proposing several revisions to the part 70 and part 71 regulations in
response to the proposed regulation of GHGs under section 111, while
retaining the general approach that we described in the Tailoring Rule.
At the time of the promulgation of the Tailoring Rule, there were no
section 111 standards (or other standards) that had been promulgated
that would have resulted in title V fee requirements being triggered
for GHGs. Thus, the rationale we use now is necessarily different than
the rationale we used for the Tailoring Rule fee discussion. If the
commenter is referring to the requests of certain state agencies in
their comments on the Tailoring Rule for the EPA to set a presumptive
fee of GHGs, we are responding to that request in this proposal by
proposing to set a presumptive fee cost adjustment. If the commenter is
referring to the fee flexibility afforded by 40 CFR 70.9(b)(3), we
respond that we are not proposing to revise that regulatory provision.
A state commenter generally asked us if it could refrain from requiring
a fee for CO2 (or GHG) if it could show that it can
otherwise generate a fee sufficient to meet the ``program support
requirements'' of title V. The response to this comment is yes, based
on the following analysis. Title V requires permitting authorities to
collect fees from sources that are ``sufficient to cover all reasonable
(direct and indirect) costs required to develop and administer [title
V] programs.'' \275\ States have adopted various fee schedules to meet
this requirement. 40 CFR 70.9(b)(3) allows a State program's fee
schedule to include emissions fees, application fees, service-based
fees or other types of fees, or any combination thereof, to meet the
requirements of the collection and retention of revenues sufficient to
cover the permit program costs. Further, states are not required to
calculate fees on any particular basis or in the same manner for all
part 70 sources or for all regulated air pollutants, provided that they
collect a total amount of fees sufficient to meet the program support
requirements. This flexibility is also true for states that use the
presumptive minimum approach to demonstrate they would collect
sufficient fees to fund the program. In the final Tailoring Rule (75 FR
31584, June 3, 2010), we did not change our fee regulations to require
title V fees for GHGs or require new fee demonstrations from states
related to permitting GHGs, and we have retained

the same policies for the purposes of the recent Step 3 rule (77 FR
41051, July 12, 2012). In the final Tailoring Rule, we recommended that
each state, local or tribal program review its resource needs for GHGs
and determine if the existing fee approaches would be adequate. If
those approaches were not adequate, we suggested that they should be
proactive in raising fees to cover the direct and indirect costs of the
program or develop other alternative approaches to meet the shortfall.
Therefore, we agree with the commenter that consistent with 40 CFR
70.9(b)(3), if a state generates fees ``sufficient to meet the program
support requirements,'' without charging fees based on GHG emissions,
then a fee does not have to be charged specifically for GHGs.\276\
Thus, this proposal does not seek to revise fee schedule flexibility
for states and instead focuses on revising the presumptive minimum fee
provisions under part 70 to more appropriately account for GHG program
costs. This notice does not propose any new requirements for states
that do not use the presumptive approach to establish adequacy of fees.
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    \275\ The fee provisions are set forth in CAA section 502(b)(3)
and in our regulations at 40 CFR 70.9 and 71.9.
    \276\ Conversely, where a state cannot show that sufficient fees
are being collected, the state would need to modify its fee schedule
(which could, but need not, involve charging fees for GHG
emissions).
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3. Today's Proposal To Address GHGs in Title V Fees
    In this part of the preamble we explain and solicit comment on
options to address the title V fee issues raised by the proposed
regulation of GHGs under this NSPS. In sum, we propose to exempt GHGs
from the presumptive fee calculation, yet account for the costs of GHG
permitting through a cost adjustment to ensure that fees will be
collected that are sufficient to cover the program costs. We request
comment on these proposals, particularly from state, local, and tribal
permitting agencies, and particularly with respect to which approach
would be most appropriate, feasible, and workable and result in fees
that would be adequate to cover the direct and indirect costs of
permitting GHGs. We also invite comments on ways to improve this
proposal and/or address this issue in other ways consistent with the
same principles, concerns, and statutory authority that we have
described for this proposal.
a. Exemption of GHGs From Presumptive Fee Calculation
    For the reasons discussed earlier in this proposal, we propose to
exempt GHGs from the definition of ``regulated pollutant (for
presumptive fee calculation)'' in 40 CFR 70.2 in order to exclude GHGs
from being subject to the statutory fee rate set for the presumptive
minimum fee calculation of 40 CFR 70.9(b)(2)(i). Pursuant to the
authority of section 502(b)(3)(B)(i), we are proposing to determine
that utilizing the statutory fee rate for GHGs would be inappropriate
because it would result in excessive fees, far above the reasonable
costs of a program. We are proposing a significantly smaller cost
adjustment for GHGs to reflect the program costs related to GHGs.
    We have estimated the cost of permitting GHGs associated with the
Tailoring Rule thresholds in an economic analysis performed for the
Tailoring Rule and in several documents related to Information
Collection Request (ICR) requirements for part 70 and 71, and we
believe these analyses provide a basis for estimating the costs related
to GHG permitting for the typical permitting authority. Thus, we
propose to revise 40 CFR 70.9(b)(2)(i) to add a GHG cost adjustment to
account for the GHG permitting program costs.
b. Addition of a GHG Cost Adjustment to the Presumptive Minimum Fee
Calculation
    We propose to revise the presumptive minimum fee provisions of part
70 to add a GHG cost adjustment to account for the typical GHG
permitting program costs that may not already be covered by the
existing presumptive minimum fee provisions of parts 70 and 71. The
current presumptive minimum fee provisions of the title V rules
implements the statutory mandate to collect fees that are sufficient to
cover the direct and indirect GHG program costs. Since we are not
proposing to charge fees for GHGs at the statutory rate ($25 per ton,
adjusted for inflation) due to concerns raised by permitting
authorities and others about this resulting in excessive fees, we may
need an alternative presumptive minimum fee to recover any costs
related to GHGs that would not otherwise be covered by the presumptive
minimum fee that is calculated based on emissions of regulated air
pollutants, excluding GHGs. We estimated certain incremental GHG
program costs that would not be covered under the context of the
Tailoring Rule, but we did not revise our permit rule to reflect those
costs at that time. We are aware that the EGU NSPS may further increase
permitting authority costs above the levels that would be covered by
presumptive minimum fee provisions that exclude GHGs, but we are also
concerned that accounting for GHGs using the statutory rate would
result in excessive calculation of costs. Thus, to address these
concerns, we are proposing two alternative options to adjust the
presumptive minimum fee provisions of the regulations, including a
modest additional cost for each GHG-related activity of certain types
that a permitting authority would process over the period covered by
the presumptive minimum fee calculation, and a modest additional
increase in the per ton rate used in the presumptive minimum
calculation. We are also soliciting comment on an option that would
calculate no additional costs for GHGs.
    When we promulgate step 4 of the Tailoring Rule, and depending on
EPA's proposal(s) and final action(s) there, we may revisit the GHG
cost adjustment and potentially revise it, taking into account any
changes in permitting authority costs for GHGs related to the
obligations for permitting authorities under that rulemaking.
    In addition, as a general matter, the presumptive minimum
adjustments for part 70 we propose for GHGs are based, in part, on
information concerning permitting authority burden (in hours) and cost
(in dollars) contained in the Information Collection Request (ICR)
renewal for part 70 \277\ approved by the Office of Management and
Budget on October 3, 2012 for the 36 month period of October 31, 2012
through September 30, 2015. Also, this information is consistent with,
and updates, burden and cost information in the Regulatory Impact
Assessment (RIA) for the Tailoring Rule \278\ and an ICR change request
for the GHG Tailoring Rule (EPA ICR Number 1587.11), which was approved
by OMB at the time of the promulgation of the Tailoring Rule\279\.
These assumptions are relevant at least through step 3 of the
implementation of the Tailoring Rule. The supporting statement for the
ICR renewal for part 70 sets forth our estimate of the three-year and
annual incremental burden related to certain activities performed by
permitting authorities under the Tailoring Rule. (See Supporting
Statement for the part 70 state Operating Permits Program, document
number EPA-HQ-OAR-2004-0016-0023). The information in the supporting
statement is designed to be a directionally correct assessment of
costs, and thus, may serve as a starting point for considerations of

the possible range of costs to consider when proposing adjustments to
the presumptive minimum fee provisions of part 70 to appropriately
account for GHG permitting program costs.
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    \277\ The most recent part 70 ICR renewal is identified as EPA
ICR number 1587.12 and the ICR for part 70 has been assigned OMB
control number 2060-0243.
    \278\ Regulatory Impact Analysis for the Final Prevention of
Significant Deterioration and Title V Greenhouse Gas Tailoring Rule,
Final Report, May 2010.
    \279\ The ICR change request form for the Tailoring Rule was
based on the assumptions made in the RIA for the Tailoring Rule.
---------------------------------------------------------------------------

