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 section 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 an exceedance of the relevant emission standard. (See,
e.g., ``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), which are both included
in the docket for this rulemaking.) The EPA is therefore proposing to
add to the final rule an affirmative defense to civil penalties for
exceedances of emission limits 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 60.10001. (See 40 CFR 22.24). The criteria ensure that the
affirmative defense is available only where the event that causes an
exceedance of the emission limit 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
excess emissions ``[w]ere caused by a sudden, infrequent, and
unavoidable failure of air pollution control and monitoring equipment,
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
section 60.10001 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 the applicable emission
limitations were being exceeded * * *'' and that ``[a]ll possible steps
were taken to minimize the impact of the excess emissions 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 part 22.77).
    The EPA is including an affirmative defense 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 limits may be exceeded 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 (DC Cir. 2008) Thus, the EPA is
required to ensure that section 112 emissions limitations are
continuous. The affirmative defense for malfunction events meets this
requirement by ensuring that even where there is a malfunction, the
emission limitation is still enforceable through injunctive relief.\43\
While ``continuous'' limitations, 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 (DC Cir.
1973), the DC 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 (DC Cir. 1973). Though
intervening case law such as Sierra Club v. EPA and the CAA 1977
amendments undermine the relevance of these cases today, they support
the EPA's view that a system that incorporates some level of
flexibility is reasonable. The affirmative defense simply provides for
a defense to civil penalties for excess emissions that are proven to be
beyond the control of the source. By incorporating an affirmative
defense, the EPA has formalized its approach to upset events. 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). But see, Weyerhaeuser Co. v. Costle, 590 F.2d 1011, 1057-58
(DC Cir. 1978) (holding that an informal approach is adequate). The
affirmative defense provisions give the EPA the flexibility to both
ensure that its emission limitations 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.
---------------------------------------------------------------------------

    \43\ Note that the Ninth Circuit recently upheld EPA's decision
to apply this affirmative defense approach to only actions seeking
civil penalties, and not also to actions seeking injunctive relief.
Montana Sulfur & Chemical Co. v. EPA, No. 02-71657 (9th Cir. August
31, 2011) (slip op. at 456).
---------------------------------------------------------------------------

    We propose that these same requirements for malfunctions would
apply to the 30-year averaging compliance option; however, we take
comment on whether it is appropriate to have an affirmative defense for
the 30-year averaging portion of that compliance option, given that we
would expect malfunctions to only impact shorter emissions limits, and
the longer the compliance period, the less likely malfunction events
are to impact a source's ability to meet the standard.

D. What are the continuous monitoring requirements?

    The EPA is proposing that a CO2 mass rate CEMS and the
associated automatic data acquisition and handling system must be
installed and operated in accordance with the requirements below.
    1. Prepare a site-specific monitoring plan that addresses the
monitoring system design, data collection, and the quality assurance
and quality control elements consistent with the requirements in 40 CFR
part 75.
    2. Use all the data collected during all other required data
collection periods in assessing the operation of the control device and
associated control system.
    3. Report any periods for which the monitoring system failed to
collect required data.
    4. Except for periods of monitoring system malfunctions, repairs
associated with monitoring system malfunctions, and required monitoring
system quality assurance or quality control activities (including, as
applicable, calibration checks and required zero and span adjustments);
failure to collect required data is a deviation of the monitoring
requirements.
    We propose that owners/operators would install the CEMS and
complete the CEMS certification in accordance with the schedule
required in 40 CFR part 75, section 75.4(b).
    We also request comment on the appropriateness of applying the
backup monitor requirements in 40 CFR part 75.10(e), the missing data
procedures in 40 CFR part 75, sections 75.31 through 75.37, and
appendix C for this proposed rule.
    We propose that these same monitoring requirements would apply to
the 30-year averaging compliance option.

E. What are the emissions performance testing requirements?

    Consistent with the performance testing requirements in the CAA
section 111 regulatory general provisions (40 CFR part 60.8) and CEMS
certification requirements (40 CFR part 75.4(b)), we propose that
owners/operators of a new unit, conduct an initial performance test to
demonstrate compliance with the CO2 emissions limits
beginning in the calendar month following initial certification of the
CO2 and flow rate monitoring CEMS.
    We propose that the initial performance test consist of collection
of hourly CO2 average concentration, mass flow rate
(standard cubic feet per hour) recorded with the certified
CO2 concentration and flow rate CEMS and the corresponding
electrical power generation data for all of the hours of operation for
the first calendar year beginning on the first day of the first month
following completion of the CEMS installation and certification. For
all of the operating hours during each monthly period, including
startup and shutdown, you would calculate compliance with the emissions
limit by dividing the sum of the hourly CO2 mass values by
the sum of the hourly useful energy output produced over the first 12
months of data.
    We propose that these same emissions performance testing
requirements would apply to the 30-year averaging compliance option.

F. What are the continuous compliance requirements?

    In this rulemaking, we propose that compliance with the applicable
average CO2 mass emissions rate (lb/MWh) must be calculated
as a 12-month rolling average, updated monthly, using the reported
hourly CO2 average concentration and flow rate values from
the certified CEMS data collected for the previous month's process
operating days along with generation data tracked by the facility for
the unit. We propose that compliance with the emissions limit must be
calculated by dividing the sum of the hourly CO2 mass
emissions values by the sum of the useful energy output produced for
each calendar month period and that the 12-month rolling average must
be updated as the average of the previous 12 months' calculations.
Affected sources will continue to be subject to the standards and
maintenance requirements in the section 111 regulatory general
provisions. 40 CFR part 60, subpart A.
    We solicit comment on, in the alternative, an annual (calendar
year) average emission limit, which would be calculated through
comparable methodology as just described.
    We propose that these same continuous compliance requirements would
apply to the 30-year averaging compliance option.

G. What are the notification, recordkeeping, and reporting
requirements?

    In this rulemaking, the EPA is proposing that you, as the owner or
operator of a new unit, must comply with the notification and
recordkeeping requirements in the section 111 regulatory general
provisions, 40 CFR part 60, subpart A, and need to report results of
performance testing and excess emissions; as well as record and
maintain hourly average CO2 emissions concentration, hourly
average flow rate, and hourly useful electrical generation. Note that
the summary form identified as Figure 1 in 40 CFR part 60.7(d) will be
revised to include CO2 as a pollutant. We are also seeking
comments on whether the EPA should require initial notification of
compliance status reports. In most rules, an initial notification of
compliance status report, where owners and operators of sources subject
to a particular rule notify the EPA and State and Local Air Pollution
Control Agencies that their source is subject to the rule and how they
intend to comply with the rule, is required. Regulators find this
information very helpful in implementing and enforcing particular
rules. In this case, most, if not

all, of the sources that are potentially subject to this rule have
already been identified because they are subject to other New Source
Performance Standards and Part 75 Acid Rain provisions.
    As part of an Agency-wide effort to facilitate reporting of
environmental data and reports, we are requiring electronic reporting
of selected reports, required by this regulation, to the EPA. We are
proposing that owners and operators subject to this regulation must
electronically submit excess emissions, continuous monitoring systems
performance and-or summary reports required under section 60.7(c).
Owners and operators would need to submit these reports to the EPA's
WebFIRE database by using the Compliance and Emissions Data Reporting
Interface (CEDRI) that is accessed in the Central Data Exchange (CDX).
The CDX is the EPA's portal for submitting and managing electronic
environmental data and reports and is accessed at www.epa.gov/cdx. The
CDX is needed to meet the EPA standards for electronic reporting set by
the Cross-Media Electronic Reporting Rule. For more information, please
see http://www.epa.gov/cromerr/. Owners and operators required to
submit electronic reports would need to register to use the CDX and for
the CEDRI node at http://cdx.epa.gov/epa_home.asp. Once a user has
access to CDX and CEDRI, the owners and operators would use the subpart
specific forms in CEDRI to enter the information for the 60.7(c)
required reports.
    In most New Source Performance Standards owners and operators are
required to keep records of their reports on site for at least 2 years.
Since the owner or operator would be submitting the data in these
reports to be housed in CDX and WebFIRE, we are proposing to forgo
recordkeeping requirements for those reports required to be submitted
in proposed section 60.5555(a)(1). We believe that since the WebFIRE
database is public that the need for recordkeeping onsite for certain
information will not be needed as the information will be readily
available for all stakeholders to access.
    We are aware that owners or operators of many existing EGUs are
required to submit some emissions data through the EPA Acid Rain
Program's Emissions Collection and Monitoring Plan System (ECMPS) for
SO2, NOX, CO2, and other related data.
We propose for affected sources to continue to use ECMPS with
modifications to allow for collecting CO2 mass emissions
data and the CEMS relative accuracy reports proposed in this rule.
    We request comment on these and other modifications to ECMPS
appropriate for implementing this rule and any other EPA rules that
apply to EGUs in order to streamline and focus all applicable emissions
data reporting requirements. We request comment on modification of the
ECMPS system to collect, track, and calculate CO2 emissions
rates based on hourly useful energy output for the unit. We also
request comment on tracking and making use of useful steam data for new
facilities.
    We are also aware that owners or operators of existing units are
required to submit electrical generation data according to procedures
required by the DOE's Energy Information Administration (EIA) for its
reports. We request comment on the appropriateness of using these
electrical generation data in this proposed rule.
    The EPA proposes that these same notice, recordkeeping, and
reporting requirements would apply to the 30-year averaging compliance
option. The EPA requests comment on whether any alterations or
additions are appropriate for the notice, recordkeeping, and reporting
requirements that would apply to the 30-year averaging compliance
option. The EPA also requests comment on whether sources that utilize
the 30-year averaging compliance option should include, as applicable
requirements in their title V permits, a specific explanation of their
compliance plan, including when CCS would be deployed, what capture
rate(s) would be achieved, how the CO2 would be sequestered,
and whether the company anticipates receiving government financial
assistance or other incentives for the CCS.

IV. Rationale for the Proposed Standards for New Sources

A. How did the EPA establish the emission limits?

1. Rationale for Proposing to Combine the Subpart Da Category and a
Component of the Subpart KKKK Category into a New Category for Purposes
of Regulating GHG Emissions
    The EPA is proposing to create a new subpart in 40 CFR part 60 by
combining the sources in subpart Da (the Da category) and a subset of
the sources in subpart KKKK (the KKKK category)--stationary combined
cycle units, but not stationary simple cycle units--for purposes of
promulgating standards of performance for emissions of GHGs from new
sources. This new subpart will be numbered TTTT. Consistent with
standard practice and Executive Order 13563, and in particular its
emphasis on ``the open exchange of information and perspectives'' and
``providing an opportunity for public comment on all pertinent parts of
the rulemaking docket, including relevant scientific and technical
findings'' and on consideration of alternatives, we invite comments on
our decision to combine the two source categories.
    At this time, the EPA is not proposing to subcategorize new sources
and is not proposing to combine the Da category and components of the
KKKK category for purposes of regulating criteria pollutants.
    CAA section 111 provides legal authority for combining the
categories into a new category. Clean Air Act section 111(b)(1)(A)
provides:

    The Administrator shall, within 90 days after December 31, 1970,
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 a list if in his judgment it causes or contributes
significantly to air pollution which may reasonably be anticipated
to endanger public health or welfare.

(Emphasis added.)

