As an alternative to the options proposed by the EPA, some
commenters asserted that the EPA should make a GHG cost adjustment
using a separate, but reduced fee rate ($/ton) for GHGs. We, however,
believe that the option 1 approach of the final rule will be more
equitable for sources and more representative of actual costs because
option 1 considers the costs of the actual permitting activities
performed by a particular permitting authority, while any emissions-
based approach would not be as directly related to actual costs
incurred by permitting authorities.
    Some commenters alleged that the EPA's proposal on adjustments to
the operating permit programs was vague. The EPA provided a thorough
discussion of our rationale in the proposal, including the basis for
the GHG adjustments, and we proposed regulatory text to implement our
proposal. We explained in the proposal that support for the cost
adjustment for GHGs under option 1 is contained in several analyses
performed by the EPA and approved by the OMB related to the effect of
the addressing GHG requirements in operating permits. These analyses
have been placed in the docket for this rulemaking. The analyses
include: The Regulatory Impact Assessment (RIA) for the Tailoring Rule
(see Regulatory Impact Analysis for the Final Prevention of Significant
Deterioration and Title V Greenhouse Gas Tailoring Rule, Final Report,
May 2010); the part 70 ICR change request for the Tailoring Rule (which
was based on the RIA for the Tailoring Rule); and the current ICR for
part 70 (EPA ICR number 1587.12; OMB control number 2060-0243).
    Several commenters asked that we make changes to the option 1
approach that we proposed, such as adding new activities or decreasing
the costs we assumed for the proposal. In response to these comments,
we note that we received no quantitative data or other information from
commenters that we believe demonstrates the need to revise the list of
activities we included under option 1 or the burden hour assumptions
under option 1 for the activities. Note that to promote consistent
implementation of the final option 1 approach, the preamble describes
elsewhere a few clarifications concerning the activities under option 1
and one minor revision to the regulatory text of one of the activities.
    Since the EPA's proposed rulemaking, the Supreme Court decided in
UARG v. EPA that the EPA may not treat GHGs as an air pollutant for
purposes of determining whether a source is a major source required to
obtain a Title V operating permit.\564\ The EPA's review of the effect
of the Supreme Court decision on the burden hour assumptions for the
GHG review activities under proposed option 1 is that the effects are
not significant enough to warrant revision of the burden hour
assumptions in the final rule. Proposed option 1 was based on the
assumption that permitting authorities would need to evaluate all
permit applications for initial permit issuance, significant and minor
permit modifications, and permit renewals for GHG issues (even if there
are no applicable GHG requirements). Even after the UARG v. EPA
decision, permitting authorities will continue to need to evaluate GHG
issues for sources applying for a title V permit and for permit
modifications and renewals for existing permits, and we do not
anticipate that the decision will significantly affect the total number
of such evaluations that will occur in any given year compared to the
assumptions in our analysis, which as explained above, were based on
the incremental costs of GHG permitting for any source. Thus, we are
finalizing the burden hour assumptions as they were proposed. See NSPS
proposal at 1494 and the supporting statement for the 2012 part 70 ICR
renewal. Also, as discussed previously, we remain committed to
collecting and analyzing additional data on costs and we may adjust the
burden hour assumptions or other aspects of option 1 in a future
rulemaking, if needed.
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    \564\ The EPA does not, however, read the UARG decision to
affect other grounds on which a Title V permit may be required or
the applicable requirements that must be addressed in Title V
permits. See Memorandum from Janet G. McCabe, Acting Assistant
Administrator, Office of Air and Radiation, and Cynthia Giles,
Assistant Administrator, Office of Enforcement and Compliance
Assurance, to Regional Administrators, Regions 1-10, Next Steps and
Preliminary Views on the Application of Clean Air Act Permitting
Programs to Greenhouse Gases Following the Supreme Court's Decision
in Utility Regulatory Group v. Environmental Protection Agency (July
24, 2014) at 5.
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c. The Fee Pollutant Clarification
    We are also finalizing the proposed addition of text within 40 CFR
part 60, subpart TTTT, to clarify that the fee pollutant for operating
permit purposes is GHG (as defined in 40 CFR 70.2 and 71.2). We are
finalizing these provisions to add clarity to our regulations and to
avoid the potential need for possible future rulemakings to adjust the
title V fee regulations if any constituent of GHG, other than
CO2, becomes subject to regulation under section 111 for the
first time. The proposal was to add this clarifying text to 40 CFR part
60, subparts Da, KKKK, and TTTT. The final rule adds the clarification
text only to subpart TTTT because the EPA is

codifying all of the requirements for the affected EGUs in a new
subpart TTTT and including all CO2 emission standards for
the affected EGUs (electric utility steam generating units, as well as
natural gas-fired stationary combustion turbines) in that newly created
subpart. See Section III.B of this preamble for more on this subject.
d. The GHG Clarification
    The EPA is taking no action at this time on the proposal to move
the definitions of ``Greenhouse gases (GHG)'' within the definition of
``Subject to regulation'' in 40 CFR parts 70 and 71. No public comments
were received on this proposed clarification; however, subsequent to
the proposal, on June 23, 2014, the Supreme Court in UARG v. EPA
decided that GHG emissions could not be used in making certain
applicability determinations under the operating permit rules. More
specifically with respect to title V, as described above, the Supreme
Court said that the EPA may not treat GHGs as an air pollutant for
purposes of determining whether a source is a major source required to
obtain a title V operating permit. In accordance with the Supreme Court
decision, on April 10, 2015, the D.C. Circuit issued an amended
judgment in Coalition for Responsible Regulation, Inc. v. Environmental
Protection Agency, Nos. 09-1322, 10-073, 10-1092 and 10-1167 (D.C. Cir.
April 10, 2015), which, among other things, vacated the title V
regulations under review in that case to the extent that they require a
stationary source to obtain a title V permit solely because the source
emits or has the potential to emit GHGs above the applicable major
source thresholds. The D.C. Circuit also directed the EPA to consider
whether any further revisions to its regulations are appropriate in
light of UARG v. EPA, and, if so, to undertake to make such revisions.
    In response to the Supreme Court decision and the D.C. Circuit's
amended judgment, the EPA intends to conduct future rulemaking action
to make the appropriate revisions to the operating permit rules. As
part of any such future rulemaking action, the EPA may consider
finalizing the proposal to move the definitions of GHGs within the
operating permit rules.

