business plans, technical and design concerns, and equitable concerns.
Because they are such large facilities, their sunk costs and planning
horizons are substantial.
    Transitional sources have already incurred substantial costs in
permitting and taking other steps preparatory to commencing
construction as coal-fired power plants within 12 months of the date of
this proposal, which may include purchasing land for the new facility.
Considering these sunk costs, converting their plant design to NGCC
would be significantly more expensive than for proposed non-
transitional sources that have not reached the stage of development
that transitional sources have reached. The EPA is required to consider
costs in determining the BSER adequately demonstrated, and under these
circumstances, the costs factor points away from treating NGCC as BSER
for transitional sources.
    In addition, because transitional sources have obtained a PSD
permit and have developed their plans to the point where they are on
the verge of commencing construction, the converting of their plant
design to NGCC would be significantly more disruptive to their plans
than for proposed non-transitional sources. It may require them to
start over the process of developing the plant, and thereby render
futile the planning and steps they have taken to date. These losses
would, at a minimum, lead to delays in their commencing construction
that realistically would be measured in years, and in fact may lead
them to abandon the project.
    Although the potentially significant planning impacts at issue here
are not explicitly identified as part of the definition of the
``standard of performance,'' they should nevertheless be considered in
determining the BSER. This is because CAA section 111(a)(2), in its
definition of ``new source,'' clearly contemplates that sources are
expected to be able to commence construction after the EPA proposes,
and before the EPA promulgates, a standard of performance applicable to
them. There is nothing in CAA section 111 that suggests that Congress
expected that the EPA may determine the BSER in a way that would
significantly disrupt the plans of the regulated sources that are
implicated here. Therefore, for this reason, too, the 1,000 lb
CO2/MWh standard cannot be considered to reflect the BSER
for transitional sources, and therefore cannot be the appropriate
standard of performance.
    Nor can transitional sources reasonably be expected to meet the
1,000 lb CO2/MWh standard through the installation of CCS,
for the reasons discussed below.
    Note that the EPA takes the position that in this particular
action, both of those factors--sunk costs and extent of planning to
commence construction--must be considered in determining whether the
1,000 lb CO2/MWh standard reflects the BSER adequately
demonstrated. That is, both are necessary conditions, and neither one,
by itself, is a sufficient condition. We believe that these reasons
concerning costs and planning suffice to justify our position that the
1,000 lb CO2/MWh standard is not appropriate for
transitional sources.
(iii) Coal-Fired Transitional Sources Not Designed for CCS
    As noted, while it is generally the case that proposed new sources
could choose to build coal-fired power plants with CCS and thereby meet
the 1,000 lb CO2/MWh standard, that is not the case for
those transitional sources that are not designed for CCS. As a
practical matter, it would be challenging for such a source to proceed
with construction without substantial re-design of the project in order
to install CCS and thereby be in compliance with the 1,000 lb
CO2/MwH standard. There are several reasons for this. First,
captured CO2 must be sequestered or used. If this was not
considered as part of the original site selection, the source will
likely be significantly challenged in its efforts to adopt CCS. Second,
if CCS was not considered in the original project

design, space considerations may make it difficult to now accommodate
it in the facility's design. Third, the requirement to use CCS could
necessitate a change in the very power generation technology that a
source may choose to use. For instance, instead of building a
pulverized coal boiler, IGCC technology may be more appropriate. This
is not to say that CCS could not be added to a project at this stage.
Projects like the AEP Mountaineer project have shown that CCS can be
successfully retrofitted into an existing plant. However, unlike in an
existing facility where retrofit decisions must take into account
previously made design decisions, in a facility in the pre-design
phase, there is more opportunity for cost savings from re-designing the
project, rather than having to adapt through retrofit.
    It bears emphasis that the requirements created by the new source
standard in today's action are fundamentally different from post-
combustion controls required to meet new source standards for
conventional pollutants in the sense that those controls could be much
more easily re-designed into an already planned plant without changing
the plant's basic underlying characteristics (such as type of unit or
even location). In contrast, CCS is more fundamental to both the design
and siting of a unit, and therefore would likely involve fundamental
changes to the underlying project. This is much more difficult in a
project that has progressed through the permitting stage and is very
close to commencing construction than it would be in other types of
projects.
(iv) Coal-Fired Transitional Sources Designed for CCS
    Although some of the proposed sources that may qualify as
transitional sources are planning for CCS, that does not provide a
basis for concluding that the 1,000 lb CO2/MWh standard is
appropriate for them. As noted, the EPA is not, in this rulemaking,
proposing that CCS is the BSER adequately demonstrated for coal-fired
EGUs.
    Moreover, these proposed sources have established their location
and developed their business plans without the expectation that the
proposal in this rulemaking for CCS would apply to them. For example,
their plans may assume installing CCS in a manner that results in
emissions at levels higher than 1,000 lb CO2/MWh, or it may
assume the sale of emission reduction credits based on an allowable
emission rate above 1,000 lb CO2/MWh. Imposition of an
unexpected emission rate requirement at such a late date could upset
carefully crafted financial plans, causing delay or even cancellation
of the project.
    Importantly, we do not have information as to key components of
their proposed project and business plan, including, among other
things, the amount of capture from the planned CCS system or possible
revenue streams associated with CCS. Any proposal for what is BSER
would depend on those costs and other information. Accordingly, we are
not able to propose determinations that are essential to proposing the
BSER for these proposed sources. As a result, we are not able to
propose a standard of performance for these proposed sources.
(v) Equitable Considerations
    For all transitional sources, the costs and delays discussed above
give rise to equitable considerations that also support our treatment
of these proposed sources. As noted, owners or operators of
transitional sources have incurred significant expenses and undertaken
a long planning period that has led them to being able to commence
construction in the very near future, and, having invested so
substantially in their current plans, should as an equitable matter be
allowed to proceed without concern about requirements other than those
in their PSD permits. To reiterate, they are in a posture that is
fundamentally different from non-transitional sources.
c. Reasons for Not Applying Other Standard of Performance
    Although, for the reasons described above, the 1,000 lb
CO2/MWh standard that the EPA proposes for non-transitional
sources does not reflect BSER for transitional sources, the EPA is not
proposing any other standard of performance for transitional sources.
It is reasonable to read section 111 not to require the EPA to propose
a standard of performance when faced with the specific circumstances
presented by transitional sources in the context of this rulemaking.
These circumstances include: (1) The EPA's lack of information with
regard to these sources and the appropriate BSER for these sources; (2)
the unique challenges with regard to adaptation of proposed projects to
the requirements of this standard; (3) the small number of these
sources and the possibility that promulgating a standard of performance
would not have a beneficial environmental impact; and (4) 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).
(i) CAA Requirements for Promulgating Standards of Performance for
Sources in a Source Category
    The EPA interprets the CAA provisions described above to authorize
the EPA not to promulgate a standard of performance for transitional
sources. Under section 111(b)(1)(B), once the EPA lists a category of
sources, the EPA is required to propose and promulgate standards of
performance for new sources in that category. The EPA is not, however,
required to promulgate standards of performance that cover all new
sources . This is clear from the directive in section 111(b)(1)(B),
which requires that the EPA propose standards of performance ``for new
sources'' within the category, but does not require that the EPA
propose such standards for all new sources or for any new source. The
EPA may fulfill that directive by proposing standards that cover some,
but not all, sources that newly commence construction or modification.
    Similarly, the term ``new source'' in section 111(a)(2) is defined
to incorporate the limitation that the EPA must propose or promulgate a
standard applicable to the source for the source to be considered
``new.'' That is, section 111(a)(2) defines a ``new source'' as any
source for which construction or modification commences after the EPA
proposes ``a standard of performance * * * which will be applicable to
such source.'' By its terms, this provision contemplates that the EPA
may not propose a standard of performance applicable to certain
sources, and that if the EPA does not, those sources would not be
considered to be ``new source[s]'' and therefore not subject to any new
source standard of performance.
    Thus, these provisions do not, by their terms, mandate that the EPA
propose standards for each and every source in the source category.
Under Chevron step 1, these provisions do not unambiguously require
that the EPA propose standards of performance for all sources in the
source category. We read these provisions as according the EPA some
measure of discretion for the EPA to determine not to set standards for
a particular portion of the source category, where appropriate, bounded
by the principle of rationality. If these provisions are read to be
ambiguous as to whether the EPA has discretion to propose and
promulgate standards of performance for all sources in the source
category, we believe it reasonable to read the provisions to provide
such discretion in appropriate circumstances and that such reading is
entitled to

deference under Chevron step 2. In addition, interpreting these
provisions to give the EPA the discretion not to propose and promulgate
standards covering all sources in a category under appropriate
circumstances--such as those present here--is consistent with the
caselaw that authorizes agencies to establish a regulatory framework in
an incremental fashion, that is, a step at a time.\72\
---------------------------------------------------------------------------

    \72\ As the U.S. Supreme Court recently stated in Massachusetts
v. EPA, 549 U.S. 497, 524 (2007): ``Agencies, like legislatures, do
not generally resolve massive problems in one fell regulatory
swoop;'' and instead they may permissibly implement such regulatory
programs over time, ``refining their preferred approach as
circumstances change and as they develop a more nuanced
understanding of how best to proceed.'' See Grand Canyon Air Tour
Coalition v. F.A.A., 154 F.3d 455 (DC Cir. 1998), City of Las Vegas
v. Lujan, 891 F.2d 927, 935 (DC Cir. 1989), National Association of
Broadcasters v. FCC, 740 F.2d 1190, 1209-14 (DC Cir. 1984).
---------------------------------------------------------------------------

(ii) Precedents in Prior NSPS Rulemakings
    In applying section 111 over the past several decades, there have
been a number of rulemakings in which the EPA has promulgated new
source performance standards that do not cover all sources within the
relevant source category that newly commence construction or
modification. Some examples include the following: (i) In an early
NSPS, involving lime kilns, the EPA promulgated an NSPS for certain
types of kilns, but not for all types of sources that remained within
the relevant source category. The DC Circuit, in its opinion reviewing
the rule, noted this state of affairs, without expressing concerns.
National Lime Ass'n v. EPA, 627 F.2d 416, 426 & n. 28 (DC Cir. 1980)
(noting that ``of the various types of kilns that may be used in the
calcinations of limestone, only rotary kilns are regulated by the
standards,'' and not ``the vertical kiln; the rotary hearth kiln; and
the fluidized bed kiln''). (ii) In the EPA's initial promulgation of
NSPS regulations for petroleum refineries, the EPA did not promulgate
standards of performance for certain units, including fluid coking
units, delayed coking units, and process heaters, instead promulgating
standards of performance for those units subsequently. See 40 CFR
60.100a(a); ``Standards of Performance for Petroleum Refineries:
Proposed Rules,'' 72 FR 27178 (May 14, 2007). (iii) Similarly, in the
EPA's recent revision of the NSPS regulations for coal preparation and
processing plants, the EPA ``expand[ed] applicability of the existing
NSPS by revising the definitions of thermal dryers, pneumatic coal-
cleaning equipment, and coal. It also establishe[d] work practice
standards for open storage piles. The final rule amend[ed] the
definition of thermal dryer for units constructed, reconstructed, or
modified after May 27, 2009, to include both direct and indirect dryers
drying all coal ranks (i.e., bituminous, subbituminous, lignite, and
anthracite coals) and coal refuse.'' ``Standards of Performance for
Coal Preparation and Processing Plants,'' 74 FR 51950, 51952 (Oct. 8,
2009). (iv) In subpart KKKK of the NSPS regulations, the EPA
promulgated regulations for the source category of stationary
combustion turbines. The EPA did not promulgate regulations for
turbines with smaller than 10 MMBtu/hr heat input, emergency units, or
combustion turbine test cells. 40 CFR 60.4305(a), 60.4310(a), (d). (v)
For other source categories, the EPA also declined to propose and
promulgate standards of performance for the smaller sources. For
example, for the source category of metal furniture coating operations,
the EPA did not apply standards of performance to metal furniture
surface coating operations that use less than 3.842 liters of coating
(as applied) per year. 40 CFR 60.310(b). (vi) In proposing standards of
performance for natural gas processing plants, the EPA proposed
standards for only two of the three emission points in the plants
(``storage emission sources'' and ``equipment leaks'') and declined to
propose standards for the third emission point (``process emission
sources'') on grounds that ``[b]est demonstrated control technology has
not been identified for [the latter] sources.'' ``Standards of
Performance for New Stationary Sources; Onshore Natural Gas Processing
Plants in the Natural Gas Production Industry, Equipment Leaks of
VOC,'' 49 FR 2636, 2637 (January 20, 1984).
(iii) Lack of Basis for Specifying Information
    A major reason why the EPA is not proposing a standard of
performance for transitional sources is that it is relying, in part, on
the one-year commence-construction limit to qualify a source as
transitional: The EPA does not have sufficient information about the
proposed sources' sunk costs and preconstruction steps to be able to
identify which of these proposed sources may qualify as transitional
sources. In addition, even if the EPA could determine that a particular
proposed source would in fact become a transitional source, the EPA
lacks information that, under these circumstances, may be important for
determining BSER. For example, the EPA lacks information as to the
amount of the proposed source's sunk costs, which may be relevant in
determining BSER for these proposed sources. In addition, for proposed
CCS sources, as noted above, the EPA does not have information as to
key components of their proposed project and business plan, including,
among other things, the amount of capture from the planned CCS system
or possible revenue streams associated with CCS.
    Moreover, because transitional sources are defined by reference to
the fact that they will commence construction within 12 months of the
date of this proposal, it would be futile for the EPA to attempt to
develop that information and then issue a proposal. By the time the EPA
could do this, which would likely take at least a year, this set of
sources will have become a null set: They either will have commenced
construction, such that they would no longer be deemed ``new sources''
for purposes of CAA section 111, or they will not have commenced
construction, such that they would be subject to the new source
standard for non-transitional sources we are proposing today.\73\
---------------------------------------------------------------------------