    As quoted, this provision grants to the Administrator the authority
to ``revise'' the list of categories. Combining categories, in whole or
in part, is a form of ``revis[ing]'' the list of categories (along with
taking other actions, such as adding more categories or delisting
categories), and accordingly is authorized.
    For three principal reasons, it is appropriate for the EPA to
combine the Da category and the stationary combined cycle component of
the KKKK category at this time for purposes of regulating GHGs. First,
all of the plants covered by the new combined category (including
fossil fuel-fired boilers, IGCC units and NGCC units) perform the same
essential function, which is to provide generation to serve baseload or
intermediate load demand. It is sensible to treat as part of the same
category units that generate baseload or intermediate load electricity,
regardless of their design or fossil fuel type.
    Second, all newly constructed sources have options in selecting
their design (although it is true that natural gas-fired plants are
inherently lower emitting with regard to CO2 than coal-fired
plants. As a result, prospective owners and operators of new sources
could readily comply with the proposed emission standards by choosing
to construct a NGCC unit. These two factors provide sufficient legal
rationale for the EPA to combine the Da category and the combined cycle
component of the KKKK category for purposes of

establishing a standard of performance for GHG emissions.
    The agency has previously combined one type of baseload and
intermediate load combined cycle unit (IGCC, previously covered under
Subpart GG) with Da units for the purposes of setting a standard [40
CFR 60.41Da(b), Feb. 28, 2005]. This action now similarly combines
another type of baseload and intermediate load combined cycle unit
(NGCC, previously covered under Subpart KKKK) with Subpart Da units for
the purposes of setting a standard.
    A third factor lends additional support. Combining the categories
does not raise adverse policy concerns. On the basis of comments made
during the listening sessions, we anticipate that some commenters may
question whether combining the categories and applying the NGCC
standard to all new plants within the combined category may limit
construction of new coal-fired power plants, and thereby have a
disruptive effect on the electric power industry, increase electricity
prices and/or have adverse implications for energy diversity in new
generation. We do not believe that this action would have those
effects. As discussed below, and importantly, economic models forecast
no new construction of coal-fired generation without CCS through the
analysis period, which extends until 2020 (when the standard will be
revisited). Accordingly, economic conditions are expected to be the
main driver precluding, or at least limiting, construction of coal-
fired EGUs. Because of those economic conditions, there is a strong
independent movement of power plants serving baseload generation toward
NGCC. In light of that movement, it is appropriate for the EPA to focus
on this technology in developing the standard, rather than
subcategorizing and providing a separate standard for new coal units.
See Portland Cement Ass'n v. EPA, 665 F.3d 177, 190 (D.C. Cir. 2011)
(affirming the EPA's decision not to subcategorize in part because of
``the universal movement in the portland cement industry towards
adoption of preheater/precalciner technology'').
    Notwithstanding these points, we recognize the possibility that a
limited amount of new coal-fired construction may nevertheless occur.
Today's action would not foreclose construction of new coal-fired EGUs.
Rather, the new coal-fired EGUs that may be expected to be built in the
foreseeable future (and for reasons stated above, this is anticipated
to be a relatively small number) may install CCS control equipment (if
not at the time of construction, then not long thereafter). By doing
so, they may achieve the same average CO2 emission rate (at
least over time) as a natural gas-fired combined cycle unit. It is
reasonable to expect that some coal-fired power plants may be able to
implement CCS at the present time, and thereby achieve the 1,000 lb
CO2/MWh standard immediately. As noted elsewhere, CCS has
been demonstrated to be technologically achievable, and, even though it
is costly, there are some State and Federal programs that can make CCS
more affordable. Several power companies have announced plans to
incorporate CCS at six already permitted coal-fired EGU construction
projects in this country (as we discuss below in section V.B.,
concerning transitional sources). Programs exist that provide some
funding for CCS through pilot or other demonstration programs, and we
expect those to continue. In addition, we reasonably expect the costs
of CCS to decline over time. As discussed below, we are not proposing
that CCS does or does not qualify as the ``best system of emission
reduction'' that ``has been adequately demonstrated'' for new coal-
fired power plants. Rather, the feasibility of CCS and its availability
for the limited amount of new coal-fired construction that may be
expected, means that this action to combine the categories and
establish the NSPS at the proposed 1,000 lb CO2/MWh emission
limit will not have notable adverse effects on new coal-fired
construction or, therefore, on the electric utility industry,
electricity prices, or energy diversity. We welcome public comments on
this discussion.
    On the other hand, at this time, we do not consider it appropriate
to include simple cycle facilities as an affected source in the new 40
CFR part 60, subpart TTTT for GHG emissions from new facilities. The
reason for this is that the function of a new simple cycle power plant
is different than that of a new combined cycle plant or coal-fired
plant. Combined cycle plants and coal-fired plants are typically
designed to provide baseload or intermediate-load power, while simple
cycle turbines are designed to provide peaking power. Because combined
cycle power plants and coal-fired power plants both serve the same
purpose and have design options to emit CO2 at similar
levels, we believe it is appropriate to combine them. Because peaking
turbines operate less and because it would be much more expensive to
lower their emission profile to that of a combined cycle power plant or
a coal-fired plant with CCS, the EPA does not believe it is appropriate
to include them in this source category.
    As noted above, some commenters in the listening sessions did
suggest that the EPA not combine the two source categories. The EPA has
rejected that option for all the reasons outlined above: (1) Fossil-
fuel-fired boilers, combined cycle natural gas units, and IGCC units
all serve the same basic function, generating baseload or intermediate
load power; (2) the proposed standards can be met by different types of
units in the category (NGCC units or coal-fired units with CCS); and
(3) it is consistent with industry trends (as further explained
elsewhere in this notice: Due largely to current and projected gas and
coal price trends, new fossil-fuel-fired builds are projected to be
natural gas combined cycle units or coal-fired units with CCS supported
by federal funding). There is an additional reason for rejecting the
option of retaining (and establishing separate standards for) separate
source categories. The EPA's analysis (in Section 5.10 of the RIA)
suggests that over a wide range of market conditions, constructing a
new unit that meets a limit of 1,000 lb CO2/MWh instead of
an advanced coal-fired unit without CCS would likely produce net social
benefits. For all of these reasons, retaining separate source
categories would be unlikely to generate substantial private cost
savings, but at the same time, would create the risk of significantly
higher GHG emissions and other air pollutants from some new units,
resulting, in turn, in higher social costs.
    By the same token, at this time, we do not consider it appropriate
to combine the Da category and the combined cycle component of the KKKK
category for any pollutants other than GHGs, that is, for criteria
pollutants. This is because although coal-fired EGUs have an array of
control options for criteria and air toxic air pollutants to choose
from, those controls generally do not reduce their criteria and air
toxic emissions to the level of conventional emissions from natural
gas-fired EGUs.
2. Endangerment and Cause-or-Contribute-Significantly Finding
    a. Overview. In today's rulemaking, we propose or solicit comment
on alternative interpretations for whether section 111 includes
prerequisites to rulemaking that involve an endangerment finding and a
cause-or-contribute-significantly finding. By its terms, CAA section
111 provides that once the EPA lists a source category for regulation
because the category causes or contributes significantly to air
pollution that may reasonably be anticipated to endanger public health
or

welfare, the EPA then establishes requirements for new sources in that
source category. The EPA proposes to interpret these provisions so that
it is authorized to promulgate the rulemaking proposed today because it
has already determined that both the Da and KKKK source categories
cause or contribute significantly to air pollution that may reasonably
be anticipated to endanger public health or welfare. The EPA solicits
comment on interpreting CAA section 111 in the alternative so as to
require (i) an endangerment finding for air pollution not specifically
covered by the endangerment finding the EPA made when listing the
source category, but that in this case, the EPA's 2009 Endangerment
Finding for GHGs under Section 202(a) of the CAA (along with the EPA's
2010 denial of petitions to reconsider (2010 Reconsideration Denial)),
fulfills that requirement; and (ii) a cause-or-contribute-significantly
finding for air pollutants not specifically covered by the cause-or-
contribute-significantly finding the EPA made when listing the source
category, and that in this case, the large amounts of CO2
emissions from power plants provide a compelling basis allowing the EPA
to propose that finding. The EPA also solicits comment on another
alternative, which is interpreting CAA section 111 so as not to require
a specific endangerment finding or cause or contribute finding, but
simply to require the EPA to establish a rational basis for regulating
an air pollutant from a source category. In this case, the EPA's 2009
Endangerment Finding for GHGs and the 2010 denial of petitions to
reconsider the Endangerment Finding, as well as the large amounts of
CO2 emissions from power plants, provide that rational
basis. Finally, as an alternative for the basis for a rational basis
determination, the 2010 and 2011 Assessment Reports from the National
Academies confirm the Endangerment Finding and the denial of petitions
to reconsider.
    b. Proposal: Previous Source Category Findings Meet Any
Endangerment Prerequisite to Regulation. In this rulemaking, the EPA
proposes to interpret CAA section 111 so that we are not required, as a
prerequisite to regulating CO2 emissions from EGUs, to issue
a new finding as to the health or welfare impacts of GHG air pollution
or a finding as to the extent that affected sources contribute to that
air pollution.
    Clean Air Act section 111(b)(1)(A), by its terms, requires that the
Administrator list a source category for regulation if the ``category *
* * in [the Administrator's] judgment, * * * causes or contributes
significantly to air pollution which may reasonably be anticipated to
endanger public health or welfare.'' Clean Air Act 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.''
    Thus, although CAA section 111 clearly requires the EPA to list a
source category if its emissions contribute significantly to air
pollution that endangers public health or welfare, and then to
promulgate standards of performance for particular pollutants, section
111 does not by its terms require that the EPA make any endangerment
finding with respect to those particular pollutants, or any cause-or-
contribute-significantly finding with respect to the source category,
at the time the EPA promulgates the standards of performance for those
pollutants. The lack of any such requirement contrasts with (i) the
definition of ``standard of performance,'' which specifically requires
the EPA to consider ``nonair quality health and environmental impact,''
CAA section 111(a)(1) (emphasis added); and (ii) 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).
    Accordingly, under our proposal, once the EPA has listed a source
category, and the EPA proceeds to regulate particular pollutants from
that source category, CAA section 111 does not require that the EPA
make an endangerment finding for the relevant air pollution or a cause-
or-contribute-significantly finding for the relevant air pollutants
from that source category. The fact that the EPA is, in this
rulemaking, proposing to partially combine the Da and KKKK source
categories does not alter this outcome. As noted above, under CAA
section 111(b)(1)(A), the EPA may add a source category to the list of
categories only after determining that the source category ``causes, or
contributes significantly to, air pollution which may reasonably be
anticipated to endanger public health or welfare.'' The EPA has
previously determined that each of the Da and KKKK categories causes or
contributes significantly to such air pollution. Combining the Da
category and some of the sources in the KKKK category does not
necessitate that the EPA make a new cause-or-contribute-significantly
finding for the expanded Da category. This is because the EPA has
already found that at least one component of the new category--the
former Da sources--by itself causes or contributes significantly to
such air pollution. There is no reason why this expansion of the Da
category to include the pre-existing Da sources plus additional sources
could be considered to contribute to such air pollution to an extent
that is less than the contribution from the pre-existing Da sources
alone. As a result, the new category must necessarily be considered to
cause or contribute significantly to such air pollution.
    In addition to proposing this interpretation, we also solicit
comment on alternative interpretations under CAA section 111, including
those described next.
    c. First Alternative Interpretation: Endangerment Finding
Prerequisite. We solicit comment on an alternative interpretation under
which the EPA is required, as a prerequisite to promulgating standards
of performance under CAA section 111(b), to have issued an endangerment
finding specifically for the relevant air pollution and a cause-or-
contribute-significantly finding specifically for the relevant source
category and air pollutant. In particular, what would be the legal
basis for such an interpretation?
    Even if CAA section 111 is interpreted to require those findings,
then, in a case in which the EPA did not make those findings under CAA
section 111, it is the EPA's view that the EPA would satisfy the need
for a CAA section 111 endangerment finding through an endangerment or
comparable finding that the EPA made or that Congress adopted under any
other provision of the CAA. For example, the EPA may regulate, under
CAA section 111, (i) NAAQS pollutants because of the determinations the
EPA made under CAA sections 108 and 109 and (ii) HAPs that Congress
listed under CAA section 112(b)(1). It is the EPA's interpretation that
once an endangerment or comparable finding is made with respect to the
relevant air pollution under another CAA provision, regulation under
CAA section 111 of source categories that cause or contribute
significantly to that same air pollution may proceed without any need
for the EPA to revisit or update that endangerment finding as part of
the

