common back up fuel is distillate oil, which has a CO2
emission rate of 163 lb CO2/MMBtu. A non-base load natural
gas-fired combustion turbine burning 9 percent distillate oil and 91
percent natural gas has an emission rate of 121 lb CO2/
MMBtu, which rounds to 120 lb CO2/MMBtu using two
significant digits. Therefore, the vast majority of owners and
operators of non-base load natural gas-fired combustion turbines will
be able to achieve the standard using business-as-usual fuels.
    While the emission reductions that will result from restricting the
use of fuels with higher CO2 emission rates is minor, the
compliance burden is also minimal. Owners and operators of non-base
load natural gas-fired combustion turbines burning fuels with
consistent chemical compositions that meet the clean fuels requirement
(e.g., natural gas, ethane, ethylene, propane, naphtha, jet fuel
kerosene, fuel oils No. 1 and 2, and biodiesel) will only need to
maintain records that they burned these fuels in the combustion
turbine. No additional recordkeeping or reporting will be required.
Owners and operators burning fuels with higher CO2 emission
rates and/or chemical compositions that vary (e.g., residual oil, non-
jet fuel kerosene, landfill gas) will have to follow the procedures in
part 98 of this part to determine the average CO2 emission
rate of the fuels burned during the applicable 12-operating-month
compliance period and submit quarterly reports to verify that they are
in compliance with the required emission standard.
d. Newly Constructed and Reconstructed Multi-Fuel-Fired Units
    We also are finalizing an input-based standard based on the use of
clean fuels, as opposed to an output-based standard, for multi-fuel
units for several reasons. Specifically, we do not currently have
continuous CO2 emissions data for multi-fuel-fired units, we
have not evaluated the potential efficiency impacts of different fuels,
and the range of carbon content of non-natural gas fuels complicates
establishing an appropriate output-based standard. Based on this lack
of data, we have concluded that we cannot establish an output-based
emission standard for multi-fuel-fired combustion turbines at this
time.
    The input-based emissions standard for this subcategory is based on
the use of clean fuels. The use of clean fuels will ensure that newly
constructed and reconstructed combustion turbines minimize
CO2 emissions during all periods of operation by limiting
the use of fuels with higher CO2 emission rates. To
accurately represent the BSER and limit the ability of units to co-fire
higher CO2 emitting fuels with natural gas, we have
concluded that it is necessary to use an equation based on the heat
input from natural gas to determine the applicable emission standard.
The 12-operating-month standard will vary from 120 lb CO2/
MMBtu to 160 lb CO2/MMBtu depending on the fraction of heat
input from natural gas. The standard will be calculated by adding the
product of the percent of heat input from natural gas and 120 with the
product of the heat input from non-natural gas fuels and 160. For
example, a combustion turbine that burns 80 percent natural gas and 20
percent distillate oil would be subject to an emission standard of 130
lb CO2/MMBtu (rounded to two significant figures), which is
equivalent to the actual emission rate of a unit burning this
combination of fuels. On the other hand, a combustion turbine that
burns 100 percent residual oil would be subject to an emission standard
of 160 lb CO2/MMBtu, but would have a higher actual emission
rate, and would thus be out of compliance. In this way, the standard
will restrict higher carbon fuels from being burned in multi-fuel-fired
units, but will be readily achievable by units burning clean fuels.
    According to information submitted to the EIA, the primary, non-
natural gas fuels used by combustion turbines today for the production
of electricity should all meet our definition of a clean fuel. Thus,
while the emission reductions that will result from restricting the use
of fuels with higher CO2 emission rates is minor, the
compliance burden is also minimal. Owners and operators of multi-fuel-
fired combustion turbines burning fuels with consistent chemical
compositions that meet the clean fuels requirement (e.g., natural gas,
ethylene, propane, naphtha, jet fuel kerosene, fuel oils No. 1 and 2,
and biodiesel) will only need to maintain records that they burned
these fuels in the combustion turbine. No additional recordkeeping or
reporting will be required. Owners and operators burning fuels with
higher CO2 emission rates and/or chemical compositions that
vary (e.g., residual oil, non-jet fuel kerosene, landfill gas) will
have to follow the procedures in part 98 of this part to determine the
average CO2 emission rate of the fuels burned during the
applicable 12-operating-month compliance period and submit quarterly
reports to verify that they are in compliance with the required
emission standard.
e. Modified Units
    The EPA is not finalizing the proposed emission standards for
stationary combustion turbines that conduct modifications. As explained
in Section XV below, we are withdrawing the June 2014 proposal with
respect to these sources. We received a significant number of comments
asserting that modified combustion turbines could not meet the proposed
emission standards of 1,000 lb/MWh-g for large turbines and 1,100 lb/
MWh-g for small turbines. For the reasons explained in Section IX.B.1
above, we have decided not to subcategorize combustion turbines based
on size for a number of reasons and are setting a single standard of

1,000 lb/MWh-g for all base load natural gas-fired turbines instead.
While we are confident that all new and reconstructed units will be
able to achieve this standard, we are less confident that all smaller
combustion turbines that undertake a modification, specifically those
that were constructed prior to 2000, will be able to do so. Until we
have the opportunity to further investigate the full range of
modifications that turbine owners and operators might undertake, we
consider it premature to finalize emission standards for these sources.
    Combustion turbines have unique characteristics that make
determining an appropriate emission standard for modified sources a
more challenging task than for coal-fired boilers. For example, each
combustion turbine engine has a specific corresponding combustor. The
development of more efficient combustor upgrades for existing turbine
designs typically requires manufacturers to expend considerable
resources. Consequently, not all manufacturers offer combustor upgrades
for smaller or older designs because it would be difficult to recoup
their investment. In contrast, efficiency upgrades for boilers can
generally be installed regardless of the specific boiler's
characteristics.
    In addition, natural gas has the lowest CO2 emission
rate (in terms of lb CO2/MMBtu) of any fossil fuel. As a
result, an owner or operator that adds the ability to burn a back up
fuel, such as distillate oil, to an existing turbine would likely
trigger an NSPS modification. This is a relatively low-capital-cost
upgrade that would significantly increase a unit's potential hourly
emission rate, even though the annual emissions increase would be
relatively minor because operating permits generally limit the amount
of distillate oil that a unit can burn. We need to conduct additional
analysis to determine an appropriate emission standard for units that
undertake this type of modification, which does not involve any of the
combustion turbine components that impact efficiency.
    To be clear, the EPA is not reaching a final decision that
modifications should be subject to different requirements than we are
finalizing in this rule for new and reconstructed sources. We have made
no decisions, and this matter is not concluded. We plan to continue to
gather information, consider the options for modifications, and develop
a new proposal for modifications in the future. Therefore, the EPA is
withdrawing the proposed standards for all combustion turbines that
conduct modifications and is not issuing final standards for those
sources at this time. See Section XV below. We note that the effect of
this withdrawal is that modified combustion turbines will continue to
be existing sources subject to section 111(d).\541\
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    \541\ As discussed above in Section VI.A of this preamble, a
modified source that is not covered by a final or pending proposed
standard continues to be an ``existing source'' and so will be
covered by requirements under section 111(d). Under the definition
of ``existing source'' in section 111(a)(6), an existing source is
any source that is not a new source. Under the definition of ``new
source'' in section 111(a)(2), a modified source is a new source
only if the modification occurs after the publication of regulations
(or proposed regulations, if earlier) that will be applicable to
that source. Because we are not finalizing regulations with respect
to modified steam turbines, and are withdrawing the proposal with
respect to such sources, there are neither final regulations nor
pending proposed regulations which will be applicable to such
modifications.
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X. Summary of Other Final Requirements for Newly Constructed, Modified,
and Reconstructed Fossil Fuel-Fired Electric Utility Steam Generating
Units and Stationary Combustion Turbines

    This section describes the final action's requirements regarding
startup, shutdown, and malfunction; continuous monitoring; emissions
performance testing; continuous compliance; and notification,
recordkeeping, and reporting for newly constructed, modified, and
reconstructed affected steam generating units and combustion turbines.
We also explain final decisions regarding several of these
requirements.

A. Startup, Shutdown, and Malfunction Requirements

    In its 2008 decision in Sierra Club v. EPA, 551 F.3d 1019 (D.C.
Cir. 2008), the D.C. Circuit vacated portions of two provisions in the
EPA's CAA section 112 regulations governing the emissions of hazardous
air pollutants (HAP) during periods of startup, shutdown, and
malfunction (SSM). Specifically, the Court vacated the SSM exemption
contained in 40 CFR 63.6(f)(1) and 40 CFR 63.6(h)(1), holding that
under section 302(k) of the CAA, emissions standards or limitations
must be continuous in nature and that the SSM exemption violates the
CAA's requirement that some CAA section 112 standards apply
continuously.
    Consistent with Sierra Club v. EPA, the EPA has established
standards in this rule that apply at all times. In establishing the
standards in this rule, the EPA has taken into account startup and
shutdown periods and, for the reasons explained below as well as in
Section V.J.1 above, has not established alternate standards for those
periods. Specifically, startup and shutdown periods are included in the
compliance calculation as periods of partial load. The final method to
calculate compliance is to sum the emissions for all operating hours
and to divide that value by the sum of the electric energy output (and
useful thermal energy output, where applicable for affected CHP EGUs),
over a rolling 12-operating-month period. In their compliance
determinations, sources must incorporate emissions from all periods,
including startup or shutdown, during which fuel is combusted and
emissions are being monitored, in addition to all power produced over
the periods of emissions measurements. As explained in Section V.J.1,
given that the duration of startup or shutdown periods is expected to
be small relative to the duration of periods of normal operation and
that the fraction of power generated during periods of startup or
shutdown is expected to be very small, the impact of these periods on
the total average over a 12-operating-month period is expected to be
minimal.
    Periods of startup, normal operations, and shutdown are all
predictable and routine aspects of a source's operations. Malfunctions,
in contrast, are neither predictable nor routine. Instead they are, by
definition sudden, infrequent and not reasonably preventable failures
of emissions control, process or monitoring equipment. (40 CFR 60.2).
The EPA interprets CAA section 111 as not requiring emissions that
occur during periods of malfunction to be factored into development of
section 111 standards. Nothing in CAA section 111 or in case law
requires that the EPA consider malfunctions when determining what
standards of performance reflect the degree of emission limitation
achievable through ``the application of the best system of emission
reduction'' that the EPA determines is adequately demonstrated. While
the EPA accounts for variability in setting emissions standards,
nothing in CAA section 111 requires the agency to consider malfunctions
as part of that analysis. A malfunction should not be treated in the
same manner as the type of variation in performance that occurs during
routine operations of a source. A malfunction is a failure of the
source to perform in a ``normal or usual manner'' and no statutory
language compels the EPA to consider such events in setting CAA section
111 standards of performance.
    Further, accounting for malfunctions in setting emission standards
would be difficult, if not impossible, given the myriad different types
of malfunctions that can occur across all sources in the