    \73\ Note that because the basic rationale for EPA's treatment
of transitional sources is that they have already incurred
substantial sunk costs and have positioned themselves to be close to
commencing construction, and the one-year period for commencing
construction is a surrogate for that, this treatment of transitional
sources cannot logically be stretched to cover sources that do not
commence within a substantially longer period. There is no reason to
believe those latter sources would have, by the time of the proposal
for the rest of the source category, already incurred significant
costs and moved close to commencing construction.
---------------------------------------------------------------------------

(iv) Practical Problems
    In addition, the EPA's lack of information and other considerations
give rise to several serious practical problems that would arise were
the EPA to propose a standard of performance for transitional sources.
Importantly, were the EPA to propose a standard of performance, all
transitional sources would face substantial uncertainty as to what
final standard the EPA would promulgate. This uncertainty would arise
for several reasons. As noted, the EPA lacks information concerning
transitional sources. In addition, transitional sources differ one from
another in terms of design and in other respects, which would render
the EPA's task more complex. As a result, there is risk that the EPA
might finalize standards of performance different from what the EPA
proposed. The final standards of performance may be more difficult for
a given transitional source to meet.

    Other forms of uncertainty may arise as well. For example, a
possible standard of performance that the EPA would consider would be
based on identifying the BSER for transitional sources as the controls
to which they would be subject under the terms of their PSD permits,
with no further controls under section 111.\74\ With this approach, the
EPA would need to determine the emission rate for each source that
would reflect that source's level of CO2 emissions in accord
with the terms of its PSD permit. This emission rate would constitute
the ``no-further-control'' standard of performance. Note that under
such an approach, each source would receive an emission limit unique to
that source. However, some of the transitional sources may have a PSD
permit that does not regulate CO2 because GHGs were not
subject to PSD until the January 2, 2011 effective date of the first
regulatory action controlling CO2 emissions under the CAA.
Particularly for those sources, this approach could create uncertainty
as to what the EPA would promulgate as the emission rate in the final
standard of performance. This is because since these sources' permits
do not specify a CO2 limit, the EPA would have to develop
limits based on the design of the unit (including the project's type of
technology and fuels).
---------------------------------------------------------------------------

    \74\ This type of standard of performance could take one of
several different forms, such as a standard that would not limit the
source's CO2 emissions, or a standard that the
transitional source itself would identify as equaling the emission
limit it would achieve through compliance with the applicable terms
of its permit.
---------------------------------------------------------------------------

    The uncertainties that the sources could experience as to what the
final standards of performance would entail could well deter those
sources from commencing construction until the EPA promulgated the
final standard of performance. Such delay 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, and thus
defeat the policy underlying the EPA's approach to transitional
sources, which, for the reasons explained above, is to exclude from
coverage by this new source standard only those sources that commence
construction within 12 months of proposal. If sources are deterred from
commencing construction until after the final rule, they will have lost
the benefit of the 12-month window. As another practical problem, we
also note concern with attempting to promulgate standards of
performance for transitional sources at a time when it may reasonably
be expected that some of the 15 sources with PSD permits may well not
commence construction within 12 months (or may never do so). As a
result, the effort to develop a standard of performance for those
sources would have been unnecessary.
(v) Small Number of Transitional Sources, Lack of Environmental Benefit
    As part of our reasoning for not proposing a standard of
performance for transitional sources, we also take into consideration
the fact that we expect the number of transitional sources to be small,
no more than a few of the 15 potential sources listed above. Further,
if we were to propose a ``no further control'' standard of performance,
as described above, that approach would provide little, if any,
environmental benefit because that standard would not likely provide
further control beyond the limits of the sources' PSD permits. In fact,
treating transitional sources as existing sources may achieve more
reductions than a no-further-control NSPS standard for those sources by
including them under the flexible existing source standard that the EPA
expects to promulgate.
(vi) Other Considerations
    The EPA's approach of not proposing a standard of performance for
transitional sources does not leave these sources uncontrolled. Rather,
they would remain subject to whatever CO2 emission limits
are included in, or result from compliance with, their PSD permits.
And, although transitional sources would not be subject to the 1,000 lb
CO2/MWh 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).
    In notable contrast, in the previous rulemakings cited above in
which the EPA did not propose coverage of all sources within the
relevant source category, because of the pollutants at issue in these
actions, the decision not to propose coverage of all sources within the
relevant source category operated without the assurance afforded by
section 111(d) that uncovered sources would necessarily be picked up as
existing sources subject to existing source guidelines. Where, as here,
that assurance mechanism applies, the recognition and application of
the Agency's discretion to not propose coverage of all sources in the
source category is all the more appropriate.
    We recognize that this approach of not proposing a standard of
performance for transitional sources could raise the question of
consistency with the requirement implicit in the definition of ``new
source'' under CAA section 111(a)(2) that a source be subject to a
standard of performance when it commences construction after the date
of proposal for that standard. We believe the approach is consistent
with, and does not circumvent, that requirement. As noted, CAA section
111 does not require that all sources that newly commence construction
be treated as new sources, and in past section 111 rulemakings, the EPA
has not applied the standards of performance that it proposes and
promulgates to all sources that newly commence construction in a source
category. In addition to the reasons for not promulgating a standard
for transitional sources provided above, where, as here, the pollutants
covered by the proposed new source standard give rise to an obligation
to develop section 111(d) guidelines for existing sources with the
source category, ultimate coverage of the sources in question is
inevitable, eliminating any prospect of a regulatory gap of any
material concern.

C. Requirements for Reconstructions

1. Overview
    The EPA's framework regulations under CAA section 111 provide that
reconstructed sources --which, in general, are existing sources that
conduct extensive replacement of components--are to be treated as new
sources and, therefore, subject to new source standards of performance.
In today's rulemaking, we do not propose any standard of performance
for reconstructed sources, and we take comment how to approach
reconstructions. We note that if we do not establish a new standard of
performance for reconstructions, as a practical matter, that would mean
that reconstructed sources would be treated as existing sources.
2. Background
    a. The EPA Regulations. The EPA's framework regulations,
interpreting the definition of ``new source'' in CAA section
111(a)(2),\75\ provide that an existing source, ``upon
reconstruction,'' becomes subject to the standard of performance for
new sources. 40 CFR 60.15(a). The regulations define ``reconstruction''
as--

    \75\ CAA section 111 does not explicitly include provisions for
reconstructed sources.

[T]he replacement of components of an existing facility to such an
---------------------------------------------------------------------------
extent that:

    (1) The fixed capital cost of the new components exceeds 50
percent of the fixed capital cost that would be required to
construct a comparable entirely new facility, and
    (2) It is technologically and economically feasible to meet the
applicable standards set forth in this part.

40 CFR 60.15(b). Thus, a reconstruction occurs if the existing source
replaces components to such an extent that the capital costs of the new
components exceed 50 percent of the capital costs of an entirely new
facility, even if the existing source does not increase emissions. In
addition, the component replacement constitutes a reconstruction only
if it is technologically and economically feasible for the source to
meet the applicable standards.
    The regulations go on to require the owner or operator of an
existing source that proposes to replace components to an extent that
exceeds the 50 percent level, to notify the EPA and to provide
specified information, including ``a discussion of any economic or
technical limitations the facility may have in complying with the
applicable standards of performance after the proposed replacements.''
In addition, the regulations require the EPA to determine, within a
specified time period, whether the proposed replacement constitutes a
reconstruction. 40 CFR 60.15(d)-(e).
    b. Reconstructions. As with modifications, our base of knowledge
concerning reconstructions 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 reconstructions for
GHGs at this time. The EPA is not aware that any power plants are
presently planning any project that could meet the requirements for a
reconstruction.
2. Options
    In this action, the EPA is not issuing a proposal for affected
sources that undertake reconstructions. Our reasoning is much the same
as with NSPS modifications, which is that the lack of adequate
information about the type of source; the type of changes; the extent
of emissions increases; and the type of control measures, including
their cost and emissions reductions, precludes proposing a standard of
performance. Instead of issuing a proposal, the EPA solicits comment on
all issues related to reconstructions, including the aspects just
noted. Depending on the information the EPA acquires about
reconstructions, the EPA may, in the future, propose and promulgate
standards of performance for them.

VI. Implications for PSD and Title V Programs

A. Overview

    The proposal in this rulemaking would, for the first time, regulate
GHGs under CAA section 111. Under the EPA's regulations for the CAA PSD
preconstruction permit program, and the CAA Title V operating permit
program, regulation of GHGs under CAA section 111 triggers the
applicability of PSD. Even so, today's proposal should not require any
additional SIP revisions to make clear that the Tailoring Rule
thresholds--described below--continue to apply to the PSD program.
    This issue arises because States with approved PSD programs in
their state implementation plans (SIPs) implement PSD, and most of
these States have recently revised their SIPs to incorporate the higher
thresholds for PSD applicability to GHGs that the EPA promulgated under
what we call the Tailoring Rule.\76\ Commenters have queried whether
under the EPA's PSD regulations, promulgation of a section 111 standard
of performance GHGs would require these states to revise their SIPs
again to incorporate the Tailoring Rule thresholds again. The EPA
included an interpretation in the Tailoring Rule preamble, which makes
clear that the Tailoring Rule thresholds continue to apply if and when
the EPA promulgates requirements under CAA section 111. Even so, in
today's proposal, the EPA is including a provision in the CAA section
111 regulations that confirms this interpretation.
---------------------------------------------------------------------------

    \76\ ``Prevention of Significant Deterioration and Title V
Greenhouse Gas Tailoring Rule; Final Rule,'' 75 FR 31514 (June 3,
2010). In the Tailoring Rule, EPA established a process for phasing
in PSD and Title V applicability to sources based on the amount of
their GHG emissions, instead of immediately applying PSD and title V
at the 100 or 250 ton per year or thresholds included under the PSD
and title V applicability provisions.
---------------------------------------------------------------------------

    However, if a state with an approved PSD SIP program that applies
to GHGs believes that were the EPA to finalize the rulemaking proposed
today, the state would be required to revise its SIP to make clear that
the Tailoring Rule thresholds continue to apply, then (i) the EPA
encourages the state to do so as soon as possible, and (ii) the EPA
will proceed with a separate rulemaking action to narrow its approval
of that state's SIP so as to assure that for federal purposes, the
Tailoring Rule thresholds will continue to apply as of the effective
date of today's rulemaking.
    In the alternative, if the Tailoring Rule thresholds did not
continue to apply when the EPA promulgates requirements under CAA
section 111, then the EPA would shortly proceed with a separate
rulemaking action to narrow its approval of all of the State's approved
SIP PSD programs to assure that for federal purposes, the Tailoring
Rule thresholds will continue to apply as of the effective date of
today's proposal.
    As discussed below, in the case of title V, today's rulemaking does
not have implications for the Tailoring Rule thresholds established
with respect to sources subject to title V requirements.