CAA section 111 regulatory process. Instead, any concerns about the
continued validity of that endangerment finding may be resolved through
a petition to reconsider that finding under the applicable CAA
provision.
    Applying this alternative interpretation of CAA section 111 to this
rulemaking, the 2009 Endangerment Finding for GHG air pollution
fulfills any requirement under CAA section 111 that the EPA issue a
finding that GHG air pollution may reasonably be anticipated to
endanger public health or welfare in order for the EPA to establish
standards of performance for GHG emissions from EGUs. As discussed
above, the EPA already issued this endangerment finding under CAA
section 202(a)(1), as part of its process for promulgating the Light
Duty Vehicle Rule.
    The EPA recognizes that under this alternative interpretation, the
EPA could be required to issue 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.
Therefore, under this alternative interpretation, in today's
rulemaking, the EPA proposes to find that CO2 emissions from
fossil fuel-fired EGUs cause or contribute significantly to the GHG air
pollution. The EPA's basis for this proposed finding is, in part, that
the large amounts of CO2 emitted by fossil fuel-fired EGUs
clearly exceed the low hurdle necessary for the cause-or-contribute-
significantly finding. As noted above in Tables 2 and 3, 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. Indeed, so great is the contribution of CO2 air
pollutants from EGUs to GHG air pollution, that it is simply not
necessary in this rulemaking to determine thresholds for when a
contribution may be considered to be a ``significant[]'' contribution.
If it were necessary, the EPA proposes that a limited amount of
contribution would meet that standard in light of the fact that GHG air
pollution is caused by a large number of types of sources and that no
one source category dominates the entire inventory.
    d. Second alternative interpretation: Rational Basis Prerequisite.
As a second alternative interpretation, the lack of any requirement in
CAA section 111 addressing whether and how the EPA is to evaluate
emissions of particular pollutants from sources in the listed source
category as a prerequisite for regulation may be viewed as a statutory
gap that requires a Chevron step 2 interpretation. In this case, the
EPA is authorized to develop an interpretation that reasonably
effectuates the purposes of CAA section 111. Under this alternative
interpretation, the EPA must demonstrate a rational basis for
controlling the emissions of the particular pollutants. That rational
basis may consist of some type of factual showing that is consistent
with the purposes of CAA section 111, but may be something short of an
endangerment and a cause-or-contribute-significantly finding.
    There are several options for the factual showings that comprise a
rational basis. Under the first option, the EPA would be justified in
the present case in taking action with respect to GHG air pollution
because of the EPA's 2009 Endangerment Finding that GHG air pollution
may reasonably be anticipated to endanger public health and welfare.
The EPA issued that Endangerment Finding quite recently, in December,
2009, and by notice dated August 13, 2010, the EPA denied ten petitions
to reconsider that Finding, an action that entailed further review of
scientific information.
    Under the second option, the EPA could conclude that the recent
Endangerment Finding and denial of reconsideration, coupled with the
even more recent assessments from the NAS, published in 2010 and 2011,
which lend further credence to the science supporting the Endangerment
Finding, suffice to provide a rational basis for promulgating
regulations under CAA section 111 designed to address contributions to
the GHG air pollution.
    Under either of these options, the EPA would need to establish a
rational basis for regulating CO2 emissions from affected
EGUs. 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, as discussed above, would readily provide such a rational
basis.
3. Rationale for Emission Limits
    a. Few New Coal-fired Power Plants. An important part of the basis
for the EPA's proposal for new sources in this rulemaking is that all
indications suggest that very few new coal-fired power plants will be
constructed in the foreseeable future. Although a small number of new
coal-fired power plants have been built recently, the industry
generally is not building these kinds of power plants at present and is
not expected to do so for the foreseeable future. The reasons include
the current economic environment, which has lead to lower electricity
demand, and competitive natural gas prices. Natural gas prices have
stabilized over the past few years as new drilling techniques have
brought additional supply to the marketplace. As a result, natural gas
prices are expected to be competitive for the foreseeable future and
utilities are likely to rely heavily on natural gas to meet new demand
for electricity generation. On average, the cost of generation from a
new NGCC power plant is expected to be lower than the cost of
generation from a new coal-fired power plant.\44\
---------------------------------------------------------------------------

    \44\ Levelized Cost of New Generation in the Annual Energy
Outlook 2011 http://<IP_ADDRESS>/oiaf/aeo/electricity_generation.html.
---------------------------------------------------------------------------

    Other drivers that may influence decisions to build new power
plants are State and Federal energy and tax policies. Many states have
adopted renewable portfolio standards (RPS), which require that a
certain portion of electricity come from renewable energy sources like
solar or wind. The federal government has also adopted incentives for
electric generation from renewable energy sources and loan guarantees
for new nuclear power plants.
    These economic, cost, and policy factors create an environment in
which natural gas-fired power plants, renewable energy, and nuclear
power are the forms of energy generation that are most often predicted
to be built to meet new electricity demand over the coming years.
    Various energy sector modeling efforts, including projections from
both the EIA and the EPA, show results that are consistent with these
findings. The Annual Energy Outlook (AEO) for 2011 shows a very modest
amount of new coal-fired power coming online beyond 2012, although
there are a number of coal-fired power plants that are currently under
construction and expected to begin operation in the next year or two.
According to the AEO 2011, the majority of new generating capacity will
be either natural gas-fired or renewable, with some lesser amounts of
nuclear power. The AEO 2011 is based on existing policy and
regulations, such as state RPS programs and Federal tax credits for
renewables.\45\ The new generation that EIA does show coming on-line
after 2012 fits into one of three categories: generation that is
currently under construction, generation that will include CCS or
industrial CHP. Units in the first group would not be subject to this
rule because, since they have commenced construction, they are
considered existing sources. Units in the second group would include
either units in the transitional category or new

units. In either case, they could be built consistent with this action.
Units in the third group would not be subject to this rule because CHP
units that generate primarily on-site power are not considered EGUs and
are thus not affected by the rule.
---------------------------------------------------------------------------

    \45\ http://www.eia.gov/forecasts/aeo/chapter_legs_regs.cfm.
---------------------------------------------------------------------------

    The EPA modeling using the Integrated Planning Model (IPM), a
detailed power sector model that the EPA uses to support power sector
regulations, is keyed to the AEO in a number of respects and shows
similar patterns of little future construction of new coal-fired power
plants under the base case.\46\ The EPA's projections from IPM can be
found in the RIA.
---------------------------------------------------------------------------

    \46\ http://www.epa.gov/airmarkets/progsregs/epa-ipm/BaseCasev410.html#documentation.
---------------------------------------------------------------------------

    As discussed below, the fact that the expected number of coal-fired
power plants is so limited supports both (i) basing the standard of
performance on NGCC, which is expected to be the most commonly built
new fossil fuel-fired generating technology; and (ii) allowing 30-year
averaging as an alternative compliance option for coal- and pet coke-
fired power plants because CCS is feasible and sufficiently available
for the few such plants expected, in light of the demonstration
programs or other incentives available for CCS, coupled with the
prospects that the costs of CCS will decline over time.
    b. Basis for the Proposed Standard of Performance. In this section,
we describe our basis for proposing a standard of 1,000 lb/MWh, and for
taking comment on a range of 950 to 1,100 lb/MWh (430 to 500 kg/MWh).
We first describe our method for calculating these levels of
CO2 emissions, and then note that several states are already
requiring these levels of CO2 emissions.
    (1) Calculation of the Standard. For reasons explained below (see
``d. Legal Justification for the Standard of Performance and 30-year
averaging compliance option''), a NGCC facility is the best system of
emission reduction for new baseload and intermediate load EGUs. To
establish an appropriate, natural gas-based standard, we reviewed the
emissions rate of natural gas-fired (non-CHP) combined cycle facilities
used in the power sector that commenced operation between 2006 and 2010
and that report complete generation data to EPA. Based on this
analysis, nearly 95% of these facilities meet the proposed standards on
an annual basis. These units represent a wide range of geographic
locations (with differing elevations and ambient temperatures),
operational characteristics, and sizes.
    We are requesting comment on a range of 950 to 1,100 lb/MWh (430 to
500 kg/MWh) for the final rule. The upper limit would incorporate
essentially all available new combined cycle designs and would have
limited impact on improving efficiency of combined cycle facilities.
This upper limit would also be consistent with standards promulgated by
some states, as noted elsewhere. The stricter standard would in general
eliminate designs without a steam reheat cycle and similar lower
efficiency designs for use in electric-only generation, and could limit
presently available options for generation below approximately 40 MW.
However, an owner/operator of combined cycle facilities with higher
heat rates could either implement CHP or integrated solar thermal for
feedwater heating to achieve the proposed standard.
    (2) States Implementing a Comparable Standard. Several states have
recently established emission performance standards or other measures
to limit emissions of GHGs from new EGUs that are comparable to the
proposal in this rulemaking. For example, in September 2006, California
Governor Schwarzenegger signed into law Senate Bill 1368. The law
limits long-term investments in baseload generation by the state's
utilities to power plants that meet an emissions performance standard
jointly established by the California Energy Commission and the
California Public Utilities Commission. The Energy Commission has
designed regulations that establish a standard for new and existing
baseload generation owned by, or under long-term contract to publicly
owned utilities, of 1,100 lb CO2/MWh.
    In May 2007, Washington Governor Gregoire signed Substitute Senate
Bill 6001, which established statewide GHG emissions reduction goals,
and imposed an emission standard that applies to any baseload electric
generation that commenced operation after June 1, 2008 and is located
in Washington, whether or not that generation serves load located
within the state. Baseload generation facilities must initially comply
with an emission limit of 1,100 lb CO2/MWh.
    In July 2009, Oregon Governor Kulongoski signed Senate Bill 101,
which mandated that facilities generating baseload electricity, whether
gas- or coal-fired, must have emissions equal to or less than 1,100 lb
CO2/MWh, and prohibited utilities from entering into long-
term purchase agreements for baseload electricity with out-of-state
facilities that do not meet that standard. Natural gas- and petroleum
distillate-fired facilities that are primarily used to serve peak
demand or to integrate energy from renewable resources are specifically
exempted from the performance standard.
    c. Basis for CCS as a Feasible Technology Option. In this section,
we describe the basis for our position that CCS is a feasible
technology option for new coal-fired power plants because CCS is
technically feasible and sufficiently available in light of the limited
amount of new coal-fired construction expected in the foreseeable
future. In brief, first, at present, CCS is technologically feasible
for implementation at new coal-fired power plants and its core
components (CO2 capture, compression, transportation and
storage) have already been implemented at commercial scale. Second,
although the costs of CCS are presently high, we have reason to expect
that the costs of CCS will decrease over time. This action will itself
contribute to downward pressure on CCS costs by shifting the regulatory
landscape towards CCS, consistent with the recent report by the
Interagency Task Force on Carbon Capture and Storage, established by
President Obama on February 3, 2010, which we describe below. Third, we
expect construction of no more than a few new coal-fired power plants
by 2020 and those plants may well be able to take advantage of
demonstration programs or other sources of funding for CCS. Fourth,
several states have set emission standards that will make
implementation of CCS necessary for new coal-fired power plants, some
projects that implement CCS or components of it are proceeding, and
other CCS projects are in the planning stages.
    (1) Technological Feasibility of CCS. The current state of affairs
concerning CCS was described and analyzed by the Interagency Task Force
on Carbon Capture and Storage, established by President Obama on
February 3, 2010, co-chaired by the DOE and the EPA, and composed of 14
executive departments and federal agencies. The Task Force was charged
with proposing a plan to overcome the barriers to the widespread, cost-
effective deployment of CCS within 10 years, with a goal of bringing
five to ten commercial demonstration projects online by 2016. The Task
Force found that, although early CCS projects face economic challenges
related to climate policy uncertainty, first-of-a-kind technology
risks, and the current high cost of CCS relative to other technologies,
there are no insurmountable technological, legal, institutional,
regulatory or other barriers that prevent CCS from playing a role in

reducing GHG emissions. The Task Force also identified the need for
comprehensive review of the overall environmental impacts of CCS.
    (a) Capture and Compression Technologies and Costs. Capture of
CO2 from industrial gas streams has occurred since the 1930s
using a variety of approaches to separate CO2 from other
gases. These processes have been used in the natural gas industry and
to produce food and chemical-grade CO2. Although current
capture technologies are feasible, the costs of CO2 capture
and compression represent the largest stumbling block to widespread
commercialization of CCS. Currently available CO2 capture
and compression processes are estimated to represent seventy to ninety
percent of the overall CCS costs.\47\
---------------------------------------------------------------------------

    \47\ Report of the Interagency Task Force on Carbon Capture and
Storage (August 2010).
---------------------------------------------------------------------------

    In general, CO2 capture technologies applicable to coal-
fired power generation can be categorized into three approaches: \48\
---------------------------------------------------------------------------

    \48\ IPCC, 2005; DOE, 2007.
---------------------------------------------------------------------------

     Pre-combustion systems are designed to separate
CO2 and H2 in the high-pressure syngas produced
at IGCC power plants.
     Post-combustion systems are designed to separate
CO2 from the flue gas produced by fossil-fuel combustion in
air.
     Oxy-combustion uses high-purity O2, rather than
air, to combust coal and therefore produces a highly concentrated
CO2 stream.