category and given the difficulties associated with predicting or
accounting for the frequency, degree, and duration of various
malfunctions that might occur. As such, the performance of units that
are malfunctioning is not ``reasonably'' foreseeable. See, e.g., Sierra
Club v. EPA, 167 F.3d 658, 662 (D.C. Cir. 1999) (``The EPA typically
has wide latitude in determining the extent of data-gathering necessary
to solve a problem. We generally defer to an agency's decision to
proceed on the basis of imperfect scientific information, rather than
to `invest the resources to conduct the perfect study.' '') See also,
Weyerhaeuser v Costle, 590 F.2d 1011, 1058 (D.C. Cir. 1978) (``In the
nature of things, no general limit, individual permit, or even any
upset provision can anticipate all upset situations. After a certain
point, the transgression of regulatory limits caused by `uncontrollable
acts of third parties,' such as strikes, sabotage, operator
intoxication or insanity, and a variety of other eventualities, must be
a matter for the administrative exercise of case-by-case enforcement
discretion, not for specification in advance by regulation.''). In
addition, emissions during a malfunction event can be significantly
higher than emissions at any other time of source operation. For
example, if an air pollution control device with 99 percent removal
goes off-line as a result of a malfunction (as might happen if, for
example, the bags in a baghouse catch fire) and the emission unit is a
steady state type unit that would take days to shut down, the source
would go from 99 percent control to zero control until the control
device was repaired. The source's emissions during the malfunction
would be 100 times higher than during normal operations. As such, the
emissions over a 4-day malfunction period would exceed the annual
emissions of the source during normal operations. As this example
illustrates, accounting for malfunctions could lead to standards that
are not reflective of (and significantly less stringent than) levels
that are achieved by a well-performing, non-malfunctioning source. It
is reasonable to interpret CAA section 111 to avoid such a result. The
EPA's approach to malfunctions is consistent with CAA section 111 and
is a reasonable interpretation of the statute.
    Given that compliance with the emission standard is determined on a
12-operating-month rolling average basis, the impact of periods of
malfunctions on the total average over a 12-operating-month period is
expected to be minimal. Thus, malfunctions over that period are not
likely to result in a violation of the standard.
    In the unlikely event that a source fails to comply with the
applicable CAA section 111 standards as a result of a malfunction
event, the EPA would determine an appropriate response based on, among
other things, the good faith efforts of the source to minimize
emissions during malfunction periods, including preventative and
corrective actions, as well as root cause analyses to ascertain and
rectify excess emissions. The EPA would also consider whether the
source's failure to comply with the CAA section 111 standard was, in
fact, sudden, infrequent, not reasonably preventable and was not
instead caused in part by poor maintenance or careless operation. 40
CFR 60.2 (definition of malfunction).
    If the EPA determines in a particular case that an enforcement
action against a source for violation of an emission standard is
warranted, the source can raise any and all defenses in that
enforcement action and the federal district court will determine what,
if any, relief is appropriate. The same is true for citizen enforcement
actions. Similarly, the presiding officer in an administrative
proceeding can consider any defense raised and determine whether
administrative penalties are appropriate.
    In summary, the EPA interpretation of the CAA and, in particular,
CAA section 111 is reasonable and encourages practices that will avoid
malfunctions. Administrative and judicial procedures for addressing
exceedances of the standards fully recognize that violations may occur
despite good faith efforts to comply and can accommodate those
situations.
    In the January 2014 proposal for newly constructed EGUs, the EPA
had proposed to include an affirmative defense to civil penalties for
violations caused by malfunctions in an effort to create a system that
incorporates some flexibility, recognizing that there is a tension,
inherent in many types of air regulation, to ensure adequate compliance
while simultaneously recognizing that despite the most diligent of
efforts, emission standards may be violated under circumstances
entirely beyond the control of the source. Although the EPA recognized
that its case-by-case enforcement discretion provides sufficient
flexibility in these circumstances, it included the affirmative defense
to provide a more formalized approach and more regulatory clarity. See
Weyerhaeuser Co. v. Costle, 590 F.2d 1011, 1057-58 (D.C. Cir. 1978)
(holding that an informal case-by-case enforcement discretion approach
is adequate); but see Marathon Oil Co. v. EPA, 564 F.2d 1253, 1272-73
(9th Cir. 1977) (requiring a more formalized approach to consideration
of ``upsets beyond the control of the permit holder''). Under the EPA's
regulatory affirmative defense provisions, if a source could
demonstrate in a judicial or administrative proceeding that it had met
the requirements of the affirmative defense in the regulation, civil
penalties would not be assessed. Recently, the U.S. Court of Appeals
for the District of Columbia Circuit vacated an affirmative defense in
one of the EPA's CAA section 112 regulations. NRDC v. EPA, 749 F.3d
1055 (D.C. Cir., 2014) (vacating affirmative defense provisions in CAA
section 112 rule establishing emission standards for Portland cement
kilns). The court found that the EPA lacked authority to establish an
affirmative defense for private civil suits and held that under the
CAA, the authority to determine civil penalty amounts in such cases
lies exclusively with the courts, not the EPA. Specifically, the Court
found: ``As the language of the statute makes clear, the courts
determine, on a case-by-case basis, whether civil penalties are
`appropriate.''' See NRDC at 1063 (``[U]nder this statute, deciding
whether penalties are `appropriate' in a given private civil suit is a
job for the courts, not EPA.'').\542\ In light of NRDC, the EPA is not
including a regulatory affirmative defense provision in this final
rule. As explained above, if a source is unable to comply with
emissions standards as a result of a malfunction, the EPA may use its
case-by-case enforcement discretion to provide flexibility, as
appropriate. Further, as the D.C. Circuit recognized, in an EPA or
citizen enforcement action, the court has the discretion to consider
any defense raised and determine whether penalties are appropriate. Cf.
NRDC, at 1064 (arguments that violations were caused by unavoidable
technology failure can be made to the courts in future civil cases when
the issue arises). The same is true for the presiding officer in EPA
administrative enforcement actions.\543\
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    \542\ The court's reasoning in NRDC focuses on civil judicial
actions. The court noted that ``EPA's ability to determine whether
penalties should be assessed for Clean Air Act violations extends
only to administrative penalties, not to civil penalties imposed by
a court.'' Id.
    \543\ Although the NRDC case does not address the EPA's
authority to establish an affirmative defense to penalties that is
available in administrative enforcement actions, the EPA is not
including such an affirmative defense in the final rule. As
explained above, such an affirmative defense is not necessary.
Moreover, assessment of penalties for violations caused by
malfunctions in administrative proceedings and judicial proceedings
should be consistent. Cf. CAA section 113(e) (requiring both the
Administrator and the court to take specified criteria into account
when assessing penalties).

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B. Continuous Monitoring Requirements

    The majority of comments received on the proposal supported the
EPA's use of existing monitoring requirements under the Acid Rain
Program, which are contained in 40 CFR part 75 requirements. In
response to this, the EPA is finalizing monitoring requirements that
incorporate and reference the part 75 monitoring requirements for the
majority of the CO2 and energy output monitoring
requirements while ensuring accuracy and stringency required under the
program.
    This final rule requires owners or operators of EGUs that combust
solid fossil fuel to install, certify, maintain, and operate continuous
emission monitoring systems (CEMS) to measure CO2
concentration, stack gas flow rate, and (if needed) stack gas moisture
content in accordance with 40 CFR part 75, in order to determine hourly
CO2 mass emissions rates (tons/hr).
    The rule allows owners or operators of affected EGUs that burn
exclusively gaseous or liquid fuels to install fuel flow meters as an
alternative to CEMS and to calculate the hourly CO2 mass
emissions rates using Equation G-4 in appendix G of part 75. To
implement this option, hourly measurements of fuel flow rate and
periodic determinations of the gross calorific value (GCV) of the fuel
are also required, in accordance with appendix D of part 75.
    In addition to requiring monitoring of the CO2 mass
emission rate, the rule requires EGU owners or operators to monitor the
hourly unit operating time and ``gross output'', expressed in megawatt
hours (MWh). The gross output includes electrical output plus any
mechanical output, plus 75 percent of any useful thermal output.
    The rule requires EGU owners or operators to prepare and submit a
monitoring plan that includes both electronic and hard copy components,
in accordance with 40 CFR 75.53(g) and (h). The electronic portion of
the monitoring plan should be submitted to the EPA's CAMD using the
Emissions Collection and Monitoring Plan System (ECMPS) Client Tool.
The hard copy portion of the plan should be sent to the applicable
state and EPA Regional office. Further, all monitoring systems used to
determine the CO2 mass emission rates have to be certified
according to 40 CFR 75.20 and section 6 of part 75, appendix A within
the 180-day window of time allotted under 40 CFR 75.4(b), and are
required to meet the applicable on-going quality assurance procedures
in appendices B and D of part 75.
    The rule requires all valid data collected and recorded by the
monitoring systems (including data recorded during startup, shutdown,
and malfunction) to be used in assessing compliance. Failure to collect
and record required data is a violation of the monitoring requirements,
except for periods of monitoring system malfunctions, repairs
associated with monitoring system malfunctions, and required monitoring
system quality assurance or quality control activities that temporarily
interrupt the measurement of stack emissions (e.g., calibration error
tests, linearity checks, and required zero and span adjustments).
    The rule requires only those operating hours in which valid data
are collected and recorded for all of the parameters in the
CO2 mass emission rate equation to be used for calculating
compliance with applicable emission limits. Additionally for EGUs using
CO2 CEMS, only unadjusted stack gas flow rate values should
be used in the emissions calculations. In this rule, part 75 bias
adjustment factors (BAFs) should not be applied to the flow rate data.
These restrictions on the use of part 75 data for part 60 compliance
are consistent with previous NSPS regulations and revisions.
Additionally if an affected EGU combusts natural gas and/or fuel oil
and the CO2 mass emissions rate are measured using Equation
G-4 in appendix G of part 75, then determination of site-specific
carbon-based F-factors using Equation F-7b in section 3.3.6 of appendix
F of part 75 is allowed, and use of these Fc values in the
emissions calculations instead of using the default Fc
values in the Equation G-4 nomenclature is also allowed.
    This final rule includes the following special compliance
provisions for units with common stack or multiple stack
configurations; these provisions are consistent with 40 CFR 60.13(g):
     If two or more EGUs share a common exhaust stack, are
subject to the same emission limit, and the operator is required to (or
elects to) determine compliance using CEMS, then monitoring the hourly
CO2 mass emission rate at the common stack instead of
monitoring each EGU separately is allowed. If this option is chosen,
the hourly gross electrical load (or steam load) is the sum of the
hourly loads for the individual EGUs and the operating time is
expressed as ``stack operating hours'' (as defined in 40 CFR 72.2).
Then, if compliance with the applicable emission limit is attained at
the common stack, each EGU sharing the stack will be in compliance with
the CO2 emissions limit.
     If the operator is required to (or elects to) determine
compliance using CEMS and the effluent from the EGU discharges to the
atmosphere through multiple stacks (or, if the effluent is fed to a
stack through multiple ducts and is monitored in the ducts), then
monitoring the hourly CO2 mass emission rate and the ``stack
operating time'' at each stack or duct separately is required. In this
case, compliance with the applicable emission limit is determined by
summing the CO2 mass emissions measured at the individual
stacks or ducts and dividing by the total gross output for the unit.
    The rule requires 95 percent of the operating hours in each
compliance period (including the compliance periods for the
intermediate emission limits) to be valid hours, i.e., operating hours
in which quality-assured data are collected and recorded for all of the
parameters used to calculate CO2 mass emissions. EGU owners
or operators have the option to use back up monitoring systems, as
provided in 40 CFR 75.10(e) and 75.20(d), to help meet this data
capture requirement. This requirement is separate from the requirement
for a source to demonstrate compliance with an applicable emission
standard. When demonstrating compliance with an emission standard the
calculation must use all valid data to calculate a compliance average
even if the percent of valid hours recorded in the period is less than
the 95 percent requirement.

C. Emissions Performance Testing Requirements

    Similarly to the comments received on monitoring for the proposal,
commenters in general supported the use of current testing requirements
required under the Acid Rain Program 40 CFR part 75 requirements. Thus
the EPA is finalizing requirements for performance testing as
consistent with part 75 requirements where appropriate to ensure the
quality and accuracy of data and measurements as required by the final
rule.
    In accordance with 40 CFR 75.64(a), the final rule requires an EGU
owner or operator to begin reporting emissions data when monitoring
system certification is completed or when the 180-day window in 40 CFR
75.4(b) allotted for initial certification of the monitoring systems
expires (whichever date is earlier). For EGUs subject to the

1,400 lb CO2/MWh-g) emission standard, the initial
performance test consists of the first 12 operating months of data,
starting with the month in which emissions are first required to be
reported. The initial 12-operating-month compliance period begins with
the first month of the first calendar year of EGU operation in which
the facility exceeds the capacity factor applicability threshold.
    The traditional 3-run performance tests (i.e., stack tests)
described in 40 CFR 60.8 are not required for this rule. Following the
initial compliance determination, the emission standard is met on a 12-
operating-month rolling average basis.