B. Implications for PSD Program

    Under the PSD program in part C of title I of the CAA, in areas
that are classified as attainment or unclassifiable for NAAQS
pollutants, a new or modified source that emits any air pollutant
subject to regulation at or above specified thresholds, is required to
obtain a preconstruction permit. This permit assures that the source
meets specified requirements, including application of best available
control technology. States authorized for the PSD program may issue PSD
permits. If a state is not authorized, then the EPA issues the PSD
permits.
    Regulation of GHG emissions in the Light Duty Vehicle Rule (75 FR
25324) triggered applicability of stationary sources to regulations for
GHGs under the PSD and title V provisions of the CAA. Hence, on June 3,
2010 (75 FR 31514), the EPA issued the ``Tailoring Rule,'' which
establishes thresholds for GHG emissions in order to define and limit
when new and modified industrial facilities must have permits under the
PSD and title V programs. The rule addresses emissions of six GHGs:
CO2, CH4, N2O, HFCs, PFCs and
SF6. On January 2, 2011, large industrial sources, including
power plants, became subject to permitting requirements for their GHG
emissions if they were already are required to obtain PSD or title V
permits due to emissions of other (non-GHG) air pollutants.
    Commenters have queried whether, because of the way that the EPA's
PSD regulations are written, promulgating the rule we propose today may
raise questions as to whether the EPA must revise its PSD regulations--
and, by the same token, whether states must revise their SIPs--to
assure that the Tailoring Rule thresholds will continue to apply to
sources subject to PSD. That is, under the EPA's regulations, PSD
applies to a ``major stationary source'' that

undertakes construction, 40 CFR 51.166(a)(7)(i), and to a ``major
modification.'' 40 CFR 51.166(a)(7)(iii). A ``major modification'' is
defined as ``any physical change in or change in the method of
operation of a major stationary source that would result in a
significant emissions increase * * * and a significant net emissions
increase. * * *'' Thus, for present purposes, the key component of
these applicability provisions is that PSD applies to a ``major
stationary source.'' This term is the regulatory replacement for the
term ``major emitting facility,'' which is central to the PSD
applicability requirements established in the CAA itself, under
sections 165(a)(1) and 169(1).
    The EPA's regulations define the term ``major stationary source''
as a ``stationary source of air pollutants which emits, or has the
potential to emit, 100 [or, depending on the source category, 250] tons
per year or more of any regulated NSR pollutant.'' 40 CFR
51.166(b)(1)(i)(a). The EPA's regulations go on to define ``regulated
NSR pollutant'' to include, among other things, ``Any pollutant that is
subject to any standard promulgated under section 111 of the Act.'' 40
CFR 51.166(b)(49)(ii).
    Thus, the PSD regulations contain a separate PSD trigger for
pollutants regulated under the NSPS, 40 CFR 51.166(b)(49)(ii) (the
``NSPS trigger provision''), so that as soon as the EPA promulgates the
first NSPS for a particular air pollutant, as we are doing in this
rulemaking with respect to the GHG air pollutant, then PSD is triggered
for that air pollutant.
    The Tailoring Rule, on the face of its regulatory provisions,
incorporated the revised thresholds it promulgated into only the fourth
prong (``[a]ny pollutant that otherwise is subject to regulation under
the Act''), and not the second prong (``[a]ny pollutant that is subject
to any standard promulgated under section 111 of the Act''). For this
reason, a question may arise as to whether the Tailoring Rule
thresholds apply to the PSD requirement as triggered by the NSPS that
the EPA is promulgating in this rulemaking.
    However, although the Tailoring Rule thresholds on their face apply
to only the term, ``subject to regulation'' in the definition of
``regulated NSR pollutant,'' the EPA stated in the Tailoring Rule
preamble that the thresholds should be interpreted to apply to other
terms in the definition of ``major stationary source'' and in the
statutory provision, ``major emitting facility.'' Specifically, the EPA
stated:

3. Other Mechanisms

    As just described, we selected the ``subject to regulation''
mechanism because it most readily accommodated the needs of States
to expeditiously revise--through interpretation or otherwise--their
state rules. Even so, it is important to recognize that this
mechanism has the same substantive effect as the mechanism we
considered in the proposed rule, which was revising numerical
thresholds in the definitions of major stationary source and major
modification. Most importantly, although we are codifying the
``subject to regulation'' mechanism, that approach is driven by the
needs of the states, and our action in this rulemaking should be
interpreted to rely on any of several legal mechanisms to accomplish
this result. Thus, our action in this rule should be understood as
revising the meaning of several terms in these definitions,
including: (1) The numerical thresholds, as we proposed; (2) the
term, ``any source,'' which some commenters identified as the most
relevant term for purposes of our proposal; (3) the term, ``any air
pollutant; or (4) the term, ``subject to regulation.'' The specific
choice of which of these constitutes the nominal mechanism does not
have a substantive legal effect because each mechanism involves one
or another of the components of the terms ``major stationary
source''--which embodies the statutory term, ``major emitting
facility''--and ``major modification,'' which embodies the statutory
term, ``modification,'' and it is those statutory and regulatory
terms that we are defining to exclude the indicated GHG-emitting
sources. \[Footnote]\
    [Footnote: We also think that this approach better clarifies our
long standing practice of interpreting open-ended SIP regulations to
automatically adjust for changes in the regulatory status of an air
pollutant, because it appropriately assures that the Tailoring Rule
applies to both the definition of ``major stationary source'' and
``regulated NSR pollutant.'']

75 FR 31582.

    Thus, according to the preamble, the definition of ``major
stationary source'' itself already incorporates the Tailoring Rule
thresholds, and not just through one component (the ``subject to
regulation'' prong of the term ``regulated NSR pollutant'') of that
definition. For this reason, it is the EPA's position that the
Tailoring Rule thresholds continue to apply even when the EPA
promulgates the first NSPS for GHGs (which, as noted above, triggers
the PSD requirement under the NSPS trigger provision in the definition
of ``regulated NSR pollutant'').\77\ To clarify and confirm that the
Tailoring Rule thresholds apply to the section 111 prong of the
definition of regulated NSR pollutant, in this proposed rulemaking, the
EPA is proposing to revise the NSPS regulations, although not the PSD
regulations, to explicitly make clear that the NSPS trigger provision
in the PSD regulations incorporate the Tailoring Rule thresholds.
---------------------------------------------------------------------------

    \77\ This position reads the regulations to be consistent with
the CAA PSD provisions themselves. Under those provisions, PSD
applies to any ``major emitting facility,'' which is defined to mean
stationary sources that emit or have the potential to emit ``any air
pollutant'' at either 100 or 250 tons per year, depending on the
source category. CAA section 165(a), 169(1). EPA has long
interpreted these provisions to apply PSD to a stationary source
that emits the threshold amounts of any air pollutant subject to
regulation. See Tailoring Rule, 75 FR 31579. Under these provisions,
at present, PSD is already applicable to GHGs because GHGs are
already subject to regulation, and regulating GHGs under CAA section
111 does not any additional type of PSD trigger.
---------------------------------------------------------------------------

    As a result, the EPA believes that states that incorporated the
Tailoring Rule thresholds into their SIPs may take the position that
they also incorporated the EPA's interpretation in the preamble that
the thresholds apply to the definition ``major stationary source.''
    The EPA requests that all States with approved SIP PSD programs
that apply to GHGs indicate during the comment period on this rule
whether they can interpret their SIPs already to apply the Tailoring
Rule thresholds to the NSPS prong or whether they must revise their
SIPs. For any State that says it must revise its SIP (or that does not
respond), the EPA expects to propose a rule that is comparable to the
SIP PSD Narrowing Rule shortly after the close of the comment period,
and expects to finalize that rule at the same time that it finalizes
this NSPS rule.

C. Implications for Title V Program

    Under the title V program, a source that emits any air pollutant
subject to regulation at or above specified thresholds (along with
certain other sources) is required to obtain an operating permit. This
permit includes all of the CAA requirements applicable to the source.
These permits are generally issued through EPA-approved State title V
programs.
    As the EPA explained in the Tailoring Rule preamble, title V
applies to a ``major source,'' CAA section 502(a), which is defined to
include, among other things, certain sources, including any ``major
stationary source,'' CAA section 501(2)(B), which, in turn, is defined
to include a stationary source of ``any air pollutant'' at or above 100
tpy. CAA section 302(j). The EPA's regulations under title V define the
term ``major source,'' and in the Tailoring Rule, the EPA revised that
definition to make clear that the term is limited to stationary sources
that emit any air pollutant ``subject to regulation.'' The EPA
incorporated the Tailoring Rule threshold within this definition of
``subject to regulation.'' The EPA

described its action as follows in the preamble to the Tailoring Rule:

    Thus, EPA is adding the phrase ``subject to regulation'' to the
definition of ``major source'' under 40 CFR 70.2 and 71.2. EPA is
also adding to these regulations a definition of ``subject to
regulation.'' Under the part 70 and part 71 regulatory changes
adopted, the term ``subject to regulation,'' for purposes of the
definition of ``major source,'' has two components. The first
component codifies the general approach EPA recently articulated in
the ``Reconsideration of Interpretation of Regulations That
Determine Pollutants Covered by Clean Air Act Permitting.'' 75 FR
17704. Under this first component, a pollutant ``subject to
regulation'' is defined to mean a pollutant subject to either a
provision in the CAA or regulation adopted by EPA under the CAA that
requires actual control of emissions of that pollutant and that has
taken effect under the CAA. See id. at 17022-23; Wegman Memorandum
at 4-5. To address tailoring for GHGs, EPA includes a second
component of the definition of ``subject to regulation,'' specifying
that GHGs are not subject to regulation for purposes of defining a
major source, unless as of July 1, 2011, the emissions of GHGs are
from a source emitting or having the potential to emit 100,000 tpy
of GHGs on a CO2e basis.

75 FR at 31,583.

    Unlike the PSD regulations described above, the title V definition
of ``major source'', as revised by the Tailoring Rule, does not on its
face distinguish among types of regulatory triggers for title V.
Because title V has already been triggered for GHG-emitting sources,
the promulgation of CAA section 111 requirements has no further impact
on title V requirements for major sources of GHGs. Accordingly, today's
rulemaking has no title V implications with respect to the Tailoring
Rule threshold. Of course, unless exempted by the Administrator through
regulation under CAA section 502(a), sources subject to a NSPS are
required to apply for, and operate pursuant to, a title V permit that
assures compliance with all applicable CAA requirements for the source,
including any GHG-related requirements. We have concluded that this
rule will not affect non-major sources and there is no need to consider
whether to exempt non-major sources

VII. Impacts of the Proposed Action

A. What are the air impacts?

    The EPA believes that electric power companies would choose to
build new EGUs that comply with the regulatory requirements of this
proposal even in the absence of this proposal, because of existing and
expected market conditions. We do not project any new coal-fired EGUs
without CCS to be built in the absence of this proposal. Accordingly,
the EPA believes that this proposed rule is not likely to produce
changes in emissions of greenhouse gases or other pollutants although
it does encourage the current trend towards cleaner generation.

B. What are the energy impacts?

    This proposed rule is not anticipated to have a notable effect on
the supply, distribution, or use of energy. As previously stated, we
believe that electric power companies would choose to build new EGUs
that comply with the regulatory requirements of this proposal even in
the absence of the proposal, because of existing and expected market
conditions. In addition, we do not project any new coal-fired EGUs
without CCS to be built in the absence of this proposal.

C. What are the compliance costs?

    The EPA believes this proposed rule will have no notable compliance
costs associated with it, because electric power companies would be
expected to build new EGUs that comply with the regulatory requirements
of this proposal even in the absence of the proposal, due to existing
and expected market conditions. The EPA does not project any new coal-
fired EGUs without CCS to be built in the absence of the proposal.