    First, we are proposing to adjust the presumptive minimum fee to
account for GHG costs by adding a cost for each GHG-related activity of
certain types that a permitting authority may perform over the period
covered by a presumptive minimum fee calculation. Additional
information supporting this approach may be found in part in Table 12
of the supporting statement (in the ICR) summarizing the permitting
authority burden for particular GHG-related permitting activities.
Table 12 in the ICR shows certain incremental burden assumptions for
certain activities related to GHG permitting program costs in the form
of an hourly burden for each activity that a permitting authority may
process. Based on observations regarding permitting activities since
the Tailoring Rule, we have adapted these assumptions for the purposes
of this option and included certain activities with a somewhat
different description than we used in the table in the ICR in an
attempt to more accurately reflect the types of permitting activities
that have occurred in the GHG permit program. In addition, by making
these clarifying changes, we are trying to more closely track the
language in the CAA and parts 70 and 71 regarding the specific of the
permit process. We are proposing to include three general activities in
this proposed option: (1) ``GHG completeness determination (for initial
permits or for updated applications)'' at 43 hours, (2) ``GHG
evaluation for a modification or related permit action'' at 7 hours,
and (3) ``GHG evaluation at permit renewal'' at 10 burden hours.\280\
The GHG cost adjustment for the presumptive fee would be calculated
under this approach by multiplying the burden hours for each activity
by the cost of staff time (in $ per hour), including wages, benefits,
and overhead, as determined by the state for the particular activities
undertaken. We also solicit comment on the specific burden hours we
propose for these GHG-related activities. The proposed burden hours for
the three activities above were not directly discussed in the ICR or
directly subject to public comment in that context. We believe this
proposal would benefit from state input on the burden hour assumptions
for the activities identified and we solicit comment the burden hour
assumptions and on additional GHG-related permitting activities that
should be added to the list.
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    \280\ A completeness determination is the first step performed
by the permitting authority once a permit application is received.
This step is generally more time consuming for an initial permit
application compared to other permit applications because this is
the initial evaluation leading to the drafting and issuance of the
permit for the first time. Because GHG permitting is in the early
stages of implementation and EPA is in the early stages of issuing
new applicable requirements for GHGs, we believe permitting
authorities will experience additional burdens related to GHGs as
part of this initial completeness determination. Thus, the first
item, ``GHG completeness determination (for initial permit or update
application)'' reflects these additional burdens for completeness
determinations related to GHGs. This item would also cover
subsequent application updates related to an initial application.
See, e.g., 40 CFR 70.5(a)(2). The second item, ``GHG evaluation for
a permit modification or related permitting action'' applies where a
permitting authority undertakes an evaluation of whether a permit
modification involves any GHG-related requirements. This might also
occur, for example, where a synthetic or true minor application is
submitted and the permitting authority needs to undertake a GHG
related analysis to determine if it affects the existing title V
permit. The third item, ``GHG evaluation at permit renewal'' applies
where the permitting authority receives a renewal application that
is not coupled with any facility modifications. The EPA suggests
this language because it is more closely tied to the specific work
to be performed by permitting authorities consistent with statutory
and regulatory obligations.
---------------------------------------------------------------------------

    We are also co-proposing an alternative option under which we would
increase the fee rate used in the presumptive minimum calculation for
each regulated air pollutant, excluding GHGs. This option would rely
primarily on data concerning the state burdens of permitting GHGs
through step 3 of the tailoring rule found in the Information
Collection Request (ICR) for part 70. This suggests that when looking
at Tailoring Rule burden in isolation, that GHG permitting increases
permitting authority burden by about 7 percent above the baseline
burden,\281\ which would be multiplied by the presumptive minimum fee
rate in effect to calculate the revise presumptive fee rate to account
for GHG. Under this approach, the new presumptive minimum fee effective
for the current period would be $50.00 per ton for each regulated
pollutant (for presumptive fee calculation).\282\ Several states
suggested an approach similar to this in comments on the Tailoring
Rule, however, their comments assumed we would not be exempting GHGs
from the definition of regulated pollutants (for presumptive fee
calculation), as we are proposing today. We solicit comment on the
appropriateness of the 7 percent fee increase for the presumptive
minimum fee we propose to account for the GHG permitting costs for
permitting authorities under this alternative option. We are
particularly interested in state input on whether this level should be
higher or lower than we propose.
---------------------------------------------------------------------------

    \281\ The baseline costs in the supporting statement for the ICR
were the costs of permitting looking at all activities except for
those related to the GHG tailoring rule and certain other recent
rule changes. Table 14 of the supporting statement shows a
permitting authority burden of 102,122 hours for implementing the
GHG tailoring rule and 1,414,293 hours of baseline permitting
authority burden, and Table 15 shows a permitting authority cost of
$5.5 million for implementing the GHG tailoring rule and $76.4
million for the baseline permitting program.
    \282\ At the current rate for part 70 of $46.73, this would
result in a GHG fee adjustment of about $3.27, or a new rate of
$50.00 per ton for each regulated pollutant (for presumptive fee
calculation).
---------------------------------------------------------------------------

    The two options we co-propose for adjusting the presumptive minimum
fee to account for the costs of GHG permitting are similar in that we
believe they would both result in about the same amount of additional
fee revenue being collected. For the first option, we took the
assumptions approved into the ICR and adapted them somewhat so that
they more accurately reflect the actual implementation experience of
permitting authorities related to GHGs. On the second, alternative
option, we used the ICR estimate to determine the relative contribution
of GHG tailoring rule costs to the total costs of title V permitting
and we assume these relative costs will hold true in any particular
state that uses the presumptive minimum fee approach to demonstrating
fee adequacy. The two options differ in that the first option
calculates the GHG adjustment to the presumptive fee minimum by
determining the number of actual GHG-related activities they have
performed for a period, while the second option calculates the GHG
adjustment by increasing the presumptive fee rate for non-GHG
pollutants by a set ratio to reflect average expected costs. The first
approach requires a state to track the number of activities of these
types it is performing and is thus more burdensome to calculate,
although it may more accurately reflect the actual costs. The second
approach is simpler to calculate and predictable but is less directly
tied to actual implementation experience in a particular state.
    We also solicit comment on whether we need to revise the
presumptive minimum calculation provisions to account for GHGs costs if
we exempt GHGs from the calculation of the presumptive minimum fee. The
basis for this option would be that because most GHG sources that would
be subject to title V permitting, whether due to GHGs or due for other
reasons under the proposed NSPS and applicability provisions of the
permitting rules (see 40 CFR 70.3 and 71.3) would have actual emissions
of other regulated air

pollutants subject to fees, and thus the cost of permitting these
sources may be adequately accounted for without charging any additional
fees specifically based on emissions of GHGs. We also note that support
for this approach can be found in the current OMB-approved ICR for part
70, tables 14, 15 and 18, where the cost of permitting for permitting
authorities is summarized, considering the effects of several recent
EPA rulemakings that were conducted since the last ICR update.
    This proposal does not directly affect those states that do not
rely on the presumptive minimum fee approach to show fee adequacy;
however, non-presumptive fee states are still required to charge
sufficient fees to recover all reasonable direct and indirect program
costs. Part 70 allows the EPA to review state fee programs at any time
to determine if they are collecting fees sufficient to cover their
costs, whether or not states rely on the presumptively minimum fee
approach. We are not requiring any additional detailed fee submittals
from states at this time based on these proposed changes.
    Some states may conclude that they wish to revise their part 70
programs in response to this proposal either to revise their state fee
schedules to prevent any possible collection of excessive fees (e.g.,
if they require any regulated pollutant subject to a section 111
standard to pay a fee) or to charge additional fees to sources because
their presumptive minimum fee target has increased. We solicit comment
on the most expeditious means for EPA to approve title V program
revisions across the states once this proposal is finalized.
    There may be other viable options consistent with statutory and
regulatory authority, principles, and concerns, in addition to those we
have described in this proposal. For example, states have previously
commented on establishing a separate, lower presumptive fee per ton of
GHG emissions). The EPA invites states, local, and/or Tribal
authorities to provide more refined data and/or information surrounding
the unique costs associated with permitting GHG sources under this
proposed rule, and other fee options such data supports. Notably, the
regulatory text included today represents only one option on which
comments are solicited. The EPA is providing full regulatory text only
for this option because it represents the most novel approach. The EPA
is also soliciting comment on other viable approaches described herein,
but considers the discussion provided herein to provide an adequate
basis for public comment. The EPA notes that the final rule may be
based on any of the approaches described in the preamble.
c. Revisions to the Part 71 Fee Schedule
    As part of the promulgation of the final part 71 rule, the EPA
performed a detailed analysis of the costs of developing and
implementing the program and reviewed the inventory of emissions of
regulated pollutants (for fee calculation) to determine the appropriate
emission fee that would be sufficient to recover all direct and
indirect programs costs--we set the fee at $32 per ton, adjusted for
inflation, times the emissions of regulated pollutant (for fee
calculation). (See Federal Operating Programs Fees, Revised Cost
Analysis, February 1996; legacy docket A-93-51, document number II-A-
3.)
    For part 71, we also propose to exempt GHGs from the definition of
regulated pollutant (for fee calculation), which is similar to the
definition of regulated pollutants (for presumptive fee calculation)
used in part 70, for the same reasons we have explained for part 70. In
addition, for the same reasons we explained for part 70, we are
proposing two options for revising the fee schedule of 40 CFR 71.9(c)
to ensure that we continue to recover sufficient fees to fully fund the
part 71 GHG permitting program. The bases for the options were
described in more detail earlier in this proposal with respect to part
70 proposals and those also apply here to part 71.
    First, the EPA (or delegate agency) burden hour assumptions we
propose for each GHG-related permitting activity under part 71 are the
same as we are proposing for states under the presumptive minimum fee
provisions of part 70.\283\ This option would rely on the following
information. The labor rate assumption we propose for the EPA (or
delegate agency) staff time under part 71 is the average hourly rate we
assumed in the supporting statement for the recent part 71 ICR renewal
of $52 per hour in 2011 dollars, including wages, benefits and overhead
costs. We propose to determine the GHG fee adjustment for each GHG
permitting program activity by multiplying the burden hour assumption
we propose by the EPA (or delegate agency) labor rate we propose. Thus,
for example, we propose a set fee to be paid by sources for each
``completeness determination (for new permit or updated application)''
of $364 (7 hours times $52 per hour for the current period). Also, we
propose to charge, for simplicity sake, the same set fees for GHG
activities, whether performed by the EPA, a delegate agency, or by the
EPA with contractor assistance. The appropriate set fees for all GHG
permitting program activities performed for the source would be added
to the traditional fee that is determined based on emissions of each
regulated pollutant (for fee calculation) to determine the total fee
for the source.
---------------------------------------------------------------------------

    \283\ See the supporting statement for the ICR renewal for part
71 approved by the Office of Management and Budget on June 13, 2012
for the 36 month period of June 30, 2012 through May 31, 2015. The
ICR renewal for part 71 is identified as EPA ICR number 1713.10 and
the ICR for part 71 has been assigned OMB control number 2060-0336.
The assumptions of this part 71 ICR renewal for GHG burden are
identical to those used for the part 70 ICR. See Table 12 of the
part 71 supporting statement.
---------------------------------------------------------------------------

    The second option we propose for part 71 is to increase the
emission fee by a modest amount for each regulated air pollutant,
excluding GHGs. For simplicity sake, we propose to charge the same
adjustment under this option that we propose for part 70, or 7 percent,
which would be multiplied by annual part 71 fee in effect to calculate
the revise fee rate.\284\ The rationale for this approach is described
in more detail earlier in this preamble during the part 70 discussion.
---------------------------------------------------------------------------

    \284\ At the current rate for part 71 of $48.33, this would
result in a GHG fee adjustment of $3.38, or a new rate of $51.71 per
ton for each regulated pollutant (for fee calculation).
---------------------------------------------------------------------------

    We also solicit comment on whether we could exclude GHG emissions
from the calculation of the annual part 71 fee for reasons similar to
those we explained for part 70 (e.g., because permitting costs can be
covered by the existing part 71 permit fee).