D. Continuous Compliance Requirements

    Commenters supported the use of a 12-operating-month rolling
average for the compliance period for the final standards. In response,
this final rule specifies that compliance with the 1,400 lb
CO2/MWh-g emission limit is determined on a 12-operating-
month rolling average basis, updated after each new operating month.
For each 12-operating-month compliance period, quality-assured data
from the certified Part 75 monitoring systems is used together with the
gross output over that period of time to calculate the average
CO2 mass emissions rate.
    The rule specifies that the first operating month included in the
initial 12-operating-month compliance period is the month in which
reporting of emissions data is required to begin under 40 CFR 75.64(a),
i.e., either the month in which monitoring system certification is
completed or the month in which the 180-day window allotted to finish
certification testing expires (whichever month is earlier).
    Initial compliance with the applicable emissions limit in kg/MWh is
calculated by dividing the sum of the hourly CO2 mass
emissions values by the total gross output for the 12-operating-month
period. Affected EGUs continue to be subject to the standards and
maintenance requirements in the CAA section 111 regulatory general
provisions contained in 40 CFR part 60, subpart A.
    Several commenters stated that the final rule should require
operators to round their calculated emissions rates to three
significant figures when comparing their actual rates to the standard.
These commenters said that allowing use of only two significant digits
when calculating the 12-operating-month rolling average emission rate
would constitute relaxation of the standard by 5 percent because an
actual emission rate of 1,049.9 lb CO2/MWh rounds to 1,000
lb of CO2 per MWh when only two significant figures are
required in the final step of compliance calculations. Commenters also
suggested that the emission limits be written in scientific notation
(e.g., 1.10 x 10-3 lb CO2/MWh) to clarify the number of
significant digits that should be used when evaluating compliance.
Other commenters suggested that the final step in compliance
calculations should reflect rounding the emission rate to the nearest
whole number using the ASTM rounding convention (ASTM E29).
    The General Provisions of Part 60 specify the rounding conventions
for compliance calculations at 40 CFR 60.13(h)(3) including the
provision that ``after conversion into units of the standard, the data
may be rounded to the same number of significant digits used in the
applicable subpart to specify the emission limit.''
    The final rule requires that the 12-operating-month rolling average
emission rate must be rounded to three significant figures if the
applicable emissions standard is greater than or equal to 1,000 (e.g.,
an actual emission rate of 1,004.9 lb CO2/MWh is rounded to
1,000 lb CO2/MWh); for standards of 1000 or less, the final
rule requires rounding the actual emission rate to two significant
figures (e.g., an actual emission rate of 454.9 kg CO2/MWh
is rounded to 450 kg CO2/MWh). Historically, many of the
emissions limits under part 60 have been expressed to two significant
digits (e.g., the original SO2 emission standard for coal-
fired units under Subpart D was 1.2 lb SO2/MMBtu). The
rounding conventions under the General Provisions allow the reporting
of all emission rates in the range from 1.15 to 1.249 as 1.2 lb
SO2/MMBtu. During compliance periods with emissions at the
lower end of this range, the operator is required to report higher
emissions than actually occurred; during compliance periods at the
upper end of this range the operator is allowed to report lower
emissions than actually occurred. In either case the absolute error
remains small because the emission rate in this example is a relatively
small numerical value. In addition, the required emission reductions
typically are large enough that rounding does not impact the emission
control strategy of affected units. However, the final standards for
CO2 emissions include numerical values that are larger than
many historical emissions standards and require a relatively small
percent reduction in emissions. Accordingly, it is appropriate to
require the use of three significant digits when completing compliance
calculations resulting in numerical values larger than 1,000. This is
particularly important when considering the relatively small emission
rate changes that may be required for compliance with the unit-specific
emission standards being finalized for modified steam generating and
IGCC units because a rounding error of 5 percent may be larger than the
percent difference between the affected unit's historically best
emission rate and the emission rate immediately preceding the
modification.
    The final rule requires rounding of emission rates with numerical
values greater than or equal to 1,000 to three significant figures and
rounding of rates with numerical values less than 1,000 to two
significant figures.

E. Notification, Recordkeeping, and Reporting Requirements

    Commenters supported the coordination of notification,
recordkeeping, and reporting required under this rule in conjunction
with the requirements already in place under part 75, so the EPA has
made the requirements as efficient and streamlined as possible with the
current requirements under part 75. The final rule requires an EGU
owner or operator to comply with the applicable notification
requirements in 40 CFR 75.61, 40 CFR 60.7(a)(1) and (a)(3), and 40 CFR
60.19. The rule also requires the applicable recordkeeping requirements
in subpart F of part 75 to be met. For EGUs using CEMS, the data
elements that are recorded include, among others, hourly CO2
concentration, stack gas flow rate, stack gas moisture content (if
needed), unit operating time, and gross electric generation. For EGUs
that exclusively combust liquid and/or gaseous fuel(s) and elect to
determine CO2 emissions using Equation G-4 in appendix G of
part 75, the key data elements in subpart F that are recorded include
hourly fuel flow rates, fuel usage times, fuel GCV, gross electric
generation.
    The rule requires EGU owners or operators to keep records of the
calculations they perform to determine the total CO2 mass
emissions and gross output for each operating month. Records of the
calculations performed to determine the average CO2 mass
emission rate (kg/MWh) and the percentage of valid CO2 mass
emission rates in each compliance period are required to be kept. The
rule also requires sources to keep records of calculations performed to
determine site-specific carbon-based F-factors for

use in Equation G-4 of part 75, appendix G (if applicable).
    Sources are required to keep all records for a period of 3 years.
All required records must be kept on-site for a minimum of two years,
after which the records can be maintained off-site.
    The rule requires all affected EGU owners/operators to submit
quarterly electronic emissions reports in accordance with subpart G of
part 75. The reports in appendix G that do not include data required to
calculate compliance with the applicable CO2 emission
standard are not required to be reported under this rule. The rule
requires the reports in 40 CFR 60.5555 to be submitted using the ECMPS
Client Tool. Except for a few EGUs that may be exempt from the Acid
Rain Program (e.g., oil-fired units), this is not a new reporting
requirement. Sources subject to the Acid Rain Program are already
required to report the hourly CO2 mass emission rates that
are needed to assess compliance with this rule.
    Additionally, in the final rule and as part of an agency-wide
effort to streamline and facilitate the reporting of environmental
data, the rule requires selected data elements that pertain to
compliance under this rule, and that serve the purpose of identifying
violations of an emission standard, to be reported periodically using
ECMPS.
    Specifically, EGU owners/operators must submit quarterly electronic
reports within 30 days after the end of each quarter consistent with
current part 75 reporting requirements. The first report is for the
quarter that includes the final (12th) operating month of the initial
12-operating-month compliance period. For that initial report and any
subsequent report in which the 12th operating month of a compliance
period (or periods) occurs during the calendar quarter, the average
CO2 mass emissions rate (kg/MWh) is reported for each
compliance period, along with the dates (year and month) of the first
and twelfth operating months in the compliance period and the
percentage of valid CO2 mass emission rates obtained in the
compliance period. The dates of the first and last operating months in
the compliance period clearly bracket the period used in the
determination, which facilitates auditing of the data. Reporting the
percentage of valid CO2 mass emission rates is necessary to
demonstrate compliance with the requirement to obtain valid data for 95
percent of the operating hours in each compliance period. Any
violations that occur during the quarter are identified. If there are
no compliance periods that end in the quarter, a definitive statement
to that effect must be included in the report. If one or more
compliance periods end in the quarter but there are no violations, a
statement to that effect must be included in the report.
    Currently, ECMPS is not programmed to receive the additional
information included in the report required under 40 CFR 60.5555(a)(2)
for affected EGUs. However, we will make the necessary modifications to
the system in order to fully implement the reporting requirements of
this rule upon promulgation.

XI. Consistency Between BSER Determinations for This Rule and the Rule
for Existing EGUs

    In the CAA section 111(d) rule for existing steam units and
combustion turbines that the EPA is promulgating at the same time as
this CAA section 111(b) rule, the EPA is identifying as part of the
BSER for those sources, building block 1 (for steam units, efficient
operation), building block 2 (for steam units, dispatch shift to
existing NGCC units), and building block 3 (for steam units and
combustion turbines, substitution of generation with new renewable
energy). In this section, we explain why the EPA is not identifying
building blocks 1, 2, or 3 as part of the BSER for new, modified, or
reconstructed steam generators or combustion turbines.

A. Newly Constructed Steam Generating Units

1. Preference for Technological Controls as the BSER for New EGUs
    As discussed in this preamble and in more detail in the preamble to
the CAA section 111(d) rule for existing sources, the phrase ``system
of emission reduction'' is undefined and provides the EPA with
discretion in setting a standard of performance under CAA section
111(b) or emission guidelines under CAA section 111(d). Because the
phrase by its plain language does not limit our review of potential
systems in either context, the same systems could be considered for
application in new and existing sources. That said, many other factors
and considerations direct us to focus on different systems when
establishing a standard of performance under CAA section 111(b) and an
emission guideline under CAA section 111(d). Thus, it is useful to
describe part of the underlying basis for the BSER--partial CCS--that
the EPA has determined for new steam units before discussing the
building blocks that form the BSER for existing units.
    For new steam generating units, the EPA is identifying, as the
BSER, systems of emission reduction that assure that these sources are
inherently low-emitting at the time of construction. The following
reasons support this approach to the BSER.
    New sources are expected to have long operating lives over which
initial capital costs can be amortized. Thus, new construction is the
preferred time to drive capital investment in emission controls. In
this case, the BSER for new steam generators, partial CCS, requires
substantial capital expenditures, which new sources are best able to
accommodate.
    While CAA section 111(b)(1)(B) and (a)(1) by their terms do not
mandate that the BSER assure that new sources are inherently low
emitting, that approach to the BSER is consistent with the legislative
history.\544\ See Section III.H.3.b.4 above. For instance, the 1970
Senate Committee Report explains that ``[t]he overriding purpose of
this section [concerning new source performance standards] would be to
prevent new air pollution problems, and toward that end, maximum
feasible control of new sources at the time of their construction is
seen by the committee as the most effective and, in the long run, the
least expensive approach.'' \545\ Existing sources, on the other hand,
would be regulated through emission standards, which were broadly
understood at the time to reflect available technology, alternative
methods of prevention and control, alternative fuels, processes, and
operating methods.\546\ \547\
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    \544\ Although Congress expressed a clear preference that new
sources would be ``designed, built, equipped, operated, and
maintained so as to reduce emissions to a minimum,'' the Senate
Committee Report also makes clear that the term standard of
performance ``refers to the degree of emission control which can be
achieved through process changes, operation changes, direct emission
control, or other methods.'' Sen. Rep. No. 91-1196 at 15-17, 1970
CAA Legis. Hist. at 415-17 (emphasis added).
    \545\ Sen. Rep. No. 91-1196 at 15-16, 1970 CAA Legis. Hist. at
416 (emphasis added).
    \546\ See 1970 CAA Amendments, Pub. L. 91-604, section 4, 84
Stat. 1676, 1679 (Dec. 31, 1970) (describing information that the
EPA must issue to the states and appropriate air pollution control
agencies along with the issuance of ambient air quality criteria
under Section 4 of the 1970 CAA titled ``Ambient Air Quality and
Emission Standards'').
    \547\ In the 1977 CAA Amendments, Congress revised section
111(a)(1) to mandate that the EPA base standards for new sources on
technological controls, but, at the same time, made clear that the
EPA was not required to base the emission guidelines for existing
sources on technological controls. In the 1990 CAA Amendments,
Congress repealed the section 111(a)(1) requirements that
distinguished between new and existing sources and largely restored
the 1970 CAA Amendments version of section 111(a)(1).

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2. Practical Implications of Including the Building Blocks
    Several practical considerations make the building blocks
inappropriate for new sources. Thus, for the following reasons, the EPA
does not consider it appropriate to include the building blocks as part
of the BSER for new sources:
a. Additional Cost
    Partial CCS will impose substantial (albeit reasonable) costs on
new steam-generating EGUs, and, as a result, the EPA does not believe
that including additional measures as part of the BSER would be
appropriate. One disadvantage in adding additional costs is that doing
so would make it more difficult for new steam-generating EGUs to
compete with new nuclear units. Because the BSER is selected after
considering cost (among other factors), the EPA is not required
to,\548\ and in this case believes it would not be appropriate to,
select the most stringent adequately demonstrated system of emission
reduction (through the combination of partial CCS and the building
blocks) for purposes of setting a standard of performance under CAA
section 111(b).
---------------------------------------------------------------------------

    \548\ For example, as early as a 1979 NSPS rulemaking for
affected EGUs, the EPA recognized that it was not required to
establish as the BSER the most stringent adequately demonstrated
system of emission reduction available, and instead could weigh the
amount of additional emission reductions against the costs. See 44
FR 52792, 52798 (Sept. 10, 1979) (``Although there may be emission
control technology available that can reduce emissions below those
levels required to comply with standards of performance, this
technology might not be selected as the basis of standards of
performance due to costs associated with its use. Accordingly,
standards of performance should not be viewed as the ultimate in
achievable emission control. In fact, the Act requires (or has
potential for requiring) the imposition of a more stringent emission
standard in several situations.'').
---------------------------------------------------------------------------

