output to the grid. Even though these projects are not generally
designed to supply more than one-third of their potential electric
output to the grid, there can be rare instances when they do. For
instance, when a large base load unit in a transmission-constrained
area experiences a long, unexpected outage, it may be necessary to
operate simple cycle combustion turbines significantly more than
anticipated. The EPA believes the combination of the actual sales
criteria and the three year rolling average to determine if the sales
criteria are met will address this concern. Second, we are proposing to
revise the

third criteria to be met if the EGU is constructed for the purpose of
supplying ``more than 219,000 MWh,'' as opposed to ``25 MW,'' net-
electrical output to the grid. This proposed change to 219,000 MWh net
sales is consistent with the EPA Acid Rain Program (ARP) definition,
and we have concluded that it is functionally equivalent to the 25 MW
net sales language. The 25 MW sales value has been interpreted to be
the continuous sale of 25 MW of electricity on an annual basis, which
is equivalent to 219,000 MWh. We are also proposing to revise the
averaging period for electric sales from an annual basis to a three-
year rolling average for stationary combustion turbines. In addition,
we are proposing to add a new applicability criterion that is not
currently in subpart Da: EGUs, for which 10 percent or less of the heat
input over a three-year period is derived from a fossil fuel, are not
subject to any of the proposed CO2 standards.
---------------------------------------------------------------------------

    \78\ E.g., 40 CFR 60.40Da(a)(1).
    \79\ 40 CFR 60.41Da (definition of (``Electric utility steam-
generating unit'').
    \80\ Id.
---------------------------------------------------------------------------

    For the purposes of this rule, we are proposing several additional
changes to the way applicability is currently determined under subpart
Da. First, the proposed definition of potential electric output
includes ``or the design net electric output efficiency'' as an
alternative to the default one-third efficiency value for determining
the value of the potential electric output. Next, we are proposing to
add ``of the thermal host facility or facilities'' to the definition of
net-electric output for determining electric sales with respect to the
NSPS. Finally, consistent with our approach in the NSPS part of the
MATS rule and the original proposal for this rulemaking, we are
proposing to amend the definition of a steam generating unit to include
``plus any integrated equipment that provides electricity or useful
thermal output to either the affected facility or auxiliary equipment''
instead of the existing language ``plus any integrated combustion
turbines and fuel cells''. We are also proposing to add the additional
language to the definition of IGCC and stationary combustion turbine.
2. CO2 Emissions Only
    This action proposes to regulate covered EGU emissions of
CO2, and not other constituent gases of the air pollutant
GHGs. We identify the pollutant we propose to regulate as GHGs, but,
again, only CO2 emissions are subject to the proposed
standard of performance. We are not proposing separate emission limits
for other GHGs (such as methane (CH4) or nitrous oxide
(N2O)) as they represent less than 1 percent of total
estimated GHG emissions from fossil fuel-fired electric power
generating units.
    The proposed CO2 emission standards do not apply a
different accounting method for biogenic CO2 emissions for
the purpose of determining compliance with the standards. However, the
proposed CO2 emission standards only apply to new fossil
fuel-fired EGUs. Based on the applicability provisions in the proposal,
as discussed above, an EGU that primarily fires biomass would not be
subject to the CO2 emission standards. Such units could fire
fossil fuels up to 10 percent on a three-year average annual heat input
basis (e.g., for start-up and combustion stabilization) without
becoming subject to the standards.
    Issues related to accounting for biogenic CO2 emissions
from stationary sources are currently being evaluated by the EPA
through its development of an Accounting Framework for Biogenic
CO2 Emissions from Stationary Sources (Accounting
Framework).\81\ In general, the overall net atmospheric loading of
CO2 resulting from the use of a biogenic feedstock by a
stationary source, such as an EGU, will ultimately depend on the
stationary source process and the type of feedstock used, as well as
the conditions under which that feedstock is grown and harvested. In
September 2011, the EPA submitted a draft of the Accounting Framework
to the Science Advisory Board (SAB) Biogenic Carbon Emissions (BCE)
Panel for peer review. The SAB BCE Panel delivered its Peer Review
Advisory to the EPA on September 28, 2012.\82\ In its Advisory, the SAB
recommended revisions to the EPA's proposed accounting approach, and
also noted that biomass cannot be considered carbon neutral a priori,
without an evaluation of the carbon cycle effects related to the use of
the type of biomass being considered. The EPA is currently reviewing
the SAB peer review report, and will move forward as warranted once the
review is complete.
---------------------------------------------------------------------------

    \81\ The EPA's draft accounting framework is available at http://www.epa.gov/climatechange/ghgemissions/biogenic-emissions.html.
    \82\ The text of the SAB Peer Review Advisory is available at
http://yosemite.epa.gov/sab/sabproduct.nsf/0/2f9b572c712ac52e8525783100704886!OpenDocument&TableRow=2.3#2.
---------------------------------------------------------------------------

3. Sources Not Subject to This Rulemaking
    We are not proposing standards for certain types of sources. These
include new steam generating units and stationary combustion turbines
that sell one-third or less of their potential output to the grid; new
non-natural gas-fired stationary combustion turbines; \83\ existing
sources undertaking modifications or reconstructions; or certain
projects under development, including the proposed Wolverine EGU
project in Rogers City, Michigan (and, perhaps, up to two others) as
discussed below. As a result, under the CAA section 111(a) definitions
of ``new source'' and ``existing source,'' \84\ if those types of
sources commence construction or modification, they would not be
treated as ``new source[s]'' subject to the standards of performance
proposed today, and instead, they would be treated as existing sources.
---------------------------------------------------------------------------

    \83\ Oil-fired stationary combustion turbines, including both
simple and combined cycle units, are not subject to these proposed
standards. These units are typically used only in areas that do not
have reliable access to pipeline natural gas (for example, in non-
continental areas).
    \84\ CAA section 111(a)(2), (6).
---------------------------------------------------------------------------

B. Emission Standards

    In this rulemaking, the EPA is proposing NSPS for CO2
emissions from several subcategories of affected sources, which are new
fossil fired EGUs described above in Section III.A.
1. Standards of Performance for Affected Sources
a. Emission Standard
    The proposed standard of performance for each subcategory is in the
form of a gross energy output-based CO2 emission limit
expressed in units of emissions mass per unit of useful recovered
energy, specifically, in pounds per megawatt-hour (lb/MWh). This
emission limit would apply to affected sources upon the effective date
of the final action. In this notice, we sometimes refer to ``gross
energy output'' as ``gross output'' or ``adjusted gross output.''
    The subcategories, for which the EPA is proposing separate
standards of performance, are (1) natural gas-fired stationary
combustion turbines with a heat input rating that is greater than 850
MMBtu/h; \85\ (2) natural gas-fired stationary combustion turbines with
a heat input rating that is less than or equal to 850 MMBtu/h; and (3)
all fossil fuel-fired boilers and IGCC units, which generally are
solid-fuel fired.
---------------------------------------------------------------------------

    \85\ This subcategorization of stationary combustion turbines is
consistent with the subcategories used in the combustion turbine
(subpart KKKK) criteria pollutant NSPS. The size limit of 850 MMBtu/
h corresponds to approximately 100 MWe.
---------------------------------------------------------------------------

    We are proposing that all affected new fossil fuel-fired EGUs are
required to meet an output-based emission rate of a specific mass of
CO2 per MWh of useful output. Specifically, new combustion
turbines with a heat input rating greater

than 850 MMBtu/h would be required to meet a standard of 1,000 lb
CO2/MWh. New combustion turbines with a heat input rating
less than or equal to 850 MMBtu/h would be required to meet a standard
of 1,100 lb CO2/MWh. As discussed below, these proposed
standards are based on the demonstrated performance of recently
constructed NGCC units, which are currently in wide use throughout the
country, and are currently the predominant fossil fuel-fired technology
for new electric generating units in the near future.
    While the EPA is proposing specific standards of performance for
each subcategory, we are also taking comment on a range of potential
emission limitations. We solicit comment on a range of 950-1,100 lb
CO2/MWh for new stationary combustion turbines with a heat
input rating greater than 850 MMBtu/h. We also solicit comment on an
emission limitation range of 1,000-1,200 lb CO2/MWh for new
stationary combustion turbines with a heat input rating less than or
equal to 850 MMBtu/h. In addition, we solicit comment on an emission
limitation for new fossil fuel-fired boilers and IGCC units in the
range of 1,000-1,200 lb CO2/MWh.
    The proposed method to calculate compliance is to sum the emissions
for all operating hours and to divide that value by the sum of the
useful energy output over a rolling 12-operating-month period. In the
alternative, we solicit comment on requiring calculation of compliance
on an annual (calendar year) period.
b. Gross Output
    Subpart Da currently defines ``gross energy output'' from new units
as the ``gross electrical or mechanical output from the affected
facility minus any electricity used to power the feedwater pumps and
any associated gas compressors (air separation unit main compressor,
oxygen compressor, and nitrogen compressor) plus 75 percent of the
useful thermal output measured relative to ISO conditions'' \86\ \87\
(referred to in today's document as ``adjusted gross output''). The
current criteria pollutant emission standards for new subpart Da units
were developed by analyzing the gross emission rates of PC and CFB
facilities, and were finalized on February 16, 2013 (77 FR 9304). In
that rulemaking, we applied the same standards to traditional coal-
fired and IGCC EGUs. The adjusted gross output definition accounts for
the largest gas compressors at an IGCC facility. Consequently, IGCC
facilities complying with the NSPS requirements would emit at
approximately the same net output based emissions rate (i.e., gross
output minus auxiliary power requirements) as a comparable traditional
coal-fired EGU. Therefore, with the definition of gross energy output
for criteria pollutant emission standards (i.e., adjusted gross
output), both IGCC and traditional coal-fired EGUs that have the same
gross energy output-based emissions rate would have a similar net
output-based emissions rate. If we did not include the parasitic load
from the primary gas compressors when determining the gross emissions
rate of an IGCC facility, it would emit more pollutants to the
atmosphere than a traditional coal-fired EGU when complying with the
criteria pollutant NSPS.
---------------------------------------------------------------------------

    \86\ 40 CFR 60.41Da.
    \87\ International Standards Organization Metric (ISO)
Conditions are 288 Kelvin (15 [deg]C), 60 percent relative humidity,
and 101.325 kilopascals (kPa) pressure.
---------------------------------------------------------------------------

    In contrast, in the April 2012 proposal, we proposed a definition
of gross output as ``the gross electrical or mechanical output from the
unit plus 75 percent of the useful thermal output measured relative to
ISO conditions that is not used to generate additional electrical or
mechanical output or to enhance the performance of the unit (i.e.,
steam delivered to an industrial process).'' This definition was
appropriate since NGCC was the BSER for the combined subcategory and
auxiliary loads associated with feedwater pumps and associated
compressors (air separation unit main compressor, oxygen compressor,
and nitrogen compressor) are not relevant to the gross efficiency of an
NGCC. However, we requested comment on requiring the use of net output
based standards. Part of the rationale behind the use of net output-
based standards is that the use of a gross output-based standard as
defined could have potentially driven the installation of electrically
driven feed pumps instead of steam driven feed pumps at a steam
generating unit, even though from an overall net efficiency basis it
may be more efficient to use steam-driven feed pumps.
    After further consideration and because many of the proposed IGCC
facilities are actually co-production facilities (i.e., they produce
useful byproducts and chemicals along with electricity), we have
concluded that measuring the electricity used by the primary gas
compressors associated with electricity production at IGCC facilities
could be more challenging to implement.
    Therefore, we are proposing to define the gross energy output for
traditional steam generating units to include the electricity measured
at the generator terminals minus electric power used to run the
feedwater pumps, and to define the gross electric output for IGCC and
subpart KKKK affected facilities to include the electricity measured at
the generator terminals. We are considering and requesting comment on
(1) whether the definition of ``gross energy output'' in subpart Da for
GHGs should be consistent with the current definition in subpart Da for
criteria pollutants, (2) whether we should adopt the proposed
definition of ``gross energy output'', and (3) whether the definition
should be the same for both traditional and IGCC facilities. We seek
comment on how to account for energy consumption associated with
products other than electricity and useful thermal output created at a
poly-generation facility and the impact of that energy use on the
numerical emissions standard, all of which is relevant to possible
adoption of an adjusted gross output definition.
    We are also considering and requesting comment on using net-output
based standards either as a compliance alternative for, or in lieu of,
gross-output based standards, including whether we should have a
different approach for different subcategories. In the compliance
alternative approach, owners/operators would elect to comply with
either a gross-output based standard or an alternate net-output based
standard. As described in the original proposal for this rulemaking,
net output is the combination of the gross electrical output of the
electric generating unit minus the parasitic (i.e., auxiliary) power
requirements. A parasitic load for an electric generating unit is any
of the loads or devices powered by electricity, steam, hot water, or
directly by the gross output of the electric generating unit that does
not contribute electrical, mechanical, or thermal output. In general,
less than 7.5 percent of non-IGCC and non-CCS coal-fired station power
output, approximately 15 percent of non-CCS IGCC-based coal-fired
station power output and about 2.5 percent of non-CCS combined cycle
station power output is used internally by parasitic energy demands,
but the amount of these parasitic loads vary from source to source.
Reasons for using net output include (1) recognizing the efficiency
gains of selecting EGU designs and control equipment that require less
auxiliary power, (2) selecting fuels that require less emissions
control equipment, and (3) recognizing the environmental benefit of
higher efficiency motors, pumps, and fans.