D. How will this proposal contribute to climate change protection?

    As previously explained, the special characteristics of GHGs make
it important to take initial steps to control the largest emissions
categories without delay. Unlike most traditional air pollutants, GHGs
persist in the atmosphere for time periods ranging from decades to
millennia, depending on the gas. Fossil-fueled power plants emit more
GHG emissions than any other stationary source category in the United
States, and among new GHG emissions sources, the largest individual
sources are in this source category.
    This proposed rule will limit GHG emissions from new sources in
this source category to levels consistent with current projections for
new fossil-fuel-fired generating units. The proposed rule will also
serve as a necessary predicate for the regulation of existing sources
within this source category under CAA section 111(d). In these ways,
the proposed rule will contribute to the actions required to slow or
reverse the accumulation of GHG concentrations in the atmosphere, which
is necessary to protect against projected climate change impacts and
risks.

E. What are the economic and employment impacts?

    The EPA does not anticipate that this proposed rule will result in
notable CO2 emission changes, energy impacts, monetized
benefits, costs, or economic impacts by 2020. Essentially the EPA
believes that owners of newly built electric generating units will
choose technologies that meet these standards even in the absence of
this proposal due to existing economic conditions as normal business
practice. Likewise, we believe this rule will not have any impacts on
the price of electricity, employment or labor markets, or the US
economy.

F. What are the benefits of the proposed standards?

    As previously stated, the EPA does not anticipate that the power
industry will incur compliance costs as a result of this proposal and
we do not anticipate any notable CO2 emission changes
resulting from the rule. Therefore, there are no direct monetized
climate benefits in terms of CO2 emission reductions
associated with this rulemaking. However, by clarifying that in the
future, new coal-fired power plants will be required to install CCS,
this rulemaking eliminates uncertainty about the status of coal and may
well enhance the prospects for new coal-fired generation and the
deployment of CCS, and thereby promote energy diversity.

VIII. Request for Comments

    We request comments on all aspects of the proposed rulemaking
including the RIA. All significant comments received will be considered
in the development and selection of the final rule. We specifically
solicit comments on additional issues under consideration as described
below.
    CEMS. We are considering and requesting comment on requiring the
use of CO2 CEMS including stack gas flow rate monitoring for
all new affected facilities, including those burning exclusively
natural gas and/or distillate oil. In addition, we are requesting
comment on requiring the use the following measurement procedures in
conducting CEMS relative accuracy testing:
    a. EPA Method 2F of 40 CFR part 60 for flow rate measurement during
the relative accuracy test audit and performance testing. Method 2F
provides velocity data for three dimensions and provides measurements
more representative of actual gas flow rates than EPA Method 2 or 2G of
40 CFR part 60.
    b. EPA Method 2H of 40 CFR part 60 or Conditional Test Method
(CTM)-041

(see: http://www.epa.gov/airmarkets/emissions/docs/square-ducts-wall-effects-test-method-ctm-041.pdf) to account for wall effects on for
stack gas flow rate calculations during CEMS relative accuracy
determinations and for performance testing.
    c. EPA Method 4 of 40 CFR part 60 to determine moisture for flow
rate during CEMS relative accuracy determinations and for performance
test calculations.
    d. EPA Method 3A of 40 CFR part 60 for CO2 concentration
measurement and for molecular weight determination during CEMS relative
accuracy determinations or for performance testing. Account for ambient
air argon concentration of 0.93 percent \78\ and a molecular weight of
39.9 lb/lb-mol in calculating the dry gas molecular weight.
---------------------------------------------------------------------------

    \78\ http://www.physicalgeography.net/fundamentals/7a.html.
---------------------------------------------------------------------------

    e. Measure the stack diameter at the CEMS measurement site and the
reference method sampling site with a laser distance measurement
device. Determine the mean average of three separate diameter
measurements for circular stack areas or the mean average of three
depth and width measurements for rectangular measurement areas.
Calculate the effective stack area for all flow rate measurements, both
CEMS system and Reference Method, using this measurement data. This
would be a one-time measurement that would fix the effective area of
the stack emissions point unless a new location is chosen for the CEMS
or Reference Method measurement point. All calculations involving pi
would use a value of 3.14159.
    f. Apply a daily calibration drift criteria not to exceed 0.3
percent CO2 for CO2 CEMS.
    g. Do not exceed a relative accuracy specification of 2.5 percent
for both CO2 and flow rate measurement CEMS.
    We also request comment on whether Method 3B of 40 CFR part 60
(integrated bag sample), in addition to Method 3A, should be allowed
for CO2 concentration measurement and for molecular weight
determination during CEMS relative accuracy determinations or for
performance testing.
    Coal refuse. Due to the multiple environmental benefits of
remediating coal refuse piles, we are considering and requesting
comment on subcategorizing EGUs that burn over 75 percent coal refuse
on an annual basis. As part of the GHG listening sessions, one
commenter mentioned the advantages of utilizing coal refuse to create
electricity. The commenter stated that if net emissions caused by using
mining waste to generate electricity are calculated, then mining waste
facility would produce no net GHG emissions in the long term and
emissions would be no greater than the short term emissions of a
combined cycle gas plant in. The comment states that due to the size of
the piles, mining waste pile exposure to atmospheric oxygen and
pressure promotes heat-generating reactions, primarily oxidation of the
mining waste itself (i.e., the coal refuse piles are slowly burning).
This process emits CO2 and other air pollutants. Remediation
would stop current and future CO2 emissions resulting from
the uncontrolled combustion of waste piles.
    Coordinates. We realize that geographic latitude and longitude
coordinates of each stack in terms of decimal degrees are presently
reported to the EPA's Clean Air Markets Division in terms of four
decimal points to the right of the decimal point. We are requesting
comment on whether we should require owners/operators of affected
facilities to submit to the EPA Administrator the geographic latitude
and longitude coordinates of each stack to have at least six values to
the right of the decimal for each location. By way of example, the
coordinates for the monument next to Zachary Taylor's tomb in
Louisville, KY are 38.279401 latitude and -85.643751 longitude.
    Combined Heat and Power. We are also considering and requesting
comment on if exempting all CHP facilities where useful thermal output
accounts for at least 20 percent of the total useful output from this
proposed rule would recognize the environmental benefit of CHP and
result in additional installations that would otherwise no occur. In
considering exemption of CHP units, the EPA is particularly interested
in the overall impact this would have on the composition of new builds.
The definition of affected sources under this rule already exempts CHP
sources that primarily generate on-site power. Therefore, as explained
earlier, today's proposal does not impact any of the small amount of
projected coal-fired CHP in EIA's AEO 2011. CHPs that would be covered
by this rule generate and sell large quantities of electricity. While
building such units is more energy efficient and results in some GHG
reductions, building new coal-fired units to meet a standard of 1,000
lb CO2/MWh would likely result in greater reductions. If
potential developers of new coal-fired generation opted instead to
build coal-fired CHP to avoid the CO2 limitations proposed
under today's rule, it could result in greater emissions of
CO2. Furthermore, requiring such units to meet a standard of
1,000 lb CO2/MWh does not preclude new coal-fired units from
being CHP units.
    Format of the Proposed Standards. Although we have proposed gross
output-based emission standards, the EPA believes that the net power
supplied to the end user is a better indicator of environmental
performance than gross output from the power producer. Net output is
the combination of the gross electrical output of the electric
generating unit minus the parasitic power requirements. A parasitic
load for an electric generating unit is any of the loads or devices
powered by electricity, steam, hot water, or directly by the gross
output of the electric generating unit that does not contribute
electrical, mechanical, or thermal output. In general, less than 7.5
percent of coal-fired station power output, and about 2.5 percent of a
combined cycle station power output, is used internally by parasitic
energy demands, but the amount of these parasitic loads vary from
source to source. Reasons for using net output include (1) recognizing
the efficiency gains of selecting EGU designs and control equipment
that require less auxiliary power, (2) selecting fuels that require
less emissions control equipment, and (3) recognizing the environmental
benefit of higher efficiency motors, pumps, and fans. In addition, use
of a gross output-based standard could potentially drive the
installation of electrically driven feed pumps instead of steam driven
feed pumps, even though from an overall net efficiency basis, it may be
more efficient to use steam-driven feed pumps. Further, monitoring net
output for new and reconstructed facilities can be designed into the
facility at low costs. Thus, we are requesting comment on the use of
net output-based emission standards for owners/operators of new
facilities.
    Stationary Simple Cycle Turbines. As stated in the preamble, the
intent of the proposed regulations is to cover stationary combustion
turbines use for intermediate and base load electric power generation
and to exempt stationary combustion turbines used for peaking
operations (i.e., simple cycle turbines). We are considering and
requesting comment on not including a definition of simple cycle
turbines in the final rule. The potential electric output requirement
in the definition of electric generating unit would already exclude
facilities with permit restricting limiting operation to less than \1/
3\ of their potential electric output, approximately 2,900 hours of
full load

operation annually. The peaking season is generally considered to be
less than 2,500 hours annually, and we are requesting comment on if the
capacity factor exemption is sufficient such that specifically
exempting simple cycle turbine is unnecessary. We are also requesting
comment on whether the exemption would provide a perverse incentive to
build less efficient simple cycle combustion turbines in order to avoid
applicability with the proposed rule. While few existing simple cycle
turbines presently generate greater than \1/3\ of their potential
electric output for sale, we are requesting comment on whether the
exemption for simple cycle turbines would result in the greater use of
simple cycle turbines for intermediate load applications when more
efficient combined cycle facilities would have otherwise been built. In
addition, it is our understanding that combined cycle facilities are
sometimes built in stages with the combustion turbine engine
installation occurring first and the heat recovery steam generator
being installed in later years as electricity demand increases. We are
requesting comment on whether the exemption would potentially delay the
installation of the heat recovery steam generator portion of new
combined cycle facilities. Finally, in the event we use the definition
approach in the final rule, we are requesting comment on whether a CHP
facility that uses the recovered exhaust heat for purposes other than
to generate steam and recuperated combustion turbines should be
considered simple or combined cycle combustion turbines.

IX. Statutory and Executive Order Reviews

A. Executive Order 12866, Regulatory Planning and Review, and Executive
Order 13563, Improving Regulation and Regulatory Review

    Under Executive Order (EO) 12866 (58 FR 51,735, October 4, 1993),
this action is a ``significant regulatory action'' because it ``raises
novel legal or policy issues arising out of legal mandates''.
Accordingly, the EPA submitted this action to the Office of Management
and Budget (OMB) for review under Executive Orders 12866 and 13563 (76
FR 3821, January 21, 2011) and any changes made in response to OMB
recommendations have been documented in the docket for this action. In
addition, the EPA prepared an analysis of the potential costs and
benefits associated with this action. This analysis is contained in the
Regulatory Impact Analysis for the Standards of Performance for
Greenhouse Gas Emissions for New Stationary Sources: Electric Utility
Generating Units.
    The EPA believes this rule will have no notable compliance costs
associated with it over a range of likely sensitivity conditions
because electric power companies would choose to build new EGUs that
comply with the regulatory requirements of this proposal even in the
absence of the proposal, because of existing and expected market
conditions. (See the RIA for further discussion of sensitivities.)
Because our modeling shows that natural gas-fired plants are the
facilities of choice, the proposed standard of performance--which is
based on the emission rate of a new NGCC unit--would not add costs. The
EPA does not project any new coal-fired EGUs without CCS to be built in
the absence of this proposal.