X. Impacts of the Proposed Action \285\
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    \285\ Note that EPA does not project any difference in the
impacts between the alternative to regulate sources under subparts
Da and KKKK versus regulating them under new subpart TTTT.
---------------------------------------------------------------------------

A. What are the air impacts?

    As explained in the Regulatory Impact Analysis (RIA) for this
proposed rule, available data indicate that, even in the absence of
this rule, existing and anticipated economic conditions will lead
electricity generators to choose new generation technologies that would
meet the proposed standard without installation of additional controls.
Therefore, based on the analysis presented in Chapter 5 of the RIA, the
EPA projects that this proposed rule will result in negligible
CO2 emission changes, quantified benefits, and costs by
2022.\286\
---------------------------------------------------------------------------

    \286\ Conditions in the analysis year of 2022 are represented by
a model year of 2020.

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

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, the
EPA believes that electric power companies would choose to build new
EGUs that comply with the regulatory requirements of this proposal even
in its absence, because of existing and expected market conditions. In
addition, the EPA does 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.
However, because some companies may choose to construct coal or other
fossil fuel-fired units, the RIA also analyzes project-level costs of a
unit with and without CCS, to quantify the potential cost for a fossil
fuel-fired unit with CCS.

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 2022. The owners of newly built
electric generating units will likely choose technologies that meet
these standards even in the absence of this proposal due to existing
economic conditions as normal business practice. Likewise, the EPA
believes this rule will not have any impacts on the price of
electricity, employment or labor markets, or the U.S. 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 meet a
particular performance standard, this rulemaking reduces uncertainty
and may enhance the prospects for new coal-fired generation and the
deployment of CCS, and thereby promote energy diversity.

XI. 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.
    Measurement. We are requesting comment on requiring the use the
following procedures that increase the precision of GHG measurements:
    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 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.
    e. An ambient air argon concentration of 0.93 percent \287\ and a
molecular weight of 39.9 lb/lb-mol in calculating the dry gas molecular
weight.
---------------------------------------------------------------------------

    \287\ http://www.physicalgeography.net/fundamentals/7a.html.
---------------------------------------------------------------------------

    f. A value for pi of 3.14159 when calculating the effective area
for circular stacks.
    g. A daily calibration drift cap no greater than 0.3 percent
CO2 for CO2 CEMS.
    h. A maximum relative accuracy specification of 2.5 percent for
both CO2 and flow rate measurement CEMS.
    i. Method 3B of 40 CFR part 60 in addition to Method 3A, for
CO2 concentration measurement and for molecular weight
determination during CEMS relative accuracy determinations or for
performance testing.
    Coal refuse. In the original proposal, we requested comment on
subcategorizing EGUs that burn over 75 percent coal refuse on an annual
basis. Multiple commenters supported the exemption, citing numerous
environmental benefits of remediating coal refuse piles. Other
commenters disagreed with any exemption, specifically citing the
N2O emissions from fluidized bed boilers (coal refuse-fired
EGUs typically use fluidized bed technology). Due to the environmental
benefits of remediating coal refuse piles cited by commenters, the
limited amount of coal refuse, and that a new coal refuse-fired EGU
would be located in close proximity to the coal refuse pile, we are
continuing to consider establishing a subcategory for coal refuse-fired
EGUs and are requesting additional comments. Specifically, we are
requesting additional information on the net environmental benefits of
coal refuse-fired EGUs, and in the event we do establish a coal refuse-
fired subcategory, what the emissions standard for that subcategory
should be (i.e., should it be based on a lower amount of partial CCS or
on highly efficient generation alone, without the use of CCS). One
commenter on the original proposal stated that existing coal refuse
piles are naturally combusting at a rate of 0.3 percent annually. We
are requesting comment

on assuming this rate of natural combustion and the proper approach to
accounting for naturally occurring emissions from coal refuse piles.
    Compressed Air Energy Storage (CAES) Facilities. CAES technology is
an energy storage technology that involves two steps. Air is compressed
by electric motor driven compressors during off-peak electricity demand
hours and stored in a storage media (e.g., an underground cavern).
Electricity is then generated during peak electricity demand periods by
releasing the high-pressure air, heating the air with natural gas, and
expanding it through sequential turbines (expanders), which drive an
electrical generator. Since natural gas is combusted in the stationary
combustion turbine, a new CAES would potentially have to comply with
one of the proposed emissions standards. However, based on anticipated
capacity factors for new CAES facilities, it is our understanding that
the proposed one-third electric sales of potential electric output
applicability criteria would exempt new CAES facilities from the
proposed emission standards. The EPA is requesting comment on whether
this assumption is accurate. In the event that this is not the case,
the EPA is considering and requesting comment on if new source review
is the appropriate mechanism to establish site specific GHG
requirements for CAES facilities and, if so, whether the EPA should
exempt stationary combustion turbines at CAES facilities from the
proposed CO2 emission standards. We have concluded this
could be appropriate since we expect only a limited number of new CAES
facilities, and the use of stored energy complicates the determination
of compliance with the proposed emission standards.
    District Energy. District energy systems produce steam, hot water
or chilled water at a central facility. The steam, hot water or chilled
water is then distributed through pipes to individual consumers for
space heating, domestic hot water heating and air conditioning. As a
result, individual consumers served by a district energy system do not
need their own heating, water heating or air conditioning systems. Even
though with the proposed definition of net-electric output it is
unlikely that a district energy system would be subject to an emissions
standard, we are considering and requesting comment on an appropriate
method to recognize the environmental benefit of district energy
systems. The steam or hot water distribution system of a district
energy system located in urban areas, college and university campuses,
hospitals, airports, and military installations eliminates the need for
multiple, smaller boilers at individual buildings. A central facility
typically has superior emission controls and consists of a few larger
boilers facilitating more efficient operation than numerous separate
smaller individual boilers. However, when the hot water or steam is
distributed, approximately two to three percent of the thermal energy
in the water and six to nine percent of the thermal energy in the steam
is lost, reducing the net efficiency advantage. To recognize the net
environmental benefit of district energy systems compared to multiple
smaller heating and cooling systems, we are requesting comment on
whether it is appropriate to adjust the measured thermal output from
district energy systems when calculating the emissions rate used for
compliance purposes. For example, if thermal energy from central
district energy systems is approximately 5 percent more efficient than
thermal energy supplied by multiple smaller heating and cooling
systems, the measured thermal output would be divided by 0.95 (e.g.,
100 MMBtu/h of measured steam would be 105 MMBtu/h when determining the
emissions rate). This approach would be similar to the proposed
approach to how the electric output for CHP is considered when
determining regulatory compliance and is consistent with the approach
in the proposed amendments to the combustion turbine NSPS (77 FR
52554). We request that comments include technical analysis of the net
benefits in support of any conclusions on an appropriate adjustment
factor.
    Emergency conditions. We are requesting comment on excluding
electricity generated as a result of a grid emergency declared by the
Regional Transmission Organizations (RTO), Independent System Operators
(ISO) or control area Administrator from counting as net sales when
determining applicability as an EGU. For example, under this approach,
if grid voltage drops below acceptable levels and the affected facility
is the only facility with available capacity, then electricity
generated during this period would not count for applicability
purposes. While the proposed 3 year average electric sales
applicability provides significant flexibility for simple cycle
turbines, we are considering including the emergency conditions
exemption to allow facilities designed with the intent to sell less
than one-third of their potential electric output to continue to
generate electricity during a grid emergency without such generation
counting towards the one-third sales applicability criterion. In the
original 1979 electric utility NSPS rulemaking (44 FR 33580), the EPA
recognized that emergency periods do occur from unplanned EGU outages,
transmission outages or surging customer demand loads. Such occurrences
may require that all available operable EGUs interconnected to the
electrical grid supply power to the grid. Provisions were added to 40
CFR part 60, subpart Da to address emergency conditions when continued
operation of an EGU with a malfunctioning flue gas desulfurization
(FGD) system is acceptable and not considered a violation of the
SO2 emissions standard. These conditions require that all
available capacity from the power company's other EGUs is being used
and all available purchase power from interconnected power companies is
being obtained. In this case, the EPA concluded that the broader
benefits of operating the power plant with the malfunctioning FGD
system to generate electrical power during emergency conditions in
order to ensure uninterrupted electricity supply to the public outweigh
any adverse impacts from a short-term increase in SO2
emission to the atmosphere from the power plant. The definition for a
system emergency we are considering is ``any abnormal system condition
that the Regional Transmission Organizations (RTO), Independent System
Operators (ISO) or control area Administrator determines requires
immediate automatic or manual action to prevent or limit loss of
transmission facilities or generators that could adversely affect the
reliability of the power system and therefore call for maximum
generation resources to operate in the affected area, or for the
specific affected facility to operate to avert loss of load.''
    Initial Design Efficiency Test. We are considering and requesting
comment on requiring an initial performance test for stationary
combustion turbines in addition to the 12-operating-month rolling
average standard. Requiring an initial compliance test that is
numerically more stringent than the annual standard for new combined
cycle facilities would insure that the most efficient stationary
combustion turbines are installed. The less stringent 12-month rolling
average standard would be set at a level that would take into account
actual operating conditions.
    Integrated Equipment. The proposed affected facility definitions
include the traditional generating unit ``plus any integrated equipment
that provides electricity or useful thermal output.''