    Each of these three carbon capture approaches (pre-combustion,
post-combustion, and oxy-combustion) is technologically feasible.
However, each results in increased capital and operating costs and
decreased electricity output (that is, an energy penalty), with a
resulting increase in the cost of electricity. The energy penalty
occurs because the CO2 capture process uses some of the
energy produced from the plant.
    (b) Current Availability of Transportation and Sequestration. The
remaining steps for CCS (i.e., pipeline transportation and storage),
are also well established but less expensive than capture and
compression.
    Carbon dioxide has been transported via pipelines in the U.S. for
nearly 40 years. Approximately 50 million metric tons of CO2
are transported each year through 3,600 miles of pipelines. Moreover, a
review of the 500 largest CO2 point sources in the U.S.
shows that 95 percent are within 50 miles of a possible geologic
sequestration site,\49\ which would lower transportation costs. For
these reasons, the transportation component of CCS is not expected to
be a significant stumbling block to the commercial availability of CCS
in the future.
---------------------------------------------------------------------------

    \49\ JJ Dooley, CL Davidson, RT Dahowski, MA Wise, N Gupta, SH
Kim, EL Malone (2006), Carbon Dioxide Capture and Geologic Storage:
A Key Component of a Global Energy Technology Strategy to Address
Climate Change. Joint Global Change Research Institute, Battelle
Pacific Northwest Division. PNWD-3602. College Park, MD.
---------------------------------------------------------------------------

    With respect to sequestration, globally, there are at least four
commercial integrated CCS facilities sequestering captured
CO2 into deep geologic formations and applying a suite of
technologies to monitor and verify that the CO2 remains
sequestered.\50\ These four sites represent over 25 years of cumulative
experience on safely and effectively storing anthropogenic
CO2 in appropriate deep geologic formations.\51\ Estimates
based on DOE studies indicate that areas of the U.S. with appropriate
geology have a storage potential of 1,800 billion to more than 20,000
billion metric tons of CO2 in deep saline formations, oil
and gas reservoirs and un-mineable coal seams.\52\ The U.S. experience
with large-scale CO2 injection, such as at enhanced oil and
gas recovery projects, combined with ongoing research, development, and
demonstration programs in the U.S. and throughout the world, provide
confidence that the storage--along with capture, compression and
transport--of large amounts of CO2 can be achieved.
---------------------------------------------------------------------------

    \50\ These projects are: Sleipner in the North Sea,
Sn[oslash]hvit in the Barents Sea, In Salah in Algeria, and Weyburn
in Canada.
    \51\ Dooley, J. J., et al. (2009). An Assessment of the
Commercial Availability of Carbon Dioxide Capture and Storage
Technologies as of June 2009. U.S. Department of Energy, Pacific
Northwest National Laboratory, under Contract DE-AC05-76RL01830.
    \52\ U.S. Department of Energy National Energy Technology
Laboratory (2010). Carbon Sequestration Atlas of the United States
and Canada, Third Edition.
---------------------------------------------------------------------------

    It should be noted that the EPA recently finalized two rules that
aim to protect drinking water and track the amount of CO2
that is sequestered from facilities that carry out geologic
sequestration. The Underground Injection Control (UIC) Class VI rule,
established under authority of the Safe Drinking Water Act, sets
requirements to ensure that geologic sequestration wells are
appropriately sited, constructed, tested, monitored, and closed in a
manner that ensures protection of underground sources of drinking
water.\53\ The UIC Class VI regulations contain monitoring requirements
to protect underground sources of drinking water, including the
development of a comprehensive testing and monitoring plan. This
includes testing of the mechanical integrity of the injection well,
ground water monitoring, and tracking of the location of the injected
CO2 using direct and indirect methods. Projects are also
required to do extended post-injection monitoring and site care to
track the location of the injected CO2 and monitor
subsurface pressures until it can be demonstrated that underground
sources of drinking water are no longer endangered. Subpart RR of the
Greenhouse Gas Reporting Program, which was established under authority
of the CAA and builds on UIC requirements, provides requirements for
quantifying the amount of CO2 sequestered by these
facilities.\54\ In addition, the EPA recently proposed a rule that
would conditionally exclude CO2 streams from the definition
of hazardous waste under RCRA, where these streams are being injected
for purposes of geologic sequestration, provided that they are managed
in accordance with certain conditions.\55\ That proposed rule is based
upon the EPA's conclusion that the management of CO2
streams, under the proposed conditions, does not present a substantial
risk to human health or the environment, and was based upon a review of
existing regulatory programs applicable to the transportation of
CO2 streams, and their injection into permitted UIC Class VI
wells. Together, these actions help create a consistent national
framework to ensure the safe and effective deployment of geologic
sequestration.
---------------------------------------------------------------------------

    \53\ Federal Requirements under the Underground Injection
Control (UIC) Program for Carbon Dioxide (CO2) Geologic
Sequestration (GS) Wells, Final Rule, 75 FR 77230 (Dec. 10, 2010).
    \54\ Mandatory Reporting of Greenhouse Gases: Injection and
Geologic Sequestration of Carbon Dioxide, Final Rule, 75 FR 75060
(Dec. 1, 2010).
    \55\ Hazardous Waste Management System: Identification and
Listing of Hazardous Waste: Carbon Dioxide (CO2) Streams
in Geologic Sequestration Activities, Proposed Rule, 76 FR 48073
(Aug. 8, 2011).
---------------------------------------------------------------------------

    (2) Expected reduction in CCS costs. Research is underway to reduce
CO2 capture costs and to improve performance. The DOE/
National Energy Technology Laboratory (NETL) sponsors an extensive
research, development and demonstration program that is focused on
developing advanced technology options that will dramatically lower the
cost of capturing CO2 from fossil-fuel energy plants
compared to today's available capture technologies. The DOE/NETL
estimates that using today's commercially available CCS technologies
would add around 80 percent to the cost of electricity for a new
pulverized coal (PC) plant, and around 35 percent to the cost of
electricity for a new advanced

gasification-based (IGCC) plant. The CCS research, development and
demonstration program is aggressively pursuing efforts to reduce these
costs to a less than 30 percent increase in the cost of electricity for
PC power plants and a less than 10 percent increase in the cost of
electricity for new gasification-based power plants.\56\ The large-
scale CO2 capture demonstrations that are currently planned
and in some cases underway, under DOE's initiatives, as well as other
domestic and international projects, will generate operational
knowledge and enable continued commercialization and deployment of
these technologies.
---------------------------------------------------------------------------

    \56\ DOE/NETL Carbon Dioxide Capture and Storage RD&D Roadmap,
U.S. Department of Energy National Energy Technology Laboratory,
December 2010.
---------------------------------------------------------------------------

    Gas absorption processes using chemical solvents, such as amines,
to separate CO2 from other gases have been in use since the
1930s in the natural gas industry and to produce food and chemical
grade CO2. The advancement of amine-based solvents is an
example of technology development that has improved the cost and
performance of CO2 capture. Most single component amine
systems are not practical in a flue gas environment as the amine will
rapidly degrade in the presence of oxygen and other contaminants. The
Fluor Econamine FG process uses a monoethanolamine (MEA) formulation
specially designed to recover CO2 and contains a corrosion
inhibitor that allows the use of less expensive, conventional materials
of construction. Other commercially available processes use sterically
hindered amine formulations (for example, the Mitsubishi Heavy
Industries KS-1 solvent) which are less susceptible to degradation and
corrosion issues. The DOE/NETL and private industry are continuing to
sponsor research on advanced solvents (including new classes of amines)
to improve the CO2 capture performance and reduce costs.
    Significant reductions in the cost of CO2 capture would
be consistent with overall experience with the cost of pollution
control technology. A significant body of literature suggests that the
per-unit cost of producing or using a given technology declines as
experience with that technology increases over time,\57\ and this has
certainly been the case with air pollution control technologies.
Reductions in the cost of air pollution control technologies as a
result of learning-by-doing, research and development investments, and
other factors have been observed over the decades.
---------------------------------------------------------------------------

    \57\ These studies include John M. Dutton and Annie Thomas,
``Treating Progress Functions as a Managerial Opportunity,'' 2, 235-
247; Dennis Epple, Linda Argote, and Rukmini Devadas,
``Organizational Learning Curves: A Method for Investigating Intra-
plant Transfer of Knowledge Acquired Through Learning by Doing,''
Organizational Science, Vol. 2, No. 1, February 1991; International
Energy Agency, Experience Curves for Energy Technology Policy, 2000;
and Paul L. Joskow and Nancy L. Rose, ``The Effects of Technological
Change, Experience, and Environmental Regulation on the Construction
Cost of Coal-Burning Generating Units,'' RAND Journal of Economics,
Vol. 16,Issue 1, 1-27, 1985. See discussion in ``The Benefits and
Costs of the Clean Air Act from 1990 to 2020,'' U.S. EPA, Office of
Air and Radiation, April 2011.
---------------------------------------------------------------------------

    We expect that the costs of capture technology will follow this
pattern. Rubin et al. assessed the historical rates of cost reductions
achieved by other energy and environmental process technologies and
then, by analogy, estimated future cost reductions that might be
achieved by four types of new power plants employing CO2
capture.\58\ The results of the study suggested that total costs of
CO2 capture can be expected to decline by the following
percentages: NGCC by 40 percent, PC by 26 percent, IGCC by 13 percent,
and Oxyfuel by 13 percent after installation of the first 100 GW of
capacity.
---------------------------------------------------------------------------

    \58\ Rubin, E.S.; Yeh, S.; Antes, M.; Berkenpas, M.; Davison,
J.; ``Use of experience curves to estimate the future cost of power
plants with CO2 capture'', Intl. J. of Greenhouse Gas
Control, 1, 188 (2007).
---------------------------------------------------------------------------

    In a subsequent study, the model used in the initial study was
extended with learning curves for several key performance variables,
including overall energy loss in power plants, the energy required for
CO2 capture, the CO2 capture ratio (removal
efficiency) and the power plant availability. The model predicted
continued reductions in cost with increased implementation.\59\
---------------------------------------------------------------------------

    \59\ Van den Broek, M.; Hoefnagels, R.; Rubin, E.; Turkenburg,
W.; Faaij, A.; ``Effects of technological learning on future cost
and performance of power plants with CO2 capture'',
Progress in Energy and Combustion Science 35 (2009) 457-480.
---------------------------------------------------------------------------