    Building block 1 measures are not appropriate (or would be
redundant) because the BSER for new steam generating units is based on
highly efficient supercritical technology, i.e., state-of-the-art,
efficient equipment. See Section V.K above. Accordingly, there is
little improvement in efficiency that can be justified as part of the
BSER.
    Building block 2 and 3 measures are not appropriate for the BSER
because new steam units would have a significantly limited range of
options to implement building blocks 2 and 3. The new source
performance standard was proposed and is being finalized as a rate-
based standard. Thus, if building blocks 2 and 3 were included in the
BSER, a more stringent rate-based standard would be applicable to all
new sources. However, it is conceivable that the EPA could propose a
hybrid standard that would include both an emission-rate limit that
reflects partial CCS and a requirement for allowances that reflects
building blocks 2 and 3. Accordingly, the following discussion assumes
either a rate-based or mass-based standard, or part of a hybrid
standard.
    In both a rate-based program and a mass-based program, building
blocks 2 and 3 measures can be implemented through a range of methods,
including trading with other EGUs. While it is not necessarily the case
that every existing source will be able to implement each of the
methods, in general, existing sources will have a range of measures to
choose from. However, at least some of those methods may not be
available to new sources, which would render compliance with their
emission limits more challenging and potentially more costly.
    One example is emission trading with other affected EGUs. For
existing sources, emission trading is an important option for
implementing the building blocks. There are large numbers of existing
sources, and they will become subject to the section 111(d) standards
of performance at the same time. It may be more cost-effective for some
to implement the building blocks than others, and, as a result, some
may over-comply and some may under-comply, and the two groups may trade
with each other. Because of the large numbers of existing sources, the
trading market can be expected to be robust. Trading optimizes
efficiency. As a result, existing sources have more flexibility in the
overall amount of their investment in building blocks 2 and 3 and can
adjust investment obligations among themselves through emissions
trading.
    In contrast, new sources construct one at a time, and it is unknown
how many new sources there will be. Without a sizeable number of new
sources, there will not be a robust trading market. Thus, a new source
cannot count on being able to find a new source trading partner. In
addition, it is not possible to count on new sources being able to
trade with existing sources, for several reasons. First, as noted,
there are indications in the legislative history that new sources
should be well-controlled at the source, which casts doubt on whether
new sources should be allowed to meet their standards through the
purchase of emission credits. Second, new sources must meet their
standards of performance as soon as they begin operations. If they do
so before the year 2022, when existing sources become subject to
section 111(d) state plan standards of performance, no existing sources
will be available as trading partners.
    In addition, for section 111(d) sources, we are granting a 7-year
period of lead-time for the implementation of the building blocks. This
is due, in part, to the benefits of allowing the ERC and allowance
markets to develop. However, the new source standards take effect
immediately, so new sources would not have the advantage of this lead
time were they subject to more stringent standards that also reflected
the building blocks.\549\
---------------------------------------------------------------------------

    \549\ At least in theory, we could consider promulgating a
standard of performance for new affected EGUs that becomes more
stringent beginning in 7 years, based on a more stringent BSER. We
are not inclined to adopt that approach because section 111(b)(1)(B)
requires that we review and, if necessary, revise the section 111(b)
standards of performance no later than every 8 years anyway.
---------------------------------------------------------------------------

    In addition, if there are an unexpectedly large number of new
sources, then they would be obliged to invest in greater amounts of
building blocks 2 and 3, and that could reduce the amounts of building
blocks 2 and 3 available for existing sources, and thereby raise the
costs of building blocks 2 and 3 for existing sources. This could
compromise the BSER under section 111(d) and undermine the ability of
existing sources to comply with their section 111(d) obligations.\550\
---------------------------------------------------------------------------

    \550\ The EPA is authorized to consider the BSER for new and
existing sources in conjunction with each other. In the 1977 CAA
Amendments, Congress revised section 111(a)(1) to require
technological controls for new combustion sources at least in part
because this requirement would preclude new sources from relying on
low-sulfur coal to achieve their emission limits, which, in turn,
would free up low-sulfur coal for existing sources.
---------------------------------------------------------------------------

B. New Combustion Turbines

    For new combustion turbines, the building blocks are not
appropriate as part of the BSER either. Building block 1 is limited to
steam generating units, and therefore has no applicability to new
combustion turbines. Measures comparable to those in building block 1
would not be appropriate because new highly efficient NGCC construction
already entails high efficiency equipment and operation. Building block
2 is also limited to steam generating units and is not appropriate as
part of the BSER for new NGCC units because it would not result in any
emission reductions.
    The reasons why building block 3 are not appropriate are the same
as discussed above for why building blocks 2 and 3 are not appropriate
for new steam generating units (limited range of options for
implementation (including lack of availability of trading), lack of

lead-time for implementation, and the possibility of reducing the
availability of renewable energy for existing sources).

C. Modified and Reconstructed Steam and NGCC Units

    For modified and reconstructed steam generators, the EPA identified
the BSER as maintenance of high efficiency or implementation of a
highly efficient unit. The resulting emission limit must be met over
the specified time period and cannot be deviated from or averaged. As a
result, a modified or reconstructed steam generator generally will
require ongoing maintenance and may find it prudent to operate below
its limit as a safety margin. This represents a substantial commitment
of resources. For these units, the additional costs of implementing the
building blocks would not be appropriate.
    In addition, building block 1 is not appropriate for modified or
reconstructed steam generating units because the BSER for these units
is already based on highly efficient performance. For the same reasons,
it does not make sense to attempt to develop the analogue to building
block 1 for reconstructed NGCC units--the BSER for them, too, is
already based on highly efficient performance.
    Building block 2 is not appropriate for reconstructed NGCC units
because it would not yield any reductions.
    Building blocks 2 and 3 are not appropriate for modified or
reconstructed steam generators, and building block 3 is not appropriate
for reconstructed NGCC units, for the same reasons that they are not
appropriate for new EGUs, as described above (limited range of options
for implementation (including lack of availability of trading), lack of
lead-time for implementation, and the possibility of reducing the
availability of renewable energy for existing sources).

XII. Interactions With Other EPA Programs and Rules

A. Overview

    This final rule will, for the first time, regulate GHGs under CAA
section 111. In Section IX of the preamble to the proposed rule, the
EPA addressed how regulation of GHGs under CAA section 111 could have
implications for other EPA rules and for permits written under the CAA
Prevention of Significant Deterioration (PSD) preconstruction permit
program and the CAA Title V operating permit program. The EPA proposed
to adopt provisions in the regulations that explicitly addressed some
of these implications.
    For purpose of the PSD program, the EPA is finalizing provisions in
part 60 of its regulations that make clear that the threshold for
determining whether a PSD source must satisfy the BACT requirement for
GHGs continues to apply after promulgation of this rule. This rule does
not require any additional revisions to State Implementation Plans. As
discussed further below, this final rule may have bearing on the
determination of BACT for new, modified, and reconstructed EGUs that
require PSD permits. With respect to the Title V operating permits
program, this rule does not affect whether sources are subject to the
requirement to obtain a Title V operating permit based solely on
emitting or having the potential to emit GHGs above major source
thresholds. However, this rule does have some implications for Title V
fees, which the EPA is addressing in this final rule.
    Finally, the fossil fuel-fired EGUs covered in this rule are or
will be potentially impacted by several other recently finalized or
proposed EPA rules, and such potential interactions with other EPA
rules are discussed below.

B. Applicability of Tailoring Rule Thresholds Under the PSD Program

    In our January 8, 2014 proposal, the EPA proposed to adopt
regulatory language in 40 CFR part 60 that would ensure the
promulgation of this NSPS would not undercut the application of rules
that limit the application of the PSD permitting program requirements
to only the largest sources of GHGs. An intervening decision of the
United States Supreme Court has, to a large extent, resolved the legal
issue that led the EPA to propose these part 60 provisions. The Supreme
Court has since clarified that the PSD program does not apply to
smaller sources based on the amount of GHGs they emit. However, because
the largest sources emitting GHGs remain subject to the PSD permitting
requirements, the EPA has concluded that it remains appropriate to
adopt the proposed regulatory provisions in 40 CFR part 60 in this
rule. We discuss our reasons for this action in detail below.
    Under the PSD program in part C of title I of the CAA, in areas
that are classified as attainment or unclassifiable for NAAQS
pollutants, a new or modified source that emits any air pollutant
subject to regulation at or above specified thresholds is required to
obtain a preconstruction permit. This permit assures that the source
meets specific requirements, including application of BACT to each
pollutant subject to regulation under the CAA. Many states (and local
districts) are authorized by the EPA to administer the PSD program and
to issue PSD permits. If a state is not authorized, then the EPA issues
the PSD permits for facilities in that state.
    To identify the pollutants subject to the PSD permitting program,
EPA regulations contain a definition of the term ``regulated NSR
pollutant.'' 40 CFR 52.21(b)(50); 40 CFR 51.166(b)(49). This definition
contains four subparts, which cover pollutants regulated under various
parts of the CAA. The second subpart covers pollutants regulated under
section 111 of the CAA. The fourth subpart is a catch-all provision
that applies to ``[a]ny pollutant that is otherwise subjection to
regulation under the Act.''
    This definition and the associated PSD permitting requirements
applied to GHGs for the first time on January 2, 2011, by virtue of the
EPA's regulation of GHG emissions from motor vehicles, which first took
effect on that same date. 75 FR 17004 (Apr. 2, 2010). As such, GHGs
became subject to regulation under the CAA and the fourth subpart of
the ``regulated NSR pollutant'' definition became applicable to GHGs.
    On June 3, 2010, the EPA issued a final rule, known as the
Tailoring Rule, which phased in permitting requirements for GHG
emissions from stationary sources under the CAA PSD and Title V
permitting programs (75 FR 31514). Under its understanding of the CAA
at the time, the EPA believed the Tailoring Rule was necessary to avoid
a sudden and unmanageable increase in the number of sources that would
be required to obtain PSD and Title V permits under the CAA because the
sources emitted GHGs emissions over applicable major source and major
modification thresholds. In Step 1 of the Tailoring Rule, which began
on January 2, 2011, the EPA limited application of PSD or Title V
requirements to sources of GHG emissions only if the sources were
subject to PSD or Title V ``anyway'' due to their emissions of non-GHG
pollutants. These sources are referred to as ``anyway sources.'' In
Step 2 of the Tailoring Rule, which began on July 1, 2011, the EPA
applied the PSD and Title V permitting requirements under the CAA to
sources that were classified as major, and, thus, required to obtain a
permit, based solely on their potential GHG emissions and to
modifications of otherwise major sources that required a PSD permit
because they increased only GHG emissions above applicable levels in
the EPA regulations.
    In the PSD program, the EPA implemented the steps of the Tailoring
Rule by adopting a definition of the