F. Interactions With Other EPA Rules

    Fossil fuel-fired EGUs are, or potentially will be, impacted by
several other recently finalized or proposed EPA rules.\565\ Many of
the rules that impact fossil fuel-fired EGUs apply to existing
facilities as well as newly constructed, modified, or reconstructed
facilities. In fact, the rules described below are more applicable to
existing EGUs than to newly constructed, modified, or reconstructed
EGUs. Although those rules will affect EGUs as existing sources,
because we expect that there will be few NSPS modifications or
reconstructions, we don't anticipate those rules affecting EGUs as
modified or reconstructed sources. In constructing new EGUs, sources
can take all applicable requirements of the various rules into
consideration.
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    \565\ We discuss other rulemakings solely for background
purposes. The effort to coordinate rulemakings is not a defense to a
violation of the CAA. Sources cannot defer compliance with existing
requirements because of other upcoming regulations.
---------------------------------------------------------------------------

1. Mercury and Air Toxics Standards (MATS)
    On February 16, 2012, the EPA issued the MATS rule (77 FR 9304) to
reduce emissions of toxic air pollutants from new and existing coal-
and oil-fired EGUs. The MATS rule will reduce emissions of heavy
metals, including mercury (Hg), arsenic (As), chromium (Cr), and nickel
(Ni); and acid gases, including hydrochloric acid (HCl) and
hydrofluoric acid (HF). These toxic air pollutants, also known as
hazardous air pollutants or air toxics, are known to cause, or
suspected of causing, damage nervous system damage, cancer, and other
serious health effects. The MATS rule will also reduce SO2
and fine particle pollution, which will reduce particle concentrations
in the air and prevent thousands of premature deaths and tens of
thousands of heart attacks, bronchitis cases and asthma episodes.
    New or reconstructed EGUs (i.e., sources that commence construction
or reconstruction after May 3, 2011) subject to the MATS rule are
required to comply by April 16, 2012 or upon startup, whichever is
later.
    Existing sources subject to the MATS rule were required to begin
meeting the rule's requirements on April 16, 2015. Controls that will
achieve the MATS performance standards are being installed on many
units. Certain units, especially those that operate infrequently, may
be considered not worth investing in given today's electricity market,
and are closing. The final MATS rule provided a foundation on which
states and other permitting authorities could rely in granting an
additional, fourth year for compliance provided for by the CAA. States
report that these fourth year extensions are being granted. In
addition, the EPA issued an enforcement policy that provides a clear
pathway for reliability-critical units to receive an administrative
order that includes a compliance schedule of up to an additional year,
if it is needed to ensure electricity reliability.\566\
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    \566\ Following promulgation of the MATS rule, industry, states
and environmental organizations challenged many aspects of the EPA's
threshold determination that regulation of EGUs is ``appropriate and
necessary'' and the final standards regulating hazardous air
pollutants from EGUs. The U.S. Court of Appeals for the D.C. Circuit
upheld all aspects of the MATS rule. White Stallion Energy Center v.
EPA, 748 F.3d 1222 (D.C. Cir. 2014). The decision was unanimous on
all issues except a dissent was filed because the EPA did not
consider cost when determining regulation of EGUs is appropriate. In
Michigan v. EPA, case no. 14-46, the Supreme Court reversed the D.C.
Circuit decision upholding the MATS rule finding that EPA erred by
not considering cost when determining that regulation of EGUs was
``appropriate'' pursuant to section 112(n)(1). The Supreme Court
considered only the narrow question of cost and did not review the
other holdings of the D.C. Circuit, nor did the Supreme Court vacate
the MATS rule.
---------------------------------------------------------------------------

2. Cross-State Air Pollution Rule (CSAPR)
    The CSAPR requires states to take action to improve air quality by
reducing SO2 and NOX emissions that cross state
lines. These pollutants react in the atmosphere to form fine particles
and ground-level ozone and are transported long distances, making it
difficult for other states to attain and maintain the NAAQS. The first
phase of CSAPR became effective on January 1, 2015, for SO2
and annual NOX, and May 1, 2015, for ozone season
NOX. The second phase will become effective on January 1,
2017, for SO2 and annual NOX, and May 1, 2017,
for ozone season NOX. Many of the power plants participating
in CSAPR have taken actions to reduce hazardous air pollutants for MATS
compliance that will also reduce SO2 and/or NOX.
In this way these two rules are complementary. Compliance with one
helps facilities comply with the other.
3. Requirements for Cooling Water Intake Structures at Power Plants
(316(b) Rule)
    On May 19, 2014, the EPA issued a final rule under section 316(b)
of the Clean Water Act (33 U.S. Code section 1326(b)) (referred to
hereinafter as the 316(b) rule.) The rule was published on August 15,
2014 (79 FR 48300; August 15, 2014), and became effective October 14,
2014. The 316(b) rule establishes new standards to reduce injury and
death of fish and other aquatic life caused by cooling water intake
structures at existing power plants and manufacturing facilities.\567\
The 316(b)

rule subjects existing power plants and manufacturing facilities that
withdraw in excess of 2 million gallons per day (MGD) of cooling water,
and use at least 25 percent of that water for cooling purposes, to a
national standard designed to reduce the number of fish destroyed
through impingement and entrainment. Existing sources subject to the
316(b) rule are required to comply with the impingement requirements as
soon as practicable after the entrainment requirements are determined.
They must comply with applicable site-specific entrainment reduction
controls based on the schedule of requirements established by the
permitting authority. Additional information regarding the 316(b) rule
for existing sources is included in Section IX.C of the preamble to the
CAA section 111(d) emission guidelines for existing EGUs that the EPA
is finalizing simultaneously with this rule. Although the recently
issued 316(b) rule discussed here applies to existing sources, there
are also 316(b) technology-based standards for new sources with cooling
water intake structures.
---------------------------------------------------------------------------

    \567\ CWA section 316(b) provides that standards applicable to
point sources under sections 301 and 306 of the Act must require
that the location, design, construction and capacity of cooling
water intake structures reflect the best technology available for
minimizing adverse environmental impacts.
---------------------------------------------------------------------------

