cell units designed to     a. CO...........................  910 ppm by volume on  1 hr minimum
 burn biomass/bio-based solids.                                        a dry basis           sampling time.
                                                                       corrected to 3
                                                                       percent oxygen.
                                    b. Filterable PM (or TSM).......  2.0E-02 lb per MMBtu  Collect a minimum of
                                                                       of heat input; or     2 dscm per run.
                                                                       (2.9E-05 lb per
                                                                       MMBtu of heat
                                                                       input).
13. Hybrid suspension grate boiler  a. CO (or CEMS).................  1,500 ppm by volume   1 hr minimum
 designed to burn biomass/bio-                                         on a dry basis        sampling time.
 based solids.                                                         corrected to 3
                                                                       percent oxygen, 3-
                                                                       run average; or
                                                                       (900 ppm by volume
                                                                       on a dry basis
                                                                       corrected to 3
                                                                       percent oxygen, 30-
                                                                       day rolling
                                                                       average).
                                    b. Filterable PM (or TSM).......  2.6E-02 lb per MMBtu  Collect a minimum of
                                                                       of heat input; or     3 dscm per run.
                                                                       (4.4E-04 lb per
                                                                       MMBtu of heat
                                                                       input).
14. Units designed to burn liquid   a. HCl..........................  4.4E-04 lb per MMBtu  For M26A: Collect a
 fuel.                                                                 of heat input.        minimum of 2 dscm
                                                                                             per run; for M26,
                                                                                             collect a minimum
                                                                                             of 240 liters per
                                                                                             run.
                                    b. Mercury......................  4.8E-07 \a\ lb per    For M29, collect a
                                                                       MMBtu of heat input.  minimum of 4 dscm
                                                                                             per run; for M30A
                                                                                             or M30B, collect a
                                                                                             minimum sample as
                                                                                             specified in the
                                                                                             method; for ASTM
                                                                                             D6784 \b\ collect a
                                                                                             minimum of 4 dscm.
15. Units designed to burn heavy    a. CO...........................  130 ppm by volume on  1 hr minimum
 liquid fuel.                                                          a dry basis           sampling time.
                                                                       corrected to 3
                                                                       percent oxygen, 3-
                                                                       run average.
                                    b. Filterable PM (or TSM).......  1.3E-02 lb per MMBtu  Collect a minimum of
                                                                       of heat input; or     2 dscm per run.
                                                                       (7.5E-05 lb per
                                                                       MMBtu of heat
                                                                       input).
16. Units designed to burn light    a. CO...........................  130 ppm by volume on  1 hr minimum
 liquid fuel.                                                          a dry basis           sampling time.
                                                                       corrected to 3
                                                                       percent oxygen.
                                    b. Filterable PM (or TSM).......  1.3E-03 \a\ lb per    Collect a minimum of
                                                                       MMBtu of heat         3 dscm per run.
                                                                       input; or (2.9E-05
                                                                       lb per MMBtu of
                                                                       heat input).
17. Units designed to burn liquid   a. CO...........................  130 ppm by volume on  1 hr minimum
 fuel that are non-continental                                         a dry basis           sampling time.
 units.                                                                corrected to 3
                                                                       percent oxygen, 3-
                                                                       run average based
                                                                       on stack test.
                                    b. Filterable PM (or TSM).......  2.3E-02 lb per MMBtu  Collect a minimum of
                                                                       of heat input; or     4 dscm per run.
                                                                       (8.6E-04 lb per
                                                                       MMBtu of heat
                                                                       input).
18. Units designed to burn gas 2    a. CO...........................  130 ppm by volume on  1 hr minimum
 (other) gases.                                                        a dry basis           sampling time.
                                                                       corrected to 3
                                                                       percent oxygen.
                                    b. HCl..........................  1.7E-03 lb per MMBtu  For M26A, Collect a
                                                                       of heat input.        minimum of 2 dscm
                                                                                             per run; for M26,
                                                                                             collect a minimum
                                                                                             of 240 liters per
                                                                                             run.
                                    c. Mercury......................  7.9E-06 lb per MMBtu  For M29, collect a
                                                                       of heat input.        minimum of 3 dscm
                                                                                             per run; for M30A
                                                                                             or M30B, collect a
                                                                                             minimum sample as
                                                                                             specified in the
                                                                                             method; for ASTM
                                                                                             D6784 \b\ collect a
                                                                                             minimum of 3 dscm.
                                    d. Filterable PM (or TSM).......  6.7E-03 lb per MMBtu  Collect a minimum of
                                                                       of heat input; or     3 dscm per run.
                                                                       (2.1E-04 lb per
                                                                       MMBtu of heat
                                                                       input).
----------------------------------------------------------------------------------------------------------------
\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 below 75 percent of this limit in order to qualify for skip
  testing.
\b\ Incorporated by reference, see Sec.   63.14.

