[Federal Register: October 8, 2009 (Volume 74, Number 194)]
[Rules and Regulations]
[Page 51949-51985]
[DOCID:fr08oc09-15]

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Part II

Environmental Protection Agency

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40 CFR Part 60

Standards of Performance for Coal Preparation and Processing Plants;
Final Rule

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ENVIRONMENTAL PROTECTION AGENCY

40 CFR Part 60

[EPA-HQ-OAR-2008-0260; FRL-8965-3]
RIN 2060-AO57

Standards of Performance for Coal Preparation and Processing
Plants

AGENCY: Environmental Protection Agency (EPA).

ACTION: Final rule.

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SUMMARY: EPA is promulgating amendments to the new source performance
standards for coal preparation and processing plants. These final
amendments include revisions to the emission limits for particulate
matter and opacity standards for thermal dryers, pneumatic coal
cleaning equipment, and coal handling equipment (coal processing and
conveying equipment, coal storage systems, and coal transfer and
loading systems) located at coal preparation and processing plants.
These revised limits apply to affected facilities that commence
construction, modification, or reconstruction after April 28, 2008. The
amendments also establish a sulfur dioxide (SO2) emission
limit and a combined nitrogen oxide (NOX) and carbon
monoxide (CO) emissions limit for thermal dryers located at coal
preparation and processing plants. In addition, the amendments
establish work practice standards to control fugitive coal dust
emissions from open storage piles located at coal preparation and
processing plants. The SO2 limit, the NOX/CO
limit, and the work practice standards apply to affected facilities
that commence construction, modification, or reconstruction of which
commences after May 27, 2009. We are also modifying the definition of
thermal dryer to include both direct contact and indirect contact
thermal dryers drying all coal ranks. We are modifying the definition
of pneumatic coal-cleaning equipment to include equipment cleaning all
coal ranks. We are also amending the definition of coal for purposes of
subpart Y to include coal refuse. The modified definitions of thermal
dryer, pneumatic coal cleaning equipment, and coal will be used to
determine whether and how the standards apply to facilities that
commence construction, modification, or reconstruction after May 27,
2009.

DATES: This final rule is effective on October 8, 2009. The
incorporation by reference of certain publications listed in the
regulation is approved by the Director of the Federal Register as of
October 8, 2009.

ADDRESSES: EPA has established a docket for this action which is Docket
ID No. EPA-HQ-OAR-2008-0260. All documents in the docket are listed in
the http://www.regulations.gov index. Certain other material, such as
copyrighted material, will be publicly available only in hard copy.
Publicly available docket materials are available either electronically
in http://www.regulations.gov or in hard copy at the EPA Docket Center,
Standards of Performance for Coal Preparation and Processing Plants
Docket, EPA West, Room 3334, 1301 Constitution Ave., NW., Washington,
DC. The Public Reading Room is open from 8:30 a.m. to 4:30 p.m., Monday
through Friday, excluding legal holidays. The telephone number for the
Public Reading Room is<PHONE_NUMBER>, and the telephone number for the
Docket Center is<PHONE_NUMBER>.

FOR FURTHER INFORMATION CONTACT: Ms. Mary Johnson, Energy Strategies
Group, Sector Policies and Programs Division (D243-01), U.S. EPA,
Research Triangle Park, NC 27711, telephone number<PHONE_NUMBER>,
facsimile number<PHONE_NUMBER>, electronic mail (e-mail) address:
<EMAIL_ADDRESS>
SUPPLEMENTARY INFORMATION: The supplementary 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 on Subpart Y
III. Summary of the Final Amendments to Subpart Y and Changes Since
Proposal
    A. Affected Facilities
    B. Emission Limits
    C. Emissions Testing and Monitoring Requirements
    D. Opacity Testing and Monitoring Requirements
    E. Recordkeeping and Reporting Requirements
    F. Electronic Reporting
    G. Additional Amendments
IV. Summary of Significant Comments and Responses
    A. Regulated Pollutants
    B. Applicability and Definitions
    C. Subcategorization
    D. Coal Drying Standards
    E. Coal Processing and Conveying Equipment, Coal Storage
Systems, Transfer and Loading Systems, and Open Storage Piles
Standards
    F. Testing and Monitoring Requirements
    G. Recordkeeping and Reporting Requirements
    H. Assessment of Impacts
V. Summary of Cost, Environmental, Energy, and Economic Impacts
    A. What Are the Primary Air Impacts?
    B. What Are the Water and Solid Waste Impacts?
    C. What Are the Energy Impacts?
    D. What Are the Secondary Air Impacts?
    E. What Are the Cost and Economic Impacts?
VI. Statutory and Executive Order Reviews
    A. Executive Order 12866: Regulatory Planning and 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 and Safety Risks
    H. Executive Order 13211: Actions Concerning Regulations That
Significantly Affect Energy Supply, Distribution, or Use
    I. National Technology Transfer 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?

    Categories and entities potentially regulated by the final
amendments to New Source Performance Standards (NSPS) for Coal
Preparation and Processing Plants (40 CFR part 60, subpart Y) include:

------------------------------------------------------------------------
                                                   Examples of regulated
           Category               NAICS code \1\          entities
------------------------------------------------------------------------
Industry......................  212111...........  Bituminous Coal and
                                                    Lignite Surface
                                                    Mining.
                                212112...........  Bituminous Coal
                                                    Underground Mining.
                                221112...........  Fossil Fuel Electric
                                                    Power Generation.
                                212113...........  Anthracite Mining.
                                213113...........  Support Activities
                                                    for Coal Mining.
                                322121...........  Paper (except
                                                    Newsprint) Mills.
                                324199...........  All other petroleum
                                                    and coal products
                                                    manufacturing.
                                325110...........  Petrochemical
                                                    Manufacturing.

                                327310...........  Cement Manufacturing.
                                331111...........  Iron and Steel Mills.
Federal Government............  22112............  Fossil fuel-fired
                                                    electric utility
                                                    steam generating
                                                    units owned by the
                                                    Federal Government.
State/local/Tribal government.  22112............  Fossil fuel-fired
                                                    electric utility
                                                    steam generating
                                                    units owned by
                                                    municipalities.
                                921150...........  Fossil fuel-fired
                                                    electric steam
                                                    generating units in
                                                    Indian Country.
------------------------------------------------------------------------
\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
final action. To determine whether your facility would be regulated by
this final action, you should examine the applicability criteria in 40
CFR 60.250 and definitions in Sec.  60.251 (subpart Y). If you have any
questions regarding the applicability of this final action to a
particular entity, contact the person listed in the preceding FOR
FURTHER INFORMATION CONTACT section.

B. Where Can I Get a Copy of This Document?

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

C. Judicial Review

    Under section 307(b)(1) of the Clean Air Act (CAA), judicial review
of this final rule is available only by filing a petition for review in
the United States Court of Appeals for the District of Columbia Circuit
by December 7, 2009. Under section 307(b)(2) of the CAA, the
requirements established by this final rule may not be challenged
separately in any civil or criminal proceedings brought by EPA to
enforce these requirements.
    Section 307(d)(7)(B) of the CAA further provides 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.'' This section also
provides a mechanism for us to convene a proceeding for
reconsideration, ``[i]f the person raising an objection can demonstrate
to EPA that it was impracticable to raise such objection within [the
period for public comment] 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.'' Any person seeking to make such a demonstration
to us should submit a Petition for Reconsideration to the Office of the
Administrator, U.S. EPA, Room 3000, Ariel Rios Building, 1200
Pennsylvania Ave., NW., Washington, DC 20460, with a copy to both the
person(s) listed in the preceding FOR FURTHER INFORMATION CONTACT
section, and the Associate General Counsel for the Air and Radiation
Law Office, Office of General Counsel (Mail Code 2344A), U.S. EPA, 1200
Pennsylvania Ave., NW., Washington, DC 20460.

II. Background Information on Subpart Y

    NSPS implement CAA section 111(b) and are issued for categories of
sources which have been identified as causing, or contributing
significantly to, air pollution which may reasonably be anticipated to
endanger public health or welfare. The primary purpose of the NSPS are
to help States attain and maintain ambient air quality by ensuring that
the best demonstrated emission control technologies are installed as
the industrial infrastructure is modernized. Since 1970, the NSPS have
been successful in achieving long-term emissions reductions in numerous
industries by assuring cost-effective controls are installed on new,
reconstructed, and modified sources.
    CAA section 111 requires that the NSPS reflect the degree of
emission limitation achievable through application of the best system
of emissions reductions which (taking into consideration the cost of
achieving such emissions reductions, any non-air quality health and
environmental impact and energy requirements) the Administrator
determines has been adequately demonstrated. This level of control is
commonly referred to as best demonstrated technology (BDT). Standards
of performance for coal preparation plants (40 CFR part 60, subpart Y)
were promulgated in the Federal Register on January 15, 1976 (41 FR
2232). The standards are applicable to facilities which process more
than 181 megagrams (Mg) (200 tons) of coal per day that commenced
construction, reconstruction, or modification after October 24, 1974.
    CAA section 111(b)(1)(B) requires EPA to periodically review and
revise the standards of performance, as necessary, to reflect
improvements in methods for reducing emissions. The first review of the
coal preparation plants NSPS was completed on April 14, 1981 (46 FR
21769). The second review of the coal preparation plants NSPS was
completed on April 3, 1989 (54 FR 13384). EPA did not make changes to
the NSPS as a result of either review.
    We proposed amendments to the coal preparation plants NSPS on April
28, 2008 (73 FR 22901) as a result of the current review. We received a
total of 42 comments from coal preparation plants, industry trade
associations, control technology vendors, environmental groups, and
State environmental agencies during the comment period. After reviewing
those comments and considering additional data, EPA decided to publish
a supplemental proposal which revised some of the emission limits and
monitoring requirements proposed on April 28, 2008, added additional
limits, and applied the requirements to additional affected facilities.
The supplemental action was proposed on May 27, 2009 (74 FR 25304). A
total of 44 comments were received from coal preparation plants, other
types of industrial facilities, industry associations, environmental
groups, and State environmental agencies. This final rule reflects our
consideration of all the comments we received regarding the April 2008
and May 2009 proposals. Detailed responses to the comments not included
in this preamble are contained in the Summary of Public Comments and
Responses document which is included in the docket for this rulemaking.

III. Summary of the Final Amendments to Subpart Y and Changes Since
Proposal

A. Affected Facilities

    Subpart Y regulates affected facilities located at coal preparation
and processing plants which process more than 181 megagrams (Mg) (200
tons) of coal per day. A coal preparation and processing plant begins
at the first hopper (i.e., drop point) used to unload coal and ends at
the load-out (i.e., distribution) of the coal either to a method of
transportation (e.g., truck, train) or to the end-use piece of
equipment (e.g., boiler).
    The affected facilities regulated by this final rule are thermal
dryers, pneumatic coal-cleaning equipment, coal processing and
conveying equipment (including breakers and crushers), coal storage
systems, transfer and loading systems, and open storage piles. This
final rule expands applicability of the existing NSPS by revising the
definitions of thermal dryers, pneumatic coal-cleaning equipment, and
coal. It also establishes work practice standards for open storage
piles. The final rule amends the definition of thermal dryer for units
constructed, reconstructed, or modified after May 27, 2009, to include
both direct and indirect dryers drying all coal ranks (i.e.,
bituminous, subbituminous, lignite, and anthracite coals) and coal
refuse. The final rule regulates emissions of SO2 and
NOX/CO only from thermal dryers that receive thermal input
from the combustion of coal, coal refuse, or residual oil; PM and
opacity are regulated from all thermal dryers.
    The emissions standards for thermal dryers apply to emissions from
the heat source for an indirect thermal dryer only if those emissions
are not otherwise regulated under another NSPS. Indirect thermal dryers
use a heat transfer medium to supply heat and blow air over the coal to
evaporate the water. If the source of heat (the source of combustion or
furnace) is subject to another subpart of Part 60, then the furnace and
the associated emissions are not considered part of the subpart Y
affected facility (i.e., the thermal dryer). However, if the source of
heat is not subject to another subpart of Part 60, then the furnace and
the associated emissions are part of the subpart Y affected facility.
In situations where the source of heat is part of the affected facility
and its exhaust is combined with the dryer exhaust in a single stack,
the combined exhaust is subject to all subpart Y requirements
applicable to the thermal dryer exhaust. However, in situations where
the furnace is part of the affected facility and its exhaust is not
combined with the dryer exhaust, the subpart Y requirements for thermal
dryers apply differently to the dryer exhaust and the combustion (i.e.,
heat source or furnace) exhaust. All of the thermal dryer requirements
of subpart Y apply to the combustion exhaust, whereas, only a subset of
the subpart Y requirements for thermal dryers apply to the dryer
exhaust. In addition, thermal dryers that use residual or waste heat
from the combustion of coal, coal refuse, or residual oil, or that
obtain all of their thermal input from gaseous fuels (e.g., blast
furnace gas, coke oven gas, natural gas) or distillate oil also are
only be subject to certain subset of the subpart Y requirements for
thermal dryers.
    Further, a thermal dryer that is part of an in-line coal mill at a
Portland cement manufacturing plant where all of the thermal input is
supplied by cement kiln exhaust or clinker cooler exhaust, is not
subject to the requirements in subpart Y, but, rather, must meet the
applicable requirements in the appropriate Portland Cement kiln
regulations (40 CFR 60 subpart F and 40 CFR 63 subpart LLL). The
amended subpart Y emissions limits for thermal dryers apply to new,
reconstructed, or modified thermal dryers at Portland cement
manufacturing plants in situations where the thermal input is not
supplied by cement kiln or clinker cooler exhaust. Other subpart Y
affected facilities located at Portland cement manufacturing plants
(e.g., storage systems, conveyors) are also subject to the requirements
of subpart Y. Similarly, a coal thermal dryer at an integrated iron or
steel manufacturing plant where all of the thermal input is provided by
process gases is not regulated under subpart Y, but, rather, under 40
CFR part 60 standards for integrated iron and steel manufacturing
plants. Again, the amended emissions limits apply to new,
reconstructed, or modified thermal dryers at integrated iron and steel
manufacturing plants only in situations where the thermal input is not
supplied by process gases. Other subpart Y affected facilities located
at integrated iron and steel manufacturing plants also are subject to
subpart Y. If an affected facility under subpart Y uses waste-heat or
process gases from a process that is subject to emission limits under
another NSPS or national emission standard for hazardous air pollutant
(NESHAP), the process using the waste-heat or process gases is not
subject to requirements under subpart Y, but, rather, is subject to the
other applicable NSPS or NESHAP.
    This final rule also amends the definition of pneumatic coal-
cleaning equipment for units constructed after May 27, 2009, to include
pneumatic coal-cleaning equipment cleaning all coal ranks. Finally, the
final rule establishes work practice standards that apply to open
storage coal piles constructed, reconstructed or modified after May 27,
2009.