4. Disposal of Coal Combustion Residuals From Electric Utilities (CCR
Rule)
    On December 19, 2014, the EPA issued the final rule for the
disposal of coal combustion residuals from electric utilities. The rule
provides a comprehensive set of requirements for the safe disposal of
coal combustion residuals (CCRs), commonly known as coal ash, from
coal-fired power plants. The CCR rule establishes technical
requirements for existing and new CCR landfills and surface
impoundments under Subtitle D of the Resource Conservation and Recovery
Act (RCRA), the nation's primary law for regulating solid waste. New
CCR landfills and surface impoundments are required to meet the
technical criteria before any CCR is placed into the unit. Existing CCR
surface impoundments and landfills are subject to implementation
timeframes established in the rule for the individual technical
criteria. For additional information regarding the CCR rule, see
Section IX.C of the preamble to the CAA section 111(d) emission
guidelines for existing EGUs that the EPA is finalizing along with this
rule.
5. Steam Electric Effluent Limitation Guidelines and Standards (SE ELG
Rule)
    The EPA is reviewing public comments and working to finalize the
proposed SE ELG rule which will impact fossil fuel-fired EGUs. In 2013,
the EPA proposed the SE ELG rule (78 FR 34432; June 7, 2013) to
strengthen the controls on discharges from certain steam electric power
plants by revising technology-based effluent limitations guidelines and
standards for the steam electric power generating point source
category. The proposed regulation, which includes new requirements for
both existing and new generating units, would reduce impacts to human
health and the environment by reducing the amount of toxic metals and
other pollutants currently discharged to surface waters from power
plants. The EPA intends to take final action on the proposed rule by
September 30, 2015. Section IX.C of the preamble to the CAA section
111(d) emission guidelines for existing EGUs that the EPA is finalizing
simultaneously with this rule includes additional information regarding
the SE ELG rule.
    The EPA recognizes the importance of assuring that each of the
rules described above can achieve its intended environmental objectives
in a commonsense, cost-effective manner, consistent with underlying
statutory requirements, and while assuring a reliable power system.
Executive Order (E.O.) 13563, ``Improving Regulation and Regulatory
Review,'' issued on January 18, 2011, states that ``[i]n developing
regulatory actions and identifying appropriate approaches, each agency
shall attempt to promote . . . coordination, simplification, and
harmonization.'' E.O. 13563 further states that ``[e]ach agency shall
also seek to identify, as appropriate, means to achieve regulatory
goals that are designed to promote innovation.'' Within the EPA, we are
paying careful attention to the interrelatedness and potential impacts
on the industry, reliability and cost that these various rulemakings
can have.
    As discussed in earlier sections of this preamble, the EPA has
identified potential alternative compliance pathways for affected newly
constructed, modified, and reconstructed fossil fuel-fired steam
generating units. We are finalizing an emission standard for newly
constructed highly efficient fossil fuel-fired steam generating units
that can be met by capturing and storing approximately 16 to 23 percent
of the CO2 produced from the facility or by utilizing other
technologies such as natural gas co-firing. For a subcategory of steam
generating units that conduct ``large'' modifications according to
definitions in this final rule, we are finalizing an emission standard
that is based on a unit-specific emission limitation consistent with
each modified unit's best one-year historical performance and can be
met through a combination of best operating practices and equipment
upgrades. For reconstructed steam generating units, the EPA is
finalizing standards of performance based on the performance of the
most efficient generation technology available, which we concluded is
the use of the best available subcritical steam conditions for small
units and the use of supercritical steam conditions for large units.
The standards can also be met through other technology options such as
natural gas co-firing. In light of these potential alternative
compliance pathways, we believe that sources will have ample
opportunity to coordinate their response to this rule with any
obligations that may be applicable to affected EGUs as a result of the
MATS, CSAPR, 316(b), SE ELG and CCR rules, all of which are or soon
will be final rules--and to do so in a manner that will help reduce
cost and ensure reliability, while also ensuring that all applicable
environmental requirements are met.\568\
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    \568\ It should be noted that regulatory obligations imposed
upon states and sources operate independently under different
statutes and sections of statutes; the EPA expects that states and
sources will take advantage of available flexibilities as
appropriate, but will comply with all relevant legal requirements.
---------------------------------------------------------------------------

    The EPA is also endeavoring to enable EGUs to comply with
applicable obligations under other power sector rules as efficiently as
possible (e.g., by facilitating their ability to coordinate planning
and investment decisions with respect to those rules) and, where
possible, implement integrated compliance strategies. Section IX.C of
the preamble to the CAA section 111(d) emission guidelines for existing
EGUs that the EPA is finalizing simultaneously with this rule describes
such an example with respect to the SE ELG and CCR rules.
    In light of the compliance flexibilities we are offering in this
action, we believe that sources will have ample opportunity to use
cost-effective regulatory strategies and build on their longstanding,
successful records of complying with multiple CAA, CWA, and other
environmental requirements, while assuring an adequate, affordable, and
reliable supply of electricity.

XIII. Impacts of This Action

    As explained in the ``Regulatory Impact Analysis for the Standards
of Performance for Greenhouse Gas Emissions for New, Modified, and
Reconstructed Stationary Sources: Electric Utility Generating Units''
(EPA-452/R-15-005, August 2015) (RIA), available data indicate that,
even in the absence of the standards of performance for newly
constructed EGUs, existing and anticipated economic conditions will
lead electricity generators to choose new generation technologies that
will meet the standards without installation of additional controls.
Therefore, based on the analysis presented in Chapter 4 of the RIA, the
EPA projects that this final rule will result in negligible
CO2 emission changes, quantified benefits, and costs on
owners and operators of newly constructed EGUs by 2022.\569\ This
conclusion is based on the EPA's own modeling as well as projections by
EIA. While the primary conclusion of the analysis presented in the RIA
is that the standards for newly constructed EGUs will result in
negligible costs and benefits, the EPA has also performed several
illustrative analyses that show the potential impacts of the rule if
certain key assumptions were to change. This includes an analysis of
the impacts under a range of natural gas prices and the costs and
benefits associated with building an illustrative coal-fired EGU with
CCS. These are presented in Chapter 5 of the RIA.
---------------------------------------------------------------------------

    \569\ Conditions in the analysis year of 2022 are represented by
a model year of 2020.
---------------------------------------------------------------------------

    As also explained in the RIA for this final rule, the EPA also
expects that few sources will trigger either the NSPS modification or
reconstruction provisions that we are finalizing in this rule. In
Chapter 6 of the RIA, we discuss factors that limit our ability to
quantify the costs and benefits of the standards for modified and
reconstructed sources.