B. Paperwork Reduction Act

    The information collection requirements in this proposed rule have
been submitted for approval to the Office of Management and Budget
(OMB) under the Paperwork Reduction Act, 44 U.S.C. 3501 et seq. The
Information Collection Request (ICR) document prepared by the EPA has
been assigned EPA ICR number 2465.01.
    This proposed action would impose minimal new information
collection burden on affected sources beyond what those sources would
already be subject to under the authorities of CAA parts 75 and 98. OMB
has previously approved the information collection requirements
contained in the existing part 75 and 98 regulations (40 CFR part 75
and 40 CFR part 98) under the provisions of the Paperwork Reduction
Act, 44 U.S.C. 3501 et seq. and has assigned OMB control numbers 2060-
0626 and 2060-0629, respectively. Apart from certain reporting costs
based on requirements in the NSPS General Provisions (40 CFR part 60,
subpart A), which are mandatory for all owners/operators subject to CAA
section 111 national emission standards, there are no new information
collection costs, as the information required by this proposed rule is
already collected and reported by other regulatory programs. The
recordkeeping and reporting requirements are specifically authorized by
CAA section 114 (42 U.S.C. 7414). All information submitted to the EPA
pursuant to the recordkeeping and reporting requirements for which a
claim of confidentiality is made is safeguarded according to Agency
policies set forth in 40 CFR part 2, subpart B.
    The EPA believes that electric power companies will choose to build
new EGUs that comply with the regulatory requirements of this proposal
because of existing and expected market conditions. The EPA does not
project any new coal-fired EGUs that commence construction after this
proposal to commence operation over the 3-year period covered by this
ICR. We estimate that 17 new affected NGCC units would commence
operation during that time period. As a result of this proposal, those
units would be required to prepare a summary report, which includes
reporting of excess emissions and downtime, every 6 months.
    When a malfunction occurs, sources must report them according to
the applicable reporting requirements of 40 CFR part 60, subpart TTTT.
An affirmative defense to civil penalties for exceedances of emission
limits that are caused by malfunctions is available to a source if it
can demonstrate that certain criteria and requirements are satisfied.
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 (sudden, infrequent, not
reasonable preventable, and not caused by poor maintenance and or
careless operation) and where the source took necessary actions to
minimize emissions. In addition, the source must meet certain
notification and reporting requirements. For example, the source must
prepare a written root cause analysis and submit a written report to
the Administrator documenting that it has met the conditions and
requirements for assertion of the affirmative defense.
    To provide the public with an estimate of the relative magnitude of
the burden associated with an assertion of the affirmative defense
position adopted by a source, the EPA has estimated what the
notification, recordkeeping, and reporting requirements associated with
the assertion of the affirmative defense might entail. The EPA's
estimate for the required notification, reports, and records, including
the root cause analysis, associated with a single incident totals
approximately totals $3,141, and is based on the time and effort
required of a source to review relevant data, interview plant
employees, and document the events surrounding a malfunction that has
caused an exceedance of an emission limit. The estimate also includes
time to produce and retain the record and reports for submission to the
EPA. The EPA provides this illustrative estimate of this burden,
because these costs are only incurred if there has been a violation,
and a source chooses to take advantage of the affirmative defense.

    The EPA provides this illustrative estimate of this burden because
these costs are only incurred if there has been a violation and a
source chooses to take advantage of the affirmative defense. Given the
variety of circumstances under which malfunctions could occur, as well
as differences among sources' operation and maintenance practices, we
cannot reliably predict the severity and frequency of malfunction-
related excess emissions events for a particular source. It is
important to note that the EPA has no basis currently for estimating
the number of malfunctions that would qualify for an affirmative
defense. Current historical records would be an inappropriate basis, as
source owners or operators previously operated their facilities in
recognition that they were exempt from the requirement to comply with
emissions standards during malfunctions. Of the number of excess
emissions events reported by source operators, only a small number
would be expected to result from a malfunction (based on the definition
above), and only a subset of excess emissions caused by malfunctions
would result in the source choosing to assert the affirmative defense.
Thus, we believe the number of instances in which source operators
might be expected to avail themselves of the affirmative defense will
be extremely small. In fact, we estimate that there will be no such
occurrences for any new sources subject to 40 CFR part 60, subpart TTTT
over the 3-year period covered by this ICR. We expect to gather
information on such events in the future, and will revise this estimate
as better information becomes available.
    The annual information collection burden for this collection
consists only of reporting burden as explained above. The reporting
burden for this collection (averaged over the first 3 years after the
effective date of the standards) is estimated to be $15,570 and 396
labor hours. This estimate includes semi-annual summary reports which
include reporting of excess emissions and downtime. All burden
estimates are in 2010 dollars. Average burden hours per response are
estimated to be 16.5 hours. The total number of respondents over the 3-
year ICR period is estimated to be 36. Burden is defined at 5 CFR
1320.3(b).
    An agency may not conduct or sponsor, and a person is not required
to respond to, a collection of information unless it displays a
currently valid OMB control number. The OMB control numbers for the
EPA's regulations in 40 CFR are listed in 40 CFR part 9.
    To comment on the Agency's need for this information, the accuracy
of the provided burden estimates, and any suggested methods for
minimizing respondent burden, the EPA has established a public docket
for this rule, which includes this ICR, under Docket ID number EPA-HQ-
OAR-2011-0660. Submit any comments related to the ICR to the EPA and
OMB. See ADDRESSES section at the beginning of this notice for where to
submit comments to the EPA. Send comments to OMB at the Office of
Information and Regulatory Affairs, Office of Management and Budget,
725 17th Street, NW., Washington, DC 20503, Attention: Desk Officer for
EPA. Since OMB is required to make a decision concerning the ICR
between 30 and 60 days after April 13, 2012, a comment to OMB is best
assured of having its full effect if OMB receives it by May 14, 2012.
The final rule will respond to any OMB or public comments on the
information collection requirements contained in this proposal.

C. Regulatory Flexibility Act as Amended by the Small Business
Regulatory Enforcement Fairness Act of 1996, 5 U.S.C. et seq.

    The Regulatory Flexibility Act (RFA) generally requires an agency
to prepare a regulatory flexibility analysis of any rule subject to
notice and comment rulemaking requirements under the Administrative
Procedure Act or any other statute unless the agency certifies that the
rule will not have a significant economic impact on a substantial
number of small entities. Small entities include small businesses,
small organizations, and small governmental jurisdictions.
    For purposes of assessing the impacts of this rule on small
entities, small entity is defined as:
    (1) A small business that is defined by the SBA's regulations at 13
CFR 121.201 (for the electric power generation industry, the small
business size standard is an ultimate parent entity defined as having a
total electric output of 4 million MWh or less in the previous fiscal
year. The NAICS codes for the affected industry are in Table 4 below);
    (2) A small governmental jurisdiction that is a government of a
city, county, town, school district or special district with a
population of less than 50,000; and
    (3) A small organization that is any not-for-profit enterprise
which is independently owned and operated and is not dominant in its
field.

                            Table 4--Potentially Regulated Categories and Entities a
----------------------------------------------------------------------------------------------------------------
                 Category                    NAICS Code          Examples of potentially regulated entities
----------------------------------------------------------------------------------------------------------------
Industry.................................          221112  Fossil fuel electric power generating units.
Federal Government.......................      \b\ 221112  Fossil fuel electric power generating units owned by
                                                            the federal government.
State/Local Government...................      \b\ 221112  Fossil fuel electric power generating units owned by
                                                            municipalities.
Tribal Government........................          921150  Fossil fuel electric power generating units in Indian
                                                            Country.
----------------------------------------------------------------------------------------------------------------
\a\ Include NAICS categories for source categories that own and operate electric power generating units
  (includes boilers and stationary combined cycle combustion turbines).
\b\ Federal, state, or local government-owned and operated establishments are classified according to the
  activity in which they are engaged.

    After considering the economic impacts of this proposed rule on
small entities, I certify that this action will not have a significant
economic impact on a substantial number of small entities.
    We do not include an analysis of the illustrative impacts on small
entities that may result from implementation of this proposed rule
because we do not anticipate any compliance costs over a range of
likely sensitivity conditions as a result of this proposal. Thus the
cost-to-sales ratios for any affected small entity would be zero costs
as compared to annual sales revenue for the entity. The EPA believes
that electric power companies will choose to build new EGUs that comply
with the regulatory requirements of this proposal because of existing
and expected market conditions. (See the RIA for further discussion of
sensitivities.) Because our modeling shows that natural gas-fired
plants are the facilities of choice, the proposed standard of
performance--which is based on the emission rate of a new NGCC unit--
would not add costs. The EPA does not project any new coal-fired EGUs
without CCS to be built. Accordingly, there are no anticipated

economic impacts as a result of this proposal.
    Nevertheless, the EPA is aware that there is substantial interest
in this rule among small entities (municipal and rural electric
cooperatives). In light of this interest, the EPA determined to seek
early input from representatives of small entities while formulating
the provisions of this proposed regulation. Such outreach is also
consistent with the President's January 18, 2011 Memorandum on
Regulatory Flexibility, Small Business, and Job Creation, which
emphasizes the important role small businesses play in the American
economy. This process has enabled the EPA to hear directly from these
representatives, at a very preliminary stage, about how it should
approach the complex question of how to apply Section 111 of the CAA to
the regulation of GHGs from these source categories. The EPA's outreach
regarded planned actions for new and existing sources, but only new
sources would be affected by this proposed action.
    The EPA conducted an initial outreach meeting with small entity
representatives on April 6, 2011. The purpose of the meeting was to
provide an overview of recent EPA proposals impacting the power sector.
Specifically, overviews of the Transport Rule, the Mercury and Air
Toxics Standards, and the Clean Water Act 316(b) Rule proposals were
presented.
    The EPA conducted outreach with representatives from 20 various
small entities that potentially would be affected by this rule. The
representatives included small entity municipalities, cooperatives, and
private investors. We distributed outreach materials to the small
entity representatives; these materials included background, an
overview of affected sources and GHG emissions from the power sector,
an overview of CAA section 111, an assessment of CO2
emissions control technologies, potential impacts on small entities,
and a summary of the listening sessions. We met with eight of the small
entity representatives, as well as three participants from
organizations representing power producers, on June 17, 2011, to
discuss the outreach materials, potential requirements of the rule, and
regulatory areas where the EPA has discretion and could potentially
provide flexibility.
    A second outreach meeting was conducted on July 13, 2011. We met
with nine of the small entity representatives, as well as three
participants from organizations representing power producers. During
the second outreach meeting, various small entity representatives and
participants from organizations representing power producers presented
information regarding issues of concern with respect to development of
standards for GHG emissions. Specifically, topics suggested by the
small entity representatives and discussed included: boilers with
limited opportunities for efficiency improvements due to NSR
complications for conventional pollutants; variances per kilowatt-hour
and in heat rates over monthly and annual operations; significance of
plant age; legal issues; importance of future determination of carbon
neutrality of biomass; and differences between municipal government
electric utilities and other utilities.
    Small entities expressed concern regarding units making
modifications being regulated as new sources. As explained above, we
are not proposing a standard of performance for modifications. As a
result, sources that undertake modifications would be treated as
existing sources and thus would not be subject to the requirements
proposed in this notice. As also explained above, the EPA is not
proposing standards of performance for existing proposed EGUs, which
are referred to as transitional sources, that have acquired a complete
preconstruction permit by the time of this proposal and that commence
construction within 12 months of this proposal. As a result, any
transitional sources owned by small entities would not be subject to
the standards of performance proposed in today's rule.
    We invite comments on all aspects of the proposal and its impacts,
including potential adverse impacts, on small entities.

D. Unfunded Mandates Reform Act of 1995

    This proposed rule does not contain a Federal mandate that may
result in expenditures of $100 million or more for State, local, and
tribal governments, in the aggregate, or the private sector in any one
year. The EPA believes this proposed rule will have no compliance costs
associated with it over a range of likely sensitivity conditions
because electric power companies will choose to build new EGUs that
comply with the regulatory requirements of this proposal because of
existing and expected market conditions. (See the RIA for further
discussion of sensitivities.) As previously explained, because our
modeling shows that natural gas-fired plants are the facilities of
choice, the proposed standard of performance--which is based on the
emission rate of a new NGCC unit--would not add costs. The EPA does not
project any new coal-fired EGUs without CCS to be built. Thus, this
proposed rule is not subject to the requirements of sections 202 or 205
of UMRA.
    This proposed rule is also not subject to the requirements of
section 203 of UMRA because it contains no regulatory requirements that
might significantly or uniquely affect small governments.
    In light of the interest in this rule among governmental entities,
the EPA initiated consultations with governmental entities. The EPA
invited the following 10 national organizations representing state and
local elected officials to a meeting held on April 12, 2011, in
Washington DC: (1) National Governors Association; (2) National
Conference of State Legislatures, (3) Council of State Governments, (4)
National League of Cities, (5) U.S. Conference of Mayors, (6) National
Association of Counties, (7) International City/County Management
Association, (8) National Association of Towns and Townships, (9)
County Executives of America, and (10) Environmental Council of States.
These 10 organizations representing elected state and local officials
have been identified by the EPA as the ``Big 10'' organizations
appropriate to contact for purpose of consultation with elected
officials. The purposes of the consultation were to provide general
background on the proposal, answer questions, and solicit input from
state/local governments. The EPA's consultation regarded planned
actions for new and existing sources, but only new sources would be
affected by this proposed action.
    During the meeting, officials asked clarifying questions regarding
CAA section 111 requirements and efficiency improvements that would
reduce CO2 emissions. In addition, they expressed concern
with regard to the potential burden associated with impacts on state
and local entities that own/operate affected utility boilers, as well
as on state and local entities with regard to implementing the rule.
Subsequent to the April 12, 2011 meeting, the EPA received a letter
from the National Conference of State Legislatures. In that letter, the
National Conference of State Legislatures urged the EPA to ensure that
the choice of regulatory options maximizes benefit and minimizes
implementation and compliance costs on state and local governments; to
pay particular attention to options that would provide states with as
much flexibility as possible; and to take into consideration the
constraints of the state legislative calendars and ensure that
sufficient time is allowed for state

actions necessary to come into compliance.