B. Emission Limits

    This action promulgates emission limits applicable to certain
thermal dryers constructed, reconstructed, or modified after April 28,
2008. It also promulgates emission limits for additional pollutants
applicable to certain thermal dryers constructed, reconstructed, or
modified after May 27, 2009.
    Direct-contact thermal dryers that use coal, coal refuse, or
residual oil as the dryer heat source and are constructed,
reconstructed, or modified after April 28, 2008, are subject to
emission limits for PM and opacity. Indirect thermal dryers
constructed, reconstructed, or modified after May 27, 2009, are subject
to the same PM and opacity limits as direct-contact thermal dryers.
Both direct-contact thermal dryers and indirect thermal dryers
constructed, reconstructed, or modified after May 27, 2009, are subject
to an SO2 emission limit and a combined NOX-CO
emissions limit. In certain instances, thermal dryers are not subject
to the SO2 and/or NOX-CO emission limits. Thermal
dryers constructed, reconstructed or modified after May 27, 2009, for
which all of the thermal input is supplied from a source other than
coal, coal refuse, or residual oil (i.e., thermal input is from gaseous
fuels such as blast furnace gas, coke oven gas, or natural gas, or
distillate oil) are not subject to SO2 or NOX-CO
emission limits. Indirect thermal dryers constructed, reconstructed, or
modified after May 27, 2009, that use residual or waste heat from the
combustion of coal, coal refuse, or residual oil also are not subject
to the emission limits for SO2 or NOX-CO.
    Indirect thermal dryers that receive all of their thermal input
from a source subject to an SO2 limit, or NOX
and/or CO limit, under another Part 60 NSPS are not subject to emission
limits under subpart Y for those pollutants (e.g., indirect thermal
dryers for which the source of heat is subject to a boiler NSPS
(subpart Da, Db, or Dc)). In that instance, the furnace (i.e., source
of thermal input) and the associated emissions are not considered part
of the subpart Y thermal dryer facility. However, if the source of heat
is not

subject to another Part 60 NSPS, then the furnace and the associated
emissions are part of the subpart Y thermal dryer facility. In the
instance where the furnace is part of the affected facility and its
exhaust is combined with the thermal dryer exhaust, the combined
exhaust contains all of the applicable pollutants (i.e., PM, opacity,
SO2, NOX, and CO) and all of the subpart Y
requirements regarding those emissions from thermal dryers apply.
However, in the instance where the furnace is part of the affected
facility, but its exhaust is not combined with the dryer exhaust, the
furnace exhaust and dryer exhaust are subject to different
requirements. The furnace exhaust is subject to emission limits for PM,
opacity, SO2, and NOX-CO. The dryer exhaust,
however, is only subject to the PM and opacity limits because the
exhaust does not contain SO2, NO, and CO.
1. PM and Opacity Limits for Thermal Dryers
    Thermal dryers constructed, reconstructed, or modified after April
28, 2008, are subject to emission limits for PM and opacity. The PM and
opacity limits in the final rule for new thermal dryers are the same as
those proposed in May 2009. EPA determined that thermal dryers
undergoing reconstruction could undergo the conversions necessary to
also comply with the PM and opacity limits that reflect BDT for new
thermal dryers (i.e., fabric filter-controlled recirculation thermal
dryers and fabric filter-controlled indirect thermal dryers). Thus, the
final rule subjects new and reconstructed thermal dryers to a PM limit
of 0.023 grams per dry standard cubic meter (g/dscm)(0.010 grains per
dry standard cubic foot (gr/dscf)) and an opacity limit of less than 10
percent. The final rule requires modified thermal dryers to continue to
comply with the 1976 rule's PM limit of 0.070 g/dscm (0.031 gr/dscf)
and the 1976 rule's opacity limit of less than 20 percent. These limits
can be achieved using the technology that EPA determined constitutes
BDT for modified thermal dryers (i.e., venturi scrubbers).
2. SO2, NOX, and CO Limits for Thermal Dryers
    Thermal dryers constructed, reconstructed, or modified after May
27, 2009, must either limit their SO2 emissions to 85
nanograms per Joule (ng/J) (0.20 pounds per million British thermal
units (lb/MMBtu)), or achieve a 90 percent reduction of potential
SO2 emissions and limit their SO2 emissions to no
more than 520 ng/J (1.2 lb/MMBtu). The percent reduction requirement
has been revised from the 50 percent requirement proposed in May 2009
to 90 percent in the final rule. In the May 27, 2009, supplemental
proposal, EPA concluded that dry sorbent injection into the thermal
dryer and spraying caustic onto the coal prior to the thermal dryer
were both BDT for SO2 reduction (74 FR 25310). We also
indicated that we were considering an SO2 percent reduction
requirement of between 50 and 90 percent for the final rule (74 FR
25311). We have reassessed the available SO2 data and
believe that the limits established in the final rule are appropriate
for new, reconstructed, and modified thermal dryers. Based on our
reassessment, we determined that BDT for modified and reconstructed
thermal dryers is a wet scrubber with a scrubbing reagent (e.g., an
upgraded venturi scrubber with sodium hydroxide or packed bed scrubber
with lime). For new thermal dryers, we determined that BDT for
controlling SO2 emissions is the injection of sodium
hydroxide directly to the venturi scrubber fluid or injection of a
sodium-based sorbent into the combustion gases prior to the drying
chamber. All three of these technologies are capable of achieving 90
percent SO2 reduction.
    In the May 27, 2009, supplemental proposal, EPA determined that BDT
for controlling NOX emissions from new, reconstructed, and
modified thermal dryers is combustion controls (e.g., low
NOX burners, staged combustion, co-firing with natural gas
or liquefied petroleum gas, and flue gas recirculation). BDT for
controlling CO emissions was determined to be good combustion practices
(e.g., ensuring that there is sufficient oxygen in the combustion zone,
maintaining appropriate combustion zone temperature and gas residence
time, and conducting proper operation and maintenance of the dryer).
For affected thermal dryers that commence construction, reconstruction,
or modification after May 27, 2009, the final NOX-CO
emissions limits are the same as those proposed in May 2009.
Reconstructed and modified thermal dryers are required to comply with a
combined NOX-CO limit of 430 ng/J (1.0 lb/MMBtu). New
thermal dryers are required to comply with a NOX-CO limit of
280 ng/J (0.65 lb/MMBtu).
3. PM and Opacity Limits for Pneumatic Coal-Cleaning Equipment, Coal
Processing and Conveying Equipment, Coal Storage Systems, Transfer and
Loading Systems, and Open Storage Piles
    The PM and opacity limits in the final rule for pneumatic coal-
cleaning equipment are the same as those proposed in the May 2009
supplemental proposal. Pneumatic coal-cleaning equipment, cleaning all
coal ranks, constructed, reconstructed, or modified after April 28,
2008, must comply with a PM limit of 0.023 g/dscm (0.010 gr/dscf) and
an opacity limit of equal to or less than 5 percent.
    For affected coal-handling equipment (coal processing and conveying
equipment (including breakers and crushers), coal storage systems, and
transfer and loading systems) constructed, reconstructed, or modified
after April 28, 2008, that is mechanically vented to the atmosphere,
the final rule requires compliance with the PM limit that was proposed
in May 2009. That is, mechanically vented coal-handling equipment
constructed, reconstructed, or modified after April 28, 2008, must
comply with a PM limit of 0.023 g/dscm (0.010 gr/dscf). The final rule
also requires affected coal handling equipment constructed,
reconstructed, or modified after April 28, 2008, to maintain opacity
levels of less than 10 percent. In the May 27, 2009, supplemental
proposal, EPA requested comment on whether an opacity limit of less
than 10 percent is more appropriate than a limit of 5 percent as
proposed in the supplemental action. We also requested comment on
whether the 5 percent limit is achievable on a long-term basis and
whether the limit provides an adequate compliance margin. As we pointed
out in supporting documentation (see EPA-HQ-OAR-2008-0260-0083, pp. 3-
4), the data used to establish the supplemental proposal's 5 percent
opacity level were primarily from initial compliance tests. Upon
reconsideration of EPA's data and consideration of public comments and
additional supporting data, EPA has determined that an opacity limit of
less than 10 percent is more appropriate for all coal handling
equipment. An opacity limit of 10 percent will allow for control
equipment degradation, adverse conditions, and variability that would
not be reflected in initial compliance tests. Although we modified our
conclusion regarding the opacity limit achievable by the application of
BDT, we did not modify our prior conclusions regarding BDT for coal-
handling