A. What are the air impacts?

    As explained immediately above, the EPA does not anticipate that
this final rule will result in notable CO2 emission changes
by 2022 as a result of the standards of performance for newly
constructed EGUs. The owners of newly constructed EGUs will likely
choose technologies, primarily NGCC, which meet the standards even in
the absence of this rule due to existing economic conditions as normal
business practice.
    As also explained immediately above, the EPA expects few EGUs to
trigger the NSPS modification or reconstruction provisions in the
period of analysis.
    New steam generating EGUs that choose to comply with the final
standard of performance by implementing partial post-combustion CCS are
likely to use commercially-available amine-based capture systems. Some
concern has been raised regarding emissions of amines and amine
degradation by-products (e.g., NH3) from the capture
process. To reduce the amine emissions, MHI introduced the first
optimized washing system within an absorber column in 1994, and
developed a proprietary washing system in 2003. In that system, a
proprietary reagent is added to the water washing section to capture
amine impurities such as amine, degraded amine, ammonia, formaldehyde,
acetaldehyde, carbonic acids and nitrosamines.\570\ MHI has continued
to improve this technology for further reduction of amine emissions and
established an ``advanced amine emission reduction system''.
---------------------------------------------------------------------------

    \570\ Sharma, S.; Azzi, M.; ``A critical review of existing
strategies for emission control in the monoethanolamine-based carbon
capture process and some recommendations for improved strategies'',
Fuel, 121, 178 (2014).
---------------------------------------------------------------------------

    Research performed by MHI at Alabama Power's Plant Barry indicated
that an increasing SO3 content in the flue gas caused a
significant increase of amine emissions. During testing, at Plant
Barry, MHI applied its proprietary washing system and confirmed that
the amine emission were drastically reduced.\571\ Others have also
studied emissions and control strategies and have determined that a
conventional multi-stage water wash and mist eliminator at the exit of
the CO2 scrubber is effective at removal of gaseous amine
and amine degradation products emissions.572 573 Additional
research continues in this area.
---------------------------------------------------------------------------

    \571\ Kamijo, T.; et al., ``SO3 Impact on Amine
Emission and Emission Reduction Technology'', Energy Procedia,
Volume 37, 1793 (2013).
    \572\ Sharma, S. (2014).
    \573\ Mertens, J.; et al., ``Understanding ethanolamine (MEA)
and ammonia emissions from amine based post combustion carbon
capture: Lessons learned from field tests'', Int'l J. of GHG
Control, 13, 72 (2013).
---------------------------------------------------------------------------

B. Endangered Species Act

    Consistent with the requirements of section 7(a)(2) of the
Endangered Species Act (ESA), the EPA has also considered the effects
of this rule and has reviewed applicable ESA regulations, case law, and
guidance to determine what, if any, impact there may be to listed
endangered or threatened species or the designated critical habitat of
such species and whether consultation with the U.S. Fish and Wildlife
Service (FWS) and/or National Marine Fisheries Service (together, the
Services) is required by the ESA. Section 7(a)(2) of the ESA requires
federal agencies, in consultation with the Service(s), to ensure that
actions they authorize, fund, or carry out are not likely to jeopardize
the continued existence of federally listed endangered or threatened
species or result in the destruction or adverse modification of
designated critical habitat of such species. 16 U.S.C. 1536(a)(2).
Under relevant implementing regulations, ESA section 7(a)(2) applies
only to actions where there is discretionary federal involvement or
control. 50 CFR 402.03. Further, under the regulations consultation is
required only for actions that ``may affect'' listed species or
designated critical habitat. 50 CFR 402.14. Consultation is not
required where the action has no effect on such species or habitat.
Under this standard, it is the federal agency taking the action that
evaluates the action and determines whether consultation is required.
See 51 FR 19926, 19949 (June 3, 1986). Effects of an action include
both the direct and indirect effects that will be added to the
environmental baseline. 50 CFR 402.02. Direct effects are the direct or
immediate effects of an action on a listed species or its habitat.\574\
Indirect effects are those that are ``caused by the proposed action and
are later in time, but still are reasonably certain to occur.'' Id. To
trigger the consultation requirement, there must thus be a causal
connection between the federal action, the effect in question, and the
listed species, and if the effect is indirect, it must be reasonably
certain to occur.
---------------------------------------------------------------------------

    \574\ See Endangered Species Consultation Handbook, U.S. Fish &
Wildlife Service and National Marine Fisheries Service at 4-25(March
1998) (providing examples of direct effects: e.g., driving an off
road vehicle through the nesting habitat of a listed species of bird
and destroying a ground nest; building a housing unit and destroying
the habitat of a listed species).
---------------------------------------------------------------------------

    The EPA notes that the projected environmental effects of this
final action are positive: Reductions in overall GHG emissions, and
reductions in PM and ozone-precursor emissions (SOX and
NOX). The EPA recognizes that beneficial effects to listed
species can, as a general matter, result in a ``may affect''
determination under the ESA. However, the EPA's assessment that the
rule will have an overall net positive environmental effect by virtue
of reducing emissions of certain air pollutants does not address
whether the rule may affect any listed species or designated critical
habitat for ESA section 7(a)(2) purposes and does not constitute any
finding of effects for that purpose. The fact that the rule will have
overall positive effects on the national

and global environment does not mean that the rule may affect any
listed species in its habitat or the designated critical habitat of
such species within the meaning of ESA section 7(a)(2) or the
implementing regulations or require ESA consultation.
    The EPA notes that the emission reductions achieved by the rule are
projected to be minor. See Section XIII.F and G. below, and RIA chapter
4. Although the final rule imposes substantial controls on
CO2 emissions, we project few if any new fossil fuel-fired
steam generating units to be built. Emissions reductions from turbines
are likewise projected to be minimal. Moreover, we reasonably project
that capacity additions during the analysis period out to 2022 would
already be compliant with the rule's requirements (e.g., natural gas
combined cycle units, low capacity factor natural gas combustion
turbines, and small amounts of coal-fired units with CCS supported by
federal and state funding). See RIA chapter 4.
    With respect to the projected GHG emission reductions, the EPA does
not believe that such minor reductions trigger ESA consultation
requirements under section 7(a)(2). In reaching this conclusion, the
EPA is mindful of significant legal and technical analysis undertaken
by FWS and the U.S. Department of the Interior (DOI) in the context of
listing the polar bear as a threatened species under the ESA. In that
context, in 2008, FWS and DOI expressed the view that the best
scientific data available were insufficient to draw a causal connection
between GHG emissions and effects on the species in its habitat.\575\
The DOI Solicitor concluded that where the effect at issue is climate
change, proposed actions involving GHG emissions cannot pass the ``may
affect'' test of the section 7 regulations and thus are not subject to
ESA consultation.
---------------------------------------------------------------------------