While the EPA has concluded that the net power supplied to the end user
is a better indicator of environmental performance than gross output
from the power producer, we only have CEMS emissions data reported on a
gross output basis because that is the way the data is currently
reported under 40 CFR part 75. As noted, switching from gross output to
net or adjusted gross output would have little or no impact on the
required rates for gas-fired NGCC plants, which are likely to be the
dominant fossil fuel-fired technology for new intermediate or base load
power generation. Since the change would have little impact on these
units in terms of environmental performance, the EPA has proposed to
use a standard consistent with current reporting protocols. However, as
is noted in Table 4, the use of net instead of gross output could have
a much larger impact on coal-fired power plants.

                 Table 4--Subpart Da Emission Rates \88\
------------------------------------------------------------------------
                                      Approximate
                                      equivalent          Approximate
   Gross output based standard      adjusted gross      equivalent net
                                     output based        output based
                                       standard            standard
------------------------------------------------------------------------
450 kg/MWh (1,000 lb/MWh).......  510 kg/MWh (1,100   560 kg/MWh (1,200
                                   lb/MWh).            lb/MWh).
500 kg/MWh (1,100 lb/MWh).......  570 kg/MWh (1,300   620 kg/MWh (1,400
                                   lb/MWh).            lb/MWh).
540 kg/MWh (1,200 lb/MWh).......  610 kg/MWh (1,300   670 kg/MWh (1,500
                                   lb/MWh).            lb/MWh).
------------------------------------------------------------------------

                  Table 5--Subpart KKKK Emission Rates
------------------------------------------------------------------------
                                             Approximate  equivalent net
        Gross output based standard            output based  standard
------------------------------------------------------------------------
430 kg/MWh (950 lb/MWh)...................  440 kg/MWh (970 lb/MWh).
450 kg/MWh (1,000 lb/MWh).................  460 kg/MWh (1,000 lb/MWh).
500 kg/MWh (1,100 lb/MWh).................  510 kg/MWh (1,100 lb/MWh).
540 kg/MWh (1,200 lb/MWh).................  560 kg/MWh (1,200 lb/MWh).
------------------------------------------------------------------------

    Requiring or including an optional net-output based standard would
provide more operational flexibility and expand the technology options
available to comply with the standard for coal-fired PC and CFB EGUs.
---------------------------------------------------------------------------

    \88\ Rounding to two significant figures results in the same
standard in units of lb/MWh in some cases.
---------------------------------------------------------------------------

    In addition, we are proposing that with respect to CO2
emissions, 75 percent credit is the appropriate discount factor for
useful thermal output. However, we are requesting comment on a range of
two-thirds to three-fourths credit for useful thermal output in the
final rule.
2. 84-Operating-Month Rolling Average Compliance Option
    We also propose an 84-operating-month rolling average compliance
option that would be available for affected subpart Da boilers and IGCC
facilities. The EPA suggests that this 84-operating-month rolling
average compliance option will offer operational flexibility and will
tend to dampen short-term emission excursions, which may be warranted
especially at the initial startup of the facility and the CCS system.
    Thus, under our proposed approach, new fossil fuel-fired boilers
and IGCC units would be required, based on the performance of currently
available CCS technology, to meet a standard of 1,100 lb
CO2/MWh on a 12-operating-month rolling average, or
alternatively a lower--but equivalently stringent--standard on an 84-
operating-month rolling average, which we propose as between 1,000 lb
CO2/MWh and 1,050 lb CO2/MWh. The EPA has
previously offered sources optional, longer-term emission standards
that are discounted from the primary emissions standard in combination
with a longer averaging period. We are requesting comment on the
appropriate numerical standard such that the 84-operating-month
standard would be as stringent as or more stringent than the 12-
operating-month standard. We also request comment on whether owners/
operators electing to comply with the 84-operating-month standard
should also be required to comply with a maximum 12-operating-month
standard. This standard would be between the otherwise applicable
proposed 1,100 lb CO2/MWh standard and an emissions rate of
a coal-fired EGU without CCS (e.g., 1,800 lb CO2/MWh), and
we solicit comment on what the standard should be. This shorter term
standard would facilitate enforceability and assure adequate emission
reductions.
    We have concluded that this alternative compliance option is not
necessary for new stationary combustion turbine EGUs, as they should be
able to meet the proposed performance standard with no need for add-on
technology. We seek comment on all other aspects of this 84-operating-
month rolling averaging compliance option.
3. Combined Heat and Power
    To recognize the environmental benefit of reduced electric
transmission and distribution losses of CHP, we are proposing that CHP
facilities where at least 20.0 percent of the total gross useful energy
output consists of electric or direct mechanical output and 20.0
percent of the total gross useful energy output consists of useful
thermal output on a rolling three calendar year basis receive similar
credit as currently in subpart Da and the proposed amendments to
subpart KKKK (77 FR 52554). Specifically, the measured electric output
would be divided by 0.95 to account for a five percent avoided energy
loss in the transmission of electricity. The minimal electric and
thermal output requirements are to avoid owners/operators from selling
trivial amounts of thermal output and claiming a line loss benefit when
in reality they are similar to a central power station.
    Actual transmission and distribution losses vary from location to
location, but we propose that this 5 percent of actual MWh represents a
reasonable average amount for the avoided transmission and distribution
losses for CHP facilities. Note that we propose to limit this 5 percent
adjustment to facilities for which the useful thermal output is at
least 20 percent of the total output.

C. Startup, Shutdown, and Malfunction Requirements

1. Startups and Shutdowns
    Consistent with Sierra Club v. EPA,\89\ the EPA is proposing
standards in this rule that apply at all times, including during
startups and shutdowns. In proposing the standards in this rule, the
EPA has taken into account startup and shutdown periods and, for the
reasons explained below has not proposed alternate standards for those
periods. In the compliance calculation, periods of startup and shutdown
are included as periods of partial load. To establish the proposed
NSPS's output-based CO2 standard, we accounted for periods
of startup and shutdown by incorporating them as periods of partial
load operation. As noted above, the proposed

method to calculate compliance is to sum the emissions for all
operating hours and to divide that value by the sum of the electrical
energy output and useful thermal energy output, where applicable for
CHP EGUs, over a rolling 12-operating-month period. The EPA is
proposing that sources incorporate in their compliance determinations
emissions from all periods, including startup or shutdown, that fuel is
combusted and emissions monitors are not out-of-control, as well as all
power produced over the periods of emissions measurements. Given that
the duration of startup or shutdown periods are 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 during startup or shutdown periods, the
impact of these periods on the total average is expected to be minimal.
Periods of startup and shutdown will be short, relative to total
operating time. Since we are primarily concerned with overall
environmental performance over extended periods of time, incorporating
relatively short periods of partial load is believed to have a
negligible effect on the performance of the source with respect to
long-term efficiency.
---------------------------------------------------------------------------

    \89\ 551 F.3d 1019 (D.C. Cir. 2008).
---------------------------------------------------------------------------

    We solicit comment on any alternative to our proposal that the
periods of startup and shutdown be included as periods of partial load
in the 12- and 84-operating-month rolling averaging compliance option.
2. Malfunctions
    Periods of startup, normal operations, and shutdown are all
predictable and routine aspects of a source's operations. However, by
contrast, malfunction is defined as a sudden, infrequent, and not
reasonably preventable failure of air pollution control and monitoring
equipment, process equipment or a process to operate in a normal or
usual manner. Failures that are caused in part by poor maintenance or
careless operations are not malfunctions.(40 CFR 60.2). The EPA has
determined that CAA section 111 does not require that emissions that
occur during periods of malfunction be factored into development of CAA
section 111 standards. Nothing in CAA section 111 or in case law
requires that the EPA anticipate and account for the innumerable types
of potential malfunction events in setting emission standards. CAA
section 111 provides that the EPA set standards of performance which
reflect the degree of emission limitation achievable through ``the
application of the best system of emission reduction'' that the EPA
determines is adequately demonstrated. Applying the concept of ``the
application of the best system of emission reduction'' to periods
during which a source is malfunctioning presents difficulties. The
``application of the best system of emission reduction'' is more
appropriately understood to include operating units in such a way as to
avoid malfunctions.
    Further, accounting for malfunctions 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, the goal of a source that
uses the best system of emission reduction is to operate in such a way
as to avoid malfunctions of the source and accounting for malfunctions
could lead to standards that are significantly less stringent than
levels that are achieved by a well-performing non-malfunctioning
source. The EPA's approach to malfunctions is consistent with section
111 and is a reasonable interpretation of the statute.
    In the 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).
    Finally, the EPA recognizes that even equipment that is properly
designed and maintained can sometimes fail and that such failure can
sometimes cause a violation of the relevant emission standard. (See,
e.g., State Implementation Plans: Response to Petition for Rulemaking;
Finding of Excess Emissions During Periods of Startup, Shutdown, and
Malfunction; Proposed Rule, 78 FR 12460 (Feb. 22, 2013): (State
Implementation Plans: Policy Regarding Excessive Emissions During
Malfunctions, Startup, and Shutdown (Sept. 20, 1999); Policy on Excess
Emissions During Startup, Shutdown, Maintenance, and Malfunctions (Feb.
15, 1983)). The EPA is therefore proposing to add an affirmative
defense to civil penalties for violations of emission standards that
are caused by malfunctions. See 40 CFR 60.10042 (defining ``affirmative
defense'' to mean, in the context of an enforcement proceeding, a
response or defense put forward by a defendant, regarding which the
defendant has the burden of proof, and the merits of which are
independently and objectively evaluated in a judicial or administrative
proceeding). We also are proposing other regulatory provisions to
specify the elements that are necessary to establish this affirmative
defense; the source must prove by a preponderance of the evidence that
it has met all of the elements set forth in Sec.  60.5530. (See 40 CFR
22.24). The criteria are designed in part to ensure that the
affirmative defense is available only where the event that causes a
violation of the emission standard meets the narrow definition of
malfunction in 40 CFR 60.2 (sudden, infrequent, not reasonably
preventable and not caused by poor maintenance and or careless
operation). For example, to successfully assert the affirmative
defense, the source must prove by a preponderance of the evidence that
the violation ``[w]as caused by a sudden, infrequent, and unavoidable
failure of air pollution control, process equipment, or a process to
operate in a normal or usual manner . . .'' The criteria also are
designed to ensure that steps are taken to correct the malfunction, to
minimize emissions in accordance with Sec.  60.5530 and to prevent
future malfunctions. For example, the source must prove by a
preponderance of the evidence that