    In addition, we note that the Administration's CCS Task Force
report recognized that CCS would not become more widely available
without the advent of a regulatory framework that promoted CCS or a
strong price signal for CO2. Today's action is an important
component in developing that framework.
    (3) Limited amount of construction of new coal-fired power plants;
opportunities for CCS funding. A third factor that supports CCS as a
feasible technology option is that through the IPM model period of up
to 2020, we expect few, if any, new builds of coal-fired EGUs, beyond
those that already have approved PSD permits. We also expect continued
opportunities for financial support for some CCS projects through a
variety of potential mechanisms such as direct grants, tax incentives
and/or regulatory programs (e.g. Clean Energy Standards or guaranteed
electricity purchase price agreements).\60\ Accordingly, the few new
coal-fired generation projects that may occur over this timeframe may
well find that financial support for CCS is available.
---------------------------------------------------------------------------

    \60\ See Center for Climate and Energy Solutions, ``Financial
Incentives for CCS''--http://www.c2es.org/sites/default/modules/usmap/pdf.php?file=8380.
---------------------------------------------------------------------------

    (4) State Requirements for CCS; Projects and Permits for CCS.
Several states have recently established requirements that new coal-
fired EGUs must implement CCS, and a number of projects with CCS have
been approved and/or are under construction.
    In May 2007, Montana Governor Schweitzer signed House Bill 25,
adopting a CO2 emissions performance standard for electric
generating units in the state. House Bill 25 prohibits the state Public
Utility Commission from approving new electric generating units
primarily fueled by coal unless a minimum of 50 percent of the
CO2 produced by the facility is captured and sequestered.
    On January 12, 2009, Illinois Governor Blagojevich signed Senate
Bill 1987, the Clean Coal Portfolio Standard Law. The legislation
establishes emission standards for new power plants that use coal as
their primary feedstock. From 2009-2015, new coal-fueled power plants
must capture and store 50 percent of the carbon emissions that the
facility would otherwise emit; from 2016-2017, 70 percent must be
captured and stored; and after 2017, 90 percent must be captured and
stored.
    The following is a brief summary of currently operating or planned
CO2 capture or storage systems, including, in some cases,
components necessary for coal-based power plant CCS applications.
    AES's coal-fired Warrior Run (Cumberland, MD) and Shady Point
(Panama, OK) power plants are equipped with amine scrubbers developed
by ABB/Lummus. They were designed to process a relatively small
percentage of each plant's flue gas. At Warrior Run, approximately
110,000 tonnes of CO2 per year are captured, whereas at
Shady Point 66,000 tonnes of CO2 per year are captured. The
CO2 from both plants is subsequently used in the food
processing industry.\61\
---------------------------------------------------------------------------

    \61\ Dooley, J.J., et al. (2009). An Assessment of the
Commercial Availability of Carbon Dioxide Capture and Storage
Technologies as of June 2009. U.S. DOE, Pacific Northwest National
Laboratory, under Contract DE-AC05-76RL01830.

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

    At the Searles Valley Minerals soda ash plant in Trona, CA,
approximately 270,000 tonnes of CO2 per year are captured
from the flue gas of a coal power plant via amine scrubbing and used
for the carbonation of brine in the process of producing soda ash.\62\
---------------------------------------------------------------------------

    \62\ IEA (2009a), World Energy Outlook 2009, OECD/IEA, Paris.
---------------------------------------------------------------------------

    A pre-combustion Rectisol[supreg] system is used for CO2
capture at the Dakota Gasification Company's synthetic natural gas
production plant located in North Dakota, which is designed to remove
approximately 1.6 million tonnes of CO2 per year from the
synthesis gas. The CO2 is purified, transported via a 200-
mile pipeline, and injected into the Weyburn oilfield in Saskatchewan,
Canada.
    In September 2009, American Electric Power Co. (AEP) began a pilot-
scale CCS demonstration at its Mountaineer Plant in New Haven, WV. The
Mountaineer Plant is a 1,300 MWe coal-fired unit that was retrofitted
with Alstom's patented chilled ammonia CO2 capture
technology on a 20 MWe portion, or ``slipstream'', of the plant's
exhaust flue gas. In May 2011, Alstom Power announced the successful
operation of the chilled-ammonia CCS validation project. The AEP-Alstom
project, the world's first facility to both capture and store
CO2 from a coal-fired power plant, represents a successful
scale-up of ten times the size of previous field pilots (e.g., at We
Energies Pleasant Prairie). The demonstration achieved capture rates
from 75 percent (design value) to as high as 90 percent, produced
CO2 at purity of greater than 99 percent, with energy
penalties within a few percent of predictions. The facility reported
robust steady-state operation during all modes of power plant operation
including load changes, and saw an availability of the CCS system of
greater than 90 percent.
    AEP, with assistance from the DOE, had planned to expand the
slipstream demonstration to a commercial scale, fully integrated
demonstration at the Mountaineer facility. The commercial-scale system
was designed to capture at least 90 percent of the CO2 from
235 MW of the plant's 1,300 MW total capacity. Plans were for the
project to be completed in four phases, with the system to begin
commercial operation in 2015. However, in July 2011, AEP announced that
it is terminating its cooperative agreement with the DOE and placing
its plans to advance CO2 capture and storage technology to
commercial scale on hold, citing the current uncertain status of U.S.
climate policy and the continued weak economy as contributors to the
decision.
    Oxy-combustion of coal is being demonstrated in a 10 MWe facility
in Germany. The Vattenfall plant in eastern Germany (Schwarze Pumpe)
has been operating since September 2008. It is designed to capture
70,000 tonnes of CO2 per year.
    In June 2011, Mitsubishi Heavy Industries, an equipment
manufacturer, announced the successful launch of operations at a 25 MW
coal-fired carbon capture facility at Southern Company's Alabama Power
Plant Barry. The demonstration is planned to capture approximately
150,000 tons of CO2 annually at a CO2 capture
rate of over 90 percent. The captured CO2 will be
permanently stored underground in a deep saline geologic formation.
    Southern Company has begun construction of Mississippi Power Plant
Ratcliffe (formerly the Kemper County IGCC Project). Plant Ratcliffe is
a 582 MW IGCC plant that will utilize local Mississippi lignite and
include pre-combustion carbon capture to reduce CO2
emissions by 65 percent. Operation is expected to begin in 2014. The
CO2 captured from Plant Ratcliffe will be used for enhanced
oil recovery (EOR) in the Heidelberg Oil Fields in Jasper County, MS.
    The Texas Clean Energy Project, a 400 MW IGCC facility located near
Odessa, TX will capture 90 percent of its CO2, which is
approximately 3 million tonnes annually. The captured CO2
will be used for EOR in the West Texas Permian Basin. (Additionally,
the plant will produce urea and smaller quantities of commercial-grade
sulfuric acid, argon, and inert slag, all of which will also be
marketed.) Construction is expected to begin in 2012.
    d. Legal Justification for the Standard of Performance and 30-year
Averaging Compliance Option. This section describes our legal
justification for proposing that new affected facilities in the TTTT
category--which combines the Da and part of the KKKK categories--(i)
must limit their CO2 emissions to 1,000 lb CO2/
MWh, which an affected facility could achieve by constructing a NGCC
unit or by constructing a coal-fired boiler that implements CCS
immediately; or (ii) in the case of a coal- or pet coke-fired power
plant, may either meet the 1,000 lb CO2/MWh standard or
implement an 30-year averaging compliance option that allows an
affected facility to meet an initial CO2 emission limit of
1,800 lb CO2/MWh (gross), and then--through the
implementation of CCS--meet the 1,000 lb CO2/MWh standard,
on a time-averaged basis, over no longer than a 30-year period.
    (1) Legal Justification for the Standard of Performance. The EPA
proposes that the emission limit of 1,000 lb CO2/MWh meets
the requirements for a ``standard of performance'' applicable to new
sources under CAA section 111(b)(1)(B). The term ``standard of
performance'' is defined under CAA section 111(a)(1) as follows:

    Definitions. For purposes of this section: (1) The term
``standard of performance'' means a standard for emissions of air
pollutants which reflects the degree of emission limitation
achievable through the application of the best system of emission
reduction which (taking into account the cost of achieving such
reduction and any nonair quality health and environmental impact and
energy requirements) the Administrator determines has been
adequately demonstrated.

    We apply this definition, in effect, from the bottom up. That is,
first, we determine the ``best system of emission reduction which
(taking into account * * * cost [and other factors]) the Administrator
determines has been adequately demonstrated.'' For EGUs, that is a NGCC
facility, for reasons discussed below. Then, we calculate the ``degree
of emission limitation achievable through the application of'' such
best system; and after that, we formulate ``a standard for emissions of
air pollutants which reflects'' that degree of emission limitation.
This standard is 1,000 lb of CO2/MWh. These analytical steps
are also discussed further below.
    In determining the ``best system of emission reduction'' for this
category of boilers and combined cycle units, we considered a range of
natural gas-fired and coal-fired generation technologies, with
available controls. We considered modern supercritical and ultra-
supercritical coal-fired boilers. This technology is available--it is
currently deployed in Europe and is now being widely deployed in Asia
(especially China)--and it offers much more efficient operation than
the subcritical boilers that have more often been constructed in the
U.S. These supercritical and ultra-supercritical boilers have
CO2 emissions of approximately 1,800 lb/MWh and provide the
lowest overall costs for conventional coal-based electricity. We also
considered new IGCC, or ``coal gasification'' facilities, which can
have CO2 emissions levels very similar to those of ultra-
supercritical coal-fired units--albeit at a higher price.
    We also considered natural gas-fired boilers which have
CO2 emissions of approximately 1,350 lb/MWh, obviously