    \575\ See, e.g., 73 FR 28212, 28300 (May 15, 2008); Memorandum
from David Longly Bernhardt, Solicitor, U.S. Department of the
Interior re: ``Guidance on the Applicability of the Endangered
Species Act's Consultation Requirements to Proposed Actions
Involving the Emission of Greenhouse Gases'' (Oct. 3, 2008).
---------------------------------------------------------------------------

    The EPA has also previously considered issues relating to GHG
emissions in connection with the requirements of ESA section 7(a)(2)
and has supplemented DOI's analysis with additional consideration of
GHG modeling tools and data regarding listed species. The EPA evaluated
this same issue in the context of the light duty vehicle GHG emission
standards for model years 2012-2016 and 2017-2025. There the agency
projected GHG emission reductions many orders of magnitude greater over
the lifetimes of the model years in question \576\ and, based on air
quality modeling of potential environmental effects, concluded that
``EPA knows of no modeling tool which can link these small, time-
attenuated changes in global metrics to particular effects on listed
species in particular areas. Extrapolating from global metric to local
effect with such small numbers, and accounting for further links in a
causative chain, remain beyond current modeling capabilities.'' EPA,
Light Duty Vehicle Greenhouse Gas Standards and Corporate Average Fuel
Economy Standards, Response to Comment Document for Joint Rulemaking at
4-102 (Docket EPA-OAR-HQ-2009-4782). The EPA reached this conclusion
after evaluating issues relating to potential improvements relevant to
both temperature and oceanographic pH outputs. The EPA's ultimate
finding was that ``any potential for a specific impact on listed
species in their habitats associated with these very small changes in
average global temperature and ocean pH is too remote to trigger the
threshold for ESA section 7(a)(2).''Id. The EPA believes that the same
conclusions apply to the present action, given that the projected
CO2 emission reductions are far less than those projected
for either of the light duty vehicle rules. See, e.g., Ground Zero
Center for Non-Violent Action v. U.S. Dept. of Navy, 383 F. 3d 1082,
1091-92 (9th Cir. 2004) (where the likelihood of jeopardy to a species
from a federal action is extremely remote, ESA does not require
consultation). The EPA's conclusion is entirely consistent with DOI's
analysis regarding ESA requirements in the context of federal actions
involving GHG emissions.\577\
---------------------------------------------------------------------------

    \576\ See 75 FR at 25438 Table I.C 2-4 (May 7, 2010); 77 FR at
62894 Table III-68 (Oct. 15, 2012).
    \577\ The EPA has received correspondence from Members of
Congress asserting that the Services have identified several listed
species affected by global climate change. The EPA's assessment of
ESA requirements in connection with the present rule does not
address whether global climate change may, as a general matter, be a
relevant consideration in the status of certain listed species.
Rather, the requirements of ESA section 7(a)(2) must be considered
and applied to the specific action at issue. As explained above, the
EPA's conclusion that ESA section 7(a)(2) consultation is not
required here is premised on the specific facts and circumstances of
the present rule and is fully consistent with prior relevant
analyses conducted by DOI, FWS, and the EPA.
---------------------------------------------------------------------------

    The EPA received a comment on the proposal referencing a prior
letter sent to the EPA by three U.S. Senators,\578\ which asserted that
the rule will cause a shift to alternative sources of energy such as
wind and solar and that such facilities may have impacts on listed
species. The comment inquired regarding ESA consultation in connection
with the rule. We reiterate that no consultation is required for a rule
without potential for a specific impact on listed species in their
habitats.
---------------------------------------------------------------------------

    \578\ See Letter from David Vitter, James M. Inhofe, and Mike
Crapo, United States Senate Committee on Environment and Public
Works, to Gina McCarthy, Administrator, U.S. Environmental
Protection Agency, and Dan Ashe, Director, U.S. Fish and Wildlife
Service, dated March 6, 2014.
---------------------------------------------------------------------------

C. What are the energy impacts?

    This final 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 will choose to build new EGUs
that comply with the regulatory requirements of this rule even in its
absence, primarily NGCC units, because of existing and expected market
conditions. As also previously stated, the EPA expects few EGUs to
trigger the NSPS modification or reconstruction provisions in the
period of analysis.

D. What are the water and solid waste impacts?

    This final rule is not anticipated to have notable impacts on water
or solid waste. As we have noted, the EPA believes that utilities and
project developers will choose to build new EGUs that comply with the
regulatory requirements of this rule even in its absence, primarily
through the construction of new NGCC units. As also previously stated,
the EPA expects few EGUs to trigger the NSPS modification or
reconstruction provisions in the period of analysis. Still there are
expected to be a small number of coal plants with CCS and the use of
CCS systems (especially post-combustion system) will increase the
amount of water used at the facility. If those plants utilize partial
CCS to meet the final standard of performance (i.e., approximately 16
to 23 percent capture), the increased water use will not be
significant. See Section V.O.2. The EPA is unaware of any solid waste
impact resulting from this rule.\579\
---------------------------------------------------------------------------

    \579\ Estimated costs for the rule include costs for fly ash and
bottom ash disposal and for spent solvent recovery and handling. See
``Cost and Performance Baseline for Fossil Energy Plants Volume 1a:
Bituminous Coal (PC) and Natural Gas to Electricity, Revision 3'',
DOE/NETL-2015/1723 (July 2015) at pp. 43, 130.
---------------------------------------------------------------------------

E. What are the compliance costs?

    For steam generating EGUs, the EPA has carefully analyzed the costs
of meeting the promulgated standard of performance for a highly
efficient SCPC

using partial CCS and found these costs to be reasonable. See Sections
V.H and I above. This analysis assumes new capacity not otherwise
compliant with the standards would be constructed. Based on the
analysis in chapter 4 of the RIA, the EPA believes the standards of
performance for newly constructed EGUs will have no notable compliance
costs, because electric power companies are expected to build new EGUs
that comply with the regulatory requirements of this final rule even in
the absence of the rule, primarily NGCC units, due to existing and
expected market conditions. While the EPA's analysis and projections
from EIA continue to show that the rule is likely to result in
negligible costs and benefits due to existing generation choices, the
EPA recognizes that some companies may choose to construct coal or
other fossil fuel-fired units and has set standards for these units
accordingly. For this reason, 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.
    In addition, the EPA believes the standards of performance for
modified and reconstructed EGUs will have minimal associated compliance
costs, because, as previously stated, the EPA expects few EGUs to
trigger the NSPS modification or reconstruction provisions in the
period of analysis.