E. Executive Order 13132, Federalism

    This proposed action does not have federalism implications. It
would not have substantial direct effects on the States, on the
relationship between the national government and the States, or on the
distribution of power and responsibilities among the various levels of
government, as specified in EO 13132. This proposed action would not
impose substantial direct compliance costs on state or local
governments, nor would it preempt state law. Thus, Executive Order
13132 does not apply to this action. The EPA consulted with state and
local officials in the process of developing the proposed rule to
permit them to have meaningful and timely input into its development.
The EPA's consultation regarded planned actions for new and existing
sources, but only new sources would be affected by this proposed
action. The EPA met with 10 national organizations representing state
and local elected officials to provide general background on the
proposal, answer questions, and solicit input from state/local
governments. The UMRA discussion in this preamble includes a
description of the consultation. In the spirit of EO 13132, and
consistent with EPA policy to promote communications between the EPA
and state and local governments, the EPA specifically solicits comment
on this proposed action from state and local officials.

F. Executive Order 13175, Consultation and Coordination With Indian
Tribal Governments

    Subject to the EO 13175 (65 FR 67249, November 9, 2000) the EPA may
not issue a regulation that has tribal implications, that imposes
substantial direct compliance costs, and that is not required by
statute, unless the Federal government provides the funds necessary to
pay the direct compliance costs incurred by tribal governments, or the
EPA consults with tribal officials early in the process of developing
the proposed regulation and develops a tribal summary impact statement.
    The EPA has concluded that this proposed action would not have
tribal implications. It would neither impose substantial direct
compliance costs on tribal governments, nor preempt Tribal law. This
proposed rule would impose requirements on owners and operators of new
EGUs. The EPA is aware of three coal-fired EGUs located in Indian
Country but is not aware of any EGUs owned or operated by tribal
entities. The EPA notes that this proposal does not affect existing
sources such as the three coal-fired EGUs located in Indian Country,
but addresses CO2 emissions for new EGU sources only.
    Because the EPA is aware of Tribal interest in this proposed rule,
the EPA offered consultation with tribal officials early in the process
of developing this proposed regulation to permit them to have
meaningful and timely input into its development. The EPA's
consultation regarded planned actions for new and existing sources, but
only new sources would be affected by this proposed action.
    Consultation letters were sent to 584 tribal leaders. The letters
provided information regarding the EPA's development of NSPS and
emission guidelines for EGUs and offered consultation. A consultation/
outreach meeting was held on May 23, 2011, with the Forest County
Potawatomi Community, the Fond du Lac Band of Lake Superior Chippewa
Reservation, and the Leech Lake Band of Ojibwe. Other tribes
participated in the call for information gathering purposes. In this
meeting, the EPA provided background information on the GHG emission
standards to be developed and a summary of issues being explored by the
Agency. Tribes suggested that the EPA consider expanding coverage of
the GHG standards to include combustion turbines, lowering the 250
MMBtu per hour heat input threshold so as to capture more EGUs, and
including credit for use of renewables. The tribes were also interested
in the scope of the emissions averaging being considered by the Agency
(e.g., over what time period, across what units). In addition, the EPA
held a series of listening sessions on this proposed action. Tribes
participated in a session on February 17, 2011 with the state agencies,
as well as in a separate session with tribes on April 20, 2011.
    The EPA will also hold additional meetings with tribal
environmental staff to inform them of the content of this proposal as
well as provide additional consultation with tribal elected officials
where it is appropriate. We specifically solicit additional comment on
this proposed rule from tribal officials.

G. Executive Order 13045, Protection of Children From Environmental
Health Risks and Safety Risks

    The EPA interprets EO 13045 (62 FR 19885, April 23, 1997) as
applying to those regulatory actions that concern health or safety
risks, such that the analysis required under section 5-501 of the Order
has the potential to influence the regulation. This proposed action is
not subject to EO 13045 because it is based solely on technology
performance. The proposal is not expected to produce notable changes in
emissions of greenhouse gases or other pollutants but does encourage
the current trend towards cleaner generation, helping to protect air
quality and children's health. The Agency recognizes that children are
among the groups most vulnerable to climate change impacts and the
public is invited to submit comments or identify peer reviewed studies
relevant to this proposal.

H. Executive Order 13211, Actions Concerning Regulations That
Significantly Affect Energy Supply, Distribution, or Use

    This proposed action is not a ``significant energy action'' as
defined in EO 13211 (66 FR 28355 (May 22, 2001)) because it is not
likely to have a significant adverse effect on the supply,
distribution, or use of energy. This proposed action is not anticipated
to have notable impacts on emissions, costs or energy supply decisions
for the affected electric utility industry.

I. National Technology Transfer and Advancement Act

    Section 12(d) of the NTTAA of 1995 (Pub. L. 104-113; 15 U.S.C. 272
note) directs the EPA to use Voluntary Census Standards in their
regulatory and procurement activities unless to do so would be
inconsistent with applicable law or otherwise impractical. Voluntary
consensus standards are technical standards (e.g., materials
specifications, test methods, sampling procedures, business practices)
developed or adopted by one or more voluntary consensus bodies. The
NTTAA directs the EPA to provide Congress, through annual reports to
the OMB, with explanations when an agency does not use available and
applicable VCS.
    This proposed rulemaking involves technical standards. The EPA
cites the following standards in this proposed rule: D5287-08 (Standard
Practice for Automatic Sampling of Gaseous Fuels), D4057-06 (Standard
Practice for Manual Sampling of Petroleum and Petroleum Products), and
D4177-95(2010) (Standard Practice for Automatic Sampling of Petroleum
and Petroleum Products). The EPA is proposing use of Appendices B, D,
F, and G to 40 CFR part 75; these Appendices contain standards that
have already been reviewed under the NTTAA.
    The EPA welcomes comments on this aspect of the proposed rulemaking
and, specifically, invites the public to identify potentially-
applicable VCS and to explain why such standards should be used in this
action.

J. Executive Order 12898: Federal Actions To Address Environmental
Justice in Minority Populations and Low-Income Populations

    Executive Order 12898 (59 FR 7629, February 16, 1994) establishes
Federal executive policy on environmental justice. Its main provision
directs Federal agencies, to the greatest extent practicable and
permitted by law, to make environmental justice part of their mission
by identifying and addressing, as appropriate, disproportionately high
and adverse human health or environmental effects of their programs,
policies, and activities on minority populations and low-income
populations in the U.S.
    The EPA has determined that this proposed rule would not result in
disproportionately high and adverse human health or environmental
effects on minority or low-income populations, including any minority,
low-income population or indigenous populations.

List of Subjects in 40 CFR Part 60

    Environmental protection, Administrative practice and procedure,
Air pollution control, Incorporation by reference, Intergovernmental
relations, Reporting and recordkeeping requirements.

    Dated: March 27, 2012.
Lisa P. Jackson,
Administrator.

    For the reasons stated in the preamble, title 40, chapter I, part
60 of the Code of the Federal Regulations is proposed to be amended as
follows:

PART 60--[AMENDED]

    1. The authority citation for part 60 continues to read as follows:

    Authority: 42 U.S.C. 7401, et seq.

    2. Part 60 is amended by adding subpart TTTT to read as follows:
Subpart TTTT Standards of Performance for Greenhouse Gas Emissions for
Electric Utility Generating Units

Applicability

Sec.
60.5508 What is the purpose of this subpart?
60.5509 Am I subject to this subpart?
60.5510 What is the affected EGU of this subpart?

Emissions Standards

60.5515 What greenhouse gases are regulated by this subpart?
60.5520 What CO2 emissions standards must I meet?

General Compliance Requirements

60.5525 What are my general requirements for complying with this
subpart?
60.5530 Affirmative Defense for Exceedance of Emission Limit During
Malfunction

Monitoring and Compliance Determination Procedures

60.5535 How do I monitor and collect data to demonstrate compliance?
60.5540 How do I demonstrate compliance and determine excess
emissions with my CO2 emissions limit?

Notifications, Reports, and Records

60.5550 What notifications must I submit and when?
60.5555 What reports must I submit and when?
60.5560 What records must I keep?
60.5565 In what form and how long must I keep my records?

Other Requirements and Information

60.5570 What parts of the General Provisions apply to me?
60.5575 Who implements and enforces this subpart?
60.5580 What definitions apply to this subpart?
Table 1 to Subpart TTTT of Part 60--Applicability of Subpart A
General Provisions to Subpart TTTT

Applicability

Sec.  60.5508  What is the purpose of this subpart?

    This subpart establishes emission standards and compliance
schedules for the control of greenhouse gas (GHG) emissions from
electric utility generating units that commenced construction after
April 13, 2012.

Sec.  60.5509  Am I subject to this subpart?

    You are subject to this subpart if you own or operate an electric
utility generating unit that commences construction after April 13,
2012 with a base load rating of more than 73 megawatts (MW) (250
million British thermal units per hour (MMBtu/h)) heat input of fossil
fuel except as specified under Sec.  60.5510(b).

Sec.  60.5510  What is the affected EGU of this subpart?

    (a) The affected facility to which this subpart applies is each
electric utility generating unit (EGU) except as provided for in
paragraph (b) of this section.
    (b) An electric utility generating unit that meets the conditions
specified in paragraphs (b)(1) through (b)(3) of this section is exempt
from this subpart.
    (1) A steam electric generating unit that meets the definition of
municipal waste combustor unit and is subject to subpart Eb of this
part.
    (2) A steam electric generating unit that meets the definition of a
commercial or industrial solid waste incineration unit and is subject
to subpart CCCC of this part.
    (3) Transitional sources.
    (i) You are not subject to this subpart if you own or operate a
transitional source that commences construction within 12 months after
April 13, 2012.
    (ii) For purposes of paragraph (b)(3)(ii) a ``transitional source''
is defined as an EGU with a base load rating of more than 73 megawatts
(MW) (250 million British thermal units per hour (MMBtu/h)) heat input
of fossil fuel, except as provided for in Sec.  60.5510(b)(1) and (2),
and that received a complete permit that meets the requirements of the
Prevention of Significant Deterioration Program under part C of Title I
of the Clean Air Act prior to April 13, 2012 (or that had an approved
PSD permit that has expired and is in the process of being extended, if
the source is participating in a Department of Energy CCS funding
program).

Emissions Standards

Sec.  60.5515  What greenhouse gases are regulated by this subpart?

    The greenhouse gas regulated by this subpart is carbon dioxide
(CO2).

Sec.  60.5520  What CO2 emissions standards must I meet?

    (a) You must not discharge any gases that contain CO2
from any affected EGU into the atmosphere in excess of 454 kilograms
(kg) of CO2 per gross output in Megawatt-hours (MWh) (454
kg/MWh) (1,000 lb/MWh) on a 12-operating month annual average basis,
except as provided for in paragraphs (b) through (d) of this section.
    (b) If the affected EGU utilizes coal or petroleum coke for fuel
and is designed to allow installation and operation of a carbon capture
and storage (CCS) system, you may comply with each standard in
paragraphs (b)(1) through (3) as an alternative to complying with
paragraph (a) of this section.
    (1) For each year until the 11th year of operation, you must not
discharge any gases that contain CO2 from the affected EGU
into the atmosphere in excess of 816 kg/MWh (1,800 lb/MWh) gross output
on a 12-operating month annual average basis, and
    (2) Beginning with the 11th year of operation, the CCS system must
be operational and you must not discharge any gases that contain
CO2 from the affected EGU into the atmosphere in excess of
272 kg/MWh (600 lb/MWh) gross output on a 12-operating month annual
average basis, and
    (3) You must not discharge any gases that contain CO2
from the affected EGU into the atmosphere in excess of 454 kg/MWh gross
output on a 30-year average basis.