term ``subject to regulation.'' The limitations in Step 1 of the
Tailoring Rule are reflected in 40 CFR 52.21(b)(49)(iv) and 40 CFR
51.166(b)(48)(iv). With respect to ``anyway sources'' covered by PSD
during Step 1, this provision established that GHGs would not be
subject to PSD requirements unless the source emitted GHGs in the
amount of 75,000 tons per year (tpy) of carbon dioxide equivalent
(CO2e) or more. The primary practical effect of this
paragraph is that the PSD BACT requirement does not apply to GHG
emissions from an ``anyway source'' unless the source emits GHGs at or
above this threshold. The Tailoring Rule Step 2 limitations are
reflected in 40 CFR 52.21(b)(49)(v) and 51.166(b)(48)(v). These
provisions contain thresholds that, when applied through the definition
of ``regulated NSR pollutant,'' function to limit the scope of the
terms ``major stationary source'' and ``major modification'' that
determine whether a source is required to obtain a PSD permit. See e.g.
40 CFR 51.166(a)(7)(i) and (iii); 40 CFR 51.166(b)(1); 40 CFR
51.166(b)(2).
    This structure of the EPA's PSD regulations created questions
regarding the extent to which the limitations in the Tailoring Rule
would continue to apply to GHGs once they became regulated, through
this final rule, under section 111 of the CAA. 79 FR 1487-1488. As
discussed above, the definition of ``regulated NSR pollutant'' in the
PSD regulations contains a separate PSD trigger for air pollutants
regulated under the NSPS, 40 CFR 51.166(b)(49)(ii) (the ``NSPS trigger
provision''). Thus, when GHGs become subject to a standard promulgated
under CAA section 111 for the first time under this rule, PSD
requirements would presumably apply for GHGs on an additional basis
besides through the regulation of GHGs from motor vehicles. However,
the Tailoring Rule, on the face of its regulatory provisions,
incorporated the revised thresholds it promulgated into only the fourth
subpart of the PSD definition of regulated NSR pollutant (``[a]ny
pollutant that otherwise is subject to regulation under the Act''). The
regulatory text does not clearly incorporate the thresholds into the
NSPS trigger provision in the second subpart (``[a]ny pollutant that is
subject to any standard promulgated under section 111 of the Act'').
For this reason, a question arose as to whether the Tailoring Rule
limitations would continue to apply to the PSD requirements after they
are independently triggered for GHGs by the NSPS that the EPA is now
promulgating. Stakeholders questioned whether the EPA must revise its
PSD regulations --and, by the same token, whether states must revise
their SIPs--to assure that the Tailoring Rule thresholds will continue
to apply to sources potentially subject to PSD under the CAA based on
GHG emissions.
    In the January 8, 2014 proposed rule, the EPA explained that the
agency had included an interpretation in the Tailoring Rule preamble,
which means that the Tailoring Rule thresholds continue to apply if and
when the EPA promulgates requirements under CAA section 111. 79 FR 1488
(citing 75 FR 31582). Nevertheless, to ensure there would be no
uncertainty as to this issue, the EPA proposed to adopt explicit
language in 40 CFR 60.46Da(j), 40 CFR 60.4315(b), and 40 CFR 60.5515 of
the agency's regulations. The proposed language makes clear that the
thresholds for GHGs in the EPA's PSD definition of ``subject to
regulation'' apply through the second subpart of the definition of
``regulated NSR pollutant'' to GHGs regulated under this rule.
    The EPA received comments supporting the adoption of this proposed
language, but several commenters also expressed concern that adding
this language to part 60 alone would not be sufficient. Several
commenters urged the EPA to instead revise the PSD regulations in parts
51 and 52. In addition, commenters expressed concern that further steps
were needed to amend the SIPs before there would be certainty that the
Tailoring Rule limitations continued to apply after the adoption of
CO2 standards under CAA section 111 in this final rule.
    On June 23, 2014, the United States Supreme Court, in Utility Air
Regulatory Group v. Environmental Protection Agency, issued a decision
addressing the application of PSD permitting requirements to GHG
emissions. The Supreme Court held that the EPA may not treat GHGs as an
air pollutant for purposes of determining whether a source is a major
source (or modification thereof) for the purpose of PSD applicability.
The Court also said that the EPA could continue to require that PSD
permits, otherwise required based on emissions of pollutants other than
GHGs, contain limitations on GHG emissions based on the application of
BACT. The Supreme Court decision effectively upheld PSD permitting
requirements for GHG emissions under Step 1 of the Tailoring Rule for
``anyway sources'' and invalidated application of PSD permitting
requirements to Step 2 sources based on GHG emissions. The Court also
recognized that, although the EPA had not yet done so, it could
``establish an appropriate de minimis threshold below which BACT is not
required for a source's greenhouse gas emissions.'' 134 S. Ct. at 2449.
    In accordance with the Supreme Court decision, on April 10, 2015,
the U.S. Court of Appeals for the District of Columbia Circuit (the
D.C. Circuit) issued an amended judgment vacating the regulations that
implemented Step 2 of the Tailoring Rule, but not the regulations that
implement Step 1 of the Tailoring Rule. The court specifically vacated
40 CFR 51.166(b)(48)(v) and 40 CFR 52.21(b)(49)(v) of the EPA's
regulations, but did not vacate 40 CFR 51.166(b)(48)(iv) or 40 CFR
52.21(b)(48)(iv). The court also directed the EPA to consider whether
any further revisions to its regulations are appropriate in light of
UARG v. EPA, and, if so, to undertake such revisions.
    The practical effect of the Supreme Court's clarification of the
reach of the CAA is that it eliminates the need for Step 2 of the
Tailoring Rule and subsequent steps of the GHG permitting phase in that
the EPA had planned to consider under the Tailoring Rule. This also
eliminates the possibility that the promulgation of GHG standards under
section 111 could result in additional sources becoming subject to PSD
based solely on GHGs, notwithstanding the limitations the EPA adopted
in the Tailoring Rule. However, for an interim period, the EPA and the
states will need to continue applying parts of the PSD definition of
``subject to regulation'' to ensure that sources obtain PSD permits
meeting the requirements of the CAA.
    The CAA continues to require that PSD permits issued to ``anyway
sources'' satisfy the BACT requirement for GHGs. Based on the language
that remains applicable under 40 CFR 51.166(b)(48)(iv) and 40 CFR
52.21(b)(49)(iv), the EPA and states may continue to limit the
application of BACT to GHG emissions in those circumstances where a
source emits GHGs in the amount of at least 75,000 tpy on a
CO2e basis. The EPA's intention is for this to serve as an
interim approach while the EPA moves forward to propose a GHG
Significant Emission Rate (SER) that would establish a de minimis
threshold level for permitting GHG emissions under PSD. Under this
forthcoming rule, the EPA intends to propose restructuring the GHG
provisions in its PSD regulations so that the de minimis threshold for
GHGs will not reside within the definition of ``subject to
regulation.'' This restructuring will be designed to make the PSD
regulatory provisions on GHGs universally

applicable, without regard to the particular subparts of the definition
of ``regulated NSR pollutant'' that may cover GHGs. Upon promulgation
of this PSD rule, it will then provide a framework that states may use
when updating their SIPs consistent with the Supreme Court decision.
    While the PSD rulemaking described above is pending, the EPA and
approved state, local, and tribal permitting authorities will still
need to implement the BACT requirement for GHGs. In order to enable
permitting authorities to continue applying the 75,000 tpy
CO2e threshold to determine whether BACT applies to GHG
emissions from an ``anyway source'' after GHGs are subject to
regulation under CAA section 111, the EPA has concluded that it
continues to be appropriate to adopt the proposed language in 40 CFR
60.5515 (subpart TTTT). Because the EPA is not finalizing the proposed
regulations in subparts Da and KKKK, it is not necessary to adopt the
comparable provisions that the EPA proposed in 40 CFR 60.46Da(j) and 40
CFR 60.4315(b).
    The EPA has evaluated 40 CFR 60.5515 in light of the Supreme Court
decision and the comments received on the question of whether this CAA
section 111 standard will undermine the application of the Tailoring
Rule limitations. While most of the Tailoring Rule limitations are no
longer needed to avoid triggering the requirement to obtain a PSD
permit based on GHGs alone, the limitation in 40 CFR 51.166(b)(48)(iv)
and 40 CFR 52.21(b)(49)(iv) will remain important to provide an interim
applicability level for the GHG BACT requirement in ``anyway source''
PSD permits. Thus, there continues to be a need to ensure that the
regulation of GHGs under CAA section 111 does not make this BACT
applicability level for anyway sources effectively inoperable. The
language in 40 CFR 60.5515 will continue to be effective at avoiding
this result after the judicial actions described above and the adoption
of this final rule. The provisions in part 60 reference 40 CFR
51.166(b)(48) and 40 CFR 52.21(b)(49) of the EPA's regulations.
However, the courts have now vacated 40 CFR 51.166(b)(48)(v) and 40 CFR
52.21(b)(49)(v), and the EPA will take steps soon to eliminate these
subparts from the CFR. As a result of these steps, the language of
final 40 CFR 60.5515 will not incorporate the vacated parts of 40 CFR
51.166(b)(48) and 40 CFR 52.21(b)(49), but these provisions in part 60
will continue to apply to those subparts of the PSD rules that are
needed on an interim basis to limit application of BACT to GHGs only
when emitted by an anyway source in amounts of 75,000 tpy
CO2e or more. Thus, in this final rule, the EPA is adopting
the proposed text of 40 CFR 60.5515 for this purpose without
substantial change.
    As to the concern expressed by some commenters that revisions to
part 60 alone are not sufficient, the GHG SER rulemaking described
above will include proposed revisions to the PSD regulations in parts
51 and 52 that should ultimately address this concern. The EPA
acknowledges that the commenters concern will not be fully addressed
for an interim period of time, but (for the reasons discussed above)
the part 60 provisions adopted in this rule are sufficient to make
explicit that the 75,000 tpy CO2e BACT applicability level
for GHGs will apply to GHGs that are subject to regulation under the
CAA section 111 standards adopted in this rule.
    Rather than adopting a temporary patch in its PSD regulations in
this rule to address the implications for PSD of regulating GHGs under
CAA section 111, the EPA believes it will be most efficient for the EPA
and the states if the EPA completes a comprehensive PSD rule that will
address all the implications of the Supreme Court decision. The
revisions the EPA will consider based on the Supreme Court decision
will inherently address the commenters concerns about the definition of
the ``subject to regulation'' and the proposed part 60 provisions. To
the extent this PSD rule is not complete before the EPA proposes
additional CAA section 111 standards for GHGs, the EPA will need to
consider adding provisions like 40 CFR 60.5515 to other subparts of
part 60. In a separate rulemaking finalized concurrently with this
rule, the EPA is also finalizing corresponding edits to 40 CFR 60.5705
in subpart UUUU to clarify that the regulated pollutant is the same for
both the CAA section 111(b) and section 111(d) rules. As of this time,
the EPA has not proposed GHG standards for other source categories
under CAA section 111. To the extent needed, this approach of adding
provisions to a few subparts in part 60 would be less burdensome to
states and more efficient than revising 40 CFR 51.166 at this time
solely to address the implications of regulating GHGs under CAA section
111.
    The EPA understands that many commenters expressed concern that PSD
SIPs would also have to be amended to address the implications of
regulating GHGs under CAA section 111. However, the language in 40 CFR
60.5515 is designed to avoid the need for states to make revisions to
the PSD regulations in their SIPs at this time. The EPA has previously
observed that the form of each pollutant regulated under the PSD
program is derived from the form of the pollutant described in
regulations, such as an NSPS, that make the pollutant regulated under
the CAA. 56 FR 24468, 24470 (May 30, 1991); 61 FR 9905, 9912-18 (Mar.
12, 1996); 75 FR 31522.
    Moreover, it is more likely that states would need to consider a
SIP revision if the EPA were to revise 40 CFR 51.166 in this rule.
Revisions to 51.166 can trigger requirements for states to revise their
PSD program provisions under 40 CFR 51.166(a)(6).
    Given the process required in states to review their SIPs and
submit them to the EPA for approval, it is most efficient for all
concerned when the EPA is able to consolidate its revisions to 40 CFR
51.166. The EPA, thus, believes it will be less work for states if we
issue a comprehensive set of rules addressing regulation of GHGs under
the PSD program after the Supreme Court decision.
    In comments on the proposed rules, states generally did not express
concern that the proposed revisions to part 60 were insufficient to
avoid the need for SIP revisions. In our proposal, we addressed any
state with an approved PSD SIP program that applies to GHGs which
believed that this final rule would require the state to revise its SIP
so that the Tailoring Rule thresholds continue to apply. First, the EPA
encouraged any state that considered such revisions necessary to make
them as soon as possible. Second, if the state could do so promptly,
the EPA said it would assess whether to proceed with a separate
rulemaking action to narrow its approval of that state's SIP so as to
assure that, for federal purposes, the Tailoring Rule thresholds will
continue to apply as of the effective date of the final NSPS rule. 79
FR 1487. The EPA did not receive any comments or other feedback from
states requesting that the EPA narrow their program to ensure the
Tailoring Rule thresholds continue to apply after promulgating this
rule. We do not believe such action will be necessary in any state
after the Supreme Court decision and our action in this rule is to
adopt the proposed part 60 provisions for purposes of ensuring the Step
1 BACT applicability level for GHGs continues to apply on an interim
basis.

C. Implications for BACT Determinations Under PSD

    New major stationary sources and major modifications at existing
major stationary sources are required by the

CAA to, among other things, obtain a permit under the PSD program
before commencing construction. The emission thresholds that define PSD
applicability can be found in 40 CFR parts 51 and 52, and the PSD
thresholds specific to GHGs are explained in the preceding section of
this preamble.
    Sources that are subject to PSD must obtain a preconstruction
permit that contains emission limitations based on application of BACT
for each regulated NSR pollutant. The BACT requirement is set forth in
section 165(a)(4) of the CAA, and in EPA regulations under 40 CFR parts
51 and 52. These provisions require that BACT determinations be made on
a case-by-case basis. CAA section 169(3) defines BACT, in general, as:

``an emissions limitation . . . based on the maximum degree of
reduction for each pollutant . . . emitted from any proposed major
stationary source or major modification which the Administrator . .
. [considering energy, environmental, and economic impacts] . . .
determines is achievable for such facility . . .''

Furthermore, this definition in the CAA specifies that

``[i]n no event shall application of [BACT] result in emissions of
any pollutants which will exceed the emissions allowed by any
applicable standard established pursuant to section 111 or 112 of
the Act.''