``[r]epairs were made as expeditiously as possible when a violation
occurred . . .'' and that ``[a]ll possible steps were taken to minimize
the impact of the violation on ambient air quality, the environment and
human health . . .'' In any judicial or administrative proceeding, the
Administrator may challenge the assertion of the affirmative defense
and, if the respondent has not met its burden of proving all of the
requirements in the affirmative defense, appropriate penalties may be
assessed in accordance with section 113 of the CAA (see also 40 CFR
22.27).
    The EPA included an affirmative defense in the proposed rule in an
attempt to balance 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 beyond the control of the source. The EPA
must establish emission standards that ``limit the quantity, rate, or
concentration of emissions of air pollutants on a continuous basis.''
42 U.S.C. 7602(k) (defining ``emission limitation'' and ``emission
standard''). See generally Sierra Club v. EPA, 551 F.3d 1019, 1021
(D.C. Cir. 2008) Thus, the EPA is required to ensure that section 111
emissions standards are continuous. The affirmative defense for
malfunction events meets this requirement by ensuring that even where
there is a malfunction, the emission standard is still enforceable
through injunctive relief. The United States Court of Appeals for the
Fifth Circuit recently upheld the EPA's view that an affirmative
defense provision is consistent with section 113(e) of the Clean Air
Act. Luminant Generation Co. LLC v. United States EPA, 2013 U.S. App.
LEXIS 6397 (5th Cir. Mar. 25, 2013) 699 F3d. 427 (5th Cir. Oct. 12,
2012) (upholding the EPA's approval of affirmative defense provisions
in a CAA State Implementation Plan). While ``continuous'' standards, on
the one hand, are required, there is also case law indicating that in
many situations it is appropriate for the EPA to account for the
practical realities of technology. For example, in Essex Chemical v.
Ruckelshaus, 486 F.2d 427, 433 (D.C. Cir. 1973), the D.C. Circuit
acknowledged that in setting standards under CAA section 111 ``variant
provisions'' such as provisions allowing for upsets during startup,
shutdown and equipment malfunction ``appear necessary to preserve the
reasonableness of the standards as a whole and that the record does not
support the `never to be exceeded' standard currently in force.'' See
also, Portland Cement Association v. Ruckelshaus, 486 F.2d 375 (D.C.
Cir. 1973). Although due to intervening case law such as Sierra Club v.
EPA and the CAA 1977 amendments (which added the ``continuous''
requirement of 42 U.S.C. 7602(k)) these cases are no longer good law on
whether EPA can exempt malfunctions from liability, their core
principle remains valid: regulatory accommodation is appropriate where
a standard cannot be achieved 100 percent of the time due to
circumstances out of the control of the owner/operator of the source,
and a system that incorporates some level of flexibility is reasonable.
The affirmative defense simply provides for a defense to civil
penalties for violations that are proven to be beyond the control of
the source. By incorporating an affirmative defense, the EPA has
formalized its approach to malfunctions. In a Clean Water Act setting,
the Ninth Circuit required this type of formalized approach when
regulating ``upsets beyond the control of the permit holder.'' Marathon
Oil Co. v. EPA, 564 F.2d 1253, 1272-73 (9th Cir. 1977). See also, Mont.
Sulphur & Chem. Co. v. United States EPA, 666 F.3d. 1174 (9th Cir.
2012) (rejecting industry argument that reliance on the affirmative
defense was not adequate). But see, Weyerhaeuser Co. v. Costle, 590
F.2d 1011, 1057-58 (D.C. Cir. 1978) (holding that an informal approach
is adequate). The affirmative defense provisions give the EPA the
flexibility to both ensure that its emission standards are
``continuous'' as required by 42 U.S.C. 7602(k), and account for
unplanned upsets and thus support the reasonableness of the standard as
a whole.
    We propose that these same requirements, an affirmative defense to
civil penalties for violations of emission limits that are caused by
malfunctions, would apply to both the 12-operating-month standard and
the 84-operating-month rolling average compliance option; however, we
will take comment on whether it is appropriate to have an affirmative
defense for the 84-operating-month rolling average portion of that
compliance option, given that we would expect malfunctions to only
impact shorter averaging periods, and the longer the compliance period,
the less likely malfunction events are to impact a source's ability to
meet the standard.

D. Continuous Monitoring Requirements

    Today's proposed rule would require owners or operators of EGUs
that combust solid 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 proposed rule would allow owners or operators of 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 proposed rule would require 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 proposed rule would require EGU owners or operators to prepare
and submit a monitoring plan that includes both electronic and hard
copy components, in accordance with Sec. Sec.  75.53(g) and (h). The
electronic portion of the monitoring plan would be submitted to the
EPA's Clean Air Markets Division (CAMD) using the Emissions Collection
and Monitoring Plan System (ECMPS) Client Tool. The hard copy portion
of the plan would be sent to the applicable State and EPA Regional
office. Further, all monitoring systems used to determine the
CO2 mass emission rates would have to be certified according
to Sec.  75.20 and section 6 of Appendix A to part 75 within the 180-
day window of time allotted under Sec.  75.4(b), and would be required
to meet the applicable on-going quality assurance procedures in
Appendices B and D of part 75.
    The proposed rule would require 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). An affirmative defense to civil penalties for
malfunctions is available to a source if it can demonstrate that
certain criteria and requirements are satisfied.
    The proposed rule would require 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 compliance
purposes. Additionally for EGUs using CO2 CEMS, only
unadjusted stack gas flow rate values would be used in the emissions
calculations. In this proposal, Part 75 bias adjustment factors (BAFs)
would 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.
    The following variations from and additions to the basic part 75
monitoring would be required:
     If you determine compliance using CEMS, you would be
required to use a laser device to measure the stack diameter at the
flow monitor and the reference method sampling locations prior to the
initial setup (characterization) of the flow monitor. For circular
stacks, you would need to make measurements of the diameter at 3 or
more distinct locations and average the results. For rectangular stacks
or ducts, you would need to make measurements of each dimension (i.e.,
depth and width) at 3 or more distinct locations and average the
results. If the flow rate monitor or reference method sampling site is
relocated, you would repeat these measurements at the new location.
     If you elect to use Method 2 in Appendix A-1 of part 60 to
perform the required relative accuracy test audits (RATAs) of the part
75 flow rate monitoring system, you would have to use a calibrated
Type-S pitot tube or pitot tube assembly. Use of the default Type-S
pitot tube coefficient would not be permitted.
     If your EGU combusts natural gas and/or fuel oil and you
elect to measure the CO2 mass emissions rate using Equation
G-4 in Appendix G of part 75, you would be allowed to determine site-
specific carbon-based F-factors using Equation F-7b in section 3.3.6 of
Appendix F of part 75, and you could use these Fc values in
the emissions calculations instead of using the default Fc
values in the Equation G-4 nomenclature.
    Today's proposed rule includes the following special compliance
provisions for units with common stack or multiple stack
configurations; these provisions are consistent with Sec.  60.13(g):
     If two or more of your EGUs share a common exhaust stack,
are subject to the same emission limit, and you are required to (or
elect to) determine compliance using CEMS, you would be allowed to
monitor the hourly CO2 mass emission rate at the common
stack instead of monitoring each EGU separately. If this option is
chosen, the hourly gross electrical load (or steam load) would be the
sum of the hourly loads for the individual EGUs and the operating time
would be 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 would be in
compliance with the CO2 emissions limit.
     If you are required to (or elect to) determine compliance
using CEMS and the effluent from your EGU discharges to the atmosphere
through multiple stacks (or, if the effluent is fed to a stack through
multiple ducts and you choose to monitor in the ducts), you would be
required to monitor the hourly CO2 mass emission rate and
the ``stack operating time'' at each stack or duct separately. In this
case, compliance with the applicable emission limit would be 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 proposed rule would require 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 would have the option to use backup monitoring systems, as
provided in Sec. Sec.  75.10(e) and 75.20(d), to help meet this
proposed data capture requirement.

E. Emissions Performance Testing Requirements

    In accordance with Sec.  75.64(a), the proposed rule would require
an EGU owner or operator to begin reporting emissions data when
monitoring system certification is completed or when the 180-day window
in Sec.  75.4(b) allotted for initial certification of the monitoring
systems expires (whichever date is earlier). For EGUs subject to the
450 kg/MWh (1,000 lb/MWh) standard or the 500 kg/MWh (1,100 lb/MWh)
emission standard, the initial performance test would consist 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 would begin 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 Sec.  60.8 would not be required for this rule. Following
the initial compliance determination, the emission standard would be
met on a 12-operating-month rolling average basis. For EGUs that
combust coal and/or petroleum coke and whose owners or operators elect
to comply with the alternative 84-operating-month rolling average
emissions standard, the first month in the compliance period would be
the month in which emissions reporting is required to begin under Sec.
75.64(a).

F. Continuous Compliance Requirements

    Today's proposed rule specifies that compliance with the 1,000 lb/
MWh (450 kg/MWh) and 1,100 lb/MWh (500 kg/MWh) CO2 mass
emissions rate limits would be 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 would be used together with the
gross output over that period of time to calculate the average
CO2 mass emissions rate.
    The proposed rule specifies that the first operating month included
in either the initial 12- or 84-operating-month compliance period would
be the month in which reporting of emissions data is required to begin
under Sec.  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).
    We are proposing that initial compliance with the applicable
emissions limit in kg/MWh be calculated by dividing the sum of the
hourly CO2 mass emissions values by the total gross output
for the 12- or 84-operating-month period. Affected EGUs would continue
to be subject to the standards and maintenance requirements in the
section 111 regulatory general provisions contained in 40 CFR Part 60,
subpart A.

G. Notification, Recordkeeping, and Reporting Requirements

    Today's proposed rule would require an EGU owner or operator to
comply with the applicable notification requirements in Sec. Sec.
75.61, 60.7(a)(1) and (a)(3) and 60.19. The proposed rule would also
require the applicable recordkeeping requirements in subpart

F of part 75 to be met. For EGUs using CEMS, the data elements that
would be 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 would be recorded
include hourly fuel flow rates, fuel usage times, fuel GCV, gross
electric generation.
    The proposed rule would require EGU owners or operators to keep
records of the calculations performed to determine the total
CO2 mass emissions and gross output for each operating
month. Records would be kept 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. The proposed rule would also require records to be
kept of calculations performed to determine site-specific carbon-based
F-factors for use in Equation G-4 of part 75, Appendix G (if
applicable).
    For EGU owners or operators who would elect to comply with the 84-
operating-month rolling average emissions standard, records must be
kept for 10 years. All other records would be kept for a period of
three years. All required records would be kept on-site for a minimum
of two years, after which the records could be maintained off-site.
    The proposed rule would require all affected EGU owners/operators
to submit quarterly electronic emissions reports in accordance with
subpart G of part 75. The proposed rule would require these reports 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 today's rule.
    Additionally, in the proposed rule and as part of an Agency-wide
effort to streamline and facilitate the reporting of environmental
data, the rule would require selected data elements that pertain to
compliance under this rule, and that serve the purpose of traditional
excess emissions reports, to be reported periodically using ECMPS.
    Specifically, for EGU owners/operators who would comply with a 12-
operating-month rolling average standard, quarterly electronic ``excess
emissions'' reports must be submitted, within 30 days after the end of
each quarter. The first report would be 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 twelfth operating month of a compliance period (or periods)
occurs during the calendar quarter, the average CO2 mass
emissions rate (kg/MWh) would be 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 would 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 excess emissions
that occur during the quarter would be identified. If there are no
compliance periods that end in the quarter, a definitive statement to
that effect would be included in the report. If one or more compliance
periods end in the quarter but there are no excess emissions, a
statement to that effect would be included in the report.
    For EGU owners or operators that would comply with an 84-operating-
month rolling average basis, quarterly electronic ``excess emissions''
reports would be submitted, within 30 days after the end of each
quarter. The first report would be for the quarter that includes the
final (60th) operating month of the initial 84-operating-month
compliance period. For that initial report and any subsequent report in
which the sixtieth operating month of a compliance period (or periods)
occurs during the calendar quarter, the average CO2 mass
emissions rate (kg/MWh) must be reported for each compliance period,
along with the dates (year and month) of the first and sixtieth
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 would clearly bracket the period used in the determination,
which facilitates auditing of the data. Reporting of 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 excess emissions
that occur during the quarter would be identified. If there are no
compliance periods that end in the quarter, a definitive statement to
that effect would be included in the report. If one or more compliance
periods end in the quarter but there are no excess emissions, a
statement to that effect would be included in the report.
    Currently, ECMPS is not programmed to receive excess emission
report information from EGUs. However, we will make the necessary
modifications to the system in order to fully implement the reporting
requirements of this rule upon promulgation.
    For EGU owners or operators that would assert an affirmative
defense for a failure to meet a standard due to malfunction, the owner
or operator must follow the reporting requirements for affirmative
defense. Those requirements are found in 40 CFR 60.5530. The report to
the Administrator, with all necessary supporting documentation,
explains how the source has met the requirements set forth in subparts
Da, KKKK, and TTTT to assert affirmative defense. This report must be
submitted on the same schedule as the next quarterly report required
after the initial occurrence of the violation of the relevant standard
(which may be the end of any applicable averaging period). If the
quarterly report is due less than 45 days after the initial occurrence
of the violation, the affirmative defense report may be included in the
second quarterly report due after the initial occurrence of the
violation of the relevant standard.