For example, the definition of a steam generating unit for GHG
purposes, ``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 equipment that provides electricity or useful thermal output
to either the boiler or to power auxiliary equipment'' (emphasis
added). We are considering and requesting comment on also including in
the definition of the affected facility co-located non-emitting energy
generation equipment that is not integrated into the operation of the
affected facility. This approach would provide additional flexibility,
lower compliance costs, and recognize the environmental benefit of non-
emitting sources of electricity and not limit options to integrated
solar thermal. The definition would include the additional language
``or co-located non-emitting energy generation included in the facility
operating permit.'' For example, the definition of a steam generating
unit for GHG purposes would be expanded to read, ``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 equipment that provides electricity or useful
thermal output to either the boiler or to power auxiliary equipment or
co-located non-emitting energy generation included in the facility
operating permit'' (emphasis added). This would permit the use of co-
located photovoltaic solar power, wind turbines, and other non-emitting
energy generation as means for achieving compliance with the emission
standards. Since integrated solar thermal is primarily a feasible
option only for facilities that operate daily (e.g., thermal energy
from the solar thermal is used in the steam cycle generated from the
combustion of fossil fuels), this approach would expand options for
more intermittent intermediate load generators to efficiently integrate
non-emitting energy generation into their design.
    Other GHGs. Today's proposed rule would require continuous
measurement of CO2 from fossil fuel-fired EGUs. Other GHGs,
such as CH4 and N2O are not included in the
proposed emission standards and are also not required to be measured
and reported by affected EGUs as part of today's proposal, even though
their 100-year global warming potential is 21 to 310 times greater than
that of CO2, because their emissions from EGUs are believed
to be negligible when compared to CO2 emissions. We request
comment on the appropriateness, technique, and frequency (one-time or
periodic, but not continuous) of measurement and reporting of
CH4 and N2O emissions from fossil fuel-fired EGUs
as part of the proposed emissions standard. Receipt of this data would
enhance understanding of total GHG emissions from EGUs and could aid
future policy decisions regarding whether these GHGs should be included
in a revised emission standard, as part of 8-year NSPS review and
potential revision cycle.
    Violations. We are proposing that the calculation of the number of
daily violations within an averaging period be determined using the
following methodology. If, for any 12- or 84-operating month period,
the source's emission rate exceeds the standard, the number of daily
violations in the 12- or 84-operating-month averaging period would be
the number of operating days in that period. However, if a violation
occurs directly following the previous 12-operating-month or 84-
operating-month averaging period, daily violations would not double
count operating days that were determined as violations under the
previous averaging period. For example, assume that a facility operates
10 days out of each month for 12 months from January 1, Year 1 to
December 31, Year 1, and exceeds the emissions standard during that 12-
month period. The violation for this January-December Year 1 period
would constitute 120 daily violations. If the facility operated 20 days
the following month, which would be January, Year 2, and was still in
excess of the emissions standard over the period from February, Year 1
to January, Year 2, then 20 additional daily violations would result,
for a total of 140 daily violations. We are requesting comment on this
determination of daily violations for owners/operators that exceeds
either a 12-operating-month or 84-operating-month standard.

XII. 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 51735, 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 Fossil Fuel-Fired Electric Utility
Steam Generating Units and Stationary Combustion Turbines.
    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). The
EPA does not project any new coal-fired EGUs without CCS to be built in
the absence of this proposal. However, because some companies may
choose to construct coal or other fossil fuel-fired units, the RIA also
analyzes project-level costs of a unit with and without CCS, to
quantify the potential cost for a fossil fuel-fired unit with CCS.

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 the EPA ICR number 2465.02.
    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 emissions and downtime, every 3 months.
    When a malfunction occurs, sources must report them according to
the applicable reporting requirements of 40 CFR part 60, subparts Da
and KKKK or subpart TTTT 60.5530. 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 reasonably preventable, and not
caused by poor maintenance 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 affirmative defense, 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.
    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
this rule applies only to sources built in the future. Of the number of
excess emissions events that may be reported by source operators, only
a small number would be expected to result from a malfunction, and only
a subset of excess emissions caused by malfunctions would result in the
source choosing to assert an 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 Da and subpart KKKK or
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 quarterly summary reports which
include reporting of emissions and downtime. All burden estimates are
in 2010 dollars. Average burden hours per response are estimated to be
8 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-2013-0495. 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
the EPA. Since OMB is required to make a decision concerning the ICR
between 30 and 60 days after January 8, 2014, a comment to OMB is best
assured of having its full effect if OMB receives it by February 7,
2014. The final rule will respond to any OMB or public comments on the
information collection requirements contained in this proposal.

C. Regulatory Flexibility Act

    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 8 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 8--Potentially Regulated Categories and Entities \a\
------------------------------------------------------------------------
                                                         Examples of
             Category                 NAICS Code         potentially
                                                     regulated entities
------------------------------------------------------------------------
Industry..........................          221112  Fossil fuel electric
                                                     power generating
                                                     units.
State/Local Government............      \b\ 221112  Fossil fuel electric
                                                     power generating
                                                     units owned by
                                                     municipalities.
------------------------------------------------------------------------
\a\ Include NAICS categories for source categories that own and operate
  electric power generating units (includes boilers and stationary
  combined cycle combustion turbines).
\b\ 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). 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, prior to the April 13, 2012
proposal (77 FR 22392), the EPA determined to seek early input from
representatives of small entities while formulating the provisions of
the 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.
    While formulating the provisions of this proposed regulation, the
EPA also considered the input provided in the over 2.5 million public
comments on the April 13, 2012 proposed rule (77 FR 22392). We invite
comments on all aspects of the proposal and its impacts, including
potential adverse impacts, on small entities.

D. Unfunded Mandates Reform Act

    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). 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 prior to the
April 13, 2012 proposal (77 FR 22392). 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.
    While formulating the provisions of this proposed regulation, the
EPA also considered the input provided in the over 2.5 million public
comments on the April 13, 2012 proposed rule (77 FR 22392).

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. Prior to the April 13, 2012
proposal (77 FR 22392), 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.
While formulating the provisions of this proposed regulation, the EPA
also considered the input provided in the over 2.5 million public
comments on the April 13, 2012 proposed rule (77 FR 22392). In the
spirit of EO 13132, and consistent with the 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

    This action does not have tribal implications, as specified in
Executive Order 13175 (65 FR 67249, November 9, 2000). 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. Thus, Executive Order 13175 does not apply to this
action.
    Although Executive Order 13175 does not apply to this action, EPA
consulted with tribal officials in developing this action. Because the
EPA is aware of Tribal interest in this proposed rule, prior to the
April 13, 2012 proposal (77 FR 22392), the EPA offered consultation
with tribal officials early in the process of developing the 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.
    While formulating the provisions of this proposed regulation, the
EPA also considered the input provided in the over 2.5 million public
comments on the April 13, 2012 proposed rule (77 FR 22392).
    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 action is not
subject to EO 13045 because it is based solely on technology
performance.

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
proposes to use 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.
    This proposed rule limits GHG emissions from new fossil fuel-fired
EGUs by establishing national emission standards for CO2.
The EPA has determined that this proposed rule would not result in
disproportionately high and adverse human health or environmental
effects on minority, low-income, and indigenous populations because it
increases the level of environmental protection for all affected
populations without having any disproportionately high and adverse
human health or environmental effects on any population, including any
minority, low-income or indigenous populations.

XIII. Statutory Authority

    The statutory authority for this action is provided by sections
111, 301, 302, and 307(d)(1)(C) of the CAA as amended (42 U.S.C. 7411,
7601, 7602, 7607(d)(1)(C)). This action is also subject to section
307(d) of the CAA (42 U.S.C. 7607(d)).

List of Subjects

40 CFR Part 60

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

40 CFR Part 70

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

40 CFR Part 71

    Environmental Protection, Administrative practice and procedure,
Air pollution control, Reporting and recordkeeping requirements.

40 CFR Part 98

    Environmental protection, Greenhouse gases and monitoring,
Reporting and recordkeeping requirements.

    Dated: September 20, 2013.
Gina McCarthy,
Administrator.
    For the reasons stated in the preamble, title 40, chapter I, part
60, 70, 71, and 98 of the Code of the Federal Regulations is proposed
to be amended as follows:

PART 60--STANDARDS OF PERFORMANCE FOR NEW STATIONARY SOURCES

0
1. The authority citation for part 60 continues to read as follows:

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

Subpart Da--Standards of Performance for Electric Utility Steam
Generating Units

0
2. Section 60.46Da is added to read as follows:

Sec.  60.46Da  Standards for carbon dioxide (CO2).

    (a) Your affected facility is subject to this section if
construction commenced after [DATE OF PUBLICATION IN THE FEDERAL
REGISTER], and the affected facility meets the conditions specified in
paragraphs (a)(1) and (a)(2) of this section, except as specified in
paragraph (b) of this section.
    (1) The affected facility combusts fossil fuel for more than 10.0
percent of the heat input during any 3 consecutive calendar years.
    (2) The affected facility supplies more than one-third of its
potential electric output and more than 219,000 MWh net-electric output
to a utility power distribution system for sale on an annual basis.
    (b) The following EGUs are not subject to this section:
    (1) The proposed Wolverine EGU project described in Permit to
Install No. 317-07 issued by the Michigan Department of Environmental
Quality, Air Quality Division, effective June 29, 2011 (as revised July
12, 2011).
    (2) The proposed Washington County EGU project described in Air
Quality Permit No. 4911-303-0051-P-01-0 issued by the Georgia
Department of Natural Resources, Environmental Protection Division, Air
Protection Branch, effective April 8, 2010, provided that construction
had not commenced for NSPS purposes as of [DATE OF PUBLICATION IN THE
FEDERAL REGISTER].
    (3) The proposed Holcomb EGU project described in Air Emission
Source Construction Permit 0550023 issued by the Kansas Department of
Health and Environment, Division of Environment, effective December 16,
2010, provided that construction had not commenced for NSPS purposes as
of [DATE OF PUBLICATION IN THE FEDERAL REGISTER].
    (c) As owner or operator of an affected facility subject to this
section, you shall not cause to be discharged into the atmosphere from
the affected facility any gases that contain CO2 in excess
of the emissions limitation specified in either paragraphs (c)(1) or
(c)(2) of this section.
    (1) 500 kilograms (kg) of CO2 per megawatt-hour (MWh) of
gross energy output (1,100 lb CO2/MWh) on a 12-operating
month rolling average basis; or
    (2) 480 kg of CO2 per MWh of gross energy output (1,050
lb CO2/MWh) on an 84-operating month rolling average basis.
    (d) You must make compliance determinations at the end of each
operating month, as provided in