0
40. Add Table 13 to subpart DDDDD of part 63 to read as follows:

[[Page 7211]]

 Table 13 to Subpart DDDDD of Part 63--Alternative Emission Limits for New or Reconstructed Boilers and Process
   Heaters That Commenced Construction or Reconstruction After December 23, 2011, and Before January 31, 2013
----------------------------------------------------------------------------------------------------------------
                                                                       The emissions must
                                                                         not exceed the
                                                                       following emission   Using this specified
 If your boiler or process heater   For the following pollutants . .     limits, except      sampling volume or
   is in this subcategory . . .                     .                   during periods of    test run duration .
                                                                      startup and shutdown           . .
                                                                              . . .
----------------------------------------------------------------------------------------------------------------
1. Units in all subcategories       a. HCl..........................  0.022 lb per MMBtu    For M26A, collect a
 designed to burn solid fuel.                                          of heat input.        minimum of 1 dscm
                                                                                             per run; for M26
                                                                                             collect a minimum
                                                                                             of 120 liters per
                                                                                             run.
                                    b. Mercury......................  8.6E-07 \a\ lb per    For M29, collect a
                                                                       MMBtu of heat input.  minimum of 4 dscm
                                                                                             per run; for M30A
                                                                                             or M30B, collect a
                                                                                             minimum sample as
                                                                                             specified in the
                                                                                             method; for ASTM
                                                                                             D6784 \b\ collect a
                                                                                             minimum of 4 dscm.
2. Pulverized coal boilers          a. Carbon monoxide (CO) (or       130 ppm by volume on  1 hr minimum
 designed to burn coal/solid         CEMS).                            a dry basis           sampling time.
 fossil fuel.                                                          corrected to 3
                                                                       percent oxygen, 3-
                                                                       run average; or
                                                                       (320 ppm by volume
                                                                       on a dry basis
                                                                       corrected to 3
                                                                       percent oxygen, 30-
                                                                       day rolling
                                                                       average).
                                    b. Filterable PM (or TSM).......  1.1E-03 lb per MMBtu  Collect a minimum of
                                                                       of heat input; or     3 dscm per run.
                                                                       (2.8E-05 lb per
                                                                       MMBtu of heat
                                                                       input).
3. Stokers designed to burn coal/   a. CO (or CEMS).................  130 ppm by volume on  1 hr minimum
 solid fossil fuel.                                                    a dry basis           sampling time.
                                                                       corrected to 3
                                                                       percent oxygen, 3-
                                                                       run average; or
                                                                       (340 ppm by volume
                                                                       on a dry basis
                                                                       corrected to 3
                                                                       percent oxygen, 10-
                                                                       day rolling
                                                                       average).
                                    b. Filterable PM (or TSM).......  2.8E-02 lb per MMBtu  Collect a minimum of
                                                                       of heat input; or     2 dscm per run.
                                                                       (2.3E-05 lb per
                                                                       MMBtu of heat
                                                                       input).
4. Fluidized bed units designed to  a. CO (or CEMS).................  130 ppm by volume on  1 hr minimum
 burn coal/solid fossil fuel.                                          a dry basis           sampling time.
                                                                       corrected to 3
                                                                       percent oxygen, 3-
                                                                       run average; or
                                                                       (230 ppm by volume
                                                                       on a dry basis
                                                                       corrected to 3
                                                                       percent oxygen, 30-
                                                                       day rolling
                                                                       average).
                                    b. Filterable PM (or TSM).......  1.1E-03 lb per MMBtu  Collect a minimum of
                                                                       of heat input; or     3 dscm per run.
                                                                       (2.3E-05 lb per
                                                                       MMBtu of heat
                                                                       input).
5. Fluidized bed units with an      a. CO (or CEMS).................  140 ppm by volume on  1 hr minimum
 integrated heat exchanger                                             a dry basis           sampling time.
 designed to burn coal/solid                                           corrected to 3
 fossil fuel.                                                          percent oxygen, 3-
                                                                       run average; or
                                                                       (150 ppm by volume
                                                                       on a dry basis
                                                                       corrected to 3
                                                                       percent oxygen, 30-
                                                                       day rolling
                                                                       average).
                                    b. Filterable PM (or TSM).......  1.1E-03 lb per MMBtu  Collect a minimum of
                                                                       of heat input; or     3 dscm per run.
                                                                       (2.3E-05 lb per
                                                                       MMBtu of heat
                                                                       input).
6. Stokers/sloped grate/others      a. CO (or CEMS).................  620 ppm by volume on  1 hr minimum
 designed to burn wet biomass fuel.                                    a dry basis           sampling time.
                                                                       corrected to 3
                                                                       percent oxygen, 3-
                                                                       run average; or
                                                                       (410 ppm by volume
                                                                       on a dry basis
                                                                       corrected to 3
                                                                       percent oxygen, 10-
                                                                       day rolling
                                                                       average).
                                    b. Filterable PM (or TSM).......  3.0E-02 lb per MMBtu  Collect a minimum of
                                                                       of heat input; or     2 dscm per run.
                                                                       (2.6E-05 lb per
                                                                       MMBtu of heat
                                                                       input).
7. Stokers/sloped grate/others      a. CO...........................  460 ppm by volume on  1 hr minimum
 designed to burn kiln-dried                                           a dry basis           sampling time.
 biomass fuel.                                                         corrected to 3
                                                                       percent oxygen.
                                    b. Filterable PM (or TSM).......  3.2E-01 lb per MMBtu  Collect a minimum of
                                                                       of heat input; or     2 dscm per run.
                                                                       (4.0E-03 lb per
                                                                       MMBtu of heat
                                                                       input).
8. Fluidized bed units designed to  a. CO (or CEMS).................  230 ppm by volume on  1 hr minimum
 burn biomass/bio-based solids.                                        a dry basis           sampling time.
                                                                       corrected to 3
                                                                       percent oxygen, 3-
                                                                       run average; or
                                                                       (310 ppm by volume
                                                                       on a dry basis
                                                                       corrected to 3
                                                                       percent oxygen, 30-
                                                                       day rolling
                                                                       average).