much lower than the advanced coal-fired or coal gasification
technologies. However, it seems unlikely that utilities would choose a
natural gas-fired boiler as the generation technology of choice when
NGCC is a much more efficient, less expensive, and more widely used
technology.
    We propose that a NGCC facility is the best system of emission
reduction for two main reasons. First, natural gas is far less
polluting than coal. Combustion of natural gas emits only about 50
percent of the CO2 emissions that combustion of coal does
per unit of energy generated. Second, new natural gas-fired EGUs are
less costly than new coal-fired EGUs, and as a result, our IPM model
projects that for economic reasons, natural gas-fired EGUs will be the
facilities of choice until at least 2020, which is the analysis period.
Indeed, those models do not project construction of any new coal-fired
EGUs during that period that would not comply with the proposed
standard. This state of affairs has come about primarily because
technological development and discoveries of abundant reserves have
caused natural gas prices to decline precipitously in recent years and
have secured those relatively low prices for the near-future.
Importantly, because the IPM modeling shows that natural gas-fired
plants are the facilities of choice, the proposed standard of
performance in today's rulemaking--which is based on the emission rate
of a new NGCC unit--does not add costs. In addition, compared to coal-
fired EGUs, natural gas-fired EGUs have fewer nonair quality health and
environmental impacts.
    Essentially because natural gas generation is cleaner and cheaper
than coal, natural gas-fired EGUs qualify as the ``best system of
emission reduction which (taking into account the cost of achieving
such reduction and any nonair quality health and environmental impact
and energy requirements) the Administrator determines has been
adequately demonstrated.''
    We recognize that today's proposed approach of combining the Da
category and a portion of the KKKK category, and applying as the
standard of performance the rate that natural gas-fired EGUs can meet,
represents a departure from prior agency practice. We consider this
departure warranted in light of both the emissions benefits and the
changed economic circumstances, notably the lowered prices of natural
gas due to technological development and recent discoveries that have
boosted recoverable reserves. We are aware that in theory, those
economic circumstances could change and if they do, then a change in
the standard of performance may be warranted. In this regard, we note
that CAA section 111(b)(1)(B) requires that the EPA ``shall, at least
every 8 years, review and, if appropriate, revise [the] standards [of
performance].'' This 8-year review cycle provides a mechanism for the
EPA to assure that the standard of performance for any particular
source category continues to reflect the ``best system.''
    (2) Legal Justification for the 30-year Averaging Compliance
Option. Although the IPM model projects that for economic reasons, new
coal- or pet coke-fired EGUs will not be built in the foreseeable
future (beyond early CCS projects), we recognize that in a few
instances, owners or operators may in fact seek to build coal- or pet
coke-fired EGUs. As discussed in detail below, those owners or
operators could avail themselves of CCS as a 30-year averaging
compliance option. In addition, today's proposed rulemaking offers
flexibility for CCS installation: The owners or operators could (i)
achieve the supercritical efficiency level for an initial period (e.g.,
up to the first 10 years), and (ii) after that, implement CCS so as to
achieve a 600 lb CO2/MWh rate on a 12-month annual average
during the latter period (i.e., the back 20 years) and thereby achieve
the 1,000 lb CO2/MWh rate on an average annual basis over
the 30-year period. The alternative compliance option could also allow
them to install and operate CCS much earlier and use the 10-year period
to address any startup challenges related to being an early adopter of
the technology.
    Because CO2 is long-lived in the atmosphere, the 30-year
averaging period, as structured, with shorter term compliance
requirements, is not expected to have a different impact on climate
compared to meeting the standard of performance.
    (a) CCS. The significance of CCS as a compliance alternative is
several-fold. As a practical matter, it offers a vehicle for the
construction of new coal-fired EGUs in those few instances in which
owners or operators decide to construct such EGUs, notwithstanding the
underlying economics. Also, it offers a vehicle for the continued
scaling of CCS, a process that can be expected to lower the costs of
CCS in the future. In addition, this compliance alternative provides
further support for the reasonableness of the EPA's proposals in this
rulemaking to combine the Da category and a portion of the KKKK
category and to determine that a NGCC facility is the ``best system of
emission reduction.'' This is because this compliance alternative, by
providing a vehicle for new coal-fired power plant builds, would
minimize any disruptions that the EPA's proposals might, at least in
theory, otherwise entail to the power plant industry.
    CCS as a compliance alternative does not achieve these goals by
necessarily qualifying, under the CAA section 111(a)(1) definition of
``standard of performance,'' as the ``best system of emission reduction
which (taking into account cost [and other factors]) the Administrator
determines has been adequately demonstrated.'' Instead, this compliance
alternative is feasible and sufficiently available for the limited
amount of new coal-fired construction that is expected, whether or not
it would qualify as the ``best system.''
    First, it is reasonable to expect that some coal-fired power plants
may be able to implement CCS at the present time, and thereby achieve
the 1,000 lb CO2/MWh standard immediately. As noted
elsewhere, CCS has been demonstrated to be technologically achievable,
and, even though it is costly, there are some state and Federal subsidy
programs that can make CCS more affordable, particularly in tandem with
use of captured CO2 for enhanced oil recovery, and those
programs may be sufficient for the very few new coal-fired plants that
are expected to be constructed in the foreseeable future. Some of these
programs are discussed above.
    We note that the need for governmental subsidies to reduce the
costs of CCS is hardly unique in the electricity generation sector.
Each of the major types of energy used to generate electricity has been
or is currently supported by some type of government subsidy--such as
tax benefits, loan guarantees, low-cost leases, or direct
expenditures--for some aspect of development and utilization, ranging
from exploration to control installation. This is true of fossil fuel-
fired; as well as nuclear-, geothermal, wind-, and solar-generated
electricity. These subsidies have been designed to overcome cost
barriers to the utilization of the energy. In this context, the need
for subsidies for CCS to overcome cost barriers does not mean that CCS
cannot be considered an alternative compliance method in this
rulemaking.
    Second, it is reasonable to expect that some coal-fired power
plants may be able to implement the supercritical efficiency standard
for an initial period of time (the first 10 years) and then implement
CCS and achieve lower 12-month annual average rates after that, so that
the source achieves the 1,000 lb CO2/MWh standard on average
over the

30-year period following construction.\63\ This is because, again, CCS
is feasible and can be expected to be sufficiently available--in light
of continued subsidies and lower future costs--in light of the limited
demand.
---------------------------------------------------------------------------

    \63\ Note that under today's proposed rulemaking, the 30-year
averaging proposal is associated only with the implementation of CCS
at new coal- or pet coke-fired EGUs. This proposal does not allow
30-year averaging for any other purpose.
---------------------------------------------------------------------------

    Third, although we do not propose that the 30-year averaging
compliance option meets the definition of the ``best system of emission
reduction [(BSER)] * * * adequately demonstrated,'' under CAA section
111, we note that identifying CCS as a compliance option based in part
on the expectation that CCS will cost less in the future is consistent
with the section 111 requirements for determining the BSER adequately
demonstrated. In determining what emissions controls qualify as the
BSER adequately demonstrated--which must take costs into account--the
EPA is authorized under CAA section 111 to anticipate that technology
that is costly at present will come down in price in the future. It is
clear from the legislative history of section 111 and relevant case law
that the EPA may anticipate future developments--as long as supported
by an adequate record--in determining whether a particular system of
emission reduction is the BSER adequately demonstrated. The Senate
Committee Report to the 1970 CAA Amendments, which first enacted CAA
section 111, made clear that the EPA may anticipate future developments
in determining the BSER adequately demonstrated:

    As used in this section, the term ``available control
technology'' is intended to mean that the Secretary should examine
the degree of emission control that has been or can be achieved
through the application of technology which is available or normally
can be made available. This does not mean that the technology must
be in actual, routine use somewhere. It does mean that the
technology must be available at a cost and at a time which the
Secretary determines to be reasonable. The implicit consideration of
economic factors in determining whether technology is ``available''
should not affect the usefulness of this section. The overriding
purpose of this section would be to prevent new air pollution
problems, and toward that end, maximum feasible control of new
sources at the time of their construction is seen by the committee
as the most effective and, in the long run, the least expensive
approach.

Sen. Rep. 91-1196 at 16 (emphasis added). As quoted, this statement
makes clear that a standard of performance may be based on a technology
that is not ``in actual routine use somewhere,'' but that ``normally
can be made available.'' Moreover, the technology need not be available
until ``a time which the Secretary determines to be reasonable.'' Id.
    In addition, the D.C. Circuit has been explicit that in setting a
CAA section 111 standard of performance, the EPA may make reasonable
projections of what technology will be available to the regulated
industry in the future. The Court stated, in Portland Cement Ass'n v.
Ruckelshaus, 486 F.2d 375 (D.C. Cir. 1973):

    We begin by rejecting the suggestion of the cement manufacturers
that the Act's requirement that emission limitations be ``adequately
demonstrated'' necessarily implies that any cement plant now in
existence be able to meet the proposed standards. Section 111 looks
toward what may fairly be projected for the regulated future, rather
than the state of the art at present, since it is addressed to
standards for new plants--old stationary source pollution being
controlled through other regulatory authority. It is the
``achievability'' of the proposed standard that is in issue. * * *
The * * * standard is analogous to the one examined in International
Harvester * * *. The Administrator may make a projection based on
existing technology, though that projection is subject to the
restraints of reasonableness and cannot be based on ``crystal ball''
inquiry.\64\

Id. at 391 (emphasis added). Again, although these statements in the
legislative history and case law are in the context of establishing the
basis for a standard of performance, the same principle -- that the EPA
may reasonably project the path of technological development --
supports treating CCS as a compliance alternative.
    Although, for the reasons noted above, we do expect the costs of
CCS to decline, we recognize that the amount of the decrease is
uncertain. Even so, the presence of cost uncertainty by itself does not
mean that prospective power plants cannot be expected to adopt the 30-
year averaging compliance option. We note that prospective power plants
face significant cost uncertainties in any event.
    For example we note that recently, several owner/operators have
announced that they do not intend to construct coal-fired power plants
without CCS. They have explained that they anticipate more widespread
CO2 control requirements in the future, so that constructing
coal-fired plants at this time without CCS could leave them subject to
liability for high retrofit control costs in the future. This sentiment
indicates that some sources may avail themselves of the 30-year
averaging compliance option.
    The inclusion of a 30-year averaging compliance option has
precedent in EPA rulemaking under the CAA. In the past, the EPA has
promulgated rules that adopt an emission limit based on a particular
technology (such as, in the present rulemaking, NGCC), but has
supported that action on grounds that sources have compliance
alternatives, even though higher priced. See ``Finding of Significant
Contribution and Rulemaking for Certain States in the Ozone Transport
Assessment Group Region for Purposes of Reducing Regional Transport of
Ozone: Final Rule'' 63 FR 57356, 57378 (Oct. 27, 1998) (in the rule
that became known as the ``NOX SIP Call,'' the EPA based
NOX emission limits that states were required to meet on the
assumption that states could adopt specified control measures that were
``highly cost-effective,'' but the EPA identified other control
measures that, even though not as cost-effective, the states could
adopt instead).
    (b) 30-year Period. We propose a 30-year period because (i) we
generally expect that ten years provides sufficient time either for
owners/operators who are interested in considering cost improvements
that occur as a result of the lessons learned from early adopters, or
provides early adopters sufficient time to address any startup
challenges; and (ii) as noted above, 30 years provides enough time for
sources to achieve the 1,000 lb CO2/MWh emission limit
following an elevated level of emissions over the first 10-year period.
    (c) Supercritical Efficiency Level. According to the Department of
Energy Cost and Performance Baseline for Fossil Energy Plants reports,
the use of supercritical steam is the most cost effective option for
new conventional coal-fired generation and results in the lowest
overall costs. In addition, the increased efficiency results in reduced
cooling water requirements and reduced environmental impacts associated
with coal mining, delivery, and handling. Therefore, considering the
benefits and minimal, if any, cost of using supercritical steam
conditions, as opposed to subcritical steam conditions, we have
concluded that an annual standard based on the best performing
conventional coal-fired generation is appropriate.
    There are a dozen bituminous-fired and 2 subbituminous-fired EGUs
that have demonstrated the proposed annual standard is achievable on a
long term basis. Furthermore, we have concluded that with coal drying
technology, which is being used on a number of power plants today, the
annual standard is achievable by a wide range of units

firing a variety of coal types, including lignites. There are multiple
vendors that offer processes to upgrade lignites to heating values that
are equal to or greater than those of subbituminous coals. The best
performing subbituminous-fired EGU has maintained a 12-month emissions
rate of 1,730 lb CO2/MWh. A new EGU using a similar design
would be able to burn upgraded lignite and be in compliance with the
proposed annual standard.
    We solicit comment on all aspects of the alternative compliance
option, including the 30-year averaging period we propose in this
action. Although we are not proposing that CCS, including the 30-year
averaging compliance option, does or does not qualify as the BSER
adequately demonstrated, we also solicit comment on that issue.

B. How did the EPA determine the other requirements for the proposed
standards?

1. Compliance Requirements
    The proposed compliance requirements, to the extent possible,
incorporate monitoring already being performed as part of existing part
60 and part 75 requirements.
    In addition, we intend to recognize the environmental benefit of
electricity generated by CHP facilities to account for the increased
end use efficiency resulting from avoided transmission and distribution
losses. Actual line losses vary from location to location, but we
intend to assume a benefit of 5 percent avoided transmission and
distribution losses when determining the electric output for CHP
facilities. This provision would be restricted to facilities where the
useful thermal output is at least 20 percent of the total output.
    We also propose to base compliance requirements on a 12-month
rolling average basis. The variability in GHG emissions rates is such
that establishing a shorter averaging period would necessitate
establishing a standard to account for the conditions that result in
the lowest efficiency and therefore the highest GHG emissions rate. A
12-month rolling average accounts for variable operating conditions,
allows consistent emissions rate averaging, allows for a more
protective standard and decreased compliance burden, and simplifies
compliance for state permitting authorities. Because the 12-month
rolling average can be calculated each month, this form of standard
makes it possible to assess compliance and take any needed corrective
action on a monthly basis. The EPA proposes that it is not necessary to
have a shorter averaging period for CO2 from these sources
because the effect of GHGs on climate change depends on global
atmospheric concentrations which are dependent on cumulative total
emissions over time, rather than hourly or daily emissions fluctuations
or local pollutant concentrations.
    Even so, we solicit comment on, in the alternative basing
compliance requirements on an annual (calendar year) average basis.