equipment. BDT for coal-handling equipment used on subbituminous and
lignite coals consists of four technologies--fabric filters, passive
enclosure containment systems (PECS), fogging systems, and wet
extraction scrubbers. BDT for coal-handling equipment processing
bituminous coal is the use of chemical suppressants. All of these
emissions reduction measures can control PM emissions equally well. See
EPA-HQ-OAR-2008-0260-0083, pp. 1-2.
    EPA also concluded that if a building in which affected coal
processing and conveying equipment (e.g., breakers, crushers, screens,
conveying systems), coal storage systems, and transfer system
operations are enclosed is found to be in compliance with the subpart Y
limits that apply to the affected facilities enclosed in the building,
the affected facilities enclosed in that building also are in
compliance. Thus, the final rule provides that buildings containing
coal processing and conveying equipment, coal storage systems, and
transfer system operations constructed, reconstructed, or modified on
or before April 28, 2008, must not exhibit 20 percent opacity or
greater. Fugitive emissions from buildings that enclose coal processing
and conveying equipment, coal storage systems, and coal transfer system
operations constructed, reconstructed, or modified after April 28,
2008, must not exhibit opacity of 10 percent or more. For buildings
enclosing coal processing and conveying equipment, coal storage
systems, and transfer system operations constructed, reconstructed, or
modified after April 28, 2008, that discharge emissions from a
mechanical vent, emissions must not contain PM in excess of 0.023 g/
dscm (0.010 gr/dscf).
4. Open Storage Pile Requirements
    EPA's May 27, 2009, supplemental action proposed to establish work
practice standards for open storage piles and roadways. EPA determined
that it was not feasible to establish opacity or PM limits for these
types of affected facilities. At the current time, EPA believes it is
difficult and prohibitively expensive to measure actual PM emissions
from individual open storage piles or roadways. Further, the size of
open storage piles and the mobile nature of coal dust from vehicle
tires on roadways currently make the use of Method 9 opacity
observations unreasonable in many situations. Based on that
determination, we proposed to require owners or operators of open
storage piles and roadways associated with coal preparation plants to
develop and comply with a fugitive coal dust emissions control plan to
control fugitive PM emissions. Commenters pointed out that the Surface
Mining Control and Reclamation Act (SMCRA) covers fugitive dust
emissions from roads at coal preparation and processing plants at mine
sites and requires a fugitive dust plan. EPA believes that coal moving
operations, once the coal enters the ``coal preparation plant,'' will
be by conveyor rather than by truck. Therefore, we believe that the
requirements of SMCRA are sufficient to address air emissions from
roadways that may be found within a coal preparation and processing
plant at mine sites. For coal preparation and processing plants at end-
user facilities, we believe that, again, once the coal enters the
``coal preparation plant,'' coal moving operations will be by conveyor
rather than by truck. Thus, EPA has decided not to finalize the
proposed requirements for roadways. EPA also proposed to require that
the fugitive coal dust emissions control plan include procedures for
limiting emissions from all types of ``coal processing and conveying
equipment'' at a coal preparation and processing plant. EPA agrees with
commenters that subpart Y should specifically designate each type of
affected facility subject to the fugitive dust emissions control plan
and, therefore, we are not finalizing that proposed requirement.
    A fugitive coal dust emissions control plan is required for open
storage piles, which include the equipment used in the loading,
unloading and conveying operations of the affected facility,
constructed, reconstructed or modified after May 27, 2009. The owner or
operator is required to prepare and operate in accordance with a
submitted fugitive coal dust emissions control plan that is appropriate
for the site conditions. The fugitive coal dust emissions control plan
must identify and describe the control measures the owner/operator will
use to minimize fugitive coal dust emissions from each open storage
pile. The owner or operator is also required to explain how the
measures are applicable and appropriate for the site conditions. For
open coal storage piles, the fugitive coal dust emissions plan must
require that one or more of the following control measures will be used
to minimize to the greatest extent practicable fugitive coal dust:
locating the source inside a partial enclosure, installing and
operating a water spray or fogging system, applying appropriate
chemical dust suppression agents on the source (when additional
provisions discussed below are met), use of a wind barrier, compaction,
or use of a vegetative cover. The owner or operator must select, from
the list provided, the control measures that are most appropriate for
the site conditions. Where appropriate chemical dust suppression agents
are selected by the owner/operator as a control measure to minimize
fugitive coal dust emissions, only chemical dust suppressants with
Occupational Safety and Health Administration (OSHA)-compliant material
safety data sheets (MSDS) are allowed, the MSDS must be included in the
fugitive coal dust emissions control plan, and the owner/operator must
consider and document in the fugitive coal dust emissions control plan
the site-specific impacts associated with the use of such chemical dust
suppressants (e.g., water run-off, water quality concerns).
    An owner/operator may petition the Administrator requesting
approval of a control measure other than those specified above. The
petition process established in the final rule is similar to the
process used in 40 CFR Part 60, subpart Db, to establish alternative
NOX limits for certain industrial boilers. The petition must
demonstrate to the Administrator that the alternate control measure
will provide equivalent overall environmental protection or that it is
either economically or technically infeasible for the affected facility
to use the control measures specified above. The owner/operator must
operate in accordance with the plan including the alternative measures
and, while operating in accordance with the plan submitted with the
petition, is deemed to be in compliance with the fugitive coal dust
emissions control plan requirements while the petition is pending. EPA
decided to include this petition process in the final rule in response
to comments objecting to provisions proposed in the May 2009
supplemental proposal that would have provided for permitting authority
approval of the fugitive coal dust emissions control plans and allowed
the permitting authorities to approve the use of alternate technologies
if it had been determined that the technology provides equivalent
overall environmental protection.
    Each owner/operator must submit their fugitive coal dust emissions
control plan to the Administrator or delegated authority to provide an
opportunity for the Administrator or delegated authority to object to
the fugitive coal dust emissions control plan. The fugitive coal dust
emissions control plan must be submitted to the Administrator or
delegated authority prior to the startup date for the affected
facility. If an objection is raised, the

owner/operator has 30 days from receipt of the objection to submit a
revised fugitive coal dust emissions control plan. The owner/operator
must operate in accordance with the revised fugitive coal dust
emissions control plan. The Administrator and delegated authority
retain the ability to object to the revised fugitive coal dust
emissions control plan.

C. Emissions Testing and Monitoring Requirements

    Based on our review of public comments submitted in response to the
May 27, 2009, supplemental proposal and further analysis, minor
revisions were made to certain emissions testing and monitoring
requirements included in that supplemental proposal. The testing and
monitoring requirements of the final rule are described below. All
affected facilities subject to emissions limits are required to conduct
initial emissions testing to show compliance with the limits included
in the final rule. PM emissions must be measured with EPA Method 5, 5B,
or 5D of 40 CFR Part 60, appendix A-4, or EPA Method 17 of 40 CFR Part
60, appendix A-7. EPA Method 6, 6A, or 6C of 40 CFR Part 60, appendix
A-4, must be used to measure SO2 emissions. NOX
and CO emissions must be measured with EPA Method 7 or 7E, and Method
10, respectively, of 40 CFR Part 60, appendix A-4. In addition, CO and
NOX performance testing must be conducted concurrently, or
within a 60-minute period. Initial testing for PM emissions is required
for coal-handling equipment exhaust that is mechanically vented and for
thermal dryer exhaust. Depending on the type of thermal dryer and its
fuel type, initial testing for SO2, NOX, and CO
may also be required. Following initial performance testing, the
frequency of subsequent emissions testing is variable. If an affected
facility, excluding thermal dryers, has a design controlled potential
PM emissions rate, considering controls, of 1.0 Mg (1.1 tons) per year
or less, annual performance testing is not required as long as: (1) PM
emissions, as determined by the initial performance test, are less than
or equal to the applicable PM limit; (2) the manufacturer's recommended
maintenance procedures for each control device are followed; and (3)
all 6-minute average opacity readings from the most recent Method 9
performance test are equal to or less than half the applicable opacity
limit.
    In addition, for similar, separate affected facilities using
identical control equipment, the Administrator or delegated authority
may authorize a single emissions test as adequate demonstration for up
to four other similar, separate affected facilities as long as: (1) The
most recent performance test for each affected facility shows that
performance of each affected facility is 90 percent or less of the
applicable emissions limit; (2) the manufacturer's recommended
maintenance procedures for each control device are followed; and (3)
each affected facility conducts a performance test for each pollutant
for which they are subject to a limit at least once every 5 years.
Affected facilities that, based on their most recent performance test,
emit at a level that is 50 percent or less of an applicable emissions
limit are only required to conduct performance testing every 24 months,
as opposed to every 12 months. Finally, an owner/operator of an
affected facility that has not operated for the 60 calendar days prior
to the due date of a performance test is not required to perform the
performance test until 30 calendar days after the next operating day.
    The final rule requires the use of bag leak detection systems on
subpart Y affected facilities with fabric filters that have a design
controlled potential PM emissions rate of 25 Mg (28 tons) or more. This
requirement applies to affected facilities constructed, reconstructed,
or modified after April 28, 2008. For affected facilities with venturi
scrubbers, continuous measurement of the pressure loss through the
venturi constriction of the scrubber and of the liquid flow rate to the
scrubber is required. If the venturi scrubber is used to control
SO2 emissions, pH of the scrubber liquor also must be
continuously measured. For affected facilities using packed bed
scrubbers with the addition of lime, the liquid flow rate to the
scrubber and the scrubber liquor pH must be continuously measured. The
final rule does not require continuous measurement of the temperature
of the gas stream at the exit of the thermal dryer for affected
facilities constructed, reconstructed, or modified after April 28,
2008. In the supplemental proposal, EPA requested comment on the
utility of collecting continuous temperature data and determined that
the requirement can be eliminated without risk of a significant
increase in emissions.

D. Opacity Testing and Monitoring Requirements

    Numerous comments were submitted to EPA regarding the opacity
testing and monitoring requirements included in the May 27, 2009,
supplemental proposal. Commenters objected to the proposed procedures
as being unreasonable, burdensome, too complex, and confusing. Based on
our review of public comments and further analysis, we modified the
proposed requirements where we determined the burden could be reduced
without compromising the integrity of the overall testing and
monitoring requirements. We also attempted to make the requirements in
the final rule less complex than those included in the supplemental
proposal. All affected facilities subject to emissions limits are
required to conduct initial emissions testing to show compliance with
the opacity limits included in the final rule. Opacity must be measured
with EPA Method 9 of 40 CFR part 60, appendix A-4. The final rule
allows the use of a continuous opacity monitoring system (COMS) as an
alternative to all other opacity monitoring requirements. The final
rule includes a 60-minute observation period for Method 9 performance
testing. The observation period may be decreased from 60 minutes to 30
minutes if, during the initial 30 minutes of the observation of a
Method 9 performance test, all the 6-minute averages are less than or
equal to half the applicable opacity limit. In the final rule, the
frequency of subsequent visible emissions testing is based on the 6-
minute average opacity readings from the most recent performance test.
Owners/operators of affected facilities where any 6-minute average
opacity reading in the most recent Method 9 performance test exceeds
half the applicable opacity limit are required to conduct a Method 9
performance test within 90 days of the previous performance test.
Owners/operators of affected facilities where all 6-minute average
opacity readings in the most recent Method 9 performance test are equal
to or less than half the applicable opacity limit are required to
conduct a Method 9 performance test within 12 months of the previous
performance test. Further, if a Method 9 opacity performance test is
conducted concurrently with (or within a 60-minute period of) a Method
5, 5B, or 5D PM performance test for affected sources with wet
scrubbers that continuously monitor the specified scrubber parameters,
no subsequent Method 9 opacity performance testing is required. The
final rule allows simultaneous Method 9 opacity performance testing for
up to three emissions points as long as all three emissions points are
within a 70-degree viewing sector or angle in front of the observer
such that the proper sun position can be maintained

for all three points. If an opacity reading for any one of the three
emissions points is within 5 percent opacity from the applicable
standard (excluding readings of zero opacity), the observer must stop
taking readings for the other two points and continue reading just that
single point.
    As an alternative to subsequent Method 9 performance testing, the
final rule allows owners/operators of affected facilities to elect to
conduct monitoring as follows: (1) Monthly visual observations of
process and control equipment must be conducted and, if any
deficiencies are observed, the necessary maintenance must be performed
as expeditiously as possible; and (2) daily walkthrough observations
consisting of a single 15-second observation (i.e., visible emissions
or no visible emissions) of each affected facility must be conducted
and, if any visible emissions are observed, within 24 hours corrective
actions must be conducted and the owner/operator must demonstrate that
there are no visible emissions. If visible emissions are still
observed, a Method 9 performance test must be conducted within 45
operating days to show compliance with the applicable opacity limit.
The final rule requires that Method 9 performance testing must be
conducted at least once every 5 years for each affected facility
complying with this alternative monitoring option. Each observer
determining the presence of visible emissions is required to meet the
training requirements of Method 22 of appendix A-7 of 40 CFR Part 60.
The final rule also allows the use of a digital opacity monitoring
system in lieu of subsequent Method 9 performance testing. The
Administrator may approve opacity monitoring plans for owners/operators
that elect to use the digital opacity monitoring system to detect the
presence of visible emissions.
    The final rule includes separate opacity testing and monitoring
requirements for coal truck dump operations. EPA determined that a
different approach for Method 9 opacity performance testing is
warranted due to the intermittent nature of coal truck dumping. Coal
truck dump operations are subject to the same opacity limits as other
coal handling operations. The final rule specifies that compliance with
the opacity limit is determined by averaging all Method 9 15-second
opacity readings made during the duration of three separate truck dump
events. A truck dump event commences when the truck bed begins to
elevate and concludes when the truck bed returns to a horizontal
position. The final rule requires monthly visual observations of the
truck dump equipment and, if any deficiencies are observed, the
necessary maintenance must be conducted as expeditiously as possible.
Subsequent Method 9 opacity performance testing using the three truck
dump procedure is required to be conducted every 90 days.

E. Recordkeeping and Reporting Requirements

    The final rule requires that a logbook be maintained by each owner/
operator of a coal preparation and processing plant that commences
construction, reconstruction, or modification after April 28, 2008. The
logbook must include records of subpart Y requirements regarding
manufacturers' recommended maintenance procedures for process and
control equipment, visual observations of coal-handling equipment, the
amount and type of coal processed, the amount of chemical stabilizer or
water purchased, the operational status of dust suppressant systems,
compliance with a fugitive coal dust emissions control plan, BLDS
operation, and measurement of monitoring parameters (e.g., scrubber
pressure loss, water supply flow rate, pH of scrubber fluid).

F. Electronic Reporting

    The final rule requires owners/operators of affected facilities at
coal preparation and processing plants to submit an electronic copy of
all performance test reports to an EPA electronic data base (WebFIRE).
Data entry requires access to the Internet and is expected to be
completed by the stack testing company as part of the work that they
are contracted to perform. Submittal to WebFIRE is required as of July
1, 2011. For performance tests not accepted by WebFIRE, owner/operators
are required to mail summary results directly to EPA.