This condition of CAA section 169(3) has historically been interpreted
to mean that BACT cannot be less stringent than any applicable standard
of performance under the NSPS. See, e.g., U.S. EPA, PSD and Title V
Permitting Guidance for Greenhouse Gases, EPA-457/B-11-001 (March 2011)
(``GHG Permitting Guidance'' or ``Guidance'') at 20-21. Thus, upon
completion of an NSPS, the NSPS establishes a ``BACT Floor'' for PSD
permits that are issued to affected facilities covered by the NSPS.
    BACT is a case-by-case review that considers a number of factors.
These factors include the availability, technical feasibility, control
effectiveness, and the economic, environmental and energy impacts of
the control option. See GHG Permitting Guidance at 17-46. The fact that
a minimum control requirement (i.e., the BACT Floor) is established by
the EPA through an applicable NSPS does not bar a permitting agency
from justifying a more stringent control level as BACT for a specific
PSD permit.
    It is important to understand how this NSPS may relate to
determining BACT for new and existing EGUs that require PSD permits.
PSD generally applies to major sources, while this NSPS applies to
units that may be within a source. Under this NSPS, an affected
facility is a new EGU or a modified or reconstructed EGU. The new
source NSPS requirements apply, in general, to any stationary source
that adds a new EGU that is an affected facility under this NSPS. This
could, for example, include a proposed brand new (``greenfield'') power
plant or an existing power plant that proposes to add a new EGU (e.g.,
to increase its generating capacity). While this latter scenario is
considered a ``new affected facility'' under the NSPS, it is generally
viewed under PSD as a ``modification'' of an existing stationary
source. Thus, the new source NSPS requirements could apply to a
modification, as that term is defined under PSD.
    In addition, this NSPS will apply to some modified and
reconstructed units, as those terms are defined under part 60.
Consequently, this NSPS could establish a BACT floor for existing
stationary sources that are modifying an existing EGU and experience an
emissions increase that makes the source subject to PSD review.
However, a physical change that triggers the NSPS modification or
reconstruction requirements does not necessarily subject the source to
PSD requirements, and vice versa. In general, in order to trigger the
NSPS modification or reconstruction requirements, a physical change
must increase the maximum hourly emission rate of the pollutant (to be
an NSPS modification) or the fixed capital cost of the change must
exceed 50 percent of the fixed capital cost of a comparable entirely
new facility (to be an NSPS reconstruction). See 40 CFR 60.2, 60.14,
60.15. Under the PSD program, however, a physical change (or change in
the method of operation) must result in an increase in annual emissions
of the pollutant by a specified emission threshold in order to be
subject to PSD requirements. This emission calculation considers the
unit's past annual emissions and its projected annual emissions. See,
e.g., 40 CFR 52.21(a)(2)(iv)(C). In addition, the PSD emissions test
for a modification allows the existing source to consider qualifying
emission reductions and increases at the source within a
contemporaneous period to ``net out'' of, or avoid, triggering PSD
review. Thus, it is important to understand the differences in how the
term ``modification'' is used in the NSPS and PSD programs, and that a
physical change that is a modification under one program may not
necessarily be a modification under the other program.
    In the preamble to the proposed NSPS for new sources, the EPA
discussed whether a standard of performance for the new source NSPS,
specifically the BSER for solid fuel-fired EGUs that is based on
partial CCS, could become the BACT floor when permitting a modified or
reconstructed EGU or non-EGU source. As noted above, BACT is a case-
specific review by a permitting agency. In evaluating BACT, the
permitting authority should consider all available control technologies
that have the potential for practical application to the facility or
emission unit under evaluation. See GHG Permitting Guidance at 24. This
BACT review must include any technologies that are part of an
applicable NSPS for the specific type of source and would therefore
establish the minimum level of stringency for the BACT. Thus, it is
possible that partial CCS could be considered in a BACT review as an
available control option for a modified or reconstructed EGU facility,
or for another type of source (e.g., natural gas processing plant), but
this NSPS is not an applicable standard to such sources so it would not
establish a requirement that partial CCS is a minimum level of
stringency for the BACT for those sources.
    Some commenters expressed concern that, if the EPA finalizes a BSER
for utility boilers and IGCC units that is based on partial CCS, it
would establish a BACT Floor for new EGUs that would be inconsistent
with prior BACT determinations for EGUs in both permits issued by EPA
Regions and permits issued by state agencies on which the EPA has
commented. Many of these comments were more directed at the development
and deployment of CCS (i.e., the commenter did not believe CCS should
be the basis for BSER) rather than examining whether an NSPS should
establish the BACT floor for applicable sources, which is the legal
consequence of setting an NSPS under the terms of the CAA.
Consequently, we respond to these comments in other sections of this
preamble that support the selection of partial CCS as the basis for the
BSER for fossil fuel-fired electric utility steam generating units.
    With regard to the commenters who stated that a BSER for EGUs that
is based on partial CCS would be inconsistent with BACT determinations
in previous GHG PSD permits, it is important to recognize that a BACT
determination is a case-by-case analysis and that technological
capabilities and costs evolve over time.\551\ In addition, to

date the EPA has not issued a PSD permit with GHG BACT for a source
that would be an affected facility requiring partial CCS under this
NSPS (i.e., a fossil fuel-fired steam generating unit), so one cannot
determine whether the EPA--as a PSD permitting authority--has been
either consistent or inconsistent by setting a BSER of partial CCS in
this NSPS. Although, in the course of a BACT review, some permitting
authorities may have determined that CCS is not technologically
feasible or economically achievable for a gas-fired EGU, because of the
case-by-case nature of the BACT analysis it does not automatically
follow that the same conclusion is appropriate for a solid fuel-fired
EGU. Furthermore, PSD permitting requirements first applied to GHGs in
January 2011 and more information about GHG control technology has been
gained in this four-and-a-half year period. Thus, we would expect BACT
decisions to evolve as well, such that a GHG BACT review for a coal-
fired EGU in 2015 may look very different from a review that was done
in 2011.
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    \551\ In this regard, the 2011 GHG Permitting Guidance states
that ``although CCS is not in widespread use at this time, EPA
generally considers CCS to be an `available' add-on pollution
control technology for facilities emitting CO2 in large
amounts and industrial facilities with high-purity CO2
streams.'' GHG Permitting Guidance at 35. The Guidance goes on to
note that CCS may not be technically feasible at modified sources
(citing possible issues with ``space for CO2 capture
equipment at an existing facility''), or in other specific
circumstances. Id. at 36 (``Logistical hurdles for CCS may include
obtaining contracts for offsite land acquisition . . ., the need for
funding . . ., timing of available transportation infrastructure,
and developing a site for secure long term storage. Not every source
has the resources to overcome the offsite logistical barriers
necessary to apply CCS technology to its operations, and smaller
sources will likely be more constrained in this regard''). Id. at
42-3 EPA also noted that CCS may be expensive in individual
instances and thus eliminated as a control option for that reason
under step 4 of the BACT analysis, noting further that revenues from
EOR may offset other costs. Id. at 42-3. See also UARG v. EPA, 134
S.Ct. 2427, 2448 (2014) (noting that EPA's GHG Permitting Guidance
states that carbon capture is reasonably comparable to more
traditional, end-of-stack BACT technologies, and that petitioners do
not dispute that).
    As explained at Section V.I.5 above, in determining that partial
CCS is BSER for new fossil fuel steam electric plants, the EPA has
carefully considered the issue of logistics (including cost
estimates for land acquisition, transportation, and sequestration)
and costs generally. Nor would new plants face the same types of
constraints as modified or reconstructed sources in a BACT
determination, since a new source has more leeway in choosing where
to site. See text at V.G.3. above. Moreover, the GHG Permitting
Guidance considered BACT determinations for all types of sources,
not just those for which the EPA has determined in this rule that
partial CCS is the BSER, and the concerns expressed in the Guidance
thus must be considered in that broader context.
---------------------------------------------------------------------------

    Additionally, if a state agency is processing a permit application
for a solid fuel-fired EGU and does not propose CCS as BACT (or does
not even consider CCS as an available control for BACT), the EPA is not
necessarily required to comment negatively on the draft permit, or to
otherwise request or require that the state agency amend the BACT to
include CCS. For state agencies that have their own EPA-approved state
implementation plan, the state has primacy over their permitting
actions and discretion to interpret their approved rules and to apply
the applicable federal and state regulatory requirements that are in
place at the time for the facility in question. The EPA's role is to
provide oversight to ensure that the state operates their PSD program
in accordance with the CAA and applicable rules. If the EPA does not
adversely comment on a certain draft permit or BACT determination, it
does not necessarily imply EPA endorsement of the proposed permit or
determination.
    Some commenters also felt that the determination of partial CCS as
BSER is inconsistent with the agency's position on CCS in the EPA's GHG
Permitting Guidance, which they say supports the notion that additional
work is required before CCS can be integrated at full-scale electric
utility applications. It is important to recognize that the EPA's
Permitting Guidance is guidance, so it does not contain any final
determination of BACT for any source. Furthermore, we disagree with the
commenters' characterization of the GHG Permitting Guidance. The
Guidance specifically states ``[f]or the purposes of a BACT analysis
for GHGs, the EPA classifies CCS as an add-on pollution control
technology that is ``available'' for facilities emitting CO2
in large amounts, including fossil fuel-fired power plants, and for
industrial facilities with high-purity CO2 streams (e.g.,
hydrogen production, ammonia production, natural gas processing,
ethanol production, ethylene oxide production, cement production, and
iron and steel manufacturing). For these types of facilities, CCS
should be listed in Step 1 of a top-down BACT analysis for GHGs.'' GHG
Permitting Guidance at 32. As discussed elsewhere in the Guidance,
technologies that should be listed in Step 1 are those that ``have the
potential for practical application to the emissions unit and regulated
pollutant under evaluation.'' GHG Permitting Guidance at 24. The EPA
continues to stand by its position on the availability of CCS in this
context, as expressed in the GHG Permitting Guidance.
    The GHG Permitting Guidance continues on to discuss case-specific
factors and potential limitations with applying CCS, and it
acknowledges that CCS may not be ultimately selected as BACT in
``certain cases'' based on technology feasibility and cost. GHG
Permitting Guidance at 36, 43. While acknowledging these potential
challenges when it was issued in March 2011, the Guidance clearly does
not rule out the selection of CCS as BACT for any source category and
it is forward looking. GHG Permitting Guidance at 43 (``. . . as a
result of ongoing research and development, . . . CCS may become less
costly and warrant greater consideration . . . in the future'') Nothing
in the Guidance is inconsistent with EPA's present position that CCS is
adequately demonstrated for the types of sources covered by this NSPS,
as articulated elsewhere in this preamble.
    A commenter asserted that the GHG Permitting Guidance should be
amended because it calls for consideration of CCS in BACT
determinations even though the proposed NSPS identified ``partial CCS''
as BSER for new boiler and IGCC EGUs. The Guidance explains that ``the
purpose of Step 1 of the process is to cast a wide net and identify all
control options with potential application to the emissions unit under
review.'' GHG Permitting Guidance at 26. The EPA agrees that the GHG
Permitting Guidance only uses the term ``CCS'' and does not distinguish
``partial CCS'' from ``full CCS.'' But considering the purpose of Step
1 of the process, we believe that the term ``CCS'', as it is used in
the GHG Permitting Guidance, adequately describes the varying levels of
CO2 capture. A BACT review should analyze all available
technologies in order to adequately support the BACT determination, and
may require evaluation of partial CCS, full CCS, and/or no
CO2 capture. The specific facility type and CO2
capture conditions will dictate the level(s) of CO2 capture
that are most appropriate to consider as ``available'' in a BACT
review.

D. Implications for Title V Program

    Under the Title V program, certain stationary sources, including
``major sources'' are required to obtain an operating permit. This
permit includes all of the CAA requirements applicable to the source,
including adequate monitoring, recordkeeping, and reporting
requirements to assure sources' compliance. These permits are generally
issued through EPA-approved state Title V programs.
    In the January 8, 2014 proposal, the EPA discussed whether this
rulemaking would impact the applicability of Title V requirements to
major sources of GHGs. 79 FR 1489-90. The relevant issue for Title V
purposes was, in essence, whether promulgation of CAA section 111
requirements for GHGs

would undermine the Tailoring Rule, which, as explained above, phased
in permitting requirements for GHG emissions for stationary sources
under the CAA PSD and Title V permitting programs. Based on the EPA's
understanding of the CAA at that time, the proposal discussed this
issue in the context of the regulatory and statutory definitions of
``major source,'' focusing on revisions that had been made in the
Tailoring Rule to the definitions in the Title V regulations of ``major
source'' and ``subject to regulation.'' 79 FR 1489-90 (quoting 75 FR
31583). Under the Title V regulations, as revised by the Tailoring
Rule, ``major source'' is defined to include, in relevant part, ``a
major stationary source . . . that directly emits, or has the potential
to emit, 100 tpy or more of any air pollutant subject to regulation.''
The proposal further explained that the GHG threshold that had been
established in the Tailoring Rule had been incorporated into the
definition of ``subject to regulation'' under 40 CFR 70.2 and 71.2,
such that those definitions specify `` `that GHGs are not subject to
regulation for purposes of defining a major source, unless as of July
1, 2011, the emissions of GHGs are from a source emitting or having the
potential to emit 100,000 tpy of GHGs on a CO2e basis.' ''
Id. (quoting 75 FR 31583). The proposal thus concluded that the Title V
definition of ``major source,'' as revised by the Tailoring Rule, did
not on its face distinguish among types of regulatory triggers for
Title V. It further noted that the Title V program had already been
triggered for GHGs, and thus concluded that the promulgation of CAA
section 111 requirements would not further impact Title V applicability
requirements for major sources of GHGs. 79 FR 1489-90.
    As noted elsewhere in this section, after the proposal for this
rulemaking was published, the United States Supreme Court issued its
opinion in UARG v. EPA, 134 S.Ct. 2427 (June 23, 2014), and in
accordance with that decision, the D.C. Circuit subsequently issued an
amended judgment in Coalition for Responsible Regulation, Inc. v.
Environmental Protection Agency, Nos. 09-1322, 10-073, 10-1092 and 10-
1167 (D.C. Cir., April 10, 2015). Those decisions support the same
overall conclusion as the EPA discussed in the proposal, though for
different reasons.
    With respect to Title V, the Supreme Court said in UARG v. EPA that
the EPA may not treat GHGs as an air pollutant for purposes of
determining whether a source is a major source required to obtain a
Title V operating permit. In accordance with that decision, the D.C.
Circuit's amended judgment in Coalition for Responsible Regulation,
Inc. v. Environmental Protection Agency, vacated the Title V
regulations under review in that case to the extent that they require a
stationary source to obtain a Title V permit solely because the source
emits or has the potential to emit GHGs above the applicable major
source thresholds. The D.C. Circuit also directed the EPA to consider
whether any further revisions to its regulations are appropriate in
light of UARG v. EPA, and, if so, to undertake to make such revisions.
These court decisions make clear that promulgation of CAA section 111
requirements for GHGs will not result in the EPA imposing a requirement
that stationary sources obtain a Title V permit solely because such
sources emit or have the potential to emit GHGs above the applicable
major source thresholds.\552\
---------------------------------------------------------------------------