V. Requirements for Modifications, Transitional Sources,
Reconstructions

A. Requirements for Modifications

1. Overview
    Under CAA section 111, existing sources are treated as new sources
if they undertake ``modification[s],'' which are generally defined as
physical or operational changes that increase emissions. CAA section
111(a)(2) and (4). The EPA's regulations exempt certain types of
changes from the definition of modification. 40 CFR 60.14(e). Available
information does not provide an adequate basis for the EPA to develop
proposed standards of performance for modifications. Our base of
knowledge concerning NSPS modifications has depended largely on the
enforcement actions brought against power plants and on self-reporting
by power plants. Over the lengthy history of the NSPS program, those
have been too few in number to allow us to develop a sufficiently
robust base of knowledge to propose a standard of performance for NSPS
modifications for GHGs at this time.
    We note that the types of projects that these EGUs are most likely
to undertake that could increase GHG emissions are projects that put on
pollution controls required under other CAA provisions and that emit
CO2 as a byproduct, and those types of projects are
specifically exempted from the definition of ``modifications'' under 40
CFR 60.14(e)(5). In addition, based on past experience, we expect that
actions that do constitute modifications to be from different types of
sources and to take different forms. In light of this, the EPA does not
have sufficient information to develop standards of performance for
modifications, and therefore the EPA is not proposing any standards for
modifications. As a result, EGUs that undertake pollution control
projects or other physical or operational changes would continue to be
treated as existing sources.
2. Statutory and Regulatory Requirements
    Clean Air Act section 111(b)(1)(B) requires the EPA to promulgate
``standards of performance'' for ``new sources'' within source
categories. For certain pollutants, CAA section 111(d)(1) requires the
EPA to prescribe regulations for state plans covering ``existing
source[s]'' in a category regulated for that pollutant under section
111(b). Clean Air Act section 111(a)(2) defines a ``new source'' as
``any stationary source, the construction or modification of which is
commenced after the publication of regulations (or, if earlier,
proposed regulations) prescribing a standard of performance under this
section which will be applicable to such source.'' Clean Air Act
section 111(a)(6) defines an ``existing source'' as ``any stationary
source other than a new source.'' Clean Air Act section 111(a)(4)
defines ``modification'' as ``any physical change in, or change in the
method of operation of, a stationary source which increases the amount
of any air pollutant emitted by such source or which results in the
emission of any air pollutant not previously emitted.''
    The EPA's regulations provide that under CAA section 111(a)(4), for
purposes of determining whether an existing electric utility steam
generating unit undertakes a modification, a physical or operational
change is treated as increasing emissions only when it increases the
``maximum hourly emissions'' above the ``maximum hourly emissions
achievable'' at the unit. 40 CFR 60.14(h). In addition, the EPA's
regulations exempt certain physical or operational changes from the
definition of modification. 40 CFR 60.14(e)(5). The exemptions include
pollution control projects:

    (e) The following shall not, by themselves, be considered
modifications * * *:
* * * * *
    (5) The addition or use of any system or device whose primary
function is the reduction of air pollutants, except when an emission
control system is removed or is replaced by a system which the
Administrator determines to be less environmentally beneficial.

40 CFR 60.14(e)(5). Thus, the EPA's current regulations define a
modification as a physical or operational change that increases an
existing affected EGU's maximum achievable hourly rate of emissions,
but specifically exempt from that definition pollution control
projects, which are projects that entail the installation of pollution
control equipment or systems.
3. The EPA's Proposed Course of Action
    We expect EGUs to undertake changes in the foreseeable future that
would increase their maximum achievable hourly rate of CO2
emissions for

purposes of the NSPS. We expect that most of those actions would
constitute pollution control projects. In many cases, those projects
would involve the installation of add-on control equipment required to
meet CAA requirements for conventional air pollutants. We expect that
these increases in CO2 emissions would occur as a chemical
byproduct of the operation of the control equipment, and would be
small. In other cases, those projects will involve equipment changes to
meet the requirements of this rulemaking and that may have the effect
of increasing the sources' maximum hourly achievable emission rate,
even while decreasing actual emission rate. Because such actions would
be treated as pollution control projects under the EPA's current NSPS
regulations, they would be specifically exempted from the definition of
modification.
    Aside from pollution control projects, in the past, there have also
been, as noted, a limited number of instances, on an annual basis, in
which power plants have undertaken actions that should be treated as
NSPS modifications. The sources that took these actions vary widely,
one from another, depending on, among other things, size, fuel type,
and physical plant configuration. The diversity of sources undertaking
modifications has reflected the diversity among power plants as a
whole. Moreover, the types of modifications they have undertaken have
also varied widely.
    Because of the limited number of modifications, their disparate
nature, and the disparate type of sources, we do not at present have an
adequate base of information to propose standards of performance for
modifications. For example, we do not have adequate information as to
the types of physical or operational changes sources may undertake or
the amount of increase in CO2 emissions from those changes.
Nor do we have adequate information as to the types of control actions
sources could take to reduce emissions, including the types of controls
that may be available or the cost or effectiveness of those controls.
The most likely candidates for control actions would be efficiency
measures and we do not have adequate information as to the types of
sources and types of changes at issue that could provide the basis for
a proposal for efficiency measures. If there were a more robust set of
data on facilities of a particular type undertaking NSPS modifications
of a particular kind, the EPA may be able to develop a standard of
performance for that type. But, as noted, that is not the case here.
    As a result, in this action, the EPA is not proposing standards of
performance for NSPS modifications for GHGs. The EPA is soliciting
comment on the types of sources that may be expected to undertake
modifications, the types of modifications, the types of control
measures, and all other aspects of this issue. This solicitation of
comment is in the nature of an advance notice of proposed rulemaking.
If we receive sufficient additional information, we may issue a
proposal for modifications in the future. However, to reiterate, we are
not proposing any standards of performance for these modifications at
this time. Accordingly, the EPA does not expect to promulgate any
standards of performance for modifications when it takes final action
on this rulemaking.
    The definitional provisions of CAA section 111, quoted above, make
clear that a stationary source that undertakes construction or
modification is considered a ``new source'' only if there is a proposed
or final ``standard of performance under this section which will be
applicable to such source.'' CAA section 111(a)(2). Accordingly, if
there is no proposed or promulgated standard of performance applicable
to a particular source, then the source cannot be considered a ``new
source'' and therefore will not be subject to any standards of
performance we finalize for new sources.
    Further, under the definitional provisions, any source that is not
a ``new'' source is an ``existing source.'' CAA section 111(a)(6).
Therefore, affected EGUs that undertake NSPS modifications for GHGs
will continue to be treated as existing sources. Although modified
sources would not be subject to the 1,000 lb CO2/MWh
standard for new sources, the EPA anticipates that modified sources
would become subject to the requirements the EPA would promulgate at
the appropriate time, for existing sources under 111(d). It is
important to note that at the same time that the EPA promulgated the
pollution control provision in the EPA's regulations under CAA section
111, the EPA promulgated a similar provision in EPA's NSR regulations.
The DC Circuit, in New York v. EPA, 413 F.3d 3, 40 (DC Cir. 2005),
vacated the NSR pollution-control-project exemption. Because of the
similarities between the NSR and the section 111 pollution control
project regulatory provisions, the Court's vacatur of the NSR
regulatory provision may call into question the continued validity of
the section 111 regulatory provision. As a result, we are soliciting
comment on whether this exemption from the definition of
``modification'' for pollution control projects, under 40 CFR
60.14(e)(5), continues to be valid or not, and what course of action,
if any, would be appropriate for the EPA to take.

B. Requirements for Transitional Sources

1. Overview
    In this action, the EPA is not proposing a standard of performance
for transitional sources. We define these sources as coal-fired power
plants that, by the date of this proposal, have received approval for
their PSD preconstruction permits that meet CAA PSD requirements (or
that have approved PSD permits that expired and are in the process of
being extended, if those sources are participating in a Department of
Energy CCS funding program), and that commence construction within a
year of the date of this proposal. For convenience, we refer to the new
sources for which we are proposing a standard of performance as non-
transitional sources.
    Transitional sources are a distinct set of sources with unique
circumstances.\65\ We have identified 15 proposed sources that may
qualify as transitional sources based on the above criteria. These
proposed sources differ considerably one from another. They range in
size from as small as 80 megawatts (MW) to as large as 1320 MWs; they
will burn different fuels: Conventional coal, waste coal, or petcoke;
and they will use different technologies: Circulating fluidized bed
(CFB), integrated gasification combined cycle (IGCC), supercritical
pulverized coal, or sub-critical pulverized coal. Recent industry
practice raises the probability that no more than a few of these 15
proposed sources will in fact be constructed.
---------------------------------------------------------------------------

    \65\ Nothing in this discussion of the unique circumstances of
transitional sources facing new GHG requirements should be
interpreted as providing a defense to any violation of the CAA by
sources that, for example, fail to obtain PSD permits or comply with
NSPS before construction.
---------------------------------------------------------------------------

    We recognize that by the date of this proposal, some of the 15
proposed sources may have incurred substantial sunk costs and may have
progressed in their preconstruction planning to the point where they
are poised to commence construction in the very near future. Under
these circumstances, the 1,000 lb CO2/MWh standard of
performance that applies to non-transitional sources would not be
appropriate for these proposed sources. As noted, that standard is
based on natural gas combined cycle (NGCC) as the ``best system of
emission reduction * * * adequately demonstrated'' because NGCC is the
least expensive