IV. Rationale for Reliance on Rational Basis To Regulate GHGs From
Fossil-Fired EGUs

A. Overview

    In our original proposal, we proposed and solicited comment on what
basis we are required to have concerning the health and welfare impacts
of GHG emissions from fossil-fuel fired power plants in order to
regulate those emissions under CAA section 111. However, we took the
position that we are not required to make findings that GHGs from
fossil-fired power plants ``cause [ ], or contribute [ ] significantly
to, air pollution which may reasonably be anticipated to endanger
public health or welfare,'' under CAA section 111(b)(1)(A).
    We have reconsidered that proposal in light of the numerous
comments we received. In today's document, we propose that under
section 111, the EPA is required to have a rational basis for

promulgating standards for GHG emissions from electricity generating
plants, and that the EPA has such a basis because the EPA has already
determined that GHG emissions may reasonably be anticipated to endanger
public health and welfare, and because electricity generating plants,
as an industry, constitute, by a significant margin, the largest
emitters in the inventory. In the April 2012 proposal, the EPA
discussed whether CAA section 111 requires that the EPA issue, as a
prerequisite for this rulemaking, another ``endangerment'' finding.
After reviewing the comments, recent scientific developments, the
amount of emissions from the power plant sector, and the case law, the
EPA has concluded that even if section 111 requires an endangerment
finding, the rational basis described in today's action would qualify
as an endangerment finding as well.
    As related matters, in this notice, we are proposing to establish
regulatory requirements for CO2 emissions of affected units,
which are included in source categories (both steam-generating units
and turbines) that the EPA already listed under CAA section
111(b)(1)(A) for regulation under CAA and we are not proposing a
listing of a new source category. We are, however, proposing to
subcategorize different sets of sources, and establish different
CO2 standards of performance for them, in accordance with
CAA section 111(b)(2). To avoid confusion, we are proposing to codify
the CO2 standards of performance in the same subparts--Da
and KKKK, depending on the types of units--that currently include the
standards of performance for conventional pollutants. We are also co-
proposing, in the alternative, to codify the CO2 standards
in a new subpart, TTTT, as we proposed in the original proposal for
this rulemaking in April, 2012.\90\
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    \90\ It should be noted that CAA section 111 clearly applies to
GHGs. The U.S. Supreme Court has made this clear because (i) section
111 applies to ``any air pollutant,'' CAA section 111(a)(3), see
section 111(d)(1)(A) (exempting, for purposes of section 111(d),
certain air pollutants); and in Massachusetts v. EPA, 549 U.S. 497
(2007), the Supreme Court held that the term ``air pollutant,'' as
defined under CAA section 302(g), includes GHGs; and (ii) in
American Electric Power Company v. Connecticut, 131 S.Ct. 2527
(2011), the Supreme Court based its holding that ``the Clean Air Act
and the EPA actions it authorizes displace any federal common law
right to seek abatement of carbon-dioxide emissions from fossil
fuel-fired power plants'' on the grounds that CAA section 111
``provides a means to seek limits on emissions of carbon dioxide
from domestic power plants * * *.'' Id. at 2538.
---------------------------------------------------------------------------

B. Climate Change Impacts From GHG Emissions; Amounts of GHGs From
Fossil Fuel-Fired EGUs

    In 2009, the EPA Administrator issued the Endangerment Finding
under CAA section 202(a)(1). With the Endangerment Finding, the
Administrator found that elevated concentrations of GHGs in the
atmosphere may reasonably be anticipated to endanger public health and
welfare of current and future generations, and focused on public health
and public welfare impacts within the United States. Fossil fuel-fired
EGUs are by far the largest emitters of GHGs, primarily in the form of
CO2, among stationary sources in the U.S. These adverse
effects of GHGs on public health and welfare, and the amounts of GHGs
emitted by fossil fuel-fired EGUs are briefly summarized in the Section
II of this preamble and described in more detail in the RIA, and need
not be recited here.

C. CAA Section 111 Requirements

    To review the key CAA section 111 requirements: CAA section
111(b)(1)(A), by its terms, requires that the Administrator publish
(and from time to time thereafter shall revise) a list of categories of
stationary sources. He shall include a category of sources in such list
if in his judgment it causes, or contributes significantly to air
pollution which may reasonably be anticipated to endanger public health
or welfare.
    CAA section 111(b)(1)(B) goes on to provide that after listing the
source category, the EPA must promulgate regulations ``establishing
federal standards of performance for new sources within such
category.'' In turn, CAA section 111(a)(1) defines a ``standard of
performance'' as a ``standard for emissions of air pollutants which
reflects the degree of emission reduction which (taking into account *
* * cost * * * and any nonair quality health and environmental impact
and energy requirements) . . . has been adequately demonstrated.'' CAA
section 111(b)(2) provides that ``The Administrator may distinguish
among classes, types, and sizes within categories of new sources for
the purpose of establishing such standards.''

D. Interpretation of CAA Section 111 Requirements

    CAA section 111(b)(1)(A) requires the EPA to list a source category
if it contributes significantly to air pollution that endangers public
health or welfare. The EPA must necessarily conduct this listing by
making determinations as to the health or welfare impacts of the
pollution to which the source category's pollutants contribute, and as
to the significance of the amount of such contribution. However, by the
terms of CAA section 111(b)(1)(A), the EPA may make these
determinations on the basis of the impacts of the air pollution as a
whole to which the source category's pollutants, taken as a whole,
contribute. Nothing in CAA section 111(b)(1)(A) requires that the EPA
make separate determinations for each type of pollution or each
pollutant.
    After listing a source category, the EPA must proceed to promulgate
standards of performance for the source category's pollutants under CAA
section 111(b)(1)(B) and 111(a)(1). However, nothing in those
provisions requires that, at the time when the EPA promulgates the
standards of performance for the individual pollutants, the EPA must
make a determination as to the health or welfare effects of those
particular pollutants or as to the significance of the amount of the
source category's emissions of those pollutants. Clearly, CAA section
111 does not by its terms require that as a prerequisite for the EPA to
promulgate a standard of performance for a particular pollutant, the
EPA must first find that the pollutant causes or contributes
significantly to air pollution that endangers public health or welfare.
The lack of any such requirement contrasts with other CAA provisions
that do require the EPA to make endangerment and cause-or-contribute
findings for the particular pollutant that the EPA regulates under
those provisions. E.g., CAA sections 202(a)(1), 211(c)(1),
231(a)(2)(A).
    The lack of any express requirement in CAA section 111 addressing
whether and how the EPA is to evaluate emissions of a particular
pollutant from the listed source category as a prerequisite for
promulgation of a standard of performance is properly viewed as a
statutory gap that requires the EPA to make what we refer to as a
Chevron step 2 interpretation. Under the U.S. Supreme Court's 1984
decision in Chevron U.S.A. Inc. v. NRDC, \91\ to interpret how a
statute applies to a particular question, an agency must, at Step 1,
determine whether Congress's intent as to the specific question is
clear, and, if so, the agency must give effect to that intent. If
congressional intent is not clear, then the agency, at Step 2, has
discretion to fashion an interpretation that is a reasonable
construction of the statute.\92\ In this

case, the EPA is authorized to develop a reasonable interpretation.
---------------------------------------------------------------------------

    \91\ 467 U.S. 837 (1984).
    \92\ Id. at 842-43.
---------------------------------------------------------------------------

    Our interpretation is that in order to promulgate a section 111
standard of performance for a particular pollutant, we do not need to
make a pollutant-specific endangerment finding, but instead must
demonstrate a rational basis for controlling the emissions of the
pollutant. That rational basis may be based on information concerning
the health and welfare impacts of the air pollution at issue, and the
amount of contribution that the source category's emissions make to
that air pollution.
    Commenters on the April 2012 proposal stated that the EPA is
required to make an endangerment finding for CO2 because
when the EPA listed this source category, it was on the basis of other
pollutants, and not CO2. However, to reiterate, CAA section
111(b)(1)(A) by its terms requires that the EPA ``shall publish (and
from time to time thereafter, shall revise) a list of categories of
stationary sources,'' and that the EPA shall list ``a category of
sources'' based on the EPA's judgment that the category ``causes, or
contributes significantly to, air pollution'' that endangers public
health or welfare. Thus, this provision requires that the EPA make the
listing decision on a category basis, and not on a pollutant-by-
pollutant basis. That is, this provision does not require that the EPA
establish separate lists of source categories, with each list covering
a different pollutant. Therefore, this provision does not require that
the EPA make an endangerment finding on a pollutant by pollutant basis.
    Commenters on the April 2012 proposal stated that the EPA was
required to make an endangerment finding because by creating the new
subpart TTTT in 40 CFR Part 60, the EPA was listing a new source
category that included the affected units. However, in neither the
original April 2012 proposal nor this new proposal has EPA proposed to
list a new source category. The EPA initially included fossil fuel-
fired electric steam generating units (which included boilers) in a
category that it listed under section 111(b)(1)(A) \93\ and the EPA
promulgated the first set of standards of performance for this source
category in 1971, which the EPA codified in subpart D.\94\
Subsequently, the EPA included fossil fuel-fired combustion turbines in
a category that the EPA listed under section 111(b)(1)(A),\95\ and the
EPA promulgated standards of performance for this source category in
1979, which the EPA codified in subpart GG.\96\
---------------------------------------------------------------------------

    \93\ ``Air Pollution Prevention and Control: List of Categories
of Stationary Sources,'' 36 FR 5931 (March 31, 1971).
    \94\ ``Standards of Performance for Fossil-Fuel-Fired Steam
Generators for Which Construction Is Commenced After August 17,
1971,'' 36 FR 24875 (Dec. 23, 1971) codified at 40 CFR 60.40-46; 36
FR 5931 (Mar. 31, 1971).
    \95\ 42 FR 53657 (Oct. 3, 1977).
    \96\ ``Standards of Performance for Electric Utility Steam
Generating Units for Which Construction is Commenced After September
18, 1978,'' 44 FR 33580 (June 11, 1979).
---------------------------------------------------------------------------

    The EPA has revised those regulations, and in some instances, has
revised the codifications (that is, the subparts), several times over
the ensuing decades. In 1979, the EPA divided subpart D into 3
subparts--Da (``Standards of Performance for Electric Utility Steam
Generating Units for Which Construction is Commenced After September
18, 1978''), Db (``Standards of Performance for Industrial-Commercial-
Institutional Steam Generating Units'') and Dc (``Standards of
Performance for Small Industrial-Commercial-Institutional Steam
Generating Units'')--in order to codify separate requirements that it
established for these subcategories.\97\ In 2006, the EPA created
subpart KKKK, ''Standards of Performance for Stationary Combustion
Turbines,'' which applied to certain sources previously regulated in
subparts Da and GG.\98\ None of these rulemakings, including the
revised codifications, however, constituted a new listing under CAA
section 111(b)(1)(A).
---------------------------------------------------------------------------