F. What are the economic and employment impacts?

    The EPA does not anticipate that this final rule will result in
notable CO2 emission changes, energy impacts, monetized
benefits, costs, or economic impacts by 2022 as a result of the
standards of performance for newly constructed EGUs. The owners of
newly constructed EGUs will likely choose technologies that meet the
standards even in the absence of this rule, 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. See RIA chapter 4.6.\580\
---------------------------------------------------------------------------

    \580\ The employment analysis in the RIA is part of the EPA's
ongoing effort to ``conduct continuing evaluations of potential loss
or shifts of employment which may result from the administration or
enforcement of [the Act]'' pursuant to CAA section 321(a).
---------------------------------------------------------------------------

    As previously stated, the EPA anticipates few units will trigger
the NSPS modification or reconstruction provisions. As with the new
source standards, the EPA does not expect macroeconomic or employment
impacts as a result of the standards.

G. What are the benefits of the final standards?

    We are not projecting direct monetized climate benefits in terms of
CO2 emission reductions associated with these standards of
performance. This is because, as stated above, the EPA believes that
electric power companies will choose to build new EGUs that comply with
the regulatory requirements of this rule even in its absence, primarily
NGCC units, because of existing and expected market conditions. See RIA
chapter 4. Moreover, a cost-reasonable standard is, in fact, what will
drive new technology deployment and provide a path forward for new
coal-fired capacity. See Section V.L above.
    As also previously stated, the EPA anticipates few units will
trigger the NSPS modification or reconstruction provisions. In Chapter
6 of the RIA, we discuss factors that limit our ability to quantify the
costs and benefits of the standards for modified and reconstructed
sources.

XIV. Statutory and Executive Order Reviews

    Additional information about these Statutory and Executive Orders
can be found at http://www2.epa.gov/laws-regulations/laws-and-executive-orders.

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

    This final action is a significant regulatory action that was
submitted to the Office of Management and Budget (OMB) for review. It
is a significant regulatory action because it raises novel legal or
policy issues arising out of legal mandates. Any changes made in
response to OMB recommendations have been documented in the established
dockets for this action under Docket ID No. EPA-HQ-OAR-2013-0495
(Standards of Performance for Greenhouse Gas Emissions from New
Stationary Sources: Electric Utility Generating Units) and Docket ID
No. EPA-HQ-OAR-2013-0603 (Carbon Pollution Standards for Modified and
Reconstructed Stationary Sources: Electric Utility Generating Units).
The EPA prepared an economic analysis of the potential costs and
benefits associated with this action. This analysis, which is contained
in the ``Regulatory Impact Analysis for the Standards of Performance
for Greenhouse Gas Emissions for New, Modified, and Reconstructed
Stationary Sources: Electric Utility Generating Units'' (EPA-452/R-15-
005, August 2015), is available in both dockets.
    The EPA does not anticipate that this final action will result in
any notable compliance costs. Specifically, we believe that the
standards for newly constructed fossil fuel-fired EGUs (electric
utility steam generating units and natural gas-fired stationary
combustion turbines) will have negligible 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 action even in the absence of the action, because
of existing and expected market conditions. (See the RIA for further
discussion of sensitivities). The EPA does not project any new coal-
fired steam generating units without CCS to be built in the absence of
this action. However, because some companies may choose to construct
coal or other fossil fuel-fired EGUs, the RIA also analyzes project-
level costs of a unit with and without CCS, to quantify the potential
cost for a fossil fuel-fired EGU with CCS.
    The EPA also believes that the standards for modified and
reconstructed fossil fuel-fired EGUs will result in minimal compliance
costs, because, as previously stated, the EPA expects few EGUs to
trigger the NSPS modification or reconstruction provisions in the
period of analysis (through 2022). In Chapter 6 of the RIA, we discuss
factors that limit our ability to quantify the costs and benefits of
the standards for modified and reconstructed sources.

B. Paperwork Reduction Act (PRA)

    The information collection activities in this final action have
been submitted for approval to OMB under the PRA. The Information
Collection Request (ICR) document that the EPA prepared has been
assigned EPA ICR number 2465.03. Separate ICR documents were prepared
and submitted to OMB for the proposed standards for newly constructed
EGUs (EPA ICR number 2465.02) and the proposed standards for modified
and reconstructed EGUs (EPA ICR number 2506.01). Because the
CO2 standards for newly constructed, modified, and
reconstructed EGUs will be included in the same new subpart (40 CFR
part 60, subpart TTTT) and are being finalized in the same action, the
ICR document for this action includes estimates of the information
collection burden on owners and operators of newly constructed,
modified, and reconstructed EGUs. Estimated cost burden is based on
2013 Bureau of Labor Statistics (BLS) labor cost data.