and lowest emitting design for a fossil-fuel fired power plant, and
because a proposed new source may choose to construct as an NGCC
facility. However, proposed coal-fired power plants that have already
received a PSD permit and that have incurred substantial sunk costs and
developed plans to commence construction in the very near future are
not in the same position as non-transitional sources. Applying the
1,000 lb CO2/MWh standard would likely result in the loss of
their sunk costs and would likely cause multi-year delays, or even
abandonment, of their plans to construct. (Nor is the 1,000 lb
CO2/MWh standard appropriate for CCS sources, as discussed
below.) This is not within the scope of BSER.
    However, we do not have sufficient information concerning the 15
proposed sources to identify which ones may be in this position.
Specifically, we do not have information as to the extent of their sunk
costs, their preconstruction planning, or their overall business plans.
    Accordingly, we propose to include a requirement that proposed
sources must commence construction within 12 months of today's
rulemaking proposal as a mechanism for revealing which of these sources
qualifies as a transitional source. We believe that any of these 15
proposed sources that commences construction within 12 months of
today's rulemaking proposal should be considered to have incurred
substantial sunk costs and will have engaged in sufficient
preconstruction planning so that the 1,000 lb CO2/MWh
standard should not apply. Any of these 15 proposed sources that do not
commence construction within this period should not be considered to be
similarly situated. For any of these latter sources that ultimately are
constructed, the 1,000 lb CO2/MWh standard would apply.
    Having identified which proposed sources could qualify as
transitional sources, we further believe that for several reasons, it
is not appropriate to propose any standard of performance for those
sources. As noted above, we necessarily lack information specifically
as to which of the 15 proposed sources will actually qualify as
transitional sources, and, given the range of size, fuel types, and
technologies among these proposed sources, that renders it problematic
to propose standards of performance. In addition, for the proposed
sources that are planning to install CCS, we lack important information
concerning the extent to which they are planning to capture
CO2 or their costs to do so. We also lack information as to
whether they have made contractual arrangements for the sale of the
CO2 or carbon credits, which may be critical to their
financing arrangements. In addition, attempting to propose a standard
of performance would give rise to serious practical problems that would
undermine the usefulness of the requirement that sources commence
construction within 12 months of today's rulemaking proposal as a
mechanism for revealing which of these sources qualifies as a
transitional source. These include creating uncertainty as to the level
of the final standard of performance to which the proposed sources
would be subject, which may have the effect of forcing them to delay
commencing construction until after we finalize the standards, at which
time they would have missed their 12-month window to commence
construction and as a result, would fail to qualify as transitional
sources. We note that CAA section 111 does not require that we propose
or promulgate standards of performance for all sources in a source
category, and on numerous occasions in past rulemakings the EPA has
taken the similar approach of not proposing standards of performance
for all sources in the source category.
    Even without an applicable standard of performance, transitional
sources will remain constrained in their emissions of CO2 by
the requirements of their PSD permits. In addition, although
transitional sources would not be subject to the 1,000 lb
CO2/MWh standard for new sources, the EPA anticipates that
transitional sources would become subject to the requirements the EPA
would promulgate at the appropriate time, for existing sources under
111(d).
2. Identification of Transitional Sources
    For purposes of this action, we define a transitional source as a
coal-fired power plant that has received approval for its complete PSD
preconstruction permit by the date of this proposal (or that has an
approved PSD permit that expired and for which the source is seeking an
extension, if the source has been issued or awarded a DOE CCS loan
guarantee or grant) for the project, and that commences construction
within 12 months of the date of this proposal. For this purpose, the
date of this proposal is the date of publication in the Federal
Register of this notice of proposed rulemaking. The 12-month period
would not be extended for any reason, including because of any
challenges to the permit that may be brought in any Federal or State
court or agency.
    The EPA is aware of approximately 15 sources that could potentially
qualify as transitional sources because, except as otherwise noted,
they have obtained PSD permits but have not yet commenced construction.
These proposed sources vary considerably one from another. They range
in size from as small as 80 megawatts (MW) to as large as 1320 MWs;
they will burn different fuels: conventional coal, waste coal, or
petcoke; and they will use different technologies: Circulating
fluidized bed (CFB), integrated gasification combined cycle (IGCC),
supercritical pulverized coal, or sub-critical pulverized coal.
    Based on recent industry practice, it appears that no more than a
few of these sources will be constructed.\66\
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    \66\ Since 2008, some 15 proposed coal-fired power plants with
approved PSD permits have cancelled plans to construct, and since
2009, only one coal-fired power plant has constructed (Southern
Company's Kemper County Project, which installed CCS and received
DOE funding).
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    Of these 15 identified potential transitional sources, six have
indicated that they plan to install CCS (and in most if not all cases
have been issued or awarded a DOE CCS loan guarantee or grant). These
six projects are: The Texas Clean Energy Project in Texas, the
Trailblazer project in Texas, the Taylorville project in Illinois, the
Good Spring facility in Pennsylvania, the Power County Advanced Energy
Center in Idaho and the Cash Creek Generation Plant in Kentucky. The
remaining nine plants, which are without CCS, are: Limestone 3, White
Stallion and Coletto Creek in Texas, Holcomb 2 in Kansas, James De
Young and Wolverine in Michigan, Washington County in Georgia, Bonanza
in Utah, and Two Elk in Wyoming.\67\
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    \67\ We note that there may be some proposed natural gas-fired
EGUs that are similarly situated to the coal-fired transitional
sources because the natural-gas fired sources have received PSD
permits but have not commenced construction by the date of this
proposal. Because they are new gas-fired EGUs, we expect that they
will be able to meet the requirements of the proposed new source
standard of performance.
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    We request that during the public comment period on this
rulemaking, each of these EGUs confirm to us that we have correctly
identified the status of their PSD permits and, in the case of any
sources that had approved permits that are in the process of being
extended, and that plan to install CCS, that they have been issued or
awarded a DOE CCS loan guarantee or grant. We also request that the
sources indicate whether their permits are undergoing challenges before
Federal or state authorities or courts. We further request that any
other EGU not listed above that has a complete PSD permit and that
otherwise meets the parameters for transitional sources described in
this

section identify itself to us (including indicating whether its PSD
permit is undergoing challenge before Federal or state authorities or
courts). In our final rulemaking, we intend to include a confirmed list
of sources that would qualify as transitional sources if they commence
construction within the 12-month period following publication of this
proposal in the Federal Register.
    As commenters have noted, among these 15 proposed sources, some may
have incurred substantial sunk costs associated with processing their
permits as well as taking additional preconstruction steps (e.g.,
purchasing land) so that they may be able to commence construction
within the near term. As examples of these types of steps, several
sources, such as the Texas Clean Energy Project, have signed contracts
for the sale of electricity, the sale or disposal of CO2 or
other enabling products, or supporting systems.\68\ Although the
Taylorville project's PSD permit has expired, the source is seeking to
extend it, and the source has entered into CCS funding arrangements
with DOE. These actions indicate that this proposed source, too, has
sunk costs and may be in a position to commence construction within the
near term, and therefore is similarly situated to the other 14 proposed
plants (assuming that it is able to secure an extension of its PSD
permit).
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    \68\ http://www.texascleanenergyproject.com/news-room/.
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    Even so, we face major gaps in our information about these sources
that would inform us at this point as to which of these sources have
incurred costs and material commitments to the extent that a 1,000 lb
CO2/MWh standard would be so costly and disruptive as not to
be BSER. For example, we do not have specific information as to those
sources' specific sunk costs, specific project development actions to
date, or overall business plan. Accordingly, we are not able to
determine which ones are in a position to commence construction in the
near term. In addition, for the sources whose PSD permit indicates that
they will install CCS, we do not have specific information as to the
amount of CO2 that they plan to capture; their costs to
operate CCS; or their possible revenue streams associated with CCS,
such as from the sale or use of CO2 in enhanced oil recovery
or the possible sale of carbon credits in voluntary or other carbon
markets.
    Instead, the 12-month period, serving as a surrogate for the
missing information, provides a mechanism for revealing the
qualification of proposed sources for treatment as transitional
sources. In light of the complex of requirements, which range from
siting to financing, needed to commence construction of a project as
large and expensive as a power plant, any proposed source that does
commence construction within the relatively short period of 12 months
of the date of proposal can be said to have incurred substantial sunk
costs and to have taken preconstruction steps by the time of this
proposal. It is these sources that would be most disadvantaged by being
subjected to the standards of performance proposed in today's
rulemaking. The one-year period serves as a type of surrogate for more
precise information as to the amount of sunk costs sources must incur
or steps leading to commencement of construction that sources must
undertake in order to qualify as transitional sources, as well as which
sources have incurred those costs or taken those steps, which
information is not available at this time. In addition, 12 months is
long enough to give these sources a reasonable period to commence
construction in accordance with the terms of their permit. Any proposed
source that does not commence construction within 12 months cannot be
said to be similarly situated.
3. The EPA's Treatment of Transitional Sources
    In this action, the EPA is treating transitional sources as a
distinct set of sources. We make clear that the proposed standard of
performance for non-transitional sources of 1,000 lb CO2/MWh
is not applicable to transitional sources because that standard is not
based on the BSER adequately demonstrated for transitional sources. In
addition, in light of the unique circumstances of transitional sources,
including a lack of information and other considerations, we do not
propose any other standard of performance for transitional sources.\69\
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    \69\ EPA intends that its treatment of transitional and non-
transitional sources be severable from each other and considers that
severability is logical because of the record-based differences
between the two types of sources and because there is no
interdependency in EPA's treatment of the two types of sources. This
statement concerning severability for these components in this
rulemaking should not be construed to have implications for whether
other components in this rulemaking are severable.
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    Although a transitional source would not be subject to new source
CO2 emissions controls under CAA section 111(b), it would be
subject to CO2 emissions limits due to any CO2
limits in the source's PSD permit. If the source received the permit
prior to January 2, 2011, the permit will not include CO2
limits, but in that case, as a practical matter, CO2
emissions would be limited by whatever design or operating constraints
are imposed on the source under the PSD permit.
    We also note that the fact that transitional sources would not be
subject to the proposed standard of performance, would not relieve them
from any requirements applicable to existing sources under section
111(d) and related state plans.
4. Legal Basis for the EPA's Treatment of Transitional Sources
    In this section, we describe the legal basis for our treatment of
transitional sources. First, we identify the relevant CAA section 111
provisions. Second, we explain why the standard of performance we
propose for non-transitional sources does not apply to transitional
sources, which is because that standard does not reflect the best
system of emission reduction adequately demonstrated for transitional
sources. Third, we explain why we are not proposing any other standard
of performance for transitional sources, which is due to lack of
information and other considerations. In the course of these
explanations, we discuss the relevant CAA section 111 requirements and
our interpretations of them.
a. Key CAA Section 111 Provisions
    As the first step in the process of promulgating regulations under
section 111, under CAA section 111(b)(1)(A), the Administrator must
``publish * * * a list of categories of stationary sources.'' Then, the
Administrator must ``[propose] * * * Federal standards of performance
for new sources within [the source] category,'' and then ``promulgate *
* * such standards with such modifications as he deems appropriate.''
Section 111(b)(1)(B). Section 111(b)(2) goes on to provide that ``[t]he
Administrator may distinguish among classes, types, and sizes within
categories of new sources for the purpose of establishing such
standards.''
    Section 111 includes several key definitions. The provision defines
a ``new source'' as ``any stationary source, the construction or
modification of which is commenced after the publication of regulations
(or, if earlier, proposed regulations) prescribing a standard of
performance under this section which will be applicable to such
source.'' CAA section 111(a)(2).\70\ A

``standard of performance'' is defined as a--
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    \70\ The CAA does not include a definition of the term
``commenced'' for these purposes, but the EPA framework regulations
promulgated under section 111 define this term as follows:
    Commenced means, with respect to the definition of new source in
section 111(a)(2) of the Act, that an owner or operator has
undertaken a continuous program of construction or modification or
that an owner or operator has entered into a contractual obligation
to undertake and complete, within a reasonable time, a continuous
program of construction or modification.
    40 CFR 60.2.

standard for emissions of air pollutants which reflects the degree
of emission limitation achievable through the application of the
best system of emission reduction which (taking into account the
cost of achieving such reduction and any nonair quality health and
environmental impact and energy requirements) the Administrator
---------------------------------------------------------------------------
determines has been adequately demonstrated.

CAA section 111(a)(2).

    Once the Administrator promulgates standards for new sources under
CAA section 111(b), the States, consistent with EPA regulatory
requirements, must take action under CAA section 111(d) to establish
requirements for ``any existing source for any air pollutant (i) [that
falls into specified categories] but (ii) to which a standard of
performance under this section would apply if such existing source were
a new source. * * *'' Section 111(d)(1). An ``existing source'' is
defined as ``any stationary source other than a new source.'' Section
111(a)(6).
b. Reasons for Not Applying the 1,000 lb CO2/MWh Standard of
Performance to Transitional Sources
(i) Introduction
    In this action, the EPA is treating transitional sources as a
distinct set of sources, although the EPA is not establishing a
specific subcategory for these sources in the regulatory
provisions.\71\ Under CAA section 111, the EPA may not apply a standard
of performance to sources unless it reflects the ``best system of
emission reduction'' (BSER) adequately demonstrated.
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    \71\ Section 111(b)(2) authorizes the EPA to ``distinguish among
classes, types, and sizes within categories of new sources for the
purpose of establishing such standards.'' In other words, once the
EPA selects the set of sources for which to propose regulations, the
EPA may establish subcategories among those new sources and
promulgate different standards for those subcategories.
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    As noted, the EPA proposes that non-transitional source fossil-
fired power plants that commence construction after the date of
proposal are subject to the standard of 1,000 lb CO2/MWh,
and the EPA proposes to base this standard on the EPA's identification
of natural gas combined cycle (NGCC) as the BSER adequately
demonstrated. The EPA justifies this proposal because owners or
operators contemplating construction of non-transitional power plants
to serve baseload and intermediate load demand have choices: They can
choose the type of facility and therefore may choose to construct a
NGCC plant. As a result, for these sources, NGCC constitutes the BSER,
and the 1,000 lb CO2/MWh emission limit reflects that BSER
and therefore is the appropriate standard of performance under section
111. Moreover, for those that choose to construct a coal-fired unit,
they may choose to construct the plant in a place and a manner that
allows installation of CCS--and thereby meet the 1,000 lb
CO2/MWh standard--either at the time of construction or, in
accordance with the 30-year averaging proposal, some years later.
(ii) Transitional Sources and NGCC
    In contrast, the circumstances surrounding transitional sources are
quite different. Transitional sources are a very small group of sources
with a distinct profile of costs, preconstruction planning, overall