    (c) Electric utility generating units located in a non-continental
area are not subject to the requirements of this subpart.
    (d) Simple cycle combustion turbines are not subject to the
requirements of this subpart.

General Compliance Requirements

Sec.  60.5525  What are my general requirements for complying with this
subpart?

    (a) You must be in compliance with the emissions limits in this
subpart applicable to your affected EGU. These limits apply at all
times.
    (b) At all times you must operate and maintain each affected EGU,
including associated equipment and monitoring equipment, in a manner
consistent with safety and good practices for minimizing CO2
emissions. Determination of whether such operation and maintenance
procedures are being used will be based on information available to the
Administrator which may include, but is not limited to, fuel use
records, monitoring results, review of operation and maintenance
procedures, review of operation and maintenance records, review of
reports required by this subpart, and inspection of the facility.
    (c) For each affected EGU subject to the CO2 emissions
limits in Sec.  60.5520, you must measure or calculate a 12 month
rolling average CO2 emission rate, calculated per calendar
month, in terms of tons/MWh.
    (1) If your EGU is subject to the requirements of 40 CFR
75.10(a)(3)(i), you must use the CO2 CEMS to measure the 12
month rolling average CO2 emissions rate.
    (d) You must conduct an initial compliance determination for your
affected EGU according to the requirements in this subpart within 30
days following the first day of the 13th operating month following the
date of initial operations. Thereafter, you must demonstrate continuous
compliance according to the requirements in this subpart each calendar
month determined to be an operating month.

Sec.  60.5530  Affirmative Defense for Exceedance of Emission Limit
During Malfunction.

    In response to an action to enforce the standards you may assert an
affirmative defense to a claim for civil penalties for exceedances of
such standards that are caused by malfunction, as defined at 40 CFR
60.2. Appropriate penalties may be assessed, however, if the respondent
fails to meet its burden of proving all of the requirements in the
affirmative defense. The affirmative defense shall not be available for
claims for injunctive relief.
    (a) To establish the affirmative defense in any action to enforce
such a limit, the owners or operators of facilities must timely meet
the notification requirements in paragraph (b) of this section, and
must prove by a preponderance of evidence that:
    (1) The excess emissions:
    (i) Were 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;
    (ii) Could not have been prevented through careful planning, proper
design or better operation and maintenance practices; and
    (iii) Did not result from any activity or event that could have
been foreseen and avoided, or planned for; and
    (iv) Were not part of a recurring pattern indicative of inadequate
design, operation, or maintenance;
    (2) Repairs were made as expeditiously as practicable when the
applicable emission limitations were being exceeded. Off-shift and
overtime labor were used, to the extent practicable to make these
repairs;
    (3) The frequency, amount and duration of the excess emissions
(including any bypass) were minimized to the maximum extent practicable
during periods of such emissions;
    (4) If the excess emissions resulted from a bypass of control
equipment or a process, then the bypass was unavoidable to prevent loss
of life, personal injury, or severe property damage;
    (5) All practicable steps were taken to minimize the impact of the
excess emissions on ambient air quality, the environment and human
health;
    (6) All emissions monitoring and control systems were kept in
operation if at all practicable, consistent with safety and good air
pollution control practices;
    (7) All of the actions in response to the excess emissions were
documented by properly signed, contemporaneous operating logs;
    (8) At all times, the facility was operated in a manner consistent
with good practices for minimizing emissions; and
    (9) A written root cause analysis has been prepared, the purpose of
which is to determine, correct, and eliminate the primary causes of the
malfunction and the excess emissions resulting from the malfunction
event at issue. The analysis shall also specify, using best monitoring
methods and engineering judgment, the amount of excess emissions that
were the result of the malfunction.
    (b) The owner or operator of an affected EGU experiencing an
exceedance of its emission limit(s) during a malfunction shall notify
the Administrator by telephone or facsimile (FAX) transmission as soon
as practicable, but no later than two (2) business days after the
initial occurrence of the malfunction, if it wishes to avail itself of
an affirmative defense to civil penalties for that malfunction. The
owner or operator seeking to assert an affirmative defense shall also
submit a written report to the Administrator within 45 days of the
initial occurrence of the exceedance of the standard to demonstrate,
with all necessary supporting documentation, that it has met the
requirements set forth in paragraph (a) of this section. The owner or
operator may seek an extension of this deadline for up to 30 additional
days by submitting a written request to the Administrator before the
expiration of the 45-day period. Until a request for an extension has
been approved by the Administrator, the owner or operator is subject to
the requirement to submit such report within 45 days of the initial
occurrence of the exceedances.

Monitoring and Compliance Determination Procedures

Sec.  60.5535  How do I monitor and collect data to demonstrate
compliance?

    (a) You must 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 applicable
requirements in Sec.  60.13, 40 CFR part 75, and this section.
    (b) Follow the applicable quality assurance procedures for
CO2 emissions in appendices B, D, and G to 40 CFR part 75.
    (c) If you determine the your affected EGU's CO2 mass
emissions rate by monitoring fuel combusted in the affected EGU and
periodic fuel sampling as allowed under Sec.  60.5525(c)(2), you must
use the procedures specified in 40 CFR part 75, appendix G.
    (1) Determine a site-specific F factor using the ultimate analysis
and GCV in equation F-7a of 40 CFR part 75, Appendix F; and
    (2) Monitor and determine the affected EGU's daily fuel consumption
for each type of fuel combusted in the affected EGU.
    (3) Use ASTM D5287-08 (Standard Practice for Automatic Sampling of
Gaseous Fuels) to collect a representative gaseous fuel sample.

    (4) Use one of the following methods to collect a representative
liquid oil fuel sample:
    (i) ASTM D4057-06 (Standard Practice for Manual Sampling of
Petroleum and Petroleum Products) or
    (ii) ASTM D4177-95 (2010) (Standard Practice for Automatic Sampling
of Petroleum and Petroleum Products).
    (d) You must monitor and record the applicable data needed to
determine your affected EGU's gross output for each operating month.
    (e) Follow the applicable missing data substitution procedures in
40 CFR part 75 for CO2 concentration, stack gas flow rate,
fuel flow rate, high heating value, and fuel carbon content.

Sec.  60.5540  How do I demonstrate compliance and determine excess
emissions with my CO2 emissions limit?

    (a) If you use a CO2 CEMS to demonstrate compliance you
must use the procedure specified in paragraphs (a)(1) through (5) of
this section to determine the 12-operating month rolling average
CO2 emissions rate for your affected EGU.
    (1) Calculate hourly CO2 mass emissions for each hour of
the operating month in terms of kilograms CO2 using CFR 40
part 75 appendix G.
    (2) Determine hourly gross output in terms of MWh for each hour of
the operating month.
    (3) Sum the hourly CO2 mass emissions for the operating
month, and sum the hourly gross output for the operating month.
    (4) Divide the total CO2 mass emissions calculated for
the month by the total hourly gross output calculated for the operating
month.
    (5) Add the quotient to the sum of the quotients of the previous 11
operating months and divide by 12 to determine the 12-operating month
rolling average.
    (6) If the 12-operating month rolling average value does not exceed
the applicable emissions limit in Sec.  60.5520, your affected EGU is
determined to be in compliance with the emissions limit. Otherwise,
your affected EGU is determined to have excess emissions.
    (b) If you use fuel sampling to demonstrate compliance, you must
use the procedure specified in paragraphs (b)(1) through (5) of this
section to determine the 12-operating month rolling average
CO2 emissions rate for your affected EGU.
    (1) Calculate monthly CO2 mass emissions by multiplying
the monthly F factor by the monthly fuel consumption.
    (2) Sum the hourly gross output in terms of MWh for the month.
    (3) Divide the monthly CO2 mass emissions by the sum of
the hourly gross output for the month.
    (4) Add the quotient to the sum of the quotients of the previous 11
operating months to determine the 12-operating month rolling average.
    (5) If the 12-operating month rolling average value does not exceed
the applicable emissions limit in Sec.  60.5520, your affected EGU is
determined to be in compliance with the emissions limit. Otherwise,
your affected EGU is determined to have excess emissions.
    (c) If you elect to comply with Sec.  60.5520(b), the 30-year
average CO2 emissions rate for your affected EGU is the sum
of the monthly CO2 emissions for each operating month for
the 30-year period divided by the sum of the monthly gross output in
terms of MWh for the 30-year period. Use the procedure specified in
paragraphs (c)(1) through (4) of this section to determine the 12-month
annual average CO2 emissions rate for your affected EGU.
    (1) If you do not use a CO2 CERMS to demonstrate
compliance with Sec.  60.5520(b), you must calculate hourly
CO2 mass emissions for each hour of the 12-month annual
period in terms of kilograms CO2 using CFR 40 Part 75
Appendix G. If you use a CO2 CERMS to demonstrate compliance
with Sec.  60.5520(b) you must calculate hourly CO2 mass
emissions for each hour of the 12-month annual period in terms of
kilograms CO2 using the CERMS hourly mass emissions
measurements.
    (2) Determine hourly gross output in terms of MWh for each hour of
the 12-month annual period.
    (3) Sum the hourly CO2 mass emissions for the 12-month
annual operating period, and sum the hourly gross output for the 12-
month annual operating period.
    (4) Divide the total CO2 mass emissions calculated for
the 12-month annual operating period by the total hourly gross output
calculated for the 12-month annual operating period.
    (5) If the 12-month annual average value does not exceed the
applicable emissions limit in Sec.  60.5520, your affected EGU is
determined to be in compliance with the emissions limit. Otherwise,
your affected EGU is determined to have excess emissions.

Notification, Reports, and Records

Sec.  60.5550  What notifications must I submit and when?

    (a) You must prepare and submit notifications specified in Sec.
60.7(a) and Sec.  60.19, as applicable to your affected EGU.
    (b) You must prepare and submit notifications specified in 40 CFR
part 75.61, as applicable to your affected EGU.

Sec.  60.5555  What reports must I submit and when?

    (a) You must prepare and submit reports specified in Sec.  60.7(c)
through (e) and Sec.  60.19, as applicable to your affected EGU. All
reports required under Sec.  60.7 must be submitted by the 30th day
following the end of each 6-month period.
    (1) The excess emissions and continuous monitoring systems
performance reports and-or summary report forms required in Sec.
60.7(c) must be submitted to the EPA's WebFIRE database by using the
Compliance and Emissions Data Reporting Interface (CEDRI) that is
accessed through the EPA's Central Data Exchange (CDX)(www.epa.gov/cdx). In CEDRI, the owner or operator shall use the appropriate
electronic reporting form for this subpart or provide an alternate
electronic file consistent with EPA's form output format.
    (b) You must follow the applicable reporting requirements and
submit reports as required in subpart G of 40 CFR part 75. You must
report CO2 mass emissions data, and other related data
electronically using the Emissions Collection and Monitoring Plan
System (ECMPS).

Sec.  60.5560  What records must I maintain?

    (a) You must maintain records of your information used to
demonstrate compliance with this subpart as specified in Sec.  60.7 (b)
and (f).
    (1) Notwithstanding the requirements of this section you do not
need to maintain records of the reports that have been submitted to the
EPA's WebFIRE database as required in Sec.  60.5555(a)(1).
    (b) You must follow the applicable recordkeeping requirements and
maintain records as required in subpart F of 40 CFR part 75.
    (c) If you determine the CO2 mass emissions rate by
monitoring fuel combusted in an affected EGU and periodic fuel sampling
according to the requirements in this rule then you must maintain
records of fuel type and quantity combusted in the affected EGU for
each operating month the information specified in paragraphs (c) (1)
and (2) of this section.
    (1) Records of fuel type and quantity combusted in the affected EGU
for each operating month.
    (2) Records of the calculations performed to determine the site-
specific F factor and monthly total CO2 mass emissions
rates.
    (d) Records of the applicable data recorded and calculations
performed used to determine your affected EGU's gross output for each
operating month.