Thus, all burden estimates are in 2013 dollars. Burden is defined at 5
CFR 1320.3(b). You can find a copy of the ICR in the dockets for this
action (Docket ID Numbers EPA-HQ-OAR-2013-0495 and EPA-HQ-OAR-2013-
0603), and it is briefly summarized here. The information collection
requirements are not enforceable until OMB approves them.
    The recordkeeping and reporting requirements in this final action
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.
    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. When OMB
approves this ICR, the agency will announce that approval in the
Federal Register and publish a technical amendment to 40 CFR part 9 to
display the OMB control number for the approved information collection
activities contained in this final action.
1. Newly Constructed EGUs
    This final action will impose minimal new information collection
burden on owners and operators of affected newly constructed fossil
fuel-fired EGUs (steam generating units and stationary combustion
turbines) 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 to comply with the emission
standards under the rule, there are no new information collection
costs, as the information required by the standards for newly
constructed EGUs is already collected and reported by other regulatory
programs.
    The EPA believes that electric power companies will choose to build
new EGUs that comply with the regulatory requirements of the rule
because of existing and expected market conditions. The EPA does not
project any newly constructed coal-fired steam generating units that
commenced construction after proposal (January 8, 2014) to commence
operation over the 3-year period covered by this ICR. We estimate that
12 affected newly constructed NGCC units and 25 affected newly
constructed natural gas-fired simple cycle combustion turbines will
commence operation during that time period. As a result of this final
action, owners or operators of those newly constructed units will be
required to prepare a summary report, which includes reporting of
emissions and downtime, every 3 months.
2. Modified and Reconstructed EGUs
    This final action is not expected to impose an information
collection burden under the provisions of the PRA on owners and
operators of affected modified and reconstructed fossil fuel-fired EGUs
(steam generating units and stationary combustion turbines). As
previously stated, the EPA expects few EGUs to trigger the NSPS
modification or reconstruction provisions in the period of analysis.
Specifically, the EPA believes it unlikely that fossil fuel-fired
electric utility steam generating units or stationary combustion
turbines will take actions that would constitute modifications or
reconstructions as defined under the EPA's NSPS regulations.
Accordingly, the standards for modified and reconstructed EGUs are not
anticipated to impose any information collection burden over the 3-year
period covered by this ICR. We have estimated, however, the information
collection burden that would be imposed on an affected EGU if it was
modified or reconstructed.
    Although not anticipated, if an EGU were to modify or reconstruct,
this final action would impose minimal information collection burden on
those affected EGUs beyond what they would already be subject to under
the authorities of CAA 40 CFR parts 75 and 98. As described above, the
OMB has previously approved the information collection requirements
contained in the existing part 75 and 98 regulations. Apart from
certain reporting costs to comply with the emission standards under the
rule, there would be no new information collection costs, as the
information required by the final rule is already collected and
reported by other regulatory programs.
    As stated above, although the EPA expects few sources will trigger
either the NSPS modification or reconstruction provisions, if an EGU
were to modify or reconstruct during the 3-year period covered by this
ICR, the owner or operator of the EGU will be required to prepare a
summary report, which includes reporting of emissions and downtime,
every 3 months. The annual reporting burden for such a unit is
estimated to be $1,333 and 16 labor hours. There are no annualized
capital costs or O&M costs associated with burden for modified or
reconstructed EGUs.
3. Information Collection Burden
    The annual information collection burden for newly constructed,
modified, and reconstructed EGUs consists only of reporting burden as
explained above. The annual reporting burden for this collection
(averaged over the first 3 years after the effective date of the
standards) is estimated to be $60,977 and 651 labor hours. There are no
annualized capital costs or O&M costs associated with burden for newly
constructed, modified, or reconstructed EGUs. Average burden hours per
response are estimated to be 7 hours. The total number of respondents
over the 3-year ICR period is estimated to be 62.

C. Regulatory Flexibility Act (RFA)

    I certify that this final action will not have a significant
economic impact on a substantial number of small entities under the
RFA. In making this determination, the impact of concern is any
significant adverse economic impact on small entities. An agency may
certify that a rule will not have a significant economic impact on a
substantial number of small entities if the rule relieves regulatory
burden, has no net burden or otherwise has a positive economic effect
on the small entities subject to the rule.
1. Newly Constructed EGUs
    The EPA believes that electric power companies will choose to build
new fossil fuel-fired electric utility steam generating units or
natural gas-fired stationary combustion turbines that comply with the
regulatory requirements of the final rule because of existing and
expected market conditions. RIA Chapter 4. The EPA does not project any
new coal-fired steam generating units without CCS to be built. We
expect that any newly constructed natural gas-fired stationary
combustion turbines will meet the standards. We do not include an
analysis of the illustrative impacts on small entities that may result
from implementation of the final rule because we anticipate negligible
compliance costs over a range of likely sensitivity conditions as a
result of the standards for newly constructed EGUs. Thus the cost-to-
sales ratios for any affected small entity would be zero costs as
compared to annual sales revenue for the entity. Accordingly, there are
no anticipated

economic impacts as a result of the standards for newly constructed
EGUs. (See the ``Regulatory Impact Analysis for the Standards of
Performance for Greenhouse Gas Emissions for New, Modified, and
Reconstructed Stationary Sources: Electric Utility Generating Units''
(EPA-452/R-15-005, August 2015) for further discussion of
sensitivities.) We have therefore concluded that this final action will
have no net regulatory burden for all directly regulated small
entities.
2. Modified and Reconstructed EGUs
    The EPA expects few fossil fuel-fired electric utility steam
generating units to trigger the NSPS modification provisions in the
period of analysis. An NSPS modification is defined as a physical or
operational change that increases the source's maximum achievable
hourly rate of emissions. The EPA does not believe that there are
likely to be EGUs that will take actions that would constitute
modifications as defined under the EPA's NSPS regulations.
    In addition, the EPA expects few reconstructed fossil fuel-fired
electric utility steam generating units or natural gas-fired stationary
combustion turbines in the period of analysis. Reconstruction occurs
when a single project replaces components or equipment in an existing
facility and exceeds 50 percent of the fixed capital cost that would be
required to construct a comparable entirely new facility.
    In Chapter 6 of the RIA, we discuss factors that limit our ability
to quantify the costs and benefits of the standards for modified and
reconstructed sources. However, we do not anticipate that the rule
would impose significant costs on those sources, including any that are
owned by small entities. (See the ``Regulatory Impact Analysis for the
Standards of Performance for Greenhouse Gas Emissions for New,
Modified, and Reconstructed Stationary Sources: Electric Utility
Generating Units'' (EPA-452/R-15-005, August 2015).

D. Unfunded Mandates Reform Act (UMRA)

    This final action does not contain an unfunded mandate of $100
million or more as described in UMRA, 2 U.S.C. 1531-1538, and does not
significantly or uniquely affect small governments.
    The EPA believes the final rule will have negligible compliance
costs on owners and operators of newly constructed EGUs over a range of
likely sensitivity conditions because electric power companies will
choose to build new fossil fuel-fired electric utility steam generating
units or natural gas-fired stationary combustion turbines that comply
with the regulatory requirements of the rule because of existing and
expected market conditions. The EPA does not project any new coal-fired
steam generating units without CCS to be built and expects that any
newly constructed natural gas-fired stationary combustion turbines will
meet the standards. (See the ``Regulatory Impact Analysis for the
Standards of Performance for Greenhouse Gas Emissions for New,
Modified, and Reconstructed Stationary Sources: Electric Utility
Generating Units'' (EPA-452/R-15-005, August 2015) for further
discussion of sensitivities.)
    As previously stated, the EPA expects few fossil fuel-fired
electric utility steam generating units or natural gas-fired stationary
combustion turbines to trigger the NSPS modification or reconstruction
provisions in the period of analysis. In Chapter 6 of the RIA, we
discuss factors that limit our ability to quantify the costs and
benefits of the standards for modified and reconstructed sources.
However, we do not anticipate that the rule would impose significant
costs on those sources. (See the ``Regulatory Impact Analysis for the
Standards of Performance for Greenhouse Gas Emissions for New,
Modified, and Reconstructed Stationary Sources: Electric Utility
Generating Units'' (EPA-452/R-15-005, August 2015).)
    We have therefore concluded that the standards for newly
constructed, modified, and reconstructed EGUs do not impose enforceable
duties on any state, local or tribal governments, or the private
sector, that may result in expenditures by state, local and tribal
governments, in the aggregate, or to the private sector, of $100
million or more in any one year. We have also concluded that this
action does not have regulatory requirements that might significantly
or uniquely affect small governments. The threshold amount established
for determining whether regulatory requirements could significantly
affect small governments is $100 million annually and, as stated above,
we have concluded that the final action will not result in expenditures
of $100 million or more in any one year. Specifically, the EPA does not
project any new coal-fired steam generating units without CCS to be
built and expects that any newly constructed natural gas-fired
stationary combustion turbines will meet the standards. Further, the
EPA expects few fossil fuel-fired electric utility steam generating
units or natural gas-fired stationary combustion turbines to trigger
the NSPS modification or reconstruction provisions in the period of
analysis.