G. Additional Amendments

    The final rule confirms the subpart Y title change from Coal
Preparation Plants to Coal Preparation and Processing Plants. In
addition to revising the definitions for coal, pneumatic coal-cleaning
equipment, and thermal dryer as described in section III.A of this
preamble, the final rule amends the definition for bituminous coal;
adds definitions for anthracite, bag leak detection system, coal
refuse, design controlled potential emissions rate, indirect thermal
dryer, lignite, mechanical vent, operating day, potential combustion
concentration, and subbituminous coal; and deletes the definition for
cyclonic flow. The definition of coal refuse in the final rule has been
modified to be consistent with the definition of coal refuse in 40 CFR
part 60, subpart Da. Also, EPA is not finalizing the April 28, 2008,
proposed revision to the definition of coal processing and conveying
equipment, but is clarifying that equipment located at the mine face is
not considered to be part of the coal preparation plant. In addition,
the May 27, 2009, proposed revision to the definition of coal storage
system is also not being promulgated. Rather, the final rule adds a
definition for open storage pile.

IV. Summary of Significant Comments and Responses

    As explained in Section II of this preamble, EPA proposed
amendments to the coal preparation plants NSPS on April 28, 2008, (73
FR 22901) and received a total of 42 comments from coal preparation
plants, industry trade associations, control technology vendors,
environmental groups, and State environmental agencies. After reviewing
those comments and considering additional data, EPA decided to publish
a supplemental proposal (see 74 FR 25304, May 27, 2009) which revised
some of the requirements proposed on April 28, 2008. A total of 44
comments regarding the supplemental proposal were received from coal
preparation plants, other types of industrial facilities, industry
associations, environmental groups, and State environmental agencies.
Responses to comments regarding the April 28, 2008, proposal are not
discussed in this preamble. In many instances, the May 27, 2009,
supplemental proposal either addressed the comment or made revisions
that negated the comment. Significant comments received regarding the
May 27, 2009, supplemental proposal and EPA's responses to those
comments are discussed below. Detailed responses to the comments not
included in this preamble, including responses to the comments
regarding the April 28, 2008, proposal, are contained in the Summary of
Public Comments and Responses document which is included in the docket
for this rulemaking.

A. Regulated Pollutants

    Comment: Many commenters stated that EPA's authority to promulgate
NSPS requires an endangerment finding for the coal preparation plant
source category and the pollutant(s) of interest. Because EPA has not
made such a finding for SO2, NOX, or CO emissions
from coal preparation plants, the commenters contend that emissions
standards for SO2, NOX, or CO

applicable to coal preparation plants under subpart Y cannot be set.
    Response: CAA section 111(b)(1)(A) requires the Administrator to
publish a list of categories of stationary sources and include a
category of sources on that list if he finds that ``in his judgment it
causes, or contributes significantly to, air pollution which may
reasonably be anticipated to endanger public health or welfare.'' 42
U.S.C. 7411(b)(1)(A) (CAA section 111(b)(1)(A)). The plain language of
section 111(b)(1)(A) provides that such findings are to be made for
source categories, not for specific pollutants emitted by the source
category. Therefore, once the Administrator determines that the source
category causes or contributes significantly to air pollution which may
endanger public health or welfare, the Administrator must add the
source category to the section 111(b)(1)(A) list and subsequently
establish standards of performance for the sources in that source
category. Determinations regarding the specific pollutants to be
regulated are made, not in the initial endangerment finding, but at the
time the performance standards are promulgated. In addition, CAA
section 111(b)(1)(B) requires EPA to review and revise, if appropriate,
the standards at least every eight years. In conducting that review,
EPA has discretion to revisit its original determination regarding
which pollutants emitted from the source category should be regulated.
Neither the text of the CAA nor subsequent statements of EPA provide
any support for the argument that an endangerment finding must be made
for specific pollutants or for the argument that the scope of the
revised NSPS must be limited to the pollutants (or affected facilities)
regulated in the initial NSPS.
    The text of section 111(b)(1)(A) provides no support for the
argument that section 111 endangerment findings must be made for each
pollutant emitted by the source category before that pollutant can be
regulated in the NSPS. In contrast, the statutory text calls for a list
of ``categories of stationary sources.'' It does not require, at the
time of listing, an identification of all the specific pollutants
emitted by the source category that may endanger public health or
welfare. Instead, it requires only a general determination that
emissions from the category cause or contribute to air pollution that
may endanger public health or welfare. The endangerment finding is used
to identify categories of sources for regulation, not to dictate the
substantive content of the required standards of performance. The
endangerment finding neither requires regulation of each pollutant
emitted by the source category, nor limits EPA's discretion to
determine (in the initial regulation or in subsequent revisions) which
pollutants should be regulated.
    Instead, section 111(b)(1)(B) requires the Administrator, after
publishing proposed regulations and providing an opportunity for
comment, to promulgate such standards as the Administrator ``deems
appropriate.'' The statutory scheme thus provides EPA with significant
discretion to determine which pollutant(s) should be regulated under
the NSPS. The Agency has long interpreted section 111(b)(1)(B) as
providing the Administrator with this flexibility. See National Lime
Assoc. v. EPA, 627 F.2d 416, 426 n.27 (DC Cir. 1980) (explaining
reasons for not promulgating standards for NOX,
SO2 and CO from lime plants); see also National Assoc. of
Clean Air Agencies v. EPA, 489 F.3d 1221, 1228-1230 (DC Cir. 2007)
(finding that the ``deems appropriate'' language in CAA section 231
provides a ``delegation of authority'' that is ``both explicit and
extraordinarily broad'').
    EPA has, in prior NSPS rulemakings, exercised its discretion to
identify pollutants for regulation. It has sometimes exercised this
discretion to defer regulation of specific pollutants to a later date.
See, e.g., 52 FR 36678, 36682 (September 30, 1987) (noting in subpart
DDD proposal that ``standards development for this industry is focusing
initially on limiting emissions of VOC''); 49 FR 2656, 2659 (Jan 20,
1984) (explaining why SO2 and VOC were the only pollutants
in the natural gas production industry selected for regulation under
subpart LLL ``at this time.''); 48 FR 37338, 37340-42 (Aug. 17, 1983)
(declining to regulate in subpart AAa, emissions of pollutants for
which adequately demonstrated control technology was not currently
available). EPA has also exercised this discretion to promulgate,
during 8-year review rulemakings, new performance standards for
pollutants not previously covered by the NSPS in question. See, e.g.,
52 FR 24624, 24710 (July 1, 1987) (considering PM10 controls
in future rulemakings); 71 FR 9866 (Feb. 27, 2006) (establishing new PM
standards for boilers); 73 FR 35838 (June 24, 2008) (adding
NOX limits for fluid catalytic cracking units,
NOX limits for fluid coking units and NOX limits
for process heaters to the refineries NSPS). In addition, EPA has
previously noted its disagreement with comments implying that an
additional endangerment finding would be required to support regulation
of a pollutant not previously regulated in that specific NSPS. See,
e.g., 73 FR 35838, 35859 n2 (June 24, 2008).
    Further, the argument that EPA must issue a separate endangerment
finding before regulating a pollutant not previously regulated in the
NSPS for a source category is illogical. Once EPA has determined that a
source category causes, or contributes significantly to, air pollution
which may reasonably be anticipated to endanger public health or
welfare emissions from a source category, the recognition that the
source has emissions above and beyond those discussed in the original
endangerment finding could only serve to strengthen the basis for the
endangerment finding for the source category. Further, the listing of
the source category is only the first step in the process. Once the
finding is made, the statute allows the more detailed analysis of which
pollutants are actually emitted and should be regulated to be conducted
in the rulemaking process used promulgate and revise the standards for
the source category.
    Finally, it is worth noting that EPA previously addressed this
topic in the context of the subpart Y NSPS for coal preparation and
processing plants. Coal preparation plants were listed under section
111(b)(1)(A) on October 24, 1974, pursuant to the Administrator's
determination that such plants ``may contribute significantly to air
pollution which causes or contributes to the endangerment of public
health or welfare.'' 39 FR 37,807 (Oct. 24, 1974). The Background
Information Document for the subpart Y standards proposed at that time
explains the process to be used for setting NSPS and explicitly notes
that ``[a]lthough a source category may be selected to be covered by a
standard of performance, treatment of some of the pollutants of
facilities within that source category may be deferred.'' Background
Information for Standards of Performance: Coal Preparation Plants
Volume 1: Proposed Standards at ix.
    For these reasons, EPA disagrees with the comment suggesting that
EPA cannot set SO2, NOX, or CO emissions
standards applicable to coal preparation plants under subpart Y.
    Comment: One commenter stated that EPA should recognize its
obligation to promulgate NSPS for emissions of carbon dioxide
(CO2), nitric oxide (N2O), and black carbon (a
component of PM) from coal preparation and processing plants. The
commenter asserts that because these pollutants are the result of
incomplete fuel combustion, they are emitted at coal prep plants,
particularly by thermal dryers heated by coal or other fossil fuels.
Emissions of each pollutant, the

commenter asserts, carries individual and distinct risks and is
controlled by different technologies so EPA must fully analyze each
pollutant and set separate NSPS for each.
    Response: At this time EPA is not aware of any emissions or
mitigation data for the pollutants noted by the commenter for this
source category. Hence, we lack sufficient information on which to base
an NSPS for emissions of CO2, N2O, and black
carbon from the source category at this time. Rough estimates of
CO2 from this source category suggest that this source
category would be among the smaller CO2-emitting NSPS
categories. At this time, we are not making any final determination
regarding whether it would be appropriate to set such standards.
    In addition, to the extent the comment suggests that EPA should
utilize its authority under other provisions of the CAA to require
sources to gather and report GHG emissions and to the extent it raises
issues not opened for public comment in the supplemental proposal, it
is beyond the scope of this rulemaking.
    Comment: One commenter asserts that CAA section 111 carries a
mandate for EPA to set NSPS for the pollutants emitted by a source. The
commenter cites to language in section 111(a)(3) that defines a
stationary sources as any building, structure, facility or installation
which emits or may emit any air pollution and language in section
111(b)(4) defining a modification as a physical or operational change
which increases the amount of any air pollution emitted by the source.
In addition, the commenter cites to the Supreme Court's decision in
Massachusetts v. EPA, 549 U.S. 497, 529 (2007) and EPA's April 2009
Proposed Endangerment and Cause or Contribute Findings for Greenhouse
Gases (74 FR 18886 (Apr. 24, 2009)).
    Response: The Agency has long exercised its discretion to regulate
only a subset of the pollutants emitted by a source category or to
defer regulation of certain pollutants to a later date. See e.g.,
National Lime Assoc. v. EPA, 627 F.2d 416, 426 n.27 (DC Cir. 1980)
(explaining reasons for not promulgating standards for NOX,
SO2, and CO from lime plants); National Assoc. of Clean Air
Agencies v. EPA, 489 F.3d 1221, 1228-1230 (DC Cir. 2007) (finding that
the ``deems appropriate'' language in CAA section 231 provides a
``delegation of authority'' that is ``both explicit and extraordinarily
broad''); 52 FR 36678, 36682 (September 30, 1987) (explaining Subpart
DDD standards' initial focus on limiting emissions of VOC); 49 FR 2656,
2659 (January 20, 1984) (explaining Subpart LLL regulates only
emissions of SO2 and VOC); 48 FR 37338, 37340-42 (August 17,
1983) (explaining why Subpart AAa does not regulate emissions of
pollutants for which adequately demonstrated control technology was not
currently available).