    \97\ 44 FR 33580 (June 11, 1979).
    \98\ 71 FR 38497 (July 6, 2006), as amended at 74 FR 11861 (Mar.
20, 2009).
---------------------------------------------------------------------------

    In today's rulemaking, the EPA is promulgating new standards of
performance for CO2 emissions from certain sets of sources,
e.g., steam-generating boilers and turbines. Moreover, we are
establishing different requirements for different sets of sources,
including steam-generating boilers as well as smaller and larger
combustion turbines, in accordance with CAA section 111(b)(2). That
provision authorizes the EPA to ``distinguish among classes, types, and
sizes within categories of new sources for the purpose of establishing
. . . standards [of performance.]''
    In today's rulemaking, we are including a proposal and, in the
alternative, a co-proposal, which take two different approaches to the
source categories and their codification.\99\ Our proposal is to codify
the new CO2 standards in the same subparts in which the
standards of performance for conventional pollutants are codified.
Thus, we propose to codify the GHG standards for steam-generating
boilers as a new section in subpart Da, and the GHG standards for
combustion turbines as new sections in subpart KKKK. This proposal does
not list a new category under section 111(a)(1)(A). Nor does this
proposal revise either of the two source categories--steam-generating
boilers and combustion turbines--that EPA has already listed, or revise
the codification of the new source requirements for those categories in
subparts Da, GG, and KKKK. Under this proposal, the establishment of
different requirements for different sets of sources--for example,
coal-fired power plants, larger NGCC plants, and smaller NGCC plants--
constitute subcategorizations within the existing categories.
---------------------------------------------------------------------------

    \99\ In the original proposal for this rulemaking, the EPA
proposed to create within 40 CFR part 60 a new subpart that would
include GHG emission regulatory requirements for electric utility
steam generating units (i.e., boilers and IGCC units), whose
conventional pollutant regulatory requirements are codified under
subpart Da; as well as stationary combustion turbines that generate
electricity for sale and meet certain size and operational criteria,
conventional pollutant regulatory requirements are codified under
subpart KKKK. The EPA proposed to number this newly created subpart
as subpart TTTT. The EPA explained that combining the GHG regulatory
requirements for those sources in TTTT was appropriate because the
EPA was establishing the same limit for all those sources based on
the same BSER, which was NGCC. 77 FR 22410/2-22411/3.
---------------------------------------------------------------------------

    In the alternative, we co-propose to combine the two source
categories--again, steam-generating boilers and combustion turbines--
for purposes of regulating CO2 emissions (but not for
regulating emissions of conventional pollutants), and to codify all of
the proposed regulatory requirements in a new subpart, TTTT.\100\ This
category, created by combining two existing categories, cannot be
considered a new source category that EPA is placing on the list of
categories for regulation under CAA section 111(b)(1)(A). Under this
co-proposal, the establishment of different requirements for different
sets of sources continues to constitute subcategorizations within the
existing category.
---------------------------------------------------------------------------

    \100\ Under this co-proposal, these regulatory requirements are
substantively the same as the requirements proposed for inclusion in
subparts Da and KKKK, and are simply collected in a separate
subpart, TTTT.
---------------------------------------------------------------------------

    We solicit comment on the relative merits of each approach. In
particular we seek comment on whether the co-proposal to combine the
categories and codify the GHG standards for all new affected sources in
subpart TTTT will offer any additional flexibility for any future
emission guidelines for existing sources, for example, by facilitating
a system-wide approach, such as emission rate averaging, that covers
fossil-fuel

fired steam generating units and combustion turbines.

E. Rational Basis To Promulgate Standards for GHGs From Fossil-Fired
EGUs

    In this rulemaking, the EPA has a rational basis for concluding
that emissions of CO2 from fossil-fired power plants, which
are the major U.S. source of greenhouse gas air pollution, merits
taking action under CAA section 111. As noted, in 2009, the EPA made a
finding that GHG air pollution may reasonably be anticipated to
endanger public health or welfare, and in 2010, the EPA denied
petitions to reconsider that finding. The EPA extensively reviewed the
available science concerning GHG pollution and its impacts in taking
those actions. In 2012, the U.S. Court of Appeals for the D.C. Circuit
upheld the finding and denial of petitions to reconsider. In addition,
assessments from the NRC and the IPCC, published in 2010, 2011, and
2012 lend further credence to the validity of the Endangerment Finding.
As discussed below, no information that commenters have presented or
that the EPA has reviewed provides a basis for rescinding that finding.
In addition, as noted, the high level of GHG emissions from the fossil-
fired EGUs makes clear that it is rational for the EPA to regulate GHG
emissions from this sector. This information amply supports that the
EPA has a rational basis for promulgating regulations under CAA section
111 designed to address GHG air pollution.
    Our conclusion is consistent with the case law handed down by the
D.C. Circuit. In its 1980 decision in National Lime Association v.
EPA,\101\ the Court upheld EPA's determination that lime manufacturing
plants emit particulates that contribute significantly to air pollution
that endangers public health or welfare. The Court noted that (i) EPA's
basis was its prior determination that ``the significant production of
particulate emissions . . . cause[s] or contribute[s] to air pollution
(which may reasonably be anticipated to endanger public health or
welfare);'' and (ii) ``[t]he Agency has made this determination for
purposes of establishing national primary and secondary ambient air
quality standards under [CAA section 109].'' The Court held:
---------------------------------------------------------------------------

    \101\ 627 F.2d 416 (D.C. Cir. 1980).

    We think the danger of particulate emissions' effect on health
has been sufficiently supported in the Agency's (and its
predecessor's) previous determinations to provide a rational basis
for the Administrator's finding in this case.\102\
---------------------------------------------------------------------------

    \102\ Id. at 431-32 n.48.

Similarly, in National Asphalt Pavement Ass'n v. Train,\103\ the D.C.
Circuit upheld a determination by the EPA that asphalt cement plants
contribute significantly to particulate matter air pollution that
endangers public health and welfare. The Court indicated that the EPA's
determination that particulate matter endangers is valid simply on
grounds that the EPA established a NAAQS for that pollutant.\104\
---------------------------------------------------------------------------

    \103\ 539 F.2d 775 (D.C. Cir. 1976).
    \104\ Id. at 784.
---------------------------------------------------------------------------

    These cases support our relying primarily on the analysis and
conclusions in our previous Endangerment Finding, and the subsequent
assessments, as providing a rational basis for our decision to impose
standards of performance on GHG emissions from fossil-fuel fired EGUs.
    In comments on the original proposal, commenters state that because
the proposed rulemaking limits emissions of only CO2, and
not other GHGs, the EPA cannot rely on the analysis and conclusions in
the 2009 Endangerment Finding because it concerned a mix of six GHGs:
carbon dioxide and five others. These commenters assert that as a
prerequisite for regulating CO2 emissions alone, the EPA
must make an endangerment finding for CO2 alone. Because the
present proposal also limits emissions of only CO2, and not
the other GHGs, we expect that the same issue may arise with respect to
this proposal. Commenters' assertion is incorrect for two reasons.
First, as discussed above, the EPA does not need to make an
endangerment finding with respect to a particular pollutant to set
standards for that pollutant under section 111(b)(1)(B). Second, the
EPA may reasonably rely on the analysis and conclusions in the 2009
Endangerment Finding on GHGs even when regulating only CO2.
With respect to this proposed rulemaking, the air pollution at issue
here is the mix of six GHGs. It is that air pollution that has caused
the various impacts on health and welfare that formed the basis for the
Endangerment Finding. The CO2 emissions from EGUs are a
major component of that air pollution. As we noted in the 2009
Endangerment Finding, CO2 is the ``dominant anthropogenic
greenhouse gas.'' \105\ The fact that we are not regulating the other
five GHGs in this rulemaking does not mean that we are required to
identify the air pollution as CO2 alone rather than the mix
of six GHGs. This is consistent with the EPA's past actions. In the
2010 Light Duty Vehicle Rule for which the Endangerment Finding served
as the predicate, the EPA regulated only four of the GHGs, not all
six.\106\
---------------------------------------------------------------------------

    \105\ 74 FR 66496, 66519 (Dec. 15, 2009).
    \106\ 75 FR 25324, 25396-97 (May 7, 2010).
---------------------------------------------------------------------------

    Further, the fact that affected EGUs emit almost one-third of all
U.S. GHGs and comprise by far the largest stationary source category of
GHG emissions, along with the fact that the CO2 emissions
from even a single new coal-fired power plant may amount to millions of
tons each year, provide a rational basis for regulating CO2
emissions from affected EGUs.\107\ This is consistent with previous EPA
actions that have been upheld by the D.C. Circuit. In the National Lime
Association v. EPA case, noted above, the Court upheld the EPA's
regulation of lime plants on grounds that they were one of the
largest--although not within the largest 10 percent--emitting
industries of particulates. The Court stated,
---------------------------------------------------------------------------

    \107\ Commenters on the original proposal stated that new solid-
fuel fired power plants made no contribution to air pollution
because EPA's modeling projected no new construction of those types
of plants. However, CAA section 111(b)(1)(A) is clear by its terms
that the source category listing that is the prerequisite to
regulation is based on the contribution of the ``category'' to air
pollution, and therefore is not based on the contribution of only
new sources in the category. The same reasoning applies to the
rational basis determination.

    EPA . . . focused . . . on the sheer quantity of dust generated
by lime plants. 42 Fed. Reg. 22507 (``A study performed for EPA in
1975 by the Research Corporation of New England ranked the lime
industry twenty-fifth on a list of 112 stationary sources categories
which are emitters of particulate matter''); SSEIS 8-2 (``In a study
performed for EPA by Argonne National Laboratory in 1975, the lime
industry ranked seventh on a list of the 56 largest particulate
source categories in the U.S.'').\108\
---------------------------------------------------------------------------

    \108\ 627 F.2d at 432, n. 48.

In the National Asphalt Pavement Ass'n v. Train case, noted above, the
Court upheld the EPA's determination that the asphalt industry
contributed significantly to the air pollution based on ``the number of
existing plants, the expected rate of growth in the number of plants,
the rate of uncontrolled emissions, and the level of emissions
currently tolerated.'' \109\
---------------------------------------------------------------------------

    \109\ 539 F.2d at 784-85.
---------------------------------------------------------------------------

F. Alternative Findings of Endangerment and Significant Contribution

    Even if CAA section 111 is interpreted to require that the EPA make
endangerment and cause-or-contribute significantly findings as
prerequisites for today's rulemaking, then our rational

basis, as described, should be considered to constitute those findings.
    As noted above, the EPA's rational basis for regulating under
section 111 GHGs is based primarily on the analysis and conclusions in
the EPA's 2009 Endangerment Finding and 2010 denial of petitions to
reconsider that Finding, coupled with the 2010, 2011, and 2012
assessments from the IPCC and NRC that describe scientific developments
since those EPA actions. In addition, as noted above, we would review
comments presenting other scientific information to determine whether
that information has any meaningful impact on our primary basis.
    This rational basis approach is substantially similar to the
approach the EPA took in the 2009 Endangerment Finding and the 2010
denial of petitions to reconsider. As noted, the D.C. Circuit upheld
that approach in the CRR case. Accordingly, that approach would support
an endangerment finding for this rulemaking.
    By the same token, if the EPA were required to make a cause-or-
contribute-significantly finding for CO2 emissions from the
fossil fuel-fired EGUs, as a prerequisite to regulating such emissions
under CAA section 111, the same facts that support our rational basis
determination would support such a finding. In particular, as noted,
fossil fuel-fired EGUs emit almost one-third of all U.S. GHG emissions,
and constitute by far the largest single stationary source category of
GHG emissions; and the CO2 emissions from even a single new
coal-fired power plant may amount to millions of tons each year. It
should be noted that at present, it is not necessary for the EPA to
decide whether it must identify a specific threshold for the amount of
emissions from a source category that constitutes a significant
contribution. Under any reasonable threshold or definition, the
emissions from EGUs are a significant contribution.\110\
---------------------------------------------------------------------------