Sec.  60.5565  In what form and how long must I keep my records?

    (a) Your records must be in a form suitable and readily available
for expeditious review.
    (b) You must keep each record for 5 years following the date of
each occurrence, measurement, maintenance, corrective action, report,
or record except those records required to demonstrate compliance with
the emissions limits in Sec.  60.5520(b). Records required to
demonstrate compliance with the emissions limits in Sec.  60.5520(b)
must be kept for at least 40 years following the date of initial
startup of the affected EGU.
    (c) You must keep each record on site for at least 2 years after
the date of each occurrence, measurement, maintenance, corrective
action, report, or record, according to Sec.  60.10. You can keep the
records off site for the remaining years as required by this subpart.

Other Requirements and Information

Sec.  60.5570  What parts of the General Provisions apply to me?

    Table 1 to this subpart shows which parts of the General Provisions
in Sec. Sec.  60.1 through 60.19 apply to you.

Sec.  60.5575  Who implements and enforces this subpart?

    (a) This subpart can be implemented and enforced by the EPA, or a
delegated authority such as your state, local, or tribal agency. If the
Administrator has delegated authority to your state, local, or tribal
agency, then that agency (as well as the EPA) has the authority to
implement and enforce this subpart. You should contact your EPA
Regional Office to find out if this subpart is delegated to your state,
local, or tribal agency.
    (b) In delegating implementation and enforcement authority of this
subpart to a state, local, or tribal agency, the authorities listed in
paragraphs (b)(1) through (5) of this section are retained by the
Administrator and are not transferred to the state, local, or tribal
agency; however, the EPA retains oversight of this subpart and can take
enforcement actions, as appropriate.
    (1) Approval of alternatives to the emission standards.
    (2) Approval of major alternatives to test methods.
    (3) Approval of major alternatives to monitoring.
    (4) Approval of major alternatives to recordkeeping and reporting.
    (5) Performance test and data reduction waivers under Sec.
60.8(b).

Sec.  60.5580  What definitions apply to this subpart?

    As used in this subpart, all terms not defined herein will have the
meaning given them in the Clean Air Act and in subpart A (General
Provisions of this part).
    Affirmative defense means, 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.
    Base load rating means the maximum amount of heat input (fuel) that
a steam generating unit can combust on a steady state basis, as
determined by the physical design and characteristics of the steam
generating unit at ISO conditions. For a stationary combustion turbine
base load means 100 percent of the design heat input capacity of the
stationary combustion turbine engine at ISO conditions.
    Carbon capture and storage (CCS) means a process that includes
capture and compression of CO2 produced by an electric
utility generating unit before release to the atmosphere; transport of
the captured CO2 (usually in pipelines); and storage of that
CO2 in geologic formations, such as deep saline formations,
oil and gas reservoirs, and unmineable coal seams.
    Coal means all solid fuels classified as anthracite, bituminous,
subbituminous, or lignite by the American Society of Testing and
Materials in ASTM D388 (incorporated by reference, see Sec.  60.17),
coal refuse, and petroleum coke. Synthetic fuels derived from coal for
the purpose of creating useful heat, including but not limited to
solvent-refined coal, gasified coal (not meeting the definition of
natural gas), coal-oil mixtures, and coal-water mixtures are included
in this definition for the purposes of this subpart.
    Coal refuse means waste products of coal mining, physical coal
cleaning, and coal preparation operations (e.g. culm, gob, etc.)
containing coal, matrix material, clay, and other organic and inorganic
material.
    Combined cycle means a stationary turbine combustion system where
heat from the turbine exhaust gases is recovered by a heat recovery
steam generating unit.
    Combined heat and power, also known as ``cogeneration,'' means a
steam-generating unit that simultaneously produces both electric (and
mechanical) and useful thermal energy from the same primary energy
source.
    Distillate oil means fuel oils that contain 0.05 weight percent
nitrogen or less and comply with the specifications for fuel oil
numbers 1 and 2, as defined by the American Society of Testing and
Materials in ASTM D396 (incorporated by reference, see Sec.  60.17),
diesel fuel oil numbers 1 and 2, as defined by the American Society for
Testing and Materials in ASTM D975 (incorporated by reference, see
Sec.  60.17), kerosene, as defined by the American Society of Testing
and Materials in ASTM D3699 (incorporated by reference, see Sec.
60.17), biodiesel as defined by the American Society of Testing and
Materials in ASTM D6751 (incorporated by reference, see Sec.  60.17),
or biodiesel blends as defined by the American Society of Testing and
Materials in ASTM D7467 (incorporated by reference, see Sec.  60.17).
    Electric utility generating unit or EGU means any steam electric
generating unit or stationary combustion turbine that is constructed
for the purpose of supplying more than one-third of its potential
electric output capacity and more than 25 MW net-electrical output to
any utility power distribution system for sale. Also, any steam
supplied to a steam distribution system for the purpose of providing
steam to a steam-electric generator that would produce electrical
energy for sale is considered in determining the electrical energy
output capacity of the affected EGU.
    Excess emissions means a specified averaging period over which the
CO2 emissions rate are higher than the applicable emissions
standard.
    Federally enforceable means all limitations and conditions that are
enforceable by the Administrator, including the requirements of 40 CFR
parts 60 and 61, requirements within any applicable State
implementation plan, and any permit requirements established under 40
CFR 52.21 or under 40 CFR 51.18 and 51.24.
    Fossil fuel means natural gas, petroleum, coal, and any form of
solid, liquid, or gaseous fuel derived from such material for the
purpose of creating useful heat.
    Gaseous fuel means any fuel that is present as a gas at standard
conditions and includes, but is not limited to, natural gas, refinery
fuel gas, process gas, coke-oven gas, synthetic gas, and gasified coal.
    Gross output means the gross electrical or mechanical output from
the unit plus 75 percent of the useful thermal output measured relative
to ISO conditions that is not used to generate additional electrical or
mechanical output or to enhance the performance of

the unit (i.e., steam delivered to an industrial process).
    Integrated gasification combined cycle electric utility generating
unit means an electric utility combined cycle gas turbine that is
designed to burn fuels containing 50 percent (by heat input) or more
solid-derived fuel not meeting the definition of natural gas. The
Administrator may waive the 50 percent solid-derived fuel requirement
during periods of the gasification system construction or repair. No
solid fuel is directly burned in the unit during operation.
    ISO conditions means 288 Kelvin (15[deg] C), 60 percent relative
humidity and 101.3 kilopascals pressure.
    Natural gas means a fluid mixture of hydrocarbons (e.g., methane,
ethane, or propane), composed of at least 70 percent methane by volume
or that has a gross calorific value between 35 and 41 megajoules (MJ)
per dry standard cubic meter (950 and 1,100 Btu per dry standard cubic
foot), that maintains a gaseous state under ISO conditions. In
addition, natural gas contains 20.0 grains or less of total sulfur per
100 standard cubic feet. Finally, natural gas does not include the
following gaseous fuels: landfill gas, digester gas, refinery gas, sour
gas, blast furnace gas, coal-derived gas, producer gas, coke oven gas,
or any gaseous fuel produced in a process which might result in highly
variable sulfur content or heating value.
    Net-electric output means the gross electric sales to the utility
power distribution system minus purchased power on a calendar year
basis.
    Non-continental area means the State of Hawaii, the Virgin Islands,
Guam, American Samoa, the Commonwealth of Puerto Rico, or the Northern
Mariana Islands.
    Operating month means a calendar month during which any fuel is
combusted in the electric utility generating unit at any time.
    Out-of-control period means any period beginning with the quadrant
corresponding to the completion of a daily calibration error, linearity
check, or quality assurance audit that indicates that the instrument is
not measuring and recording within the applicable performance
specifications and ending with the quadrant corresponding to the
completion of an additional calibration error, linearity check, or
quality assurance audit following corrective action that demonstrates
that the instrument is measuring and recording within the applicable
performance specifications.
    Potential electric output means 33 percent of the maximum design
heat input capacity of the steam generating unit, divided by 3,413 Btu/
KWh, divided by 1,000 kWh/MWh, and multiplied by 8,760 h/yr (e.g., a
steam generating unit with a 100 MW (340 MMBtu/h) fossil-fuel heat
input capacity would have a 289,080 MWh 12 month potential electrical
output capacity).
    Simple cycle combustion turbine means a stationary combustion
turbine that which does not recover heat from the combustion turbine
exhaust gases for purposes other than enhancing the performance of the
combustion turbine itself.
    Solid fuel means any fuel that has a definite shape and volume, has
no tendency to flow or disperse under moderate stress, and is not
liquid or gaseous at ISO conditions. This includes, but is not limited
to, coal, biomass, and pulverized solid fuels.
    Stationary combustion turbine means all equipment, including but
not limited to the turbine, the fuel, air, lubrication and exhaust gas
systems, control systems (except emissions control equipment), heat
recovery system, fuel compressor, heater, and/or pump, post-combustion
emission control technology, and any ancillary components and sub-
components comprising any simple cycle stationary combustion turbine,
any combined cycle combustion turbine, and any combined heat and power
combustion turbine based system. Stationary means that the combustion
turbine is not self propelled or intended to be propelled while
performing its function. It may, however, be mounted on a vehicle for
portability.
    Steam electric generating unit means any furnace, boiler, or other
device used for combusting fuel for the purpose of producing steam
(including fossil fuel-fired steam generators associated with combined
cycle gas turbines; nuclear steam generators are not included) plus any
integrated device that provides electricity or useful thermal output to
either the boiler or to power auxiliary equipment.
    Useful thermal output means the thermal energy made available for
use in any industrial or commercial process, or used in any heating or
cooling application, i.e., total thermal energy made available for
processes and applications other than electrical generation or to
enhance the performance of the stationary combustion turbine. Thermal
output for this subpart means the energy in recovered thermal output
measured against the energy in the thermal output at ISO conditions.

        Table 1 to Subpart TTTT of Part 60--Applicability of Subpart A General Provisions to Subpart TTTT
----------------------------------------------------------------------------------------------------------------
    General provisions citation        Subject of citation     Applies to  subpart TTTT         Explanation
----------------------------------------------------------------------------------------------------------------
Sec.   60.1........................  Applicability.........  Yes.                         ......................
Sec.   60.2........................  Definitions...........  Yes........................  Additional terms
                                                                                defined in Sec.
                                                                                60.5580.
Sec.   60.3........................  Units and               Yes.                         ......................
                                      Abbreviations.
Sec.   60.4........................  Address...............  Yes.                         ......................
Sec.   60.5........................  Determination of        Yes.                         ......................
                                      construction or
                                      modification.
Sec.   60.6........................  Review of plans.......  Yes.                         ......................
Sec.   60.7........................  Notification and        Yes........................  Except for the
                                      Recordkeeping.                                       requirements to
                                                                                submit written excess
                                                                                emissions reports
                                                                                under Sec.   60.7(c).
Sec.   60.8........................  Performance tests.....  No.                          ......................
Sec.   60.9........................  Availability of         Yes.                         ......................
                                      Information.
Sec.   60.10.......................  State authority.......  Yes.                         ......................
Sec.   60.11.......................  Compliance with         No.                          ......................
                                      standards and
                                      maintenance
                                      requirements.
Sec.   60.12.......................  Circumvention.........  Yes.                         ......................
Sec.   60.13.......................  Monitoring              Yes.                         ......................
                                      requirements.
Sec.   60.14.......................  Modification..........  No.                          ......................
Sec.   60.15.......................  Reconstruction........  No.                          ......................

Sec.   60.16.......................  Priority list.........  No.                          ......................
Sec.   60.17.......................  Incorporations by       Yes.                         ......................
                                      reference.
Sec.   60.18.......................  General control device  No.                          ......................
                                      requirements.
Sec.   60.19.......................  General notification    Yes.                         ......................
                                      and reporting
                                      requirements.
----------------------------------------------------------------------------------------------------------------

[FR Doc. 2012-7820 Filed 4-12-12; 8:45 am]
BILLING CODE 6560-50-P