B. Applicability and Definitions

    Comment: Many commenters stated that EPA proposed to add
``processing'' to the title of subpart Y and, although EPA indicated in
the preamble to the May 27, 2009, supplemental proposal, that it did
not intend to change the applicability of subpart Y, the commenters are
concerned that EPA has not adequately justified the need to make the
change. Subpart Y already defines ``processing equipment'' as
``machinery used to reduce the size of coal or to separate coal from
refuse.'' Despite EPA's stated intentions, commenters believe that the
risk exists that EPA, in future applicability interpretations, will
determine that additional, non-preparation operations meet the meaning
of processing, and will thereby bring them under subpart Y purview. To
avoid confusion, the commenters stated that EPA should remove
``processing'' from the title.
    Response: In the preamble to the supplemental proposal, EPA
indicated that the proposed title change was for clarification purposes
(i.e., to more accurately reflect the affected facilities subject to
subpart Y). The affected facilities covered by subpart Y since its 1976
promulgation include both preparation and processing units. We do not
intend the title change to have any impact on the extent of EPA's
authority to regulate specific affected facilities now or in the
future. The final action promulgates the proposed title change
``Standards of Performance for Coal Preparation and Processing
Plants.''
    Comment: Many commenters acknowledged that in its May 27, 2009,
supplemental action, EPA proposed to amend the definition of ``coal''
to include ``coal refuse'' and ``petroleum coke.'' These commenters
objected to EPA's proposed inclusion of ``coal refuse'' because its
inclusion further expands the subpart Y applicability with no data
specific to ``coal refuse'' on what constitutes adequately demonstrated
technologies and their respective levels of achievable emissions.
Specifically, one commenter is concerned that subpart Y's definition of
``coal refuse'' could create the potential for the unintended
application of such definition to the overburden from surface mines or
to mine-development waste associated with underground mining. The
commenter stated that the final rule must make clear that the
definition of ``coal refuse'' does not apply to these types of
operations and suggested using the SMCRA definition instead (Coal
refuse is defined as ``any waste coal, rock, shale, slurry, culm, gob,
boney, slate, clay and related materials, associated with or near a
coal seam, which are either brought aboveground or otherwise removed
from a coal mine in the process of mining coal or which are separated
from coal during the cleaning or preparation operations. The term
includes underground development wastes, coal processing wastes, excess
spoil, but does not mean overburden from surface mining activities'').
In contrast, several other commenters stated either that they support,
or that they have no objections to, including ``coal refuse'' in the
definition of ``coal'' for subpart Y.
    Response: EPA is including ``coal refuse'' in the final rule's
definition of ``coal'' for the purposes of subpart Y because it is
handled in the same machinery as other types of coal at coal
preparation and processing plants. ``Coal refuse'' is separately
defined, as well as included in the definition of ``coal'' in other
NSPS (e.g., 40 CFR part 60 subparts Da and Db), and its inclusion here
provides consistency with other EPA regulations. EPA has modified the
definition of ``coal refuse'' in subpart Y to be consistent with the
definition in 40 CFR subpart Da. Given the historical inclusion of
``coal refuse'' in these other NSPS and the fact that the constituents
and emission characteristics of ``coal'' and ``coal refuse'' are
believed to be the same, EPA has concluded that inclusion of ``coal
refuse'' in subpart Y is appropriate.
    Comment: Many commenters objected to EPA extending the
applicability of subpart Y to facilities producing petroleum coke by
adding ``petroleum coke'' to the subpart Y definition of ``coal''. They
noted that the emission standards in the May 27, 2009, supplemental
proposal appear to have been developed primarily for coal processing
plants, and do not seem to reflect the differences between coal and
petroleum coke, or contemplate the emissions associated with petroleum
coke handling operations. Without more information on these emissions,
the commenters contend that it is inappropriate for EPA to broaden the
definition of ``coal'' to include ``petroleum coke'' in this final
rulemaking at this time. However, if ``petroleum coke'' is included,
several commenters recommended petroleum

coke operations that should be specifically exempted from being subject
to subpart Y. Reasons cited by commenters include: (1) ``Petroleum
coke'' is a petroleum product that should not be subject to a rule
(i.e., NSPS subpart Y) intended to pertain to standards of performance
for coal preparation and processing plants; (2) petroleum refining
operations that include petroleum coke production are subject to
numerous NSPS rules to ensure protection of public health and the
environment, to two separate maximum achievable control technology
(MACT) rules specific to air emissions from process units, including
petroleum coke production, and to the NSR permitting process to ensure
compliance with National Ambient Air Quality Standards (NAAQS) for PM;
(3) EPA did not provide adequate notice that petroleum coke
manufacturing equipment (e.g., refinery coker units) was being
considered for new standards; (4) EPA neither gathered or requested
data to determine if petroleum coke manufacturing equipment should be
included in the affected sources subject to subpart Y; and (5)
standards for coal processing and conveying equipment, coal storage
systems, and transfer and loading system operations are not suitable
for petroleum coke.
    Two commenters suggested that EPA change the approach to include
end-user petroleum coke processing in the existing NSPS for Coal
Preparation and Processing Plants by retaining the existing definition
of ``coal'' and adding ``petroleum coke'' as a separate material with
associated provisions. If EPA expands the source category by including
facilities that handle only ``petroleum coke'' (and not ``coal''), the
commenters believe it should do so only for end-users of ``petroleum
coke'' used as fuel. Numerous commenters presented arguments that
petroleum coke calciners are not same as coal thermal dryers and,
therefore, believe it is inappropriate to apply the subpart Y thermal
dryer standards to coke calciners. The commenters explained that the
purpose and function of a petroleum coke calciner is to fundamentally
change the material by rearranging carbon molecules and, thus, it acts
as a reactor, not a ``dryer''. In addition, commenters noted that
calciners in the petroleum industry operate at much higher temperatures
than typical coal dryers, intuitively would have different emission
profiles, and use different methods than coal thermal dryers to control
PM emissions.
    Response: Based on a review of the comments received and because of
the limited amount of currently available data, EPA has decided not to
include ``petroleum coke'' in the subpart Y definition of ``coal'' at
this time. EPA plans on obtaining additional data on petroleum coking
activities at petroleum refineries through current actions on the
refinery NSPS review (40 CFR part 60 subpart J). In addition,
additional data will also be obtained on petroleum coke activities at
end-user locations (e.g., coal-fired power plants).
    Comment: Several commenters supported EPA's proposal to distinguish
between indirect and direct contact thermal dryers. The commenters
anticipate that more electric utilities will use indirect contact
thermal dryers in the future. Commenters agreed with EPA's decision to
exclude indirect thermal dryers from the coal dryer SO2 and
NOX/CO standards ``[i]f the source of heat (the source of
combustion or furnace) is subject to a boiler NSPS (subpart Da, Db, or
Dc). However, one commenter stated that in the case of one facility,
the waste heat being used for the facility's coal dryer does not come
from the exhaust gases of a boiler, but rather from the condensing
water from steam turbines. In that case, there is no affected source to
which the combustion pollutant emission limits can apply. Thus, the
commenter agreed that the thermal dryer would only be subject to the PM
limit, but not because it is subject to another NSPS. The commenter
further stated their belief that subpart Y coal dryer emission limits
should not apply to the source of heat for an indirect thermal dryer.
    Response: It is EPA's intent to regulate, at this time, emissions
from thermal dryers only in circumstances where coal, coal refuse, or
residual oil are used to provide thermal input. Thermal dryers that use
residual or waste heat from the combustion of these fuels are only
subject to the PM and opacity standards. As pointed out by the
commenters, indirect thermal dryers for which the source of heat is
subject to a boiler NSPS are not subject to the emission limits for
SO2 and NOX/CO because those pollutants would not
be present in the thermal dryer exhaust. In addition, EPA has concluded
that affected thermal dryers for which all of the thermal input is
supplied by gaseous fuels (e.g., blast furnace gas, coke oven gas,
natural gas) or distillate oil also should not be subject to the
emission limits for SO2 and NOX/CO. Those
pollutants are relatively small from these types of thermal dryers and
the testing requirements will not result in any emissions reductions.
As is the case with the facility described by the commenter, if there
is no combustion process providing the heat for the dryer, then there
is no practicality in having emission limits for SO2 and
NOX/CO.
    Comment: Several commenters stated that emissions from thermal
dryers integrated with in-line coal mills at cement manufacturing
plants should not be subject to subpart Y and instead be subject to the
standard for the affected facility as part of the cement manufacturing
process. According to the commenters, the unique coal processing and
handling systems found at Portland cement plants are best addressed by
the Portland Cement NSPS (40 CFR part 60, subpart F) and NESHAP (40 CFR
part 63, subpart LLL). The commenters requested that the subpart Y
definition of ``thermal dryer'' be revised to read ``Thermal dryer does
not include drying of coal that occurs intentionally or incidentally in
the manufacture of Portland cement through direct or indirect contact
with hot gases generated by cement manufacturing process units, such as
cement kilns, preheaters, precalciners, or clinker coolers.''
Commenters explained that this approach would (a) clearly distinguish
between separately fired, stand-alone thermal dryers that are located
at a cement plant, versus thermal dryers or coal mills that are
integrated into a cement manufacturing line, and (b) avoid any
potential confusion about incidental drying of coal that occurs in the
cement-making process. Reasons presented by commenters to support the
requested exemption are summarized below.
     In a 1995 determination, EPA stated that when ``gases
originate in one affected facility and pass through another affected
facility as part of the manufacturing process, EPA applies the standard
for the affected facility from which the gases are discharged directly
into the atmosphere.'' [Applicability Determination 9600082
``Alternative Monitoring and Opacity Limit Clarification for San Juan
Cement Company,'' John B. Rasnic (May 12, 1995)]. However, a year later
EPA qualified this guidance when it concluded that an in-line raw mill
was subject to the 40 CFR part 60, subpart F, kiln standards, stating
''This determination clarifies that for dry process Portland cement
plants with an ``in-line'' kiln/raw mill configuration, the raw mill
does not exist as a separate affected facility and; hence, the
appropriate emission limit is that which applies to the kiln.''
[Applicability Determination 9600083; ``Opacity Limitation for `In-
line' Portland Cement Plants,'' John B. Rasnic (September 7, 1996)].
     Just as emissions from the in-line raw mill in
Applicability Determination

9600083 were subject to 40 CFR Part 60, subpart F, NSPS, PM mass and
opacity limitations for cement kilns, so should emissions from an in-
line coal mill at a cement plant where kiln gases are used to heat and
dry the coal be treated as an extension of the kiln and subject to
subpart F NSPS and 40 CFR Part 63, subpart LLL, NESHAP cement kiln PM
and opacity limits. This approach is consistent with multiple different
applicability determinations stating that kiln exhaust gases are
subject to the Portland cement NESHAP (40 CFR part 63, subpart LLL)
regardless of whether they are routed through the coal mill prior to
discharge to the atmosphere. It is also consistent with the data that
EPA has reviewed in establishing the proposed subpart Y limits. In the
absence of data related to emissions from in-line coal mills, EPA would
not have a rational basis supported by evidence in the record for
establishing limits that apply to these unique gas streams.
     As Portland cement plants have striven to increase energy
efficiency, a common plant configuration has been to employ kiln
exhaust gas or heated gas from the plant's clinker cooler to thermally
dry coal before it is combusted. Cement kiln exhaust gas is extremely
hot, and one of the primary means of improving energy efficiency has
been to route this gas back through the process to extract as much heat
as reasonably possible. Likewise, the product leaving the kiln
(referred to as clinker) will enter a cooling area where gases are
blown through the clinker to accelerate the cooling process. In some
plants this heated gas is then used to heat the coal entering the
combustion process. Both kilns and clinker coolers are affected
facilities under 40 CFR part 60, subpart F, NSPS. The use of waste heat
from the kiln or the clinker cooler is highly energy efficient, driving
down the combustion emissions, including GHG emissions, from the plant
as a whole.
     Some cement plants have stand-alone thermal dryers for
coal, where the heat for drying is provided by a dedicated combustion
source (e.g., coal or natural gas). Those thermal dryers generally
should have similar emissions, and similar possibilities for emissions
control, as comparable-size thermal coal dryers at other facilities.
But where coal drying is integrated into the cement-making process,
through direct or indirect exposure of the coal to heat in exhaust
gases from units such as cement kilns, preheater/precalciners, or
clinker coolers, the emissions from that coal drying, and the potential
for controlling those emissions, is very different from a stand-alone
thermal dryer.
     To the extent that subpart Y may apply to coal drying that
occurs using waste heat from the manufacture of Portland cement, EPA's
assessments of control technology and derivation of emission standards
under subpart Y have not taken into account cement-process-related
loadings of SO2, NOX, and CO. EPA has not shown,
for example, that it would be feasible for a cement plant to
demonstrate compliance with SO2 mass limits or percent
reduction requirements where exhaust gases from coal drying are
combined with cement kiln gases, which include SO2 from fuel
consumption and from raw materials. Similarly, NOX limits
that may be achievable through combustion controls on a standalone
thermal dryer may not be achievable in exhaust gases mixed with cement
kiln gases containing both fuel NOX and thermal
NOX from the cement-making process.
     The supplemental proposal would not impose SO2,
NOX, and CO limits on indirect thermal dryers where the
source of the heat is subject to NSPS under 40 CFR Part 60, subpart Da,
Db, or Dc. Although EPA has not really explained the basis for that
exclusion, it is inferred that EPA believes the BDT determinations
associated with the NSPS for the source of heat are more appropriate
and should be applied. The same rationale should be applied to thermal
drying that is incidental to cement manufacturing, and EPA should
exclude exhaust gases that are subject to the 40 CFR part 60, subpart
F, NSPS from being subject to the subpart Y SO2,
NOX, and CO limits.
    Response: EPA agrees that in the case of a coal dryer at a cement
manufacturing facility where all of the thermal input is supplied by
cement kiln exhaust or clinker cooler exhaust, the dryer should be
regulated under the appropriate Portland Cement kiln regulations (40
CFR part 60, subpart F, and 40 CFR part 63, subpart LLL). This would
also imply that any emissions from the thermal dryer are considered as
part of the kiln or clinker cooler emissions. The final rule's
emissions limits apply to new, reconstructed, or modified thermal
dryers at Portland cement manufacturing plants in situations where the
thermal input is not supplied by cement kiln or clinker cooler exhaust.
Other subpart Y affected facilities located at Portland cement
manufacturing plants (e.g., storage systems, conveyors) also are
subject to subpart Y.
    Comment: One commenter requested that thermal dryers fired with
process gases at integrated iron and steel plants be exempted from the
subpart Y emission limits for SO2 and NOX/CO.
Reasons presented by commenter to support the requested exemption are
summarized below.
     The pulverized coal injection systems at some integrated
iron and steel plants also burn process gases (i.e., blast furnace gas
or coke oven gas) as the primary fuel in thermal dryers. These process
gases are valuable substitutes for other sources of purchased energy
and are produced on-site. However, they have lower heating values than
natural gas and must be consumed on-site to be utilized most
effectively, or be flared. As is the case for waste heat, the use of
these gases improves overall plant energy efficiency and reduces GHG
emissions and should not be discouraged by applying unachievable
emission limits when used for thermal drying of coal.
     The use of these process gases for coal drying will not
generate any more emissions than if the gases are combusted elsewhere
or flared. Instead, if the process gases burned for coal drying were
replaced entirely by burning natural gas, emissions (mainly
NOX and CO) from the integrated iron and steel plant would
actually increase. Establishing emission limits for thermal dryers
using these process gas fuels will only serve to discourage their use.
     The proposed subpart Y standards are based on the
assumption that thermal dryers located at traditional mine sites and
coal preparation plants are typically fired with coal, but in the
examples noted above, other fuels are normally used. At the very least,
the final rule should include a provision to allow operators of thermal
dryers fired by natural gas, waste heat, or process gases to apply for
a variance upon demonstration that emissions of SO2,
NOX, CO and/or PM are well below the prescribed standards.
Upon such a demonstration, monitoring requirements for these pollutants
should be reduced or eliminated.
    Response: As previously noted, EPA has maintained that coal
preparation and processing plants may be found at industrial sites such
as those described by the commenter. In the Response to Comments
document for the October 24, 1974, proposal, EPA stated ``[t]he
specific coal processing operations regulated by these standards are
affected regardless of whether they are located in coal liquefaction
plants, power plants, coke ovens, etc.'' (see ``Background Information
for Standards of Performance: Coal Preparation Plants; Volume 3:
Supplemental Information. January 1976. p. 22). Thus, EPA has not