    \552\ As explained elsewhere in this notice, the EPA intends to
conduct future rulemaking action to make the appropriate revisions
to the operating permit rules to respond to the Supreme Court
decision and the D.C. Circuit's amended judgment. To the extent
there are any issues related to the potential interaction between
the promulgation of CAA section 111 requirements for GHGs and Title
V applicability based on emissions above major source thresholds,
the EPA expects there would be an opportunity to consider those
during that rulemaking.
---------------------------------------------------------------------------

    To be clear, however, unless exempted by the Administrator through
regulation under CAA section 502(a), any source, including an area
source (a ``non-major source''), subject to an NSPS is required to
apply for, and operate pursuant to, a Title V permit that assures
compliance with all applicable CAA requirements for the source,
including any GHG-related applicable requirements. This aspect of the
Title V program is not affected by UARG v. EPA, as the EPA does not
read that decision to affect either the grounds other than those
described above on which a Title V permit may be required or the
applicable requirements that must be addressed in Title V permits.\553\
Consistent with the proposal, the EPA has concluded that this rule will
not affect non-major sources and there is no need to consider whether
to exempt non-major sources. Thus, sources that are subject to the CAA
section 111 standards promulgated in this rule are required to apply
for, and operate pursuant to, a Title V permit that assures compliance
with all applicable CAA requirements, including any GHG-related
applicable requirements.
---------------------------------------------------------------------------

    \553\ See Memorandum from Janet G. McCabe, Acting Assistant
Administrator, Office of Air and Radiation, and Cynthia Giles,
Assistant Administrator, Office of Enforcement and Compliance
Assurance, to Regional Administrators, Regions 1-10, Next Steps and
Preliminary Views on the Application of Clean Air Act Permitting
Programs to Greenhouse Gases Following the Supreme Court's Decision
in Utility Regulatory Group v. Environmental Protection Agency (July
24, 2014) at 5.
---------------------------------------------------------------------------

E. Implications for Title V Fee Requirements for GHGs

1. Why is the EPA revising Title V fee rules as part of this action?
    The January 8, 2014 notice of proposed rulemaking (79 FR 1430) (the
``EGU GHG NSPS proposal'' or ``NSPS proposal'') proposed the first
section 111 standards to regulate GHGs at EGUs. That notice also
included proposed revisions to the fee requirements of the 40 CFR part
70 and part 71 operating permit rules under Title V of the CAA to avoid
inadvertent consequences for fees that would be triggered by the
promulgation of the first CAA section 111 standard to regulate GHGs. If
we do not revise the fee rules by the time of the promulgation of the
NSPS standards for GHGs, then approved part 70 programs implemented by
state, local and tribal permitting authorities \554\ that rely on the
``presumptive minimum'' approach and the part 71 program implemented by
the EPA would be required to account for GHGs in emissions-based fee
calculations at the same dollar per ton ($/ton) rate as other air
pollutants. The EPA believes this would result in the collection of
fees in excess of what is required to cover the reasonable costs of an
operating permit program. See NSPS proposal 79 FR 1490.
---------------------------------------------------------------------------

    \554\ Hereafter, for the sake of simplicity, we will generally
refer to part 70 permitting authorities as ``state'' permitting
authorities and refer to part 70 programs as ``state'' programs.
---------------------------------------------------------------------------

    In response to these concerns, the EPA proposed regulatory changes
to limit the fees collected based on GHG emissions and proposed two fee
adjustment options to increase the fees collected based on the costs
for permitting authorities to conduct certain review activities related
to GHG emissions, while still providing sufficient funding for an
operating permit program. Also, we proposed an option that would have
provided for no fee adjustments to recover the costs of conducting
review activities related to GHG emissions. Id. 79 FR 1490. The EPA did
not propose any action related to state and local permitting
authorities that do not use the presumptive minimum approach.
    Most commenters on the proposal, including state and local
permitting authorities, were supportive of exempting GHGs from the
emissions-based fee calculations of the permit

rules, but support for the fee adjustment options was mixed, with state
and local permitting authorities generally supporting either of the two
fee adjustments, and other commenters generally supporting the option
that provides for no fee adjustment.
2. Background on the Fee Requirements of Title V
    In the NSPS proposal, the EPA explained the statutory and
regulatory background related to the requirement that permitting
authorities collect fees from the owner or operator of Title V sources
that are sufficient to cover the costs of the operating permit program.
CAA section 502(b)(3)(A) requires an operating permit program to
include a requirement that sources ``pay an annual fee, or the
equivalent over some other period, sufficient to cover all reasonable
(direct and indirect) costs required to develop and administer the
permit program.'' See also 40 CFR 70.9(a). CAA section 502(b)(3)(B)(i)
requires that, in order to have an approvable operating permit program,
the permitting authority must show that ``the program will result in
the collection, in the aggregate, from all sources [required to get an
operating permit]'' of either ``an amount not less than $25 per ton of
each regulated pollutant [adjusted annually for changes in the consumer
price index], or such other amount as the Administrator may determine
adequately reflects the reasonable costs of the permit program.'' See
also 40 CFR 70.9(b)(2). This has been generally referred to as the
``presumptive minimum'' approach. If a permitting authority does not
wish to use the presumptive minimum approach, it may demonstrate ``that
collecting an amount less than the [presumptive minimum amount] will''
result in the collection of funds sufficient to cover the costs of the
program. CAA section 503(b)(3)(B)(iv); see also 40 CFR 70.9(b)(5). This
has been generally referred to as the ``detailed accounting'' approach.
CAA section 502(b)(3)(B)(ii) sets forth a definition of ``regulated
pollutant'' for purposes of calculating the presumptive minimum that
includes each pollutant regulated under section 111 of the CAA. See
also 40 CFR 70.2.
3. What fee rules did we propose to revise?
    In the NSPS proposal, to exempt GHGs from emissions-based fee
calculations, we proposed to exempt GHGs from the definition of
``regulated pollutant'' for purposes of operating permit fee
calculations (``the GHG exemption''). The EPA then proposed two
alternative ways to account for the costs of addressing GHGs in
operating permits through a cost adjustment. First, we proposed a
modest additional cost for each GHG-related activity of certain types
that a permitting authority would process (``the GHG adjustment option
1''). Alternatively, we proposed a modest additional increase in the
per ton rate used in the presumptive minimum calculation for all non-
GHG fee pollutants (``the GHG adjustment option 2''). The EPA also
solicited comment on an option that would provide no additional cost
adjustment to account for GHGs (``the GHG adjustment option 3''). All
of the GHG adjustment options are based on the assumption that the GHG
exemption is finalized. See NSPS Proposal 79 FR 1493-1495.
    The EPA additionally proposed two clarifications. The first was
regulatory text in 40 CFR part 60, subparts Da, KKKK, and TTTT, to
clarify that GHGs, as opposed to CO2, is the regulated
pollutant for fee purposes (``the fee pollutant clarification''). Id.
at 1505, 1506 and 1511. The second was a proposal to move the existing
definition of ``Greenhouse gases (GHGs)'' within 40 CFR 70.2 and 71.2
to promote clarity in the regulations (``the GHG clarification''). Id.
79 FR 1490, 1517, 1518.
    For background purposes, below is a brief summary of each of the
proposals.
a. The GHG Exemption
    To address the fee issues discussed in the NSPS proposal, the EPA
proposed to exempt GHG emissions from the definition of ``regulated
pollutant (for presumptive fee calculation)'' in 40 CFR 70.2 and the
definition of ``regulated pollutant (for fee calculation)'' in 40 CFR
71.2.\555\ See NSPS preamble 79 FR 1493, 1495.
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    \555\ Hereafter we will refer to these definitions as the ``fee
pollutant'' definitions. Also, note that both fee pollutant
definitions cross-reference the definitions of ``regulated air
pollutant'' which includes air pollutants ``subject to any standard
promulgated under section 111 of the Act.''
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b. The GHG Adjustment Option 1
    The first proposed ``GHG adjustment'' option (option 1) was to
include an additional cost for each GHG-related activity of certain
types that a permitting authority would process (an activity-based
adjustment). The three activities identified for this option were ``GHG
completeness determination (for initial permit or for updated
application)'' at 43 hours of burden,\556\ ``GHG evaluation for a
modification or related permit action'' at 7 hours of burden, and ``GHG
evaluation at permit renewal'' at 10 hours of burden. See also 79 FR
1494, fn. 280 (providing a description of each of these activities).
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    \556\ Burden is the hours of staff time necessary to perform a
task.
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    For part 70, the burden hours per activity would be multiplied by
the cost of staff time (in $/hour) specific to the state, including
wages, benefits, and overhead, to determine the cost of each activity.
All the activities for a given period would be totaled to determine the
total GHG adjustment for the state. See 79 FR 1494.
    For part 71, we proposed a labor rate assumption of $52 per hour in
2011 dollars. Using that labor rate, we proposed to determine the GHG
fee adjustment for each GHG permitting program activity to be a
specific dollar amount for each activity (``set fees'') that the source
would pay for each activity performed. See 79 FR 1495. The EPA proposed
to revise 40 CFR 70.9(b)(2)(v) and 40 CFR 71.9(c)(8) to implement this
option.
c. The GHG Adjustment Option 2
    The second proposed GHG adjustment option (option 2) was to
increase the dollar per ton ($/ton) rates used in the fee calculations
for each non-GHG fee pollutant. The revised $/ton rates would be
multiplied by the total tons of non-GHG fee pollutants actually emitted
by any source to determine the applicable total fees. The EPA proposed
to increase the $/ton rates by 7 percent.\557\ See NSPS proposal 79 FR
1494, 1495.
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    \557\ The EPA estimated that both options 1 and 2 would result
in about a 7 percent increase in the fees collected by operating
permit programs affected by the proposed rule. For example, the
presumptive minimum fee rate in effect for September 1, 2014 through
August 31, 2015 is $48.27/ton. A 7 percent increase under option 2
would result in a revised fee of $51.65/ton.
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d. The GHG Adjustment Option 3
    The EPA also solicited comment on not charging any fees related to
GHGs (option 3). The basis for this proposed option was the observation
that most sources that need to address GHGs in a permit would also emit
non-GHG fee pollutants, and thus, the cost of permitting for any
particular source may be accounted for adequately without charging any
additional fees related to GHGs. Id. 79 FR 1494-1495.
e. The Fee Pollutant Clarification
    Another fee-related proposal was to add regulatory text to 40 CFR
part 60, subparts Da, KKKK, and TTTT, to clarify that the fee pollutant
for operating permit purposes would be considered to be ``GHGs,'' (as
defined in