[[Page 7212]]

 
                                    b. Filterable PM (or TSM).......  9.8E-03 lb per MMBtu  Collect a minimum of
                                                                       of heat input; or     3 dscm per run.
                                                                       (8.3E-05 \a\ lb per
                                                                       MMBtu of heat
                                                                       input).
9. Suspension burners designed to   a. CO (or CEMS).................  2,400 ppm by volume   1 hr minimum
 burn biomass/bio-based solids.                                        on a dry basis        sampling time.
                                                                       corrected to 3
                                                                       percent oxygen, 3-
                                                                       run average; or
                                                                       (2,000 ppm by
                                                                       volume on a dry
                                                                       basis corrected to
                                                                       3 percent oxygen,
                                                                       10-day rolling
                                                                       average).
                                    b. Filterable PM (or TSM).......  5.1E-02 lb per MMBtu  Collect a minimum of
                                                                       of heat input; or     2 dscm per run.
                                                                       (6.5E-03 lb per
                                                                       MMBtu of heat
                                                                       input).
10. Dutch Ovens/Pile burners        a. CO (or CEMS).................  810 ppm by volume on  1 hr minimum
 designed to burn biomass/bio-                                         a dry basis           sampling time.
 based solids.                                                         corrected to 3
                                                                       percent oxygen, 3-
                                                                       run average; or
                                                                       (520 ppm by volume
                                                                       on a dry basis
                                                                       corrected to 3
                                                                       percent oxygen, 10-
                                                                       day rolling
                                                                       average).
                                    b. Filterable PM (or TSM).......  3.6E-02 lb per MMBtu  Collect a minimum of
                                                                       of heat input; or     2 dscm per run.
                                                                       (3.9E-05 lb per
                                                                       MMBtu of heat
                                                                       input).
11. Fuel cell units designed to     a. CO...........................  910 ppm by volume on  1 hr minimum
 burn biomass/bio-based solids.                                        a dry basis           sampling time.
                                                                       corrected to 3
                                                                       percent oxygen.
                                    b. Filterable PM (or TSM).......  2.0E-02 lb per MMBtu  Collect a minimum of
                                                                       of heat input; or     2 dscm per run.
                                                                       (2.9E-05 lb per
                                                                       MMBtu of heat
                                                                       input).
12. Hybrid suspension grate boiler  a. CO (or CEMS).................  1,500 ppm by volume   1 hr minimum
 designed to burn biomass/bio-                                         on a dry basis        sampling time.
 based solids.                                                         corrected to 3
                                                                       percent oxygen, 3-
                                                                       run average; or
                                                                       (900 ppm by volume
                                                                       on a dry basis
                                                                       corrected to 3
                                                                       percent oxygen, 30-
                                                                       day rolling
                                                                       average).
                                    b. Filterable PM (or TSM).......  2.6E-02 lb per MMBtu  Collect a minimum of
                                                                       of heat input; or     3 dscm per run.
                                                                       (4.4E-04 lb per
                                                                       MMBtu of heat
                                                                       input).
13. Units designed to burn liquid   a. HCl..........................  1.2E-03 lb per MMBtu  For M26A: Collect a
 fuel.                                                                 of heat input.        minimum of 2 dscm
                                                                                             per run; for M26,
                                                                                             collect a minimum
                                                                                             of 240 liters per
                                                                                             run.
                                    b. Mercury......................  4.9E-07 \a\ lb per    For M29, collect a
                                                                       MMBtu of heat input.  minimum of 4 dscm
                                                                                             per run; for M30A
                                                                                             or M30B, collect a
                                                                                             minimum sample as
                                                                                             specified in the
                                                                                             method; for ASTM
                                                                                             D6784 \b\ collect a
                                                                                             minimum of 4 dscm.
14. Units designed to burn heavy    a. CO (or CEMS).................  130 ppm by volume on  1 hr minimum
 liquid fuel.                                                          a dry basis           sampling time.
                                                                       corrected to 3
                                                                       percent oxygen, 3-
                                                                       run average; or (18
                                                                       ppm by volume on a
                                                                       dry basis corrected
                                                                       to 3 percent
                                                                       oxygen, 10-day
                                                                       rolling average).
                                    b. Filterable PM (or TSM).......  1.3E-03 lb per MMBtu  Collect a minimum of
                                                                       of heat input; or     3 dscm per run.
                                                                       (7.5E-05 lb per
                                                                       MMBtu of heat
                                                                       input).
15. Units designed to burn light    a. CO (or CEMS).................  130 \a\ ppm by        1 hr minimum
 liquid fuel.                                                          volume on a dry       sampling time.
                                                                       basis corrected to
                                                                       3 percent oxygen;
                                                                       or (60 ppm by
                                                                       volume on a dry
                                                                       basis corrected to
                                                                       3 percent oxygen, 1-
                                                                       day block average)..
                                    b. Filterable PM (or TSM).......  1.1E-03 \a\ lb per    Collect a minimum of
                                                                       MMBtu of heat         3 dscm per run.
                                                                       input; or (2.9E-05
                                                                       lb per MMBtu of
                                                                       heat input).
16. Units designed to burn liquid   a. CO...........................  130 ppm by volume on  1 hr minimum
 fuel that are non-continental                                         a dry basis           sampling time.
 units.                                                                corrected to 3
                                                                       percent oxygen, 3-
                                                                       run average based
                                                                       on stack test; or
                                                                       (91 ppm by volume
                                                                       on a dry basis
                                                                       corrected to 3
                                                                       percent oxygen, 3-
                                                                       hour rolling
                                                                       average).