changed its interpretation. In addition, EPA has made no assumptions as
to the source of the heat used in the thermal dryer as the commenter
suggests. However, as noted above for Portland cement plants, EPA
agrees that in the case of an affected source at an integrated iron and
steel manufacturing facility, where the emissions from the thermal
dryer would be considered as part of the blast furnace or coke oven
emissions, the facility should be regulated under the appropriate steel
mill or coke oven NSPS. As previously explained, EPA's intent at this
time is to regulate emissions from a thermal dryer only in
circumstances where coal, coal refuse, or residual oil are used as
thermal input. Thermal dryers that use residual or waste heat from the
combustion of these fuels would only be subject to the PM and opacity
standards. Indirect thermal dryers for which the source of heat is
subject to SO2, NOX, and/or CO limits under
another 40 CFR part 60 subpart would not be subject to the emission
limits for SO2 and NOX/CO. In addition, affected
thermal dryers for which all of the thermal input is supplied by
gaseous fuels (e.g., blast furnace gas, coke oven gas, natural gas) or
distillate oil also would not be subject to the emission limits for
SO2 and NOX/CO.

C. Subcategorization

    Comment: Numerous commenters stated that when establishing
standards of performance for new stationary sources under the CAA,
section 111(b)(2) authorizes the Administrator to ``distinguish among
classes, types and sizes within categories of new sources.'' The
commenters requested that the final amendments to subpart Y include a
distinction between the regulatory requirements for coal preparation
plants associated with coal mines (i.e., the ``producers'') and for
coal preparation plants at coal-fired power plants and large industrial
sources such as cement manufacturing and coke ovens (i.e., the
``users''). The commenters cited the following regulatory requirement
and facility characteristics distinctions between coal producers and
coal users to support their request.
     Most new coal-fired power plants as well as large
industrial coal-fired sources (i.e., the ``users'') in the future will
be major sources of PM emissions and, therefore, be required to use
state-of-the-art control technologies (i.e., best available control
technology (BACT)). In contrast, surface coal mines with coal
preparation facilities as well as stand-alone coal preparation
facilities associated with coal mines (i.e., the ``producers'') are
typically minor sources and will not be subject to BACT under the
Prevention of Significant Deterioration (PSD) program but rather to
control technology requirements of Minor New Source Review (NSR)
programs of individual States. Thus, adoption of industry sectors-based
subcategorized emission standards for subpart Y should be considered so
that a BACT level of control is not mandated as NSPS for ``producers.''
     Resource requirements to maintain and demonstrate
compliance with the subpart Y emission standards is a function of the
number of affected facilities at a particular coal preparation plant.
Coal preparation plants of ``producers'' tend to have more sizing,
cleaning and overall ``handling'' operations than the typical
preparation plant at a coal-fired ``user.'' Consequently, as a general
rule, the total number of affected facilities at a ``producer's'' coal
preparation plant will be greater than the number of such facilities at
the preparation plant of a ``user.'' Moreover, a single affected
facility associated with coal mining can frequently have multiple
points of fugitive emissions. With more affected facilities per source
and more emission points per affected facility, preparation plants
associated with coal mining generally will have much greater
monitoring/recordkeeping/reporting requirements than will its
preparation counterparts at coal-fired ``user'' sources.
     Fugitive dust from surface coal mines is already regulated
by U.S. Department of the Interior regulations in 30 CFR Parts 700-899
under authority of SMCRA, and the existing air pollution control
requirements imposed on coal mines by SMCRA must be accounted for.
Commenters believe that an EPA examination of SMCRA's dust control
requirements in the context of possible NSPS regulation of preparation
facilities at coal mines would result in a conclusion that concurrent
regulation with similar CAA requirements is not appropriate.
    Response: The subpart Y NSPS covers coal preparation and processing
plants that may be found, as the commenter notes, both at mine sites
(``producers'') and at industrial sites (``users''). In the Response to
Comments document for the October 24, 1974, proposal, EPA stated
``[t]he specific coal processing operations regulated by these
standards are affected regardless of whether they are located in coal
liquefaction plants, power plants, coke ovens, etc.'' (See ``Background
Information for Standards of Performance: Coal Preparation Plants;
Volume 3: Supplemental Information.'' January 1976. p. 22.)
    Commenters' request that EPA create a separate category for coal
preparation and processing facilities at ``producers'' appears to be
based on the assertion that these facilities should not be required to
install and operate emissions control technologies that are currently
in use or will be used at coal preparation and processing facilities at
``users.'' A primary objective of CAA section 111, however, is to
require new sources to be built using the best system of emissions
reduction that has been adequately demonstrated. Under CAA section 111,
EPA is required to set standards of performance (i.e., standards that
reflect the degree of emission limitation achievable through the
application of the best system of emission reduction). As the Court has
noted, ``Section 111 looks toward what may fairly be projected for the
regulated future, rather than the state of the art at present, since it
is addressed to standards for new plants.'' Portland Cement, 486 F.2d
at 391. In developing NSPS standards, EPA must identify all
technologies in use or being developed for use to determine that the
Administrator determinations have been adequately demonstrated. This
analysis must take into account the cost of achieving the reductions
and any nonair quality health and environmental impacts and energy
requirements. This analysis is separate and distinct from any BACT
analysis that may be done for an individual plant. Finally, EPA
disagrees with the comment to the extent it suggests that EPA should
not consider technologies determined to be BACT for an individual plant
in its BDT analyses. Control technologies change and can improve over
time and EPA does not believe that it would be appropriate for EPA to
ignore these developments when evaluating what currently constitutes
BDT for this source category.
    The commenters point out that preparation plants associated with
coal mining generally have more affected facilities per source and more
emission points per affected facility. Commenters have not suggested,
however, and EPA has no reason to believe, that the types of emissions
from coal preparation and processing sources associated with coal mines
differ from the types of emissions from those same source types at
``user'' facilities. They further have not demonstrated, and EPA has no
reason to believe, that emission control technologies that are
adequately demonstrated for facilities at ``user'' facilities would not
be adequately demonstrated for use at facilities located at mines.
Thus, EPA continues to believe it is appropriate to regulate these

sources in the same manner and sees no need to establish subcategories
at this point. Further, the comment could be read to suggest that a
separate subcategory should be created for facilities at mines because
these facilities are subject to differences in the degree of control
required by other regulations or because these facilities are currently
achieving different levels of control or using different emission
control technologies. EPA does not believe it would be appropriate to
create a separate subcategory on these bases. Further, these factors do
not affect what technologies could be found to be ``adequately
demonstrated'' or the emission reductions available from those
technologies.
    In addition, the regulation of fugitive dust from surface coal
mines under SMCRA by the Department of Interior does not, as commenters
suggest, result in a ``conclusion that concurrent regulation with
similar CAA requirements would not be appropriate.''
    The October 1974 Background Information Document stated that ``Coal
preparation'' is a segment of the coal industry that encompasses
operations between the mining of raw coal and the distribution of
product coal. (See ``Background Information for Standards of
Performance: Coal Preparation Plants; Volume 1: Proposed Standards.
October 1974. p. 1.) The support document for the April 1981 NSPS
review states that ``[t]he first step in the coal preparation process
is the delivery of ROM [run of mine] coal to the plant site.'' (See ``A
Review of Standards of Performance for new Stationary Sources--Coal
Preparation Plants. December 1980. p. 2-3.)
    EPA's Office of Water has included the following definitions in
their regulations for the coal mining industry (at 40 CFR 434.11).
    (b) The term ``active mining area'' means the area, on and beneath
land, used or disturbed in activity related to the extraction, removal,
or recovery of coal from its natural deposits. This term excludes coal
preparation plants, coal preparation plant associated areas and post-
mining areas.
    (e) The term ``coal preparation plant'' means a facility where coal
is subjected to cleaning, concentrating, or other processing or
preparation in order to separate coal from its impurities and then is
loaded for transit to a consuming facility.

Thus, EPA, in both the air and water offices, has maintained a
distinction between the ``active mining area'' and the ``coal
preparation plant.'' The process of ``coal preparation'' generally
involves, among other things, separation of coal from impurities (i.e.,
``breaking'' or ``crushing''). As discussed in the response to comment
<IP_ADDRESS>.1 in the Response to Comments Document, EPA interprets the
``beginning'' of the ``coal preparation plant'' to be the first hopper
(i.e., ``drop point'') for receipt of coal from any form of
transportation.