    \110\ Indeed, it is literally true that if fossil-fuel fired
EGUs cannot be found to contribute significantly to GHG air
pollution, then there is no source category in the U.S. that does
contribute significantly to GHG air pollution, a result that would
defeat the purposes of CAA section 111.
---------------------------------------------------------------------------

G. Comments on the State of the Science of Climate Change

    The EPA received a number of comments in response to the original
proposed NSPS rule addressing the scientific underpinnings of the EPA's
2009 Endangerment Finding and, in essence, the scientific justification
for this rule. Because this action is not a final action, we are not
required to respond to those comments. Even so, we have carefully
reviewed all of those comments, and we do provide some responses in
this action. It is important to place these comments in the context of
the voluminous record on this subject that has been compiled over the
last few years. This includes: (1) The process by which the
Administrator reached the 2009 finding that GHGs are reasonably
anticipated to endanger the public health and welfare of current and
future generations; (2) the EPA's response in 2010 to ten
administrative petitions for reconsideration of the Endangerment
Finding, the ``Reconsideration Denial''; and, (3) the decision by the
United States Court of Appeals for the D.C. Circuit (D.C. Circuit) in
2012 to uphold the Endangerment Finding and the Reconsideration Denial.
    As outlined in Section VIII.A. of the 2009 Endangerment Finding,
the EPA's approach to providing the technical and scientific
information to inform the Administrator's judgment regarding the
question of whether GHGs endanger human health and welfare was to rely
primarily upon the recent, major assessments by the U.S. Global Change
Research Program (USGCRP), the Intergovernmental Panel on Climate
Change (IPCC), and the National Research Council (NRC) of the National
Academies. In brief, these assessments addressed the scientific issues
that the EPA was required to examine, were comprehensive in their
coverage of the GHG and climate change problem, and underwent rigorous
and exacting peer review by the expert community, as well as rigorous
levels of U.S. government review and acceptance, in which the EPA took
part. The EPA received thousands of comments on the proposed
Endangerment Finding and responded to them in depth in an 11-volume RTC
document. While the EPA gave careful consideration to all of the
scientific and technical information received, it placed less weight on
the much smaller number of individual studies that were not considered
or reflected in the major assessments--often these studies were
published after the submission deadline for those larger assessments.
Primary reliance on the major scientific assessments provided the EPA
greater assurance that it was basing its judgment on the best
available, well-vetted science that reflected the consensus of the
climate science community, rather than selecting the studies it would
rely on. Nonetheless, the EPA reviewed individual studies not
incorporated in the assessment literature to see if they would lead the
EPA to change its interpretation of, or place less weight on, the major
findings reflected in the assessment reports. From its review of
individual studies submitted by commenters, the EPA concluded that
these studies did not change the various conclusions or judgments the
EPA would draw based on the more comprehensive assessment reports. The
major findings of the USGCRP, IPCC, and NRC assessments supported the
EPA's determination that GHGs threaten the public health and welfare of
current and future generations. The EPA demonstrated this scientific
support at length in the Endangerment Finding itself, in its Technical
Support Document (which summarized the findings of USGCRP, IPCC and
NRC), and in its RTC document.
    The EPA then reviewed ten administrative petitions for
reconsideration of the Endangerment Finding in 2010. The Administrator
denied those petitions in the ``Reconsideration Denial'' on the basis
that the Petitioners failed to provide substantial support for the
argument that the Endangerment Finding should be revised and therefore
their objections were not of ``central relevance'' to the Finding.\111\
The EPA prepared an accompanying 3-volume RTP document to provide
additional information, often more technical in nature, in response to
the arguments, claims, and assertions by the petitioners to reconsider
the Endangerment Finding.
---------------------------------------------------------------------------

    \111\ ``EPA's Denial of the Petitions To Reconsider the
Endangerment and Cause or Contribute Findings for Greenhouse Gases
Under Section 202(a) of the Clean Air Act'' (``Reconsideration
Denial''), 75 FR 49556, 58 (Aug. 13, 2010).
---------------------------------------------------------------------------

    The 2009 Endangerment Finding and the 2010 Reconsideration Denial
were challenged in a lawsuit, and on June 26, 2012, the D.C. Circuit
upheld them, ruling that they were neither arbitrary nor capricious,
were consistent with Massachusetts v. EPA,\112\ and were adequately
supported by the administrative record.\113\ The Court found that the
EPA had based its decision on ``substantial scientific evidence,''
\114\ and noted that the EPA's reliance on assessments was consistent
with the methods decision-makers often use to make a science-based
judgment.\115\ The Court also found that the Petitioners had ``not
provided substantial support for their argument that the Endangerment
Finding should be revised.'' \116\ Moreover, the Court assessed the
EPA's reliance on the major scientific assessment reports that were

conducted by USGCRP, IPCC, and NRC, and subjected to rigorous expert
and government review, and found that--
---------------------------------------------------------------------------

    \112\ Massachusetts v. EPA, 549 U.S. 497.
    \113\ CRR, 684 F.3d at 102.
    \114\ Id at 121.
    \115\ Id at 120.
    \116\ Id at 125.

    EPA evaluated the processes used to develop the various
assessment reports, reviewed their contents, and considered the
depth of the scientific consensus the reports represented. Based on
these evaluations, the EPA determined the assessments represented
the best source material to use in deciding whether GHG emissions
may be reasonably anticipated to endanger public health or
welfare.\117\
---------------------------------------------------------------------------

    \117\ Id at 120.

---------------------------------------------------------------------------
    As the Court stated,

    It makes no difference that much of the scientific evidence in
large part consisted of `syntheses' of individual studies and
research. Even individual studies and research papers often
synthesize past work in an area and then build upon it. This is how
science works. The EPA is not required to re-prove the existence of
the atom every time it approaches a scientific question.\118\
---------------------------------------------------------------------------

    \118\ Id at 120.

    It is within the context of this extensive record, and recent
affirmation of the Endangerment Finding by the Court, that the EPA has
considered all of the submitted science-related comments and reports
for the April 2012 proposed rule, and will consider any further
comments in response to today's proposed rule. As we did in the
original Endangerment Finding, the EPA is giving careful consideration
to all of the scientific and technical information in the record.
However, the major peer-reviewed scientific assessments continue to
provide the primary scientific and technical basis upon which the
Administrator's judgment relies regarding the threat to public health
and welfare posed by GHGs.
    Commenters on the April 2012 proposed rule submitted two major
peer-reviewed scientific assessments that were released since the
administrative record concerning the Endangerment Finding was closed
after the EPA's 2010 Reconsideration Denial: the IPCC Special Report on
Managing the Risks of Extreme Events and Disasters to Advance Climate
Change Adaptation (2012) (SREX) and the NRC Report on Climate
Stabilization Targets: Emissions, Concentrations, and Impacts over
Decades to Millennia (2011) (Climate Stabilization Targets). The EPA
has reviewed these assessments and they are briefly characterized here:
    SREX. The IPCC SREX assessment states that, ``A changing climate
leads to changes in the frequency, intensity, spatial extent, duration,
and timing of extreme weather and climate events, and can result in
unprecedented extreme weather and climate events.'' The SREX documents
observational evidence of changes in some of the weather and climate
extremes that have occurred globally since 1950. The SREX assessment
provides evidence regarding the attribution of some of these changes to
elevated concentrations of GHGs, including warming of extreme daily
temperatures, intensification of extreme precipitation events, and
rising extreme coastal high water due to increases in sea level. The
assessment notes that further increases in some extreme weather and
climate events are projected over the 21st century. The assessment also
concludes that, combined with increasing vulnerability and exposure of
populations and assets, changes in extreme weather and climate events
have consequences for disaster risk, with particular impacts on the
water, agriculture and food security, and health sectors.
    Climate Stabilization Targets. The NRC Climate Stabilization
Targets assessment states that, ``Emissions of carbon dioxide from the
burning of fossil fuels have ushered in a new epoch where human
activities will largely determine the evolution of Earth's climate.
Because carbon dioxide in the atmosphere is long lived, it can
effectively lock Earth and future generations into a range of impacts,
some of which could become very severe.'' The assessment addresses the
fact that emissions of carbon dioxide will alter the composition of the
atmosphere, and therefore the climate, for thousands of years and
attempts to quantify the implications of stabilizing GHG concentrations
at different levels. The report also estimates a number of specific
climate change impacts, finding warming could lead to increases in
heavy rainfall and decreases in crop yields and Arctic sea ice extent,
along with other important changes in precipitation and stream flow.
For an increase in global average temperature of 1 to 2 [deg]C above
pre-industrial levels, the assessment found that the area burnt by
wildfires in western North America will likely more than double and
coral bleaching and erosion will increase due both to warming and ocean
acidification; an increase of 3 [deg]C will lead to a sea level rise of
0.5 to 1.0 meters by 2100; and with an increase of 4 [deg]C, the
average summer in the United States would be as warm as the warmest
summers of the past century. The assessment notes that although many
important aspects of climate change are difficult to quantify, the risk
of adverse impacts is likely to increase with increasing temperature,
and the risk of dangerous surprises can be expected to increase with
the duration and magnitude of the warming.
    A number of other National Academy assessments regarding climate
have also been released recently. The EPA has reviewed these
assessments, and finds that the improved understanding of the climate
system resulting from the two assessments described above and the
National Academy assessments strengthens the case that GHGs are
endangering public health and welfare. Perhaps the most dramatic change
relative to the prior assessments concern sea level rise. The previous
2007 IPCC AR4 assessment projected a rise in global sea level of
between 7 and 23 inches by the end of the century relative to 1990
(with an acknowledgment that inclusion of ice sheet processes that were
poorly understood would likely increase those projections). Three new
NRC assessments have provided estimates of projected sea level rise
that are much larger, in some cases more than twice as large as the
previous IPCC estimates. Climate Stabilization Targets; National
Security Implications for U.S. Naval Forces (2011); Sea Level Rise for
the Coasts of California, Oregon, and Washington: Past, Present, and
Future (2012). While the three NRC assessments continue to recognize
and characterize the uncertainty inherent in accounting for ice sheet
processes, these revised estimates strongly support and strengthen the
existing finding that GHGs are reasonably anticipated to endanger human
health and welfare. Other key findings of the recent assessments are
described briefly below:
    The Sea Level Rise for the Coasts of California, Oregon, and
Washington: Past, Present, and Future (2012) assessment notes that
observations have shown that sea level rise on the West Coast has risen
south of Cape Mendocino over the past century but dropped north of that
point during that time due to tectonic uplift and other factors in
Oregon and Washington. However, the assessment projects a global sea
level rise of 1.6 to 4.6 feet by 2100, which is sufficient to lead to
rising relative sea level even in the northern states. The National
Security Implications of Climate Change for U.S. Naval Forces also
considers potential impacts of sea level rise, using a range of 1.3 to
6.6 feet by 2100. This assessment also suggests preparing for increased
needs for humanitarian aid, responses to climate change in geopolitical
hotspots including possible mass migrations, and addressing changing
security needs in the Arctic as sea ice retreats. The Climate and
Social Stress: Implications for Security Analysis (2012) assessment
found that it