40 CFR 70.2 and 71.2),\558\ rather than solely CO2, which
would be regulated under the section 111 standards and implemented
through the EGU GHG NSPS. Id. 79 FR 1505, 1506, and 1511.
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    \558\ Note that in 40 CFR 70.2 and 71.2, the term ``Greenhouse
gases (GHGs)'' is defined as the ``aggregate group of six greenhouse
gases: Carbon dioxide, nitrous oxide, methane, hydrofluorocarbons,
perfluorocarbons, and sulfur hexafluoride.''
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f. The GHG Clarification
    The EPA proposed to move the existing definition of ``Greenhouse
gases (GHGs)'' within the definition of ``Subject to regulation'' in 40
CFR 70.2 and 71.2 to a separate definition within those sections to
promote clarity in the regulations. Id. 79 FR 1490, 1517, 1518.
4. What action is the EPA finalizing?
    In this action, the EPA is finalizing the following elements as
proposed: (1) The GHG exemption, (2) the GHG adjustment option 1, and
(3) the fee pollutant clarification.
    Public commenters on the proposal stated both support and
opposition to using the NSPS rulemaking action to revise the Title V
fee rules. Two commenters stated that proposing the Title V fee
revisions within the NSPS rulemaking would result in fewer commenters,
particularly state and local permitting authorities, having knowledge
of the changes to the fee rules and sufficient opportunity to comment
on the changes because the NSPS proposal is limited to a single source
category, and one stated that a separate proposal for the fee rules
would provide a sufficient opportunity for public comment. The EPA
believes it is appropriate to move forward with final action amending
the Title V fee regulations as part of this NSPS. As we explained in
the preamble for the proposal and elsewhere in this final rule, the fee
rules and the section 111 standards are interrelated because, if we do
not revise the fee rules, promulgation of the final NSPS will trigger
certain requirements related to Title V fees for GHG emissions that the
EPA believes will result in the collection of excessive fees in states
that implement the presumptive minimum approach and in the part 71
program. Thus, it is important to finalize the revisions to the fee
rules at the same time or prior to this NSPS, and it is within the
EPA's discretion to address the NSPS and the fee rules at the same time
as part of the same rulemaking action. In response to the commenters
who were concerned that including the fee rule proposal as part of the
NSPS proposal would result in the public not having sufficient public
comment opportunities, the EPA believes sufficient public comment
opportunities were provided on the fee rule changes because the
proposal met all public participation requirements and we provided
additional public outreach, including to state and local permitting
authorities, which discussed the fee rule proposal. In addition to the
publication of the proposed rulemaking in the Federal Register, the EPA
held numerous hearings, reached out to state partners and the public,
and developed numerous fact sheets and other information to support
public comment on this rule. The EPA has complied with the applicable
public participation requirements and executive orders. The proposal
met all the requirements for public notice--it contained a clear and
detailed explanation of how the part 70 and 71 rules would be affected
by the promulgation of the CAA section 111 standard for EGUs and how
the EPA proposed to revise the related regulatory provisions. We
received many comments on the proposal to revise the fee rule for
operating permits programs, and we are taking those comments into
consideration in the finalization of the rulemaking action.
a. The GHG Exemption
    The EPA is taking final action to revise the definition of
regulated pollutant (for presumptive fee calculation) in 40 CFR 70.2
and regulated pollutant (for fee calculation) in 40 CFR 71.2 to exempt
GHG emissions. This regulatory amendment will have the effect of
excluding GHG emissions from being subject to the statutory ($/ton) fee
rate set for the presumptive minimum calculation requirement of part 70
and the fee calculation requirements of part 71. We received supportive
comments from the majority of public commenters, including state and
local permitting authorities and others, on revising the operating
permit rules to exempt GHGs from the emission-based calculations that
use the statutory fee rates. We are finalizing this portion of the
proposal for the same reasons we explained in the proposal notice,
including that leaving these regulations unchanged would have resulted
in the collection of fee revenue far beyond the reasonable costs of an
operating permit program. The EPA believes that these revisions (in
conjunction with the GHG adjustment, see below) are consistent with the
CAA requirements for fees pursuant to the authority of section
502(b)(3)(B)(i).
    Some members of the public opposed the proposed GHG exemption for
reasons including that it may limit permitting authorities' ability to
charge sufficient fees to cover the cost of GHG permitting \559\ if the
state is barred from exceeding minimum requirements set by the EPA.
Despite this adverse comment, the EPA believes it is appropriate to
finalize the GHG exemption because we are not finalizing any
requirements that would require states to charge any particular fees to
any particular sources. The changes we are finalizing to part 70
concern the presumptive minimum approach, which sets a minimum fee
target for states that have decided to follow the presumptive minimum
approach. Neither the statute nor the final rule require any state
following the presumptive minimum approach (or any other approach) to
charge fees to sources using any particular method. Thus, the GHG
exemption will not limit states' ability to structure their individual
fee programs however they see fit in order to meet the requirement that
they collect revenue sufficient to cover all reasonable costs of their
permitting program. See CAA section 502(b)(3); 40 CFR 70.9(b)(3).
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    \559\ We use the term ``GHG permitting'' in this section of the
notice to refer to measures undertaken by permitting authorities to
ensure that GHGs and any applicable requirements related to GHGs are
appropriately addressed in Title V permitting.
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b. The GHG Adjustment Option 1
    The EPA is finalizing GHG adjustment option 1 because we believe it
will result in a system for the calculation of costs for part 70 and
fees for part 71 that is most directly related to the costs of GHG
permitting. The EPA has determined that some adjustment to cost and fee
accounting is important because the recent addition of GHG emissions to
the operating permitting program does add new burdens for permitting
authorities. Although GHG adjustment option 3 (no GHG permitting fee
adjustments) was supported by many industrial commenters, the EPA
rejected it because it is in tension with the statutory requirement
that permitting authorities collect sufficient fees to cover all the
reasonable costs of permitting. See CAA section 502(b)(3)(A). Some
state and local permitting authorities provided comments supporting
option 1, while others supported option 2, and some supported either
option, stating no preference. Also, a few state and local permitting
authorities supported finalizing no adjustment and a few others asked
for flexibility to set fee adjustments not proposed by the EPA, but
that they believed would be appropriate for their program.

    The EPA is finalizing option 1 instead of option 2 because the
option 1 adjustments are based on the actual costs for permitting
authorities to process specific actions that require GHG reviews. The
option 2 approach, which would have added a 7 percent surcharge to the
$/ton rate used in the fee-related calculations, may have been
administratively easier to implement, but is tied to the emissions of
non-GHG air pollutants, which are not directly related to the costs of
GHG permitting.
    Consistent with CAA section 502(b)(3)(B)(i), the Administrator has
determined that the final rule's approach of exempting GHG emissions
from fee-related calculations and accounting for the GHG permitting
costs through option 1 will result in fees that will cover the
reasonable costs of the permitting programs.
    The EPA is revising the part 70 regulations through this final
action, specifically 40 CFR 70.9(b)(2), to modify the presumptive
minimum approach to add the activity-based cost of GHG permitting
activities, outlined in the revised 40 CFR 70.9(b)(2)(v), to the
emissions-based calculation of 40 CFR 70.9(b)(2)(i), which is being
revised to now exclude GHG emissions. To determine the activity-based
GHG adjustment under 40 CFR 70.9(b)(2)(v), the permitting authority
will multiply the burden hours for each activity (set forth in the
regulation) by the cost of staff time (in $ per hour), including wages,
benefits, and overhead, as determined by the state, for the particular
activities undertaken during the particular time period.
    States that implement the presumptive minimum approach will need to
follow the final rule's option 1 approach.\560\ States that use the
detailed accounting approach are not directly affected by this
rulemaking, but they must ensure that their fee collection programs are
sufficient to fully fund all reasonable costs of the operating permit
program, including costs attributable to GHG-related permitting. The
EPA suggests states that use the detailed accounting approach consider
the 7 percent assumption for the costs of GHG permitting in any such
analysis, consistent with the EPA analysis of options 1 and 2 in the
proposal.
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    \560\ A presumptive minimum state may require various changes to
its approved operating permit program before it may begin to
implement the option 1 approach. For example, its regulations, and/
or program procedures and practices, may need to be revised,
depending on the structure of the fee provisions in the state's
program; thus, the exact response necessary to address this final
action may vary from state to state.
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    Consistent with 40 CFR 70.4(i), a state that wishes to change its
operating permit program as a result of this final rule must apprise
the EPA. The EPA will review the materials submitted concerning the
change and decide if a formal program revision process is needed and
will inform the state of next steps. The communication apprising the
EPA of any such changes should include at least a narrative description
of the change and any other information that will assist the EPA in its
assessment of the significance of the changes. Certain changes, such as
switching from the presumptive minimum method to a detailed accounting
method, will be considered substantial program revisions and be subject
to the requirements of 40 CFR 70.4(i)(2).
    With respect to the part 71 program, in this final action the EPA
is revising 40 CFR 71.9(c) to require each part 71 source to pay an
annual fee which is the sum of the activity-based fee of 40 CFR
71.9(c)(8) and the emissions-based fee of 40 CFR 71.9(c)(1)-(4),\561\
which excludes GHG emissions. To determine the activity-based fee, the
revised 40 CFR 71.9(c)(8) requires the source to pay a ``set fee'' for
each listed activity that has been initiated since the fee was last
paid. Under part 71, fees are typically paid at the time of initial
application submittal, and thereafter, annually on the anniversary of
the initial fee payment, or on any other dates that may be established
in the permit. These set fees would not change until such time as we
may revise our part 71 rule to change the set fees.
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    \561\ Note that the emissions-based fee calculation differs
somewhat depending on whether the part 71 program is being
implemented by the EPA (see 40 CFR 71.9(c)(1)); a state, local or
tribal agency with delegated authority from the EPA (see Sec.
71.9(c)(2)); the EPA with contractor assistance (see Sec.
71.9(c)(3)); or an agency with partial delegation authority (see
Sec.  71.9(c)(4)).
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    The final rule implements the option 1 approach by listing three
activities performed by permitting authorities that involve GHG
reviews. The following describes the activities as described in our
proposal and certain clarifications we are making in the final rule to
ensure consistent implementation.
    The EPA is finalizing that the first listed activity under option 1
is ``GHG completeness determination (for initial permit or updated
application).'' This activity must be counted for each new initial
permit application, even for applications that do not include GHGs
emissions or applicable requirements, since an important part of any
completeness determination will be to determine that GHG emissions and
applicable requirements have been properly addressed, as needed, in the
application. The fee for this activity is a one-time charge that covers
the initial application and any supplements or updates. The EPA
believes that a single charge for a GHG completeness determination will
be adequate to cover the reasonable costs for a permitting authority to
review an initial application and any subsequent application updates
related to initial permit issuance; thus, any updates to an initial
application are included in a single ``GHG completeness
determination,'' rather than as a separate activity for which the
source would be charged in addition to the completeness determination
for the initial application. This is an important distinction because
many sources submit multiple permit application updates, either
voluntarily or as required by the permitting authority, during
application review, many of which do not require a separate or
comprehensive completeness determination.
    The EPA is finalizing regulatory text that would describe the
second listed activity as ``GHG evaluation for a permit modification or
related permit action.'' \562\ The EPA had proposed that the second
listed activity under option 1 would be ``GHG evaluation for a
modification or related permit action.'' For the final rule, we are
clarifying that we are adding a cost for a ``permit modification''
rather than for a ``modification.'' The term ``modification'' may be
interpreted to refer to any change at a source, even a change that
would not be required to be processed as a ``permit modification,''
while ``permit modification'' refers to any revision to an operating
permit that cannot be processed as an administrative permit amendment
and thus requires a review by a permitting authority as either a
significant or minor permit modification.
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    \562\ The EPA notes that the term ``permit modification'' in
this context refers to all significant permit modifications and
minor permit modifications under operating permit rules, but not to
``administrative permit amendments,'' as such amendments are not
defined as ``permit modifications'' in the permit rules. See, e.g.,
40 CFR 70.7(d), (e), and (f).
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    The EPA is finalizing the third activity as ``GHG evaluation at
permit renewal.'' This activity covers the processing of all permit
renewal applications and will involve evaluations of whether any GHG
applicable requirements are properly included.
    Some members of the public commented that finalizing a GHG
adjustment would inappropriately

increase sources' financial burdens. The EPA has explained, both in the
proposal notice and elsewhere in this preamble, the importance of the
fee-related revisions to account for the costs associated with GHG-
related permitting. The EPA believes that the revisions being finalized
will result in modest and reasonable fee increases necessary to cover
states' increased costs.\563\ To the extent that commenters intended to
argue that the adjustments we proposed would exceed the actual costs of
GHG permitting, no commenters provided any information or analysis to
support that position. Some commenters did state that the costs
associated with GHG-related permitting should be minimal because few
applicable requirements will apply to GHGs. As stated earlier in this
notice, the EPA's cost estimate for the proposal concerned the
incremental costs of GHG permitting for any source, not just those that
would have, at the time of the analysis, triggered the requirement to
get a permit based on GHG emissions or applicable requirements.
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    \563\ The EPA estimated in the proposal that option 1 would
result in about a 7 percent overall increase in the annual part 70
fees that are collected by all permitting authorities nationally.
See 79 FR 1494.
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    Despite some comments received to the contrary, the EPA does not
believe it is appropriate to delay the finalization of the GHG
adjustment. The EPA does not believe such delays would be consistent
with CAA section 502(b)(3)(A) because states have been incurring costs
attributable to GHG permitting for several years now and increased fees
must be collected to cover the increased costs. The regulatory changes
being finalized in this action provide the states with optimal
flexibility and sufficient funding to implement their GHG permitting
programs. Some commenters had specifically stated that the EPA should
delay finalization of this rule until the completion of the next ICR
renewal process. While we do not believe delaying this rule is
appropriate, as explained above, the EPA notes that we remain committed
to collecting and analyzing additional data on costs attributable to
GHG permitting for operating permit programs. We may adjust the GHG
cost adjustments in future rulemakings if necessary to comply with the
requirements of the Act.