[Federal Register Volume 78, Number 21 (Thursday, January 31, 2013)]
[Rules and Regulations]
[Pages 7137-7213]
[FR Doc No: 2012-31646]

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

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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.

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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<PHONE_NUMBER>, and the telephone number for the
Air Docket is<PHONE_NUMBER>.

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<PHONE_NUMBER>; Email address:
<EMAIL_ADDRESS>
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

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?

    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
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              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

(``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

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.

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

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

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

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.''

    ``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

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

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

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

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.

    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

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

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.

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