would be ``prudent for security analysts to expect climate surprises in
the coming decade . . . and for them to become progressively more
serious and more frequent thereafter[.]'' Understanding Earth's Deep
Past: Lessons for Our Climate Future (2011) examines the period of
Earth's history prior to the formation of the Antarctic and Greenland
Ice Sheets because CO2 concentrations by the end of the
century will have exceeded levels seen in the 30 million years since
that time. The assessment discusses the possibility that analogous
paleoclimate states might suggest higher climate sensitivity, less well
regulated tropical surface temperatures, higher sea level rise, more
anoxic oceans, and more potential for non-linear events such as the
Paleo-Eocene Thermal Maximum than previously estimated. The assessment
notes that three or four out of the five major coral reef crises of the
past 500 million years were probably driven by acidification and
warming caused by GHG increases similar to the changes expected over
the next hundred years. The assessment states that ``the magnitude and
rate of the present greenhouse gas increase place the climate system in
what could be one of the most severe increases in radiative forcing of
the global climate system in Earth history.'' Similarly, the Ocean
Acidification: A National Strategy to Meet the Challenges of a Changing
Ocean (2010) assessment found that ``[t]he chemistry of the ocean is
changing at an unprecedented rate and magnitude due to anthropogenic
carbon dioxide emissions; the rate of change exceeds any known to have
occurred for at least the past hundreds of thousands of years.'' The
assessment notes that the full range of consequences is still unknown,
but the risks ``threaten coral reefs, fisheries, protected species, and
other natural resources of value to society.''
    Several commenters on the April 2012 proposed rule argue that the
Endangerment Finding should be reconsidered or overturned based on
those commenters' reviews of specific climate science literature,
particularly newer publications that have appeared since the EPA's 2010
Denial of Petitions. Some commenters have presented their own
compilations of individual studies as support for their assertions that
climate change will have beneficial effects in many cases and that
climate impacts will not be as severe or adverse as the EPA and
assessments like the USGCRP (2009) report have stated. These commenters
conclude that U.S. society will continue to easily adapt to climate
change and that climate change therefore does not pose a threat to
human health and welfare.
    The EPA has reviewed the information submitted and finds that, the
fundamental issues raised in the comments that critique the scientific
justification for the rule have been addressed by the EPA's 11-volume
response to comments for the 2009 Endangerment Finding, the EPA's
responses to all issues raised by Petitioners in the Reconsideration
Denial, or the D.C. Circuit in its 2012 decision to uphold the EPA's
2009 Endangerment Finding. These comments do not change the various
conclusions or judgments that the EPA would draw based on the
assessment reports relied upon in the recent 2009 Finding.
    These comments often highlight uncertainty regarding climate
science as an argument for reconsideration. However, uncertainty was
explicitly recognized in the 2009 Endangerment Finding: ``The
Administrator acknowledges that some aspects of climate change science
and the projected impacts are more certain than others'',\119\ and the
decision to find endangerment was made with full recognition of the
uncertainty involved. In addition, the D.C. Circuit Court decision
noted that, ``the existence of some uncertainty does not, without more,
warrant invalidation of an endangerment finding.'' \120\ In short,
these recent publications submitted by commenters, and any new issues
that are extracted from them, do not undermine either the significant
body of scientific evidence that has accumulated over the years or the
conclusions presented in the substantial peer-reviewed assessments of
the USGCRP, NRC, and IPCC.
---------------------------------------------------------------------------

    \119\ 74 FR 66524.
    \120\ CRR, 684 F.3d at 121.
---------------------------------------------------------------------------

    Regarding the contentions that the U.S. will adapt to climate
change impacts and that therefore climate change impacts pose no
threat, the EPA stated in the 2009 Endangerment Finding,

    Risk reduction through adaptation and GHG mitigation measures is
of course a strong focal area of scientists and policy makers,
including the EPA; however, the EPA considers adaptation and
mitigation to be potential responses to endangerment, and as such
has determined that they are outside the scope of the endangerment
analysis.\121\
---------------------------------------------------------------------------

    \121\ 74 FR 66512 (emphasis added).

The D.C. Circuit upheld this position, ruling that ``These contentions
[that the U.S. can adapt] are foreclosed by the language of the statute
and the Supreme Court's decision in Massachusetts v. EPA'' because
``predicting society's adaptive response to the dangers or harms caused
by climate change'' does not inform the ``scientific judgment'' that
the EPA is required to take regarding Endangerment.\122\
---------------------------------------------------------------------------

    \122\ 984 F.3d at 117.
---------------------------------------------------------------------------

    Some commenters raise issues regarding the EPA Inspector General's
report, Procedural Review of EPA's Greenhouse Gases Endangerment
Finding Data Quality Processes (2011). These commenters mischaracterize
the report's scope and conclusions and, thus, vastly overstate the
significance of the Inspector General's procedural recommendations.
Ultimately, nothing in the Inspector General report questions the
validity of the EPA's Endangerment Finding because that report did not
evaluate the scientific basis of the Endangerment Finding. Rather, the
Inspector General offers recommendations for clarifying and
standardizing internal procedures for documenting data quality and peer
review processes when referencing existing peer reviewed science in the
EPA actions. Unrelated to the Endangerment Finding and its validation
by the Court, the EPA has made progress towards implementing the
recommendations by the Inspector General.
    One commenter submitted a number of emails from the period 1999 to
2009 that were obtained from a University of East Anglia server in 2009
and publicly released in 2011. After reviewing these emails, the EPA
finds that they raise no issues that were not previously raised by
Petitioners in regard to an earlier group of emails from the same
incident, released in 2009. The commenter makes unsubstantiated
assumptions and subjective assertions regarding what the emails purport
to show about the state of climate change science; this provides
inadequate evidence to challenge the voluminous and well documented
body of science that is the technical foundation of the Administrator's
Endangerment Finding.
    A number of comments were also submitted in support of the
Endangerment Finding and/or providing further evidence that climate
change is a threat to human health and welfare. A number of individual
studies were submitted and a number of observed or projected climate
changes of local importance or concern to commenters were documented.
Again, the EPA places lesser weight on individual studies than on the
major scientific assessments. Local observed changes can be of great
concern to individuals

and communities but must be assessed in the context of the broader
science, as it is more difficult to draw robust conclusions regarding
climate change over short time scales and in small geographic regions.

V. Rationale for Applicability Requirements

A. Applicability Requirements--Original Proposal and Comments

    The original proposal was designed to apply to new intermediate and
base load EGUs, specifically, (1) fossil fuel-fired utility boilers and
IGCC EGUs subject to subpart Da for criteria pollutant emissions, and
(2) natural gas combined cycle EGUs subject to subpart KKKK for
criteria pollutant emissions. The original proposal explicitly did not
apply to simple cycle turbines because we concluded that they were
operated infrequently and therefore only contributed small amounts to
total GHG emissions. (For convenience, we occasionally refer to this
explicit statement that the original proposed NSPS did not apply to a
type of source as an exclusion.)
    We received comments that supported the simple cycle exclusion and
others that opposed it. Commenters in support stated that a new simple
cycle power plant serves a different purpose than a new combined cycle
plant and that economics will drive the use of combined cycle
facilities over simple cycle plants. They also stated that the original
proposed standard is not achievable by, and therefore is not BSER for,
simple cycle turbines. Commenters opposing the exclusion stated that it
creates an opportunity to evade the standard and could thereby increase
GHG emissions. According to these commenters, any applicability
distinctions should be based on utilization and function rather than
purpose or technology.
    After considering these comments, we are proposing a different
approach to the applicability provisions with respect to simple cycle
turbines.

B. Applicability Requirements--Today's Proposal

    In today's rulemaking, we propose that standards of performance
apply to a facility if the facility supplies more than one-third of its
potential electric output and more than 219,000 MWh net electric output
to the grid per year. (We refer to a facility's sale of more than one-
third of its potential electric output as the one-third sales
criterion, and we refer to the amount of potential electric output
supplied to a utility power distribution system, expressed in MWh, as
the capacity factor.) This proposed definition does not explicitly
exclude simple cycle combustion turbines, but as a practical matter, it
would exclude most of them because the vast majority of simple cycle
turbines sell less than one-third of their potential electric output.
The few simple-cycle combustion turbines that sell more than one-third
of their potential electric output to the grid would be subject to the
proposed standards of performance. As explained below, we have
concluded that at this level of output, there are less expensive and
lower emitting technologies that could be constructed consistent with
today's proposed standards. Although, as noted, today's proposal does
not explicitly exclude simple cycle combustion turbines, we solicit
comment on whether to provide an explicit exclusion.
    We are proposing to apply the one-third sales criterion on a
rolling three year basis instead of an annual basis for stationary
combustion turbines for multiple reasons. First, extending the period
to three years would ensure that the CO2 standards apply
only to intermediate and base load EGUs by allowing facilities intended
to generally operate at low capacity factors (e.g. simple cycle
turbines that generally sell less than one-third of their potential
electric output) to avoid applicability even though they may provide
system capacity and, in fact, operate at high capacity factors during
individual years with abnormally high electric demand. Second, only 0.2
percent of existing simple cycle turbines had a three-year average
capacity factor of greater than one-third between 2000 and 2012.
Therefore, as noted, from a practical standpoint, few new simple cycle
turbines will be subjected to the standards of performance in this
rulemaking.
    The 2013 AEO cost and performance characteristics for new
generation technologies include costs for advanced and conventional
combined cycle facilities and advanced simple cycle turbines. According
to the AEO 2013 values, advanced combined cycle facilities have a lower
cost of electricity than advanced simple cycle turbine facilities above
approximately a 20 percent capacity factor. Therefore, the use of a
combined cycle technology would be BSER for higher capacity factor
stationary combustion turbines. However, advanced combined cycle
facilities do not have a lower cost of electricity than less capital
intensive conventional combined cycle facilities until above
approximately a 40 percent capacity factor. Between approximately 20 to
40 percent capacity factors, conventional combined cycle facilities
offer the lowest cost of electricity, and below approximately 20
percent capacity factors advanced simple cycle turbines offer the
lowest cost of electricity. A capacity factor exemption at 40 percent
(i.e., sales of less than two-fifths of potential electric output per
year) would allow conventional combined cycle facilities built with the
intent to operate at relatively low capacity factors as an alternative
technology to simple cycle turbines because neither would be subject to
the NSPS requirements. Based on these cost considerations, we are
specifically requesting comment on a range of 20 to 40 percent of
potential electric output sales on a three-year basis for the capacity
factor exemption. The 20 percent applicability limit is consistent with
generating the lowest cost of electricity for advanced combined cycle
turbines compared to advanced simple cycle turbines, and based on
historical capacity factors would impact the operation of only
approximately two percent of simple cycle turbines. The 40 percent
applicability limit would be more consistent with the annual run hour
limitations currently contained in many simple cycle operating permits.
    We are also requesting comments on whether applicability for
stationary combustion turbines should be defined on a single calendar
year basis, similar to the current subpart Da applicability provisions
for criteria pollutants, instead of a three-year basis. With a single
year basis, we are considering an applicability level of up to 40
(instead of 33 and one-third) percent sales. Only 0.4 percent of
existing simple cycle turbines had an annual capacity factor of greater
than 40 percent between 2000 and 2012. Assuming the average hourly
output of a simple cycle turbine is 80 percent of the maximum rated
output, a simple cycle turbine could operate up to 4,400 hours annually
before exceeding the capacity factor threshold. This is consistent with
the operation hour limitation in many permits. Therefore, with this 40
percent sales criterion on a single-year basis, as a practical matter,
it is anticipated that few new simple cycle turbines would be subject
to the proposed standards of performance. Thus, we are specifically
requesting comment on a range of one-third to two-fifths of potential
electric output annual sales. The lower range would be consistent with
how an EGU is currently defined in the EPA rules, and would mean that
the proposed standards of performance would impact approximately one
percent of new simple cycle turbines.