D. Coal Drying Standards

    Comment: Two commenters supported EPA's decisions not to set
separate limits for fine PM (FPM) (i.e., PM2.5 or
PM10) or condensable PM (CPM). In contrast, another
commenter rejected EPA's rationale presented in the May 27, 2009,
supplemental proposal that EPA cannot set limits applicable to
PM10, PM2.5, and CPM emissions because EPA has
insufficient data and lacks a consistent measurement methodology to
collect the needed data. The commenter stated that EPA's failure to
gather such data does not excuse EPA from a statutory obligation, that
FPM and CPM emissions standards can be set pending resolution of any
measurement issues by a future date certain, and, should EPA conclude
that an inability to accurately measure emissions of FPM and CPM from
dryers renders the implementation of FPM or CPM standards of
performance infeasible, EPA must impose a design, equipment, work
practice, or operational standard, or combination thereof.
    Response: EPA stands by the rationale presented in the May 27,
2009, subpart Y supplemental proposal notice. That is, the available PM
emissions data for thermal dryers collected by EPA were measured using
EPA Method 5 (see 40 CFR 60, appendix A-3). For this method, solid FPM
is collected isokinetically on a filter media (typically glass or
quartz fiber) and is then measured gravimetrically to determine FPM
emissions. Method 5, when performed correctly, provides an accurate
measurement of total FPM (for PM > 0.3 [mu]), but does not measure FPM
emissions by particle size distribution (i.e., PM10 or
PM2.5), nor does the method measure CPM. EPA is revising
existing test methods, EPA Method 201A--Determination of
PM10 Emissions (Constant Sampling Rate Procedure) and EPA
Method 202--Determination of Condensible Particulate Emissions from
Stationary Sources, to provide test methods that will accurately
measure PM10, PM2.5, and CPM from stationary
sources such as coal thermal dryers. Amendments to these test methods
were proposed on March 26, 2009 (see 74 FR 12970). The amendments to
Method 201A add a particle-sizing device to allow for sampling of
PM2.5, PM10, or both PM10 and
PM2.5. The amendments to Method 202 revise the sample
collection and recovery procedures of the method to provide for more
accurate and precise measurement of CPM. Methods 201A and 202 are not
yet finalized and sufficient test data using these methods has not yet
been collected for coal-fired thermal dryers. For these reasons, EPA is
not currently able to determine whether or not it would be appropriate
to add separate PM emission limits to subpart Y for PM2.5,
PM10, or CPM emissions from coal-fired thermal dryers and
would not currently be able to establish national standards to address
PM2.5, PM10, or CPM emissions.
    Comment: One commenter disagreed with EPA's rationale for not
setting coal dryer VOC standards. Specifically, the commenter disagrees
with (1) EPA's decision to not set standards for VOC and CO that
reflect use of a gas recirculation thermal dryers, although EPA asserts
that VOC and CO emissions would be minimized because new thermal dryers
are likely to use a gas recirculation design; (2) EPA's assertion that
not setting a standard for VOC is reasonable because by setting an
emissions limit that contains a CO emissions rate, the VOC emissions
that result from incomplete combustion also are minimized; and (3)
EPA's assertions that VOC standards cannot be established because a
method of control beyond combustion controls has not been identified
and the variability of VOC emissions from the coal bed preclude
determination of a standard that would be achievable nationwide.
    Response: EPA has discretion to determine which pollutants are
appropriate for regulation in a particular NSPS. In this case, for the
reasons noted, EPA concluded that it was not appropriate or feasible to
establish a standard of performance for VOC emissions from coal
preparation and processing plants at this time. This conclusion does
not prohibit EPA from establishing such a standard in a future
rulemaking. EPA disagrees with the commenter's suggestion that a
standard could be based on oxidation of VOC in a recirculation thermal
dryer. As noted elsewhere, EPA has concluded that there is no one
thermal dryer design that will work in all situations found within the
industries utilizing coal preparation and processing plants. Control of
VOC emissions through activated carbon absorption or regenerative
thermal oxidizers are not utilized on thermal dryers at coal
preparation and processing plants; further, EPA did not have other
information showing that

these technologies are adequately demonstrated for use on coal
preparation and processing plant sources. VOC emissions vary, in part,
due to the variability in volatile contents of the coals being
processed; absent demonstrated control technology, this variability can
not be addressed through add-on technology as it is with variable
sulfur contents of coal. Thus, EPA believes its decision not to
establish VOC emission limits under subpart Y at this time is
appropriate.
    Comment: One commenter stated that the proposed standards for coal
drying failed to meet the basic legislative requirements of CAA section
111. The commenter presented the following reasons to support the
position that for EPA to comply with CAA section 111, EPA must set
standards based on the best demonstrated technologies for drying coal
not for the thermal drying of coal through the application of heat
generated by coal combustion specifically for that purpose.
     CAA section 111 defines ``standard of performance'' to
mean ``a standard for emissions of air pollutants which reflects the
degree of emission limitation achievable through the application of the
best system of emission reduction which (taking into account the cost
of achieving such reduction and any nonair quality health and
environmental impact and energy requirements) the Administrator
determines has been adequately demonstrated'' [42 U.S.C. 7411(a)(1))].
     Another provision in CAA section 111 provides that
standards of performance must represent the best ``technological system
of continuous emission reduction,'' see, e.g., 42 U.S.C. 7411(g)(4),
which is defined to include ``a technological process for production or
operation by any source which is inherently low-polluting or
nonpolluting'' [42 U.S.C. 7411(a)(7)(A)]. This provision further
demonstrates that EPA must evaluate mechanical, indirect, and
recirculation dryers, as each is inherently low polluting, in
comparison to once-through coal-fired thermal dryers.
     CAA section 111 requires ``specific and rigorous limits on
the amounts of pollutants that may be emitted.'' ASARCO, Inc. v. EPA,
578 F.2d 319, 322 (DC Cir. 1978). The legislative history of this
requirement confirms Congress's determination that ``[t]he maximum use
of available means of preventing and controlling air pollution is
essential to the elimination of new pollution problems * * *'' S. Rep.
No. 1196, 91st Cong., 2d Sess. at 16. In revising the standards of
performance for coal preparation plants, EPA may not simply codify
existing levels of performance.
     Because NSPS apply only to new, modified, or reconstructed
sources and must reflect application of the best demonstrated system of
reduction, they do not have to be achievable for all types of existing
sources. See Portland Cement, 486 F.2d at 391. Nor can EPA forego
setting limits reflecting the best demonstrated system merely because
some sources may prefer a different system, ASARCO, 578 F.2d at 322
(``NSPS are designed to force new sources to employ the best
demonstrated systems of emission reduction.''). The legislative history
of CAA section 111 demonstrates that Congress intended for EPA to
prescribe standards that override the design preferences of regulated
sources: ``[T]he emission standards shall provide that sources of such
emissions shall be designed and equipped to prevent and control such
emissions to the fullest extent compatible with the available
technology and economic feasibility. * * * '' H.R. Rep. No. 1146, 91st
Cong., 2d Sess. at 10 (emphasis added). Thus, EPA's assumption that
NSPS must be set at levels lenient enough to accommodate all types of
existing dryers is contrary to Congress' plainly expressed intent.
     CAA section 111 ``looks toward what may fairly be
projected for the regulated future, rather than the state of the art at
present. * * *'' Portland Cement Assn v. Ruckelshaus, 486 F.2d 375, 391
(DC Cir. 1973). An ``achievable standard is one * * * within the realm
of the adequately demonstrated system's efficiency and which, although
not at a level that is purely theoretical or experimental, need not
necessarily be routinely achieved within the industry prior to its
adoption.'' Essex Chemical Corporation v. Ruckelshaus, 486 F.2d 427,
433-34 (DC Cir. 1973). Instead of looking toward a future of mechanical
dryers and indirect thermal dryers, or even gas-fired recirculation
thermal dryers, the proposed standards attempt to lock-in standards
that reflect the performance of coal-fired once-through thermal dryers.
     Even assuming for the sake of argument that it is
permissible to set a standard for emissions from coal drying that
presumes the use of thermal dryers, the proposed rule violates the
straightforward intent of Congress. Congress purposefully chose the
superlative ``best'' to describe the system of emissions reductions on
which the NSPS were to be based [42 U.S.C. 7411(a)(1)]. Moreover, one
of the enumerated purposes of the NSPS was to create incentives for new
technology. CAA Conference Report: Statement of Intent; Clarification
of Select Provisions, 123 Cong. Rec. 27071 (1977). However, instead of
proposing standards based on the performance of the cleanest new coal
drying technologies, the proposal sets lax standards and then allows a
mix of coal drying technologies to meet those standards.
    Response: EPA followed the statutory requirements of CAA section
111 in its review of the existing standard of performance for thermal
dryers at coal preparation and processing plants. The review was
conducted pursuant to the requirement in section 111(b)(1)(B) that EPA
review and revise, if appropriate, the previously promulgated standards
of performance. Section 111(b)(1)(B) requires EPA, when revising the
standards, to follow the procedure required for the promulgation of
standards. Section 111b(1)(B) further requires publication of proposed
regulations, an opportunity for written comment, and requires the
Administrator to promulgate such standards as she ``deems
appropriate.'' The commenter correctly noted that a standard of
performance is defined as ``a standard for emissions of air pollutants
which reflects the degree of emission limitation achievable through the
application of the best system of emission reduction which (taking into
account the cost of achieving such reduction and any nonair quality
health and environmental impact and energy requirements) the
Administrator determines has been adequately demonstrated.'' 42 U.S.C.
7411(a)(1). The commenter, however, takes the language from 42 U.S.C.
7411(g)(4) out of context. CAA section 111(g)(4) provides that the
Administrator shall revise a standard of performance upon application
of the Governor of a State that meets certain criteria. The language
quoted by the commenter appears in this section and describes what must
be included in the application of the Governor, and does not modify the
definition of a standard of performance in section 111(a)(1).
    To determine the appropriate level for a particular standard of
performance, EPA conducts an analysis to determine what emission rates
reflect application of ``best demonstrated technology'' or BDT. This
BDT analysis includes consideration of available emission controls and
technologies. In the BDT analysis for controlling PM emissions from
coal dryers for this final rule, EPA explicitly considered alternate
processes for drying coal as well as add-on emission control
technologies. For modified facilities, EPA recognized the limitations
that may be associated with

the physical layout of existing dryers. For reconstructed facilities
and new facilities, however, we concluded that design options, and
alternative replacement technologies, could be taken into account
during the reconstruction or construction process. EPA concluded that
recirculation thermal dryers and indirect thermal dryers are both
adequately demonstrated and readily available technologies for drying
coal. It did not restrict its analysis, or the definition of affected
facility, to the once-through direct contact thermal dryers covered by
the existing NSPS standards for thermal dryers. Contrary to the
commenter's assertions, EPA neither presumed the use of existing once-
through direct contact thermal dryers nor merely codified existing
levels of performance achieved by such dryers. Instead, EPA concluded
that BDT for controlling PM emissions for new and reconstructed thermal
dryers is fabric filters applied to recirculation thermal dryers and
indirect thermal dryers. The PM standards in the final rule are based
on these conclusions.
    Although mechanical coal drying technologies, because they do not
burn fuel, may inherently produce lower air pollutant emissions
compared to some thermal drying technologies, they may not be
technically applicable, cost-effective, or the most energy efficient
for all possible coal drying applications that could be subject to
subpart Y. EPA does not, at this time, have data to support a
conclusion that standards based on an assumption that mechanical dryers
are BDT would be achievable by the industry as a whole (see National
Lime Ass'n v. EPA, 627 F.2d 416, 431 (1980)). Even though the
``adequately demonstrated'' requirement does not ``necessarily impl[y]
that any [covered facility] now in existence be able to meet the
proposed standards,'' Portland Cement, 486 F.2d at 391, EPA must
demonstrate that the standard is, in fact, achievable taking into
consideration variables that may affect emissions in different
circumstances and at different plants. National Lime, 627 F.2d at 433.
In fact, the type of coal drying technology used at a given facility is
influenced by a variety of factors, including type of facility, coal
moisture reduction requirements, availability of waste heat sources at
the coal processing location, and drying process energy requirements
including electrical power consumption. Mechanical drying techniques
are not suitable replacements for thermal dryers under all
circumstances. Mechanical drying techniques can remove free moisture
adsorbed onto the surface of the coal particles, as well as a portion
of the hydroscopic moisture contained by capillary action within
microfractures in the coal particles, but are ineffective at removing
inherent moisture (and, thus, would only be applicable at preparation
plants utilizing coal washing). Some type of thermal energy is required
to remove the interstitial and molecular (inherent) moisture from the
coal for applications where extremely low moisture content is
desirable. Therefore, mechanical drying techniques are not suitable
replacements for thermal dryers under all circumstances, and because
waste heat is not available at all locations, thermal dryers using
waste heat are not a technically possible substitute for thermal dryers
in all situations. EPA will continue to follow the development of
mechanical drying techniques. To the extent the commenter is suggesting
that EPA should require use of a certain technology for drying coal and
coal preparation plants, EPA notes that CAA section 111(h), 42 U.S.C.
7411(h)(1) only allows the Administrator to promulgate design,
equipment, work practice, or operational standards if ``in the judgment
of the Administrator, it is not feasible to prescribe or enforce a
standard of performance.'' No such finding has been made here.
    In the BDT analysis for controlling SO2 emissions from
coal dryers for the final rule, EPA determined that BDT for modified
and reconstructed thermal dryers is a wet scrubber with a scrubbing
reagent (e.g., an upgraded venturi scrubber with sodium hydroxide or
packed bed scrubber with lime). The information that EPA has indicates
that all of the once-through direct contact thermal dryers currently
use venturi scrubbers for PM control. Thus, the upgraded venturi
scrubber with sodium hydroxide or the packed bed scrubber with lime
(would be in addition to the venturi scrubber) would provide
SO2 control, along with additional PM control necessary for
reconstructed thermal dryers to meet their PM and opacity limits. For
new thermal dryers, we determined that BDT for controlling
SO2 emissions is the injection of sodium hydroxide directly
to the venturi scrubber fluid or injection of a sodium-based sorbent
into the combustion gases prior to the drying chamber. For a new once-
through direct contact thermal dryer, the caustic injection into the
scrubber fluid for SO2 control would be in addition to a
high-energy venturi scrubber which is the likely control technology
that would be used for PM and opacity control. For a new coal
recirculation thermal dryer, sorbent injection into the combustion
gases for SO2 control would be used in conjunction with a
fabric filter which is the likely control technology that would be used
for PM and opacity control. EPA determined that BDT for controlling
NOX emissions from new, reconstructed, and modified thermal
dryers is combustion controls. Combustion controls can be used across
the range of thermal dryers currently in use. Combustion controls
include low NOX burners, staged combustion, co-firing with
natural gas or liquefied petroleum gas, and flue gas recirculation. BDT
for controlling CO emissions was determined to be good combustion
practices. Good combustion practices limit the formation of CO (and
VOC) by providing sufficient oxygen in the combustion zone such that
complete combustion can occur. Maintaining appropriate combustion zone
temperature and gas residence time also are good combustion practices,
as is proper operation and maintenance of the dryer.
    Comment: Several commenters stated that the proposed PM emission
limit of 0.010gr/dscf for new coal dryers does not reflect an adequate
margin of compliance to the fabric filter test data used and that the
proposed limit needs to be less stringent because the test data do not
represent a demonstration of the performance of control technology over
the life of the facility and over the range of operating conditions
that may be encountered at thermal dryers. Therefore, the commenters
recommended that the PM emission limit remain at the current NSPS
emission rate of 0.031 gr/dscf. Other commenters presented an opposing
argument that the proposed PM limit needs to be lower. The commenters
asserted that the compliance margin of two to three times applied by
EPA to fabric filter test data is unjustified in that EPA has not
explained why use of a fabric filter to control PM emissions would
require such a large margin of safety, given the demonstrated
performance of fabric filters for the subject source as well as similar
sources in numerous other industries.
    Response: EPA has reviewed the available PM emissions and permit
data for thermal dryers; no additional PM data were provided during the
public comment period. We believe that the proposed PM limit of 0.023
g/dscm (0.010 gr/dscf) for new thermal dryers is appropriate. We
further believe that, in the presence of limited data showing actual
emissions, permit information can be useful in determining whether a
particular emission limit is achievable