paragraphs (d)(1) and (d)(2) of this section. For the purpose of this
section, operating month means a calendar month during which any fossil
fuel is combusted in the affected facility.
    (1) If you elect to comply with the CO2 emissions
limitation in paragraph (c)(1) of this section, you must determine
compliance monthly by calculating the average CO2 emissions
rate for the affected facility at the end of each 12-operating month
period that includes, as the last month, the month for which you are
determining compliance.
    (2) If you elect to comply with the CO2 emissions
limitation in paragraph (c)(2) of this section, you must determine
compliance monthly by calculating the average CO2 emissions
rate for the affected facility at the end of each 84-operating month
period that includes, as the last month, the month for which you are
determining compliance.
    (e) You must conduct an initial compliance determination with the
CO2 emissions limitation for your affected facility within
30 days after accumulating the required number of operating months for
the compliance period with which you have elected to comply (i.e., 12-
operating months or 84-operating months). The first operating month
included in this compliance period is the month in which emissions
reporting is required to begin under Sec.  75.64(a) of this chapter.
    (f) You must monitor and collect data to demonstrate compliance
with the CO2 emissions limitation according to the
requirements in paragraphs (f)(1) through (4) of this section.
    (1) You must prepare a monitoring plan in accordance with the
applicable provisions in Sec.  75.53(g) and (h) of this chapter.
    (2) You must measure the hourly CO2 mass emissions from
each affected facility using the procedures in paragraphs (f)(2)(i)
through (vii) of this section, except as provided in paragraph (f)(3)
of this section.
    (i) You must install, certify, operate, maintain, and calibrate a
CO2 continuous emission monitoring system (CEMS) to directly
measure and record CO2 concentrations in your affected
facility's exhaust gases that are emitted to the atmosphere and an
exhaust gas flow rate monitoring system according to Sec.
75.10(a)(3)(i) of this chapter. If you measure CO2
concentration on a dry basis, you must also install, certify, operate,
maintain, and calibrate a continuous moisture monitoring system,
according to Sec.  75.11(b) of this chapter.
    (ii) For each monitoring system used to determine the
CO2 mass emissions, you must meet the applicable
certification and quality assurance procedures in Sec.  75.20 of this
chapter and Appendices B and D to part 75 of this chapter.
    (iii) You must use a laser device to measure the dimensions of each
exhaust gas stack or duct at the flow monitor and the reference method
sampling locations prior to the initial setup (characterization) of the
flow monitor. For circular stacks, you must make measurements of the
diameter at three or more distinct locations and average the results.
For rectangular stacks or ducts, you must make measurements of each
dimension (i.e., depth and width) at three or more distinct locations
and average the results. If the flow rate monitor or reference method
sampling site is relocated, you must repeat these measurements at the
new location.
    (iv) You can only use unadjusted exhaust gas volumetric flow rates
to determine the hourly CO2 mass emissions from the affected
facility; you must not apply the bias adjustment factors described in
section 7.6.5 of Appendix A to part 75 of this chapter to the exhaust
gas flow rate data.
    (v) If you choose to use Method 2 in Appendix A-1 to this part to
perform the required relative accuracy test audits (RATAs) of the part
75 flow rate monitoring system, you must use a calibrated Type-S pitot
tube or pitot tube assembly. You must not use the default Type-S pitot
tube coefficient.
    (vi) If two or more affected facilities share a common exhaust gas
stack and are subject to the same CO2 emissions limitation
in paragraph (c) of this section, you may monitor the hourly
CO2 mass emissions at the common exhaust gas stack rather
than monitoring each affected facility separately.
    (vii) If the exhaust gases from the affected facilities are emitted
to the atmosphere through multiple stacks (or if the exhaust gases are
routed to a common stack through multiple ducts and you choose to
monitor in the ducts), you must monitor the hourly CO2 mass
emissions and the ``stack operating time'' (as defined in Sec.  72.2 of
this chapter) at each stack or duct separately.
    (3) As an alternative to complying with paragraph (f)(2) of this
section, for affected facilities that do not combust any solid fuel,
you may determine the hourly CO2 mass emissions by using
Equation G-4 in Appendix G to part 75 of this chapter according to the
requirements specified in paragraphs (f)(3)(i) and (f)(3)(ii) of this
section.
    (i) You must implement the applicable procedures in Appendix D to
part 75 of this chapter to determine hourly unit heat input rates
(MMBtu/h), based on hourly measurements of fuel flow rate and periodic
determinations of the gross calorific value (GCV) of each fuel
combusted.
    (ii) You may determine site-specific carbon-based F-factors
(Fc) using Equation F-7b in section 3.3.6 of Appendix F to
part 75 of this chapter, and you may use these Fc values in
the emissions calculations instead of using the default Fc
values in the Equation G-4 nomenclature.
    (4) You must install, calibrate, maintain, and operate a sufficient
number of watt meters to continuously measure and record the gross
electric output from the affected facility, and you must meet the
requirements specified in paragraphs (f)(4)(i) and (ii) of this
section, as applicable.
    (i) If your affected facility is a combined heat and power unit as
defined in Sec.  60.42Da, you must also install, calibrate, maintain,
and operate meters to continuously determine and record the total
useful recovered thermal energy. For process steam applications, you
must install, calibrate, maintain, and operate meters to continuously
determine and record steam flow rate, temperature, and pressure. If
your affected facility has a direct mechanical drive application, you
must submit a plan to the Administrator or delegated authority for
approval of how gross energy output will be determined. Your plan shall
ensure that you install, calibrate, maintain, and operate meters to
continuously determine and record each component of the determination.
    (ii) If two or more affected facilities have steam generating units
that serve a common electric generator, you must apportion the combined
hourly gross electric output to each individual affected facility using
a plan approved by the Administrator (e.g., using steam load or heat
input to each affected facility). Your plan shall ensure that you
install, calibrate, maintain, and operate meters to continuously
determine and record each component of the determination.
    (g) You must demonstrate compliance with the CO2
emissions limitation using the procedures specified in paragraphs
(g)(1) and (2) of this section.
    (1) You must calculate the CO2 mass emissions rate for
your affected facility using the calculation procedures in paragraphs
(g)(1)(i) through (v) of this section with the hourly CO2
mass emissions and gross energy output data determined and recorded
according to the procedures in paragraph (f) of this section for each
operating hour in the applicable compliance period (i.e., 12-

operating months or 84-operating months).
    (i) You must only use operating hours in the compliance period for
which you have valid data for all the parameters you use to determine
the hourly CO2 mass emissions and gross output data. You
must not use operating hours which use the substitute data provisions
of part 75 of this chapter for any of the parameters in the
calculation. For the compliance determination calculation, you must
obtain valid hourly values for a minimum of 95 percent of the operating
hours in the applicable compliance period.
    (ii) You must calculate the total CO2 mass emissions by
summing all of the valid hourly CO2 mass emissions values
for the applicable compliance period. If exhaust gases from the
affected facility are emitted to the atmosphere through multiple stacks
or ducts, you must calculate the total CO2 mass emissions
for the affected facility by summing the total CO2 mass
emissions from each of the individual stacks or ducts.
    (iii) For each operating hour of the compliance period used in
paragraph (g)(1)(ii) of this section to calculate the total
CO2 mass emissions, you must determine the affected
facility's corresponding hourly gross energy output using the
appropriate definitions in Sec.  60.42Da and paragraph (k) of this
section and using the procedure specified in paragraphs (g)(3)(iii)(A)
through (D) of this section.
    (A) Calculate Pgross for your affected facility using
the following equation:
[GRAPHIC] [TIFF OMITTED] TP08JA14.000

Where: a
Pgross = Gross energy output of your affected facility in
megawatt-hours in MWh.
(Pe)ST = Electric energy output plus mechanical energy
output (if any) of steam turbines in MWh.
(Pe)CT = Electric energy output plus mechanical energy
output (if any) of stationary combustion turbine(s) in MWh.
(Pe)IE = Electric energy output plus mechanical energy
output (if any) of your affected facility's integrated equipment
that provides electricity or mechanical energy to the affected
facility or auxiliary equipment in MWh.
(Pe)FW = Electric energy used to power boiler feedwater
pumps at steam generating units in MWh. This term is not applicable
to IGCC facilities.
(Pt)PS = Useful thermal energy output of steam measured
relative to ISO conditions that is used for applications that do not
generate additional electricity, produce mechanical energy output,
or enhance the performance of the affected facility. This term is
calculated using the equation specified in paragraph (g)(3)(iii)(B)
of this section in MWh.
(Pt)HR = Hourly useful thermal energy output measured
relative to ISO conditions from heat recovery that is used for
applications other than steam generation or performance enhancement
of the affected facility in MWh.
(Pt)IE = Useful thermal energy output relative to ISO
conditions from any integrated equipment that provides thermal
energy to the affected facility or auxiliary equipment in MWh.
T = Electric Transmission and Distribution Factor.
    T = 0.95 for a combined heat and power affected facility where
at least on an annual basis 20.0 percent of the total gross energy
output consists of electric or direct mechanical output and 20.0
percent of the total gross energy output consists of useful thermal
energy output on a rolling 3 year basis.
    T = 1.0 for all other affected facilities.

    (B) If applicable to your affected facility, calculate
(Pt)PS using the following equation:
[GRAPHIC] [TIFF OMITTED] TP08JA14.001

Where:
Qm = Measured steam flow in kilograms (kg) (or pounds
(lb)) for the operating hour.
H = Enthalpy of the steam at measured temperature and pressure
relative to ISO conditions in Joules per kilogram (J/kg) (or Btu/
lb).
3.6 x 10\9\ = Conversion factor (J/MWh) (or 3.413 x 10\6\ Btu/MWh).