    We are also proposing a different definition of potential electric
output from the current definition that determines the potential
electric output (in MWh on an annual basis) considering only the design
heat input capacity of the facility and does not account for
efficiency. It assumes a 33 percent net electric efficiency, regardless
of the actual efficiency of the facility and could discourage the
installation of more efficient facilities. For example, a 33 percent
efficient 100 MW facility would have a heat input of 1,034 MMBtu/h and
a 40 percent efficient 100 MW facility would have a heat input of 853
MMBtu/h.\123\ The 33 percent efficient facility would become subject to
the NSPS requirements when it sells more than one-third of its
potential electric output, 880,000 MWh. The 40 percent efficient
facility would become subject to the NSPS requirements when it sells
more than 730,000 MWh.\124\ This could potentially encourage the
construction of less efficient facilities, since they could have a
higher actual capacity factor than a more efficient unit, while still
not being an EGU subject to a CO2 standard. Therefore, we
are proposing a definition of potential electric output that allows the
source the option of calculating its potential electric output on the
basis of its actual design electric output efficiency on a net output
basis, as an alternative to the default one-third value. The proposed
definition would permit the 40 percent efficient facility to use the
actual efficiency of the facility so that the electric sales
applicability criteria would be 880,000 MWh and applicability would be
determined the same as for the less efficient facility.
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    \123\ (100 MW)*(3.412 MMBtu/h/1 MWh)*(1/0.33) = 1,034 MMBtu/h.
(100 MW)*(3.412 MMBtu/h/1 MWh)*(1/0.40) = 853 MMBtu/h.
    \124\ (1,034 MMBtu/h)*(1 MWh/3.412MMBtu/h)*(1/3)*(8,760h/yr) =
880,000 MWh. (853 MMBtu/h)*(1 MWh/3.412MMBtu/h)*(1/3)*(8,760h/yr) =
730,000 MWh.
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    The April 2012 proposal would have applied to facilities that
primarily burn non-fossil fuels but also co-fire a fossil fuel. We have
concluded that it is not appropriate to subject these facilities to the
standards in today's proposal. This is because these types of units
more closely resemble the non-fossil fuel-fired boilers and stationary
combustion turbines that are not covered by today's proposed rule, than
they do the fossil fuel-fired boilers and stationary combustion
turbines that are covered by this rule. This approach is similar to the
approach used in the Mercury and Air Toxics Standards, another CAA
regulatory effort focused on fossil fuel-fired power plants. Therefore,
we are proposing to limit the applicability of the standard to
facilities where the heat input is comprised of more than 10.0 percent
fossil fuel on a three-year rolling average basis. To simplify
determining applicability with the CO2 standard, we also
request comment on whether the applicability for facilities that co-
fire non-fossil fuels should be made on an annual average basis,
instead of a three-year rolling average basis.
    In the original proposal, we requested comment on the applicability
of the GHG NSPS to combined heat and power (CHP) facilities and if
applicability should be changed from how it is currently determined in
subpart Da. In today's action, we propose that if CHP facilities meet
the general applicability criteria they should be subject to the same
requirements as electric-only generators. However, one potential issue
that we have identified is inequitable applicability to third-party CHP
developers compared to CHP facilities owned by the facility using the
thermal output from the CHP facility. As noted above, we propose that
the proposed CO2 standard of performance apply to a facility
that supplies more than one-third of its potential electricity output
and more than 219,000 MWh ``net electric output'' to the grid per year.
The current definition of net electric output for purposes of criteria
pollutants is ``the gross electric sales to the utility power
distribution system minus purchased power on a calendar year basis.''
40 CFR 60.41Da. Owners/operators of a CHP facility under common
ownership as an adjacent facility using the thermal output from the CHP
facility (i.e., the thermal host) can subtract out power purchased by
the adjacent facility on an annual basis when determining
applicability. However, third-party CHP developers would not be able to
benefit from the ``minus purchased power on a calendar year basis''
provision in the definition of net electric output when determining
applicability since the CHP facility and the thermal host(s) are not
under common ownership. We are therefore proposing to add ``of the
thermal host facility or facilities'' to the definition of net-electric
output for qualifying CHP facilities (i.e., the clause would read,
``the gross electric sales to the utility power distribution system
minus purchased power of the thermal host facility or facilities on a
calendar year basis'' (emphasis added)). This would make applicability
consistent for both facility-owned CHP and third-party-owned CHP.
    This proposal includes within the definition of a steam electric
generating unit, IGCC, and stationary combustion turbine that are
subject to the proposed requirements, any integrated device that
provides electricity or useful thermal output to the boiler, the
stationary combustion turbine or to power auxiliary equipment. The
rationale behind including integrated equipment recognizes that the
integrated equipment may be a type of combustion unit that emits GHGs,
and that it is important to assure that those GHG emissions are
included as part of the overall GHG emissions from the affected source.
Including integrated equipment avoids circumvention of the requirements
by having a boiler not subject to the standard supplying useful energy
input (e.g., an industrial boiler supplying steam for amine
regeneration in a CCS system) without accounting for the GHG emissions
when determining compliance with the NSPS. In addition, the proposed
definition would provide additional compliance flexibility similar to
when the HRSG was included in the combustion turbine NSPS by
recognizing the environmental benefit of integrated equipment that
lowers the overall emissions rate of the affected facility. Even
without this specific language, the original 1979 steam electric
generating unit definition in subpart Da allows the use of solar
thermal equipment for feedwater heating as an approach to integrating
non-emitting generation to reduce environmental impact and lower the
overall emissions rate. The current definition expands the flexibility
to include combustion turbines, fuel cells, or other combustion
technology for reheating or preheating boiler feedwater, preheating
combustion air, producing steam for use in the steam turbine or to
power the boiler feedpumps, or using the exhaust directly in the boiler
to generate steam. This in theory could lower generation costs as well
as lower the GHG emissions rate for an EGU.
    We solicit comment on various issues concerning, and different
approaches to, the applicability requirements for steam generating
units and combustion turbines. In particular, we recognize that several
of the requirements proposed today are based on the source's
operations. These include, for both steam generating units and
combustion turbines, the requirement that the source supply more than
one-third of its potential electric output and more than 219,000 MWh
net-electric output to the grid for sale on an annual or tri-annual
basis (the one-third and 219,000 MWh sales requirement), as well as the
requirement that the source burn fossil fuel for more than 10 percent
of the heat input during three years; and for

combustion turbines, the additional requirement that the source combust
over 90 percent natural gas on a heat input basis over three years.
    We solicit comment on whether these requirements raise
implementation issues because they are based on source operation after
construction has occurred. We also solicit comment on whether, to avoid
any such implementation issues, these requirements should be recast to
be based on the source's purpose at the time of construction. For
example, should we recast the 10% percent requirement so that it would
be met if the source was constructed for the purpose of burning fossil
fuel for more than 10 percent of its heat input over any three-year
period?
    In addition, we solicit comment on whether we should include these
requirements not as applicability requirements for whether the source
is subject to the standard of performance, but rather as criteria for
which part of the standard of performance the source is subject to.
Under this approach, at least for combustion turbines, the EPA would
promulgate applicability requirements or a definition of utility unit
designed to assure that combustion turbine utility units--but not
combustion turbine industrial units or other types of non-utility
units--would be subject to the standard of performance. For example,
under this approach, all combustion turbine units that meet such
applicability requirements or definition of utility units and that have
a design heat input to the turbine engine greater than 250 MMBtu/h,
would be subject to the standard of performance for CO2
emissions. That standard would be: (i) during periods when certain
conditions (noted below) are met, 1,000 or 1,100 lb CO2/MWh
(depending on whether the unit has a design heat input to the turbine
engine of greater than 850 MMBtu/h); and (ii) during periods when one
or more of those conditions is not met, no emission limit (that is, the
unit could emit at an uncontrolled level). In the latter case, although
the unit would not be subject to an emission limit, it would remain
subject to the standard of performance, and therefore would be subject
to any monitoring, reporting, and recordkeeping requirements. The
conditions could include, during any 3-year period on a rolling average
basis, combusting over 10% fossil fuel on a heat input basis,
combusting over 90% natural gas on a heat input basis, and selling more
than one-third of potential electric output and more than 219,000 MWh
net-electric output to the grid.
    Under this approach, as noted, in order to be consistent with
today's proposal to apply the standard of performance for
CO2 emissions to only utility units--and not to industrial
or other non-utility units--we would need to include other
applicability requirements or definitional provisions that would
explicitly limit the standard to utility units.
    We solicit comment on all aspects of this approach, including the
extent to which it would achieve the policy objectives of assuring that
a simple cycle turbine and a combined cycle turbine are subject to the
same standard if they sell more than one-third of their capacity and
more than 219,000 KWh net electric output to the grid, and are subject
to the same standard if they sell less than those amounts to the grid.
We also solicit comment on how to implement the three-year requirements
described above during the period within three years after an affected
EGU begins operations. For example, under the approach where
operational criteria that entail a three-year compliance period are
used to determine to which standard of performance the facility is
subject, the owner or operator and permitting authority would not know
for certain what standard applies to the facility until three years
after initial startup. For this scenario, we request comment on how to
implement the three year operational requirements and what
documentation should be collected and reported to the EPA during the
period up to the end of the third year after a source begins operation.

C. Certain Projects Under Development

    This proposal does not apply to the proposed Wolverine EGU project
in Rogers City, Michigan. Based on current information, the Wolverine
project appears to be the only fossil fuel-fired boiler or IGCC EGU
project presently under development that may be capable of ``commencing
construction'' for NSPS purposes \125\ in the very near future and, as
currently designed, could not meet the 1,100 lb CO2/MWh
standard proposed for other new fossil fuel-fired boiler and IGCC EGUs.
The EPA has not formulated a view as to the project's status in the
development process or as to whether the proposed 1,100 lb
CO2/MWh standard or some other CO2 standard of
performance would be representative of BSER for this project, and
invites comment on these questions.\126\ At the time of finalization of
this proposal, if the Wolverine project remains under development and
has not either commenced construction or been canceled, we anticipate
proposing that the project either be made subject to the 1,100 lb
CO2/MWh standard or be assigned to a subcategory with an
alternate CO2 standard. Further discussion is provided in
the technical support document in the docket entitled ``Fossil Fuel-
Fired Boiler and IGCC EGU Projects under Development: Status and
Approach.''
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    \125\ The NSPS regulations include definitions of ``commenced''
and ``construction''. See 40 CFR 60.2.
    \126\ The EPA's lack of view regarding the appropriate
CO2 standard is closely related to the existence of
conflicting information on where the project stands in the
development process. The developer has claimed that the project was
delayed by issues related to the standards of performance for
hazardous air pollutants promulgated in December 2011, 77 FR 9304
(Feb. 16, 2012) (Mercury and Air Toxics Standards, or MATS).
Specifically, the developer cited a perceived inability to obtain
guarantees from pollution control equipment vendors that the plant
would achieve the MATS standards. See Jim Dulzo, As Coal Plant
Teeters, Groups Mount Legal Attack, Michigan Land Use Institute
blog, Feb. 13, 2012, http://www.mlui.org/energy/news-views/news-views-articles/as-coal-plant-teeters-groups-mount-legal-attack.html.
While some of the MATS new-unit standards were revised upon
reconsideration in March 2013, 78 FR 24073 (Apr. 24, 2013), the
developer's claims raise the possibility that the EPA's own actions
may have delayed the project and contributed to the present
uncertainty as to the project's development status.
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    There are two other fossil fuel-fired boiler or IGCC EGU projects
without CCS--the Washington County project in Georgia and the Holcomb
project in Kansas--that appear to remain under development but whose
developers have recently represented that the projects have commenced
construction for NSPS purposes. Based solely on the developers'
representations, the projects would be existing sources, and thus not
subject to this proposal. However, neither developer has sought a
formal EPA determination of NSPS applicability; and, if upon review it
was determined that the projects have not commenced constructions, the
projects should be situated similarly to the Wolverine project.
Accordingly, if it is determined in the future that either of these
projects has not commenced construction as of the date of this
proposal, then that project will be addressed in the same manner as the
Wolverine project.\127\ Further discussion

is provided in the technical support document in the docket referenced
above.\128\
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    \127\ In this event, there will not be any proposed standard
``which will be applicable to such source'' within the meaning of
CAA section 111(a)(2), and to the extent that this proposal did,
until the time of the construction commencement determination, apply
to that project, this proposal will be considered automatically to
be withdrawn as it applies to that project as of the time of that
determination. The purpose of this automatic withdrawal is to ensure
that the project is placed on the same footing as the Wolverine