[[Page 7213]]

 
                                    b. Filterable PM (or TSM).......  2.3E-02 lb per MMBtu  Collect a minimum of
                                                                       of heat input; or     2 dscm per run.
                                                                       (8.6E-04 lb per
                                                                       MMBtu of heat
                                                                       input).
17. Units designed to burn gas 2    a. CO...........................  130 ppm by volume on  1 hr minimum
 (other) gases.                                                        a dry basis           sampling time.
                                                                       corrected to 3
                                                                       percent oxygen.
                                    b. HCl..........................  1.7E-03 lb per MMBtu  For M26A, Collect a
                                                                       of heat input.        minimum of 2 dscm
                                                                                             per run; for M26,
                                                                                             collect a minimum
                                                                                             of 240 liters per
                                                                                             run.
                                    c. Mercury......................  7.9E-06 lb per MMBtu  For M29, collect a
                                                                       of heat input.        minimum of 3 dscm
                                                                                             per run; for M30A
                                                                                             or M30B, collect a
                                                                                             minimum sample as
                                                                                             specified in the
                                                                                             method; for ASTM
                                                                                             D6784 \b\ collect a
                                                                                             minimum of 3 dscm.
                                    d. Filterable PM (or TSM).......  6.7E-03 lb per MMBtu  Collect a minimum of
                                                                       of heat input; or     3 dscm per run.
                                                                       (2.1E-04 lb per
                                                                       MMBtu of heat
                                                                       input).
----------------------------------------------------------------------------------------------------------------
\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 and you are not required
  to conduct testing for CEMS or CPMS monitor certification, 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 below 75 percent of this limit in order to qualify for skip testing.
\b\ Incorporated by reference, see Sec.   63.14.

[FR Doc. 2012-31646 Filed 1-30-13; 8:45 am]
BILLING CODE 6560-50-P
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