    (C) For an operating hour in which there is no gross electric load,
but there is mechanical or useful thermal output, you must still
determine the gross energy output for that hour. In addition, for an
operating hour in which there is no useful output, you must still
determine the hourly gross CO2 emissions for that hour.
    (D) If hourly CO2 mass emissions are determined for a
common stack, you must determine the hourly gross energy output
(electric, thermal, and/or mechanical, as applicable) by summing the
hourly loads for the individual affected facility and you must express
the operating time as ``stack operating hours'' (as defined in Sec.
72.2 of this chapter).
    (iv) You must calculate the total gross energy output by summing
the hourly gross energy output values for the affected facility
determined from paragraph (g)(1)(iii) of this section for all of the
operating hours in the applicable compliance period.
    (v) You must calculate the CO2 mass emissions rate for
the applicable compliance period interval by dividing the total
CO2 mass emissions value from paragraph (g)(1)(ii) of this
section by the total gross energy output value from paragraph
(g)(1)(iv) of this section.
    (2) You must determine compliance with the CO2 emissions
limitation in paragraph (c) of this section is determined as specified
in paragraphs (g)(2)(i) and (ii) of this section using the
CO2 mass emissions rate for your affected facility that you
determined in paragraph (g)(1) of this section.
    (i) If the CO2 mass emissions rate for your affected
facility is less than or equal to the CO2 emissions
limitation applicable to your affected facility, then your affected
facility is in compliance with the CO2 emissions limitation.
If you attain compliance with the CO2 emissions limitation
at a common stack for two or more affected facilities subject to the
same CO2 emissions limitation, each affected facility
sharing the stack is in compliance with the CO2 emissions
limitation.
    (ii) If the CO2 mass emissions rate for the affected
facility is greater than the CO2 emissions limitation in
paragraph (c) of this section applicable to the affected facility, then
the affected facility has excess CO2 emissions.
    (h) You must prepare and submit notifications and reports according
to paragraphs (h)(1) through (4) of this section.
    (1) You must prepare and submit the notifications in Sec. Sec.
60.7(a)(1) and (a)(3) and 60.19, as applicable to your affected
facility.
    (2) You must prepare and submit notifications in Sec.  75.61 of
this chapter, as applicable to your affected facility.
    (3) You must submit electronic quarterly reports according to the
requirements specified in paragraphs (h)(3)(i) through (iii) of this
section.
    (i) Initially, after you have accumulated the required number of
operating months for the CO2 emission limitation compliance
period that you have chosen to comply with (i.e., 12-operating months
or 84-operating months), you must submit a report for

the calendar quarter that includes the final (12th- or 84th) operating
month no later than 30 days after the end of that quarter. Thereafter,
you must submit a report for each subsequent calendar quarter no later
than 30 days after the end of the quarter.
    (ii) In each quarterly report you must include the information in
paragraphs (h)(3)(ii)(A) through (E) of this section.
    (A) The CO2 emission limitation compliance period with
which you have chosen to comply.
    (B) Any months in the calendar quarter that you are not counting as
operating months.
    (C) For each operating month in the calendar quarter, the
corresponding average CO2 mass emissions rate for the
applicable compliance period interval that you determined according to
paragraph (g) of this section.
    (D) The percentage of valid CO2 mass emission rates in
each compliance period (i.e., the total number of valid CO2
mass emission rates in that period divided by the total number of
operating hours in that period, multiplied by 100 percent).
    (E) Any operating months in the calendar quarter with excess
CO2 emissions.
    (iii) In the final quarterly report of each calendar year you must
include the following:
    (A) Net electric output sold to an electric grid over the calendar
year; and
    (B) The potential electric output of the facility.
    (iv) You must submit each electronic report using the Emissions
Collection and Monitoring Plan System (ECMPS) Client Tool provided by
the Clean Air Markets Division in the EPA Office of Atmospheric
Programs.
    (4) You must meet all applicable reporting requirements and submit
reports as required under subpart G of part 75 of this chapter.
    (5) If your affected unit uses geologic sequestration to meet the
applicable emissions limit, you must report in accordance with the
requirements of 40 CFR Part 98, subpart PP and either:
    (i) if injection occurs onsite, report in accordance with the
requirements of 40 CFR Part 98, subpart RR, or
    (ii) if injection occurs offsite, transfer the captured
CO2 to a facility or facilities that reports in accordance
with the requirements of 40 CFR Part 98, subpart RR.
    (i) For each affected electric utility stream generating unit, you
must maintain records according to paragraphs (i)(1) through (i)(8) of
this section.
    (1) You must comply with the applicable recordkeeping requirements
and maintain records as required under subpart F of part 75 of this
chapter.
    (2) You must maintain records of the calculations you performed to
determine the total CO2 mass emissions for each operating
month, and the averages for each compliance period interval (i.e., 12-
operating months or 84-operating months, as applicable to the
CO2 emissions limitations).
    (3) You must maintain records of the applicable data recorded and
calculations performed that you used to determine the gross energy
output for each operating month.
    (4) You must maintain records of the calculations you performed to
determine the percentage of valid CO2 mass emission rates in
each compliance period.
    (5) You must maintain records of the calculations you performed to
assess compliance with each applicable CO2 emissions
limitation in paragraph (c) of this section.
    (6) Your records must be in a form suitable and readily available
for expeditious review.
    (7) You must maintain each record for 5 years after the date of
each occurrence, measurement, maintenance, corrective action, report,
or record except those records required to demonstrate compliance with
an 84-operating month compliance period. You must maintain records
required to demonstrate compliance with an 84-operating month
compliance period for at least 10 years following the date of each
occurrence, measurement, maintenance, corrective action, report, or
record.
    (8) You must maintain 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.  60.7. You may maintain
the records off site and electronically for the remaining year(s) as
required by this subpart.
    (j) PSD and Title V Thresholds for Greenhouse Gases.
    (1) For purposes of 40 CFR 51.166(b)(49)(ii), with respect to GHG
emissions from new affected facilities, the ``pollutant that is subject
to the standard promulgated under section 111 of the Act'' shall be
considered to be the pollutant that otherwise is subject to regulation
under the Act as defined in 40 CFR 51.166(b)(48) and in any SIP
approved by the EPA that is interpreted to incorporate, or specifically
incorporates, 40 CFR 51.166(b)(48).
    (2) For purposes of 40 CFR 52.21(b)(50)(ii), with respect to GHG
emissions from new affected facilities, the ``pollutant that is subject
to the standard promulgated under section 111 of the Act'' shall be
considered to be the pollutant that otherwise is subject to regulation
under the Act as defined in 40 CFR 52.21(b)(49).
    (3) For purposes of 40 CFR 70.2, with respect to greenhouse gas
emissions from new affected facilities, the ``pollutant that is subject
to any standard promulgated under section 111 of the Act'' shall be
considered to be the pollutant that otherwise is ``subject to
regulation'' as defined in 40 CFR 70.2.
    (4) For purposes of 40 CFR 71.2, with respect to greenhouse gas
emissions from new affected facilities, the ``pollutant that is subject
to any standard promulgated under section 111 of the Act'' shall be
considered to be the pollutant that otherwise is ``subject to
regulation'' as defined in 40 CFR 71.2.
    (k) For purposes of this section, the following definitions apply:
    Gross energy output means:
    (i) Except as provided under paragraph (ii) of this definition, for
electric utility steam generating units, the gross electric or
mechanical output from the affected facility (including, but not
limited to, output from steam turbine(s), combustion turbine(s), and
gas expanders) minus any electricity used to power the feedwater pumps
plus 75 percent of the useful thermal output measured relative to ISO
conditions that is not used to generate additional electric or
mechanical output or to enhance the performance of the unit (e.g.,
steam delivered to an industrial process for a heating application);
    (ii) For electric utility steam generating unit combined heat and
power facilities where at least 20.0 percent of the total gross energy
output consists of electric or direct mechanical output and at least
20.0 percent of the total gross energy output consists of thermal
output on a rolling 3 year basis, the gross electric or mechanical
output from the affected facility (including, but not limited to,
output from steam turbine(s), combustion turbine(s), and gas expanders)
minus any electricity used to power the feedwater pumps, that
difference divided by 0.95, plus 75 percent of the useful thermal
output measured relative to ISO conditions that is not used to generate
additional electric or mechanical output or to enhance the performance
of the unit (e.g., steam delivered to an industrial process for a
heating application);
    (iii) Except as provided under paragraph (ii) of this definition,
for a IGCC electric utility generating unit, the gross electric or
mechanical output from the affected facility (including, but not
limited to, output from steam turbine(s), combustion turbine(s), and
gas expanders) plus 75 percent of the useful

thermal output measured relative to ISO conditions that is not used to
generate additional electric or mechanical output or to enhance the
performance of the unit (e.g., steam delivered to an industrial process
for a heating application);
    (iv) For IGCC electric utility generating unit combined heat and
power facilities where at least 20.0 percent of the total gross energy
output consists of electric or direct mechanical output and at least
20.0 percent of the total gross energy output consists of thermal
output on a rolling 3 year basis, the gross electric or mechanical
output from the affected facility (including, but not limited to,
output from steam turbine(s), combustion turbine(s), and gas expanders)
divided by 0.95, plus 75 percent of the useful thermal output measured
relative to ISO conditions that is not used to generate additional
electric or mechanical output or to enhance the performance of the unit
(e.g., steam delivered to an industrial process for a heating
application);
    IGCC facility is an integrated gasification combined cycle electric
utility steam generating unit, which means an electric utility combined
cycle facility that is designed to burn fuels containing 50 percent (by
heat input) or more solid-derived fuel not meeting the definition of
natural gas plus any integrated equipment that provides electricity or
useful thermal output to either the affected facility or auxiliary
equipment. The Administrator may waive the 50 percent solid-derived
fuel requirement during periods of the gasification system
construction, startup and commissioning, shutdown, or repair. No solid
fuel is directly burned in the facility during operation.
    Net-electric output means:
    (i) Except as provided under paragraph (ii) of this definition, the
gross electric sales to the utility power distribution system minus
purchased power on a calendar year basis, or
    (ii) For combined heat and power facilities where at least 20.0
percent of the total gross energy output consists of electric or direct
mechanical output and at least 20.0 percent of the total gross energy
output consists of thermal output, the gross electric sales to the
utility power distribution system minus purchased power of the thermal
host facility or facilities on a calendar year basis.
    Potential electric output means:
    (i) Either 33 percent or the design net electric output efficiency,
at the election of the owner/operator of the affected facility,
    (ii) Multiplied by the maximum design heat input capacity of the
steam generating unit,
    (iii) Divided by 3,413 Btu/KWh,
    (iv) Divided by 1,000 kWh/MWh, and
    (v) Multiplied by 8,760 h/yr.
    (vi) For example, a 35 percent efficient steam generating unit with
a 100 MW (341 MMBtu/h) fossil-fuel heat input capacity would have a
310,000 MWh 12 month potential electric output capacity.
    Steam generating unit means any furnace, boiler, or other device
used for combusting fuel for the purpose of producing steam (nuclear
steam generators are not included) plus any integrated equipment that
provides electricity or useful thermal output to either the boiler or
auxiliary equipment.