by sources in the source category. EPA has available three emission
test data points for fabric filters installed on thermal dryers,
including two tests one year apart at one facility. We believe that
these three data points provide adequate information on the performance
of the technology. However, EPA also has examined the permit data which
identifies emission limits agreed upon between State regulators and the
regulated community and believe that the emission limits contained in
permits constitute limits that could be achieved over the range of
operating conditions to be found within the industry. Nat'l. Lime
Ass'n. v. EPA, 627 F.2d 416, 431 (DC Cir. 1980) requires EPA to show
that the limit selected is achievable under different conditions at an
individual plant and conditions at different plants. EPA believes that
basing the emission limit on use of the data points from two
facilities, including two data sets from one facility, in conjunction
with the permit data, adequately accounts for the variability to be
found within the industry. Therefore, the final rule reflects no
changes to the proposed PM emission limit for new thermal dryers.
    Comment: Two commenters supported the proposal to revise the PM
limit for units reconstructed after April 28, 2008, to 0.045 g/dscm
(0.020 gr/dscf) and to maintain the existing 1976 rule's opacity limit
of less than 20 percent. In contrast, a third commenter disagreed with
the proposed PM standard for reconstructed dryers, which is twice as
high as the proposed standard for new dryers (0.010 gr/dscf). The
commenter stated that EPA must either require reconstructed dryers to
meet the same PM standards as new dryers, or explain why such limits do
not reflect BDT for reconstructed dryers. The commenter further stated
that EPA has not explained why it would not also be feasible to further
modify existing dryers, at the time of reconstruction, by converting
them to recirculation dryers or by otherwise modifying them to use
fabric filters, and that EPA must examine whether a fabric filter is a
feasible option for control of PM emissions from reconstructed dryers.
Another commenter recommended that the PM emission limitations not be
changed from the current NSPS emission rate of 0.031 gr/dscf. The
commenter believes that the limited data EPA has cited to justify
reducing the limit by a third for reconstructed dryers using the same
control technology is insufficient to conclude that thermal dryers with
the specified control equipment would, throughout the life of the
facility, be able to continuously meet a lower emission limit than the
current NSPS provide.
    Response: EPA agrees that units undergoing reconstruction as
defined in the CAA could undergo the conversions necessary to install
BDT for PM emissions control for new thermal dryers and, thus, meet the
PM and opacity limits of new facilities. Thus, the regulation has been
changed accordingly.
    Comment: One commenter stated that information in the supplemental
proposal preamble and support documentation show that the
SO2 emissions limits for new and reconstructed coal dryers
should be set lower than the proposed level. The commenter explained
that the proposal preamble states that ``[w]et scrubbers designed
specifically for SO2 control are able to achieve greater
than 95 percent reduction.'' EPA, however, dismisses wet scrubbers from
further consideration, as the wet scrubbers currently used on existing
thermal dryers are designed for PM control and not specifically for
SO2 controls, and high levels of SO2 control may
be difficult to achieve without redesign of the wet scrubber. The
commenter asserted that this is not a valid reason for eliminating a
viable technology from consideration, and that wet scrubbers are widely
used on similar sources and, as EPA recognizes, routinely achieve
greater than 95 percent reduction. Even if EPA ultimately determines
that wet scrubbers are not BDT for SO2 control for some coal
dryers, the commenter stated that the subpart Y SO2 emission
limit must be more stringent for those dryers. The commenter cited as
support EPA's assertion that sorbent injection controls that use
sodium-based agents can meet removal efficiencies of 90 percent.
    Response: EPA indicated in the May 27, 2009, supplemental proposal
that it was considering an SO2 percent reduction requirement
of between 50 and 90 percent for the final rule (74 FR 25311). EPA has
reviewed the available data and believes that a 90 percent removal
requirement is appropriate for new, reconstructed, and modified thermal
dryers. Affected facilities that meet the alternative SO2
emissions limit of 85 ng/J (0.20 lb/MMBtu) heat input are not required
to meet this requirement.
    Comment: Many commenters stated that EPA's proposal to set a
combined NOX and CO emissions limit for coal dryers is
inappropriate. Another commenter stated explicitly that separate
NOX and CO emissions limits must be set for coal dryers.
Reasons cited by individual commenters include the following.
     A combined NOX/CO limit enables permitting
authorities to trade off higher NOX emissions for lower CO
emissions, and vice versa. EPA's proposed approach of allowing States
to trade NOX and CO emissions at essentially a 1:1 ratio
ignores that CO and NOX are different pollutants that do not
have equivalent environmental impacts.
     A combined NOX/CO limit violates CAA for the
reason that the proposed combined limit is based on an assumed CO
emissions rate that does not reflect application of the best system of
emission reduction. EPA admits that the presumed levels of CO emissions
(0.45 lb/MMBtu for modified and reconstructed dryers and 0.25 lb/MMBtu
for new dryers) are levels that are already surpassed by nearly all
existing industrial boilers and has not explained why industrial
boilers would be capable of meeting more stringent CO limits than
thermal dryers.
     Test data provided in the docket indicates a wide
variation in test results, especially for CO. Test data is almost
exclusively based on bituminous coal drying operations, and these data
do not support the conclusion that the proposed combined
NOX/CO limit is applicable across all grades of coal.
     Combustion controls currently represent BDT in use by the
source category. Going beyond the demonstrated technologies for the
source category (e.g., incorporating post combustion control
technologies, specifically selective non-catalytic reduction (SNCR) on
new thermal dyers) is not required in developing NSPS.
     EPA does not have sufficient data to support the proposed
NOX standards, and EPA has not demonstrated that thermal
dryers with different design and function can meet the same limitations
as coal-fired boilers. Also, EPA has identified combustion controls
that may not be available as the basis for the proposed NOX
standards, especially for existing thermal dryers.
    Response: EPA believes that the use of a combined NOX/CO
limit is appropriate because it acknowledges the inherent trade-off
between the two pollutants (i.e., a decrease in emissions of one often
leads to an increase in emissions of the other). EPA has based the
combined NOX/CO limit on what it believes to be adequate
data from thermal dryers at subpart Y facilities; thus, the comparison
to industrial boilers is misplaced. In addition, as the Court has
noted, ``[t]he `adequately demonstrated' requirement does not imply
that any [covered facility] now in

existence be able to meet the proposed standards. CAA section 111 looks
toward what may be fairly be projected for the regulated future, rather
than the state of the art at present.'' Portland Cement Ass'n v.
Ruckelshaus, 486 F.2d 375, 391 (DC Cir. 1973).

E. Coal Processing and Conveying Equipment, Coal Storage Systems,
Transfer and Loading Systems, and Open Storage Piles Standards

    Comment: Many commenters acknowledged EPA's decision in the
supplemental proposal to add fogging systems and passive enclosure
containment systems (PECS) to its list of BDT for coal processing and
conveying equipment, but stated that EPA's BDT determination still
failed to meet the requirements of CAA Sec.  111. Additional commenters
also disagreed with EPA's finding of chemical suppression to be BDT for
coal handling equipment processing bituminous coal, stating that EPA's
current BDT approach of focusing only on emission control systems with
the highest control efficiency is an inappropriate, unjustified
departure from its prior technology assessments for coal preparation
plants. Commenters stated that EPA's evaluation of technologies for
control of fugitive emissions from coal-handling should have included
wet suppression. Further, commenters asserted that EPA must explain why
it has either rejected or ignored Peabody Energy's compelling
comparison of wet suppression costs and chemical suppression costs. The
commenters believe that the record demonstrates that cost
considerations favor the use of wet suppression instead of chemical
suppression for controlling fugitive emissions from preparation
facilities at coal mines.
    Response: As pointed out by the commenters, EPA has added fogging
systems and PECS as technologies representative of BDT for coal-
handling equipment processing subbituminous and lignite coals (fabric
filters and wet extraction scrubbers also are considered representative
of BDT). As noted in the supporting documentation (see EPA-HQ-OAR-2008-
0260-0083, pp. 1-2), EPA has reviewed our determination of chemical
suppressants as BDT for coal-handling equipment processing bituminous
coal. However, as also noted in the support document, an owner/operator
may use any combination of controls at a particular site as long as the
requirements of subpart Y are met. With respect to Peabody Energy's
comparison of wet suppression and chemical suppression costs, their
estimates indicate that the incremental cost of chemical suppression as
compared to wet suppression is $4,400 per ton of PM removed.
    Comment: Many commenters stated that the data used by EPA does not
demonstrate the continuous achievability of the proposed opacity limit
of 5 percent. Commenters further stated that the promulgation of NSPS
based upon inadequate proof of achievability would defy the
Administrative Procedure Act's mandate against action that is
arbitrary, capricious, an abuse of discretion, or otherwise not in
accordance with the law. National Lime Ass'n v. EPA, 627 F.2d 416, 430
(DC Cir. 1980).
    Response: In the May 27, 2009, supplemental proposal, EPA requested
comment on whether an opacity limit of less than 10 percent is more
appropriate than the proposed limit of 5 percent. We also requested
comment on whether the 5 percent limit is achievable on a long-term
basis for all subpart Y coal-handling facilities under all operating
conditions and whether the limit provides an adequate compliance
margin. As we pointed out in supporting documentation (see EPA-HQ-OAR-
2008-0260-0083, pp. 3-4), the data used to establish the supplemental
proposal's 5 percent opacity level were primarily from initial
compliance tests, and the reported highest 6-minute average opacity
reading was 5 percent for a recently installed facility. Data for coal
handling facilities submitted by commenters in response to the
supplemental proposal indicate that 60 percent of the highest 6-minute
average opacity readings are less than 10 percent. Upon reconsideration
of EPA's data and consideration of the public comments and supporting
data, EPA has determined that an opacity limit of less than 10 percent
is more appropriate for all coal-handling equipment. An opacity limit
of 10 percent will allow for control equipment degradation, adverse
conditions, and variability that would not be reflected in initial
compliance tests. Thus, the final rule requires coal handling
facilities to maintain opacity levels of less than 10 percent.
    Comment: Many commenters requested that subpart Y provide the same
compliance alternative for affected sources located in enclosed
buildings as that provided in 40 CFR part 60, subpart OOO. Under
subpart OOO, performance standards and applicable monitoring techniques
for the exhaust systems of these buildings have been specified as an
appropriate alternative to individual compliance by each affected
facility enclosed within the building. Commenters explained that
building enclosure of certain coal handling and processing operations
at coal preparation plants has become more commonplace throughout the
industry for several reasons, including the ability to effectively
control emissions and to protect personnel and equipment from the
elements. These commenters urged EPA to extend this practical and
achievable alternative to subpart Y and recognize within the rule the
beneficial control technique of enclosing coal preparation facilities
within buildings.
    Response: EPA has determined that if a building in which affected
coal processing and conveying equipment (e.g., breakers, crushers,
screens, conveying systems), coal storage systems, and coal transfer
system operations are enclosed is found to be in compliance with the
subpart Y limits applicable to the affected facilities enclosed in the
building, then the affected facilities enclosed in that building also
are in compliance. Because exhaust from a building that encloses
affected facilities would be comprised of exhaust from the affected
facilities, it follows that in order for the building to be able to
meet a specific PM or opacity limit, each facility enclosed in the
building also would have to meet that same PM or opacity limit. If the