Subpart KKKK--Standards of Performance for Stationary Combustion
Turbines

0
3. Section 60.4305 is amended by adding paragraph (c) to read as
follows:

Sec.  60.4305  Does this subpart apply to my stationary combustion
turbine?

* * * * *
    (c) For purposes of regulation of greenhouse gases, the applicable
provisions of this subpart affect your stationary combustion turbine if
it meets the applicability conditions in paragraphs (c)(1) through
(c)(5) of this section.
    (1) Commenced construction after [DATE OF PUBLICATION IN THE
FEDERAL REGISTER];
    (2) Has a design heat input to the turbine engine greater than 73
MW (250 MMBtu/h);
    (3) Combusts fossil fuel for more than 10.0 percent of the heat
input during any 3 consecutive calendar years.
    (4) Combusts over 90% natural gas on a heat input basis on a 3 year
rolling average basis; and
    (5) Was constructed for the purpose of supplying, and supplies,
one-third or more of its potential electric output and more than
219,000 MWh net-electrical output to a utility distribution system on a
3 year rolling average basis.

0
4. Section 60.4315 is revised to read as follows:

Sec.  60.4315  What pollutants are regulated by this subpart?

    (a) The pollutants regulated by this subpart are nitrogen oxides
(NOX), sulfur dioxide (SO2), and greenhouse
gases.
    (b)(1) The greenhouse gases regulated by this subpart consist of
carbon dioxide (CO2).
    (2) PSD and Title V Thresholds for Greenhouse Gases.
    (i) For purposes of 40 CFR 51.166(b)(49)(ii), with respect to GHG
emissions from affected stationary combustion turbine, the ``pollutant
that is subject to the standard promulgated under section 111 of the
Act'' shall be considered to be the pollutant that otherwise is subject
to regulation under the Act as defined in 40 CFR 51.166(b)(48) and in
any SIP approved by the EPA that is interpreted to incorporate, or
specifically incorporates, 40 CFR 51.166(b)(48).
    (ii) For purposes of 40 CFR 52.21(b)(50)(ii), with respect to GHG
emissions from affected stationary combustion turbines, the ``pollutant
that is subject to the standard promulgated under section 111 of the
Act'' shall be considered to be the pollutant that otherwise is subject
to regulation under the Act as defined in 40 CFR 52.21(b)(49).
    (iii) For purposes of 40 CFR 70.2, with respect to greenhouse gas
emissions from affected stationary combustion turbines, the ``pollutant
that is subject to any standard promulgated under section 111 of the
Act'' shall be considered to be the pollutant that otherwise is
``subject to regulation'' as defined in 40 CFR 70.2.
    (iv) For purposes of 40 CFR 71.2, with respect to greenhouse gas
emissions from affected stationary combustion turbines, the ``pollutant
that is subject to any standard promulgated under section 111 of the
Act'' shall be considered to be the pollutant that otherwise is
``subject to regulation'' as defined in 40 CFR 71.2.

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5. Section 60.4326 is added to read as follows:

Sec.  60.4326  What CO2 emissions standard must I meet?

    You must not discharge from your affected stationary combustion
turbine into the atmosphere any gases that contain CO2 in
excess of the applicable CO2 emissions standard specified in
Table 2 of this subpart.

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6. Section 60.4333 is amended by adding paragraph (c) to read as
follows:

Sec.  60.4333  What are my general requirements for complying with this
subpart?

* * * * *
    (c) If you own or operate an affected stationary combustion turbine
subject to a CO2 emissions standard in Sec.  60.4326, you
must make compliance determinations on a 12-operating month rolling
average basis, and you must determine compliance monthly by calculating
the average CO2 emissions rate for the affected stationary

combustion turbine at the end of each 12-operating month period.

0
7. Section 60.4373 is added under undesignated center heading
``Monitoring'' to read as follows:

Sec.  60.4373  How do I monitor and collect data to demonstrate
compliance with my CO2 emissions standard using a
CO2 CEMS?

    (a) You must prepare a monitoring plan in accordance with the
applicable provisions in Sec.  75.53(g) and (h) of this chapter.
    (b) You must measure the hourly CO2 mass emissions from
each affected stationary combustion turbine using the procedures in
paragraphs (b)(1) through (5) of this section, except as provided in
paragraph (c) of this section.
    (1) You must install, certify, operate, maintain, and calibrate a
CO2 continuous emission monitoring system (CEMS) to directly
measure and record CO2 concentrations in the stationary
combustion turbine exhaust gases emitted to the atmosphere and an
exhaust gas flow rate monitoring system according to Sec.
75.10(a)(3)(i) of this chapter. If you measure CO2
concentration on a dry basis, you must also install, certify, operate,
maintain, and calibrate a continuous moisture monitoring system,
according to Sec.  75.11(b) of this chapter.
    (2) For each monitoring system that you use to determine the
CO2 mass emissions, you must meet the applicable
certification and quality assurance procedures in Sec.  75.20 of this
chapter and Appendices B and D to part 75 of this chapter.
    (3) You must use a laser device to measure the dimensions of each
exhaust gas stack or duct at the flow monitor and the reference method
sampling locations prior to the initial setup (characterization) of the
flow monitor. For circular stacks, you must make measure of the
diameter at three or more distinct locations and average the results.
For rectangular stacks or ducts, you must measure each dimension (i.e.,
depth and width) at three or more distinct locations and average the
results. If the flow rate monitor or reference method sampling site is
relocated, you must repeat these measurements at the new location.
    (4) You must use unadjusted exhaust gas volumetric flow rates only
to determine the hourly CO2 mass emissions from the affected
stationary combustion turbine; you must not apply the bias adjustment
factors described in section 7.6.5 of Appendix A to part 75 of this
chapter to the exhaust gas flow rate data.
    (5) If you chose to use Method 2 in Appendix A-1 to this part to
perform the required relative accuracy test audits (RATAs) of the part
75 flow rate monitoring system, you must use a calibrated Type-S pitot
tube or pitot tube assembly. You must not use the default Type-S pitot
tube coefficient.
    (c) As an alternative to complying with paragraph (b) of this
section, you may determine the hourly CO2 mass emissions by
using Equation G-4 in Appendix G to part 75 of this chapter according
to the requirements specified in paragraphs (c)(1) and (2) of this
section.
    (1) You must implement the applicable procedures in appendix D to
part 75 of this chapter to determine hourly unit heat input rates
(MMBtu/h), based on hourly measurements of fuel flow rate and periodic
determinations of the gross calorific value (GCV) of each fuel
combusted.
    (2) You may determine site-specific carbon-based F-factors
(Fc) using Equation F-7b in section 3.3.6 of Appendix F to
part 75 of this chapter, and you may use these Fc values in
the emissions calculations instead of using the default Fc
values in the Equation G-4 nomenclature.
    (d) You must install, calibrate, maintain, and operate a sufficient
number of watt meters to continuously measure and record the gross
electric output from the affected stationary combustion turbine. If the
affected stationary combustion turbine is a CHP stationary combustion
turbine, you must also install, calibrate, maintain, and operate meters
to continuously determine and record the total useful recovered thermal
energy. For process steam applications, you will need to install,
calibrate, maintain, and operate meters to continuously determine and
record steam flow rate, temperature, and pressure. If the affected
stationary combustion turbine has a direct mechanical drive
application, you must submit a plan to the Administrator or delegated
authority for approval of how gross energy output will be determined.
Your plan shall ensure that you install, calibrate, maintain, and
operate meters to continuously determine and record each component of
the determination.
    (e) If two or more affected stationary combustion turbines serve a
common electric generator, you must apportion the combined hourly gross
output to the individual stationary combustion turbines using a plan
approved by the Administrator (e.g., using steam load or heat input to
each affected stationary combustion turbine). Your plan shall ensure
that you install, calibrate, maintain, and operate meters to
continuously determine and record each component of the determination.
    (f) In accordance with Sec.  60.13(g), if two or more stationary
combustion turbines that implement the continuous emission monitoring
provisions in paragraph (b) of this section share a common exhaust gas
stack and are subject to the same emissions standard under Sec.
60.4326, you may monitor the hourly CO2 mass emissions at
the common stack in lieu of monitoring each stationary combustion
turbine separately. If you choose this option, the hourly gross load
(electric, thermal, and/or mechanical, as applicable) must be the sum
of the hourly loads for the individual stationary combustion turbines
and you must express the operating time as ``stack operating hours''
(as defined in Sec.  72.2 of this chapter). If you attain compliance
with the applicable emissions standard in Sec.  60.4326 at the common
stack, each stationary combustion turbine sharing the stack is in
compliance.
    (g) In accordance with Sec.  60.13(g), if the exhaust gases from a
stationary combustion turbine that implements the continuous emission
monitoring provisions in paragraph (b) of this section are emitted to
the atmosphere through multiple stacks (or if the exhaust gases are
routed to a common stack through multiple ducts and you chose to
monitor in the ducts), you must monitor the hourly CO2 mass
emissions and the ``stack operating time'' (as defined in Sec.  72.2 of
this chapter) at each stack or duct separately. In this case, you
determine compliance with the applicable emissions standard in Sec.
60.4326 by summing the CO2 mass emissions measured at the
individual stacks or ducts and dividing by the total gross output for
the unit.
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8. Section 60.4374 is added under undesignated center heading
``Monitoring'' to read as follows:

Sec.  60.4374  How do I demonstrate compliance with my CO2
emissions standard and determine excess emissions?

    (a) You must calculate the CO2 mass emissions rate for
your affected stationary combustion turbine by using the hourly
CO2 mass emissions and total gross output data determined
and recorded according to the procedures in Sec.  60.4373 for the
compliance period for the CO2 emissions standard applicable
to the affected stationary combustion turbine, and the calculation
procedures in paragraphs (a)(1) through (a)(5) of this section.
    (1) You must only use operating hours in the compliance period for
the compliance determination calculation for which you obtained valid
data for all

parameters you used to determine the hourly CO2 mass
emissions and gross output data, are used for the compliance
determination calculation. You must not include operating hours in
which you used the substitute data provisions of part 75 of this
chapter for any of the parameters in the calculation. For the
compliance determination calculation, you must obtain valid hourly
CO2 mass emission values for a minimum of 95 percent of the
operating hours in the compliance period.
    (2) You must calculate the total CO2 mass emissions by
summing the hourly CO2 mass emissions values for the
affected stationary combustion turbine determined to be valid according
to the conditions specified in paragraph (a)(1) of this section for all
of the operating hours in the applicable compliance period.
    (3) For each operating hour of the compliance period used in
paragraph (a)(2) of this section to calculate the total CO2
mass emissions, you must determine the affected stationary combustion
turbine's corresponding hourly gross output (Pgross) by
applying the appropriate definitions in Sec. Sec.  60.4420 and 60.4421
of this subpart and according to the procedures specified in paragraphs
(a)(3)(i) and (iv) of this section.
    (i) Calculate Pgross for your affected stationary
combustion turbine using the following equation:
[GRAPHIC] [TIFF OMITTED] TP08JA14.002

    Where:
Pgross = Gross energy output of your affected stationary
combustion turbine in megawatt-hours in MWh.
(Pe)CT = Electric energy output plus mechanical energy
output (if any) of stationary combustion turbines in MWh.
(Pe)ST = Electric energy output plus mechanical energy
output (if any) of steam turbines in MWh.
(Pe)IE = Electric energy output plus mechanical energy
output (if any) of your affected stationary combustion turbine's
integrated equipment that provides electricity to the affected
facility or auxiliary equipment in MWh.
(Pt)PS = Useful thermal energy output of steam relative
to ISO conditions that is used for applications that do not generate
additional electricity, produce mechanical energy output, enhance
the performance of the affected facility. Calculated using the
equation specified in paragraph (a)(3)(ii) of this section in MWh.
(Pt)HR = Useful thermal energy output relative to ISO
conditions from heat recovery that is used for applications other
than steam generation or performance enhancement of the affected
facility in MWh.
(Pt)IE = Useful thermal energy output relative to ISO
conditions from any integrated equipment that provides input to the
affected facility or auxiliary equipment in MWh.
T = Electric Transmission and Distribution Factor.
    T = 0.95 for a CHP stationary combustion turbine where at least
on an annual basis 20.0 percent of the total gross energy output
consists of electric or direct mechanical output and 20.0 percent of
the total gross energy output consists of useful thermal energy
output on a rolling 3 year basis.
    T = 1.0 for all other affected stationary combustion turbines.

    (ii) If applicable to your affected stationary combustion turbine,
calculate (Pt)PS using the following equation:
[GRAPHIC] [TIFF OMITTED] TP08JA14.003

Where:
Qm = Measured steam flow in kilograms (kg) (or pounds
(lb)) for the operating hour.
H = Enthalpy of the steam at measured temperature and pressure
relative to ISO conditions in Joules per kilogram (J/kg) (or Btu/
lb).
3.6 x 10\9\ = Conversion factor (J/MWh) (or 3.413 x 10\6\ Btu/MWh).

    (iii) You must determine the hourly gross energy output for each
operating hour in which there is no electric output, but there is
mechanical output or useful thermal output. In addition you must
determine the hourly gross CO2 emissions for each operating
hour in which there is no useful output.
    (iv) In the case for which compliance is demonstrated according to
Sec.  60.4373(f) for affected stationary combustion turbines that vent
to a common stack, then you must calculate the hourly gross energy
output (electric, mechanical, and/or thermal, as applicable) by summing
the hourly gross energy output you determined for each of your
individual affected stationary combustion turbines that vent to the
common stack; and you must express the operating time as ``stack
operating hours'' (as defined in Sec.  72.2 of this chapter).
    (4) You must calculate the total gross output for the affected
stationary combustion turbine's compliance period by summing the hourly
gross output values for the affected stationary combustion turbine
determined from paragraph (a)(2) of this section for all of the
operating hours in the applicable compliance period.
    (5) You must calculate the CO2 mass emissions rate for
the affected stationary combustion turbine by dividing the total
CO2 mass emissions value as calculated according to the
requirements of paragraph (a)(2) of this section by the total gross
output value as calculated according to the requirements of paragraph
(a)(4) of this section.
    (b) If the CO2 mass emissions rate for the affected
stationary combustion turbine determined according to the procedures
specified in paragraph (a) of this section is less than or equal to the
CO2 emissions standard in Table 2 of this subpart applicable
to the affected stationary combustion turbine, then your affected
stationary combustion turbine is in compliance with the emissions
standard. If the average CO2 mass emissions rate is greater
than the CO2 emissions standard in Table 2 of this subpart
applicable to the affected stationary combustion turbine, then your
affected stationary combustion turbine has excess CO2
emissions.
0
9. Section 60.4375 is amended by revising the section heading to read
as follows:

Sec.  60.4375  What reports must I submit to comply with my
NOX and SO2 emissions limits?

* * * * *
0
10. Section 60.4376 is added to read as follows:

Sec.  60.4376  What notifications and reports must I submit to comply
with my CO2 emissions standard?

    (a)(1) You must prepare and submit the notifications specified in
Sec. Sec.  60.7(a)(1) and (a)(3) and 60.19, as applicable to your
affected stationary combustion turbine.
    (2) You must prepare and submit notifications specified in Sec.
75.61 of this chapter, as applicable to your affected stationary
combustion turbine.
    (b) You must prepare and submit reports according to paragraphs
(b)(1) through (d) of this section, as applicable.
    (1) For stationary combustion turbines that are required, by Sec.
60.4333(c), to conduct initial and on-going compliance determinations
on a 12-operating month rolling average basis for the standard in Sec.
60.4326, you must submit electronic quarterly reports as follows. After
you

have accumulated the first 12-operating months for the affected
stationary combustion turbine, you must submit a report for the
calendar quarter that includes the 12th-operating month no later than
30 days after the end of that quarter. Thereafter, you must submit a
report for each subsequent calendar quarter, no later than 30 days
after the end of the quarter.
    (2) In each quarterly report, you must include the following
information, as applicable:
    (i) Each rolling average CO2 mass emissions rate for
which the last (12th) operating month in a 12-operating month
compliance period falls within the calendar quarter. You must calculate
each average CO2 mass emissions rate according to the
requirements of Sec.  60.4374. You must report the dates (month and
year) of the 1st and 12th-operating months in each compliance period
for which you performed a CO2 mass emissions rate
calculation. If there are no compliance periods that end in the
quarter, you must include a statement to that effect;
    (ii) If one or more compliance periods end in the quarter, you must
identify each operating month in the calendar quarter with excess
CO2 emissions;
    (iii) The percentage of valid CO2 mass emission rates
(as defined in Sec.  60.4374) in each 12-operating month compliance
period described in paragraph (b)(2)(i) of this section (i.e., the
total number of valid CO2 mass emission rates in that period
divided by the total number of operating hours in that period,
multiplied by 100 percent); and
    (iv) The CO2 emissions standard (as identified in Table
2 of this subpart) with which your affected stationary combustion
turbine is complying.
    (3) The final quarterly report of each calendar year must contain
the following:
    (i) Net electric output sold to an electric grid over the 4
quarters of the calendar year; and
    (ii) The potential electric output of the stationary combustion
turbine.
    (c) You must submit all electronic reports required under paragraph
(b) of this section using the Emissions Collection and Monitoring Plan
System (ECMPS) Client Tool provided by the Clean Air Markets Division
in the Office of Atmospheric Programs of the EPA.
    (d) You must meet all applicable reporting requirements and submit
reports as required under subpart G of part 75 of this chapter.
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11. Section 60.4391 is added to read as follows:

Sec.  60.4391  What records must I maintain to comply with my
CO2 emissions limits?

    (a) You must maintain records of the information you used to
demonstrate compliance with this subpart as specified in Sec.  60.7(b)
and (f).
    (b) You must follow the applicable recordkeeping requirements and
maintain records as required under subpart F of part 75 of this
chapter.
    (c) You must keep records of the calculations you performed to
determine the total CO2 mass emissions for:
    (1) Each operating month (for all affected units);
    (2) Each compliance period, including, as applicable, each 12-
operating month compliance period.
    (d) You must keep records of the applicable data recorded and
calculations performed that you used to determine your affected
stationary combustion turbine's gross output for each operating month.
    (e) You must keep records of the calculations you performed to
determine the percentage of valid CO2 mass emission rates in
each compliance period.
    (f) You must keep records of the calculations you performed to
assess compliance with each applicable CO2 mass emissions
standard in Sec.  60.4326.
    (g) You must keep records of the calculations you performed to
determine any site-specific carbon-based F-factors you used in the
emissions calculations (if applicable).
    (h)(1) Your records must be in a form suitable and readily
available for expeditious review.
    (2) You must keep each record for 5 years after the date of each
occurrence, measurement, maintenance, corrective action, report, or
record to demonstrate compliance with a 12-operating month emissions
standard.
    (3) 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.  60.7. You may keep the
records off site and electronically for the remaining year(s) as
required by this subpart.
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12. Section 60.4395 is revised to read as follows:

Sec.  60.4395  When must I submit my reports?

    All of your reports required under Sec.  60.7(c) must be postmarked
by the 30th day after the end of each 6-month period, except as
specified in Sec.  60.4376
0
13. Section 60.4421 is added to read as follows:

Sec.  60.4421  What definitions with respect to CO2
emissions apply to this subpart?

    As used in this subpart:
    Base load rating means 100 percent of the manufacturer's design
heat input capacity of the combustion turbine engine at ISO conditions