E. Executive Order 13132: Federalism

    This final action does not have federalism implications. It will
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.
The EPA believes that electric power companies will choose to build new
fossil fuel-fired electric utility steam generating units or natural
gas-fired stationary combustion turbines that comply with the
regulatory requirements of the final rule because of existing and
expected market conditions. In addition, as previously stated, the EPA
expects few fossil fuel-fired electric utility steam generating units
or natural gas-fired stationary combustion turbines to trigger the NSPS
modification or reconstruction provisions in the period of analysis.
We, therefore, anticipate that the final rule will impose minimal
compliance costs.

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

    This final action does not have tribal implications as specified in
Executive Order 13175. The final rule will impose requirements on
owners and operators of newly constructed, modified, and reconstructed
EGUs. The EPA is aware of three facilities with coal-fired steam
generating units, as well as one facility with natural gas-fired
stationary combustion turbines, located in Indian Country, but is not
aware of any EGUs owned or operated by tribal entities. We note that
because the rule addresses CO2 emissions from newly
constructed, modified, and reconstructed EGUs, it will affect existing
EGUs such as those located at the four facilities in Indian Country
only if those EGUs were to take actions constituting modifications or
reconstructions as defined under the EPA's NSPS regulations. As
previously stated, the EPA expects few EGUs to trigger the NSPS
modification or reconstruction provisions in the period of analysis.
Thus, the rule will neither impose substantial direct compliance costs
on tribal governments nor preempt Tribal law. Accordingly, Executive
Order 13175 does not apply to this action.
    Nevertheless, because the EPA is aware of Tribal interest in carbon
pollution standards for the power sector and, consistent with the EPA
Policy on Consultation and Coordination with Indian Tribes, the EPA
offered consultation with tribal officials during

development of this rule. Prior to the April 13, 2012 proposal (77 FR
22392), the EPA sent consultation letters to the leaders of all
federally recognized tribes. Although only newly constructed, modified,
and reconstructed EGUs will be affected by this action, the EPA's
consultation regarded planned actions for new and existing sources. 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. A description
of that consultation is included in the preamble to the proposed
standards for new EGUs (79 FR 1501, January 8, 2014).
    The EPA also offered consultation to the leaders of all federally
recognized tribes after the proposed action for newly constructed EGUs
was signed on September, 20, 2013. On November 1, 2013, the EPA sent
letters to tribal leaders that provided information regarding the EPA's
development of carbon pollution standards for new, modified,
reconstructed and existing EGUs and offered consultation. No tribes
requested consultation regarding the standards for newly constructed
EGUs.
    In addition to offering consultation, the EPA also conducted
outreach to tribes during development of this rule. The EPA held a
series of listening sessions prior to proposal of GHG standards for
newly constructed EGUs. Tribes participated in a session on February
17, 2011, with the state agencies, as well as in a separate session
with tribes on April 20, 2011. The EPA also held a series of listening
sessions prior to proposal of GHG standards for modified and
reconstructed EGUs and GHG emission guidelines for existing EGUs.
Tribes participated in a session on September 9, 2013, together with
the state agencies, as well as in a separate tribe-only session on
September 26, 2013. In addition, an outreach meeting was held on
September 9, 2013, with tribal representatives from some of the
federally recognized tribes. The EPA also met with tribal environmental
staff with the National Tribal Air Association, by teleconference, on
July 25, 2013, and December 19, 2013. Additional detail regarding this
stakeholder outreach is included in the preamble to the proposed
emission guidelines for existing EGUs (79 FR 34830, June 18, 2014).

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

    This action is not subject to Executive Order 13045 because it is
not economically significant as defined in Executive Order 12866. While
the action is not subject to Executive Order 13045, the EPA believes
that the environmental health or safety risk addressed by this action
has a disproportionate effect on children. Accordingly, the agency has
evaluated the environmental health and welfare effects of climate
change on children.
    CO2 is a potent GHG that contributes to climate change
and is emitted in significant quantities by fossil fuel-fired power
plants. As stated above, the EPA believes the final rule will have
negligible effects on owners and operators of newly constructed EGUs
over a range of likely sensitivity conditions because electric power
companies will choose to build new fossil fuel-fired electric utility
steam generating units or natural gas-fired stationary combustion
turbines that comply with the regulatory requirements of the rule
because of existing and expected market conditions. However, 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. RIA
chapter 5. Under these scenarios, the rule would result in substantial
reductions of both CO2, and also fine particulate matter
(sulfate PM 2.5) such that net quantifiable benefits exceed regulatory
costs under a range of assumptions. Under these same scenarios, this
rule would have a positive effect for children's health.
    The assessment literature cited in the EPA's 2009 Endangerment
Finding concluded that certain populations and lifestages, including
children, the elderly, and the poor, are most vulnerable to climate-
related health effects. The assessment literature since 2009
strengthens these conclusions by providing more detailed findings
regarding these groups' vulnerabilities and the projected impacts they
may experience.
    These assessments describe how children's unique physiological and
developmental factors contribute to making them particularly vulnerable
to climate change. Impacts to children are expected from heat waves,
air pollution, infectious and waterborne illnesses, and mental health
effects resulting from extreme weather events. In addition, children
are among those especially susceptible to most allergic diseases, as
well as health effects associated with heat waves, storms, and floods.
Additional health concerns may arise in low income households,
especially those with children, if climate change reduces food
availability and increases prices, leading to food insecurity within
households.
    More detailed information on the impacts of climate change to human
health and welfare is provided in Section II.A of this preamble.

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

    This final action is not a ``significant energy action'' because it
is not likely to have a significant adverse effect on the supply,
distribution, or use of energy. See Section V.O.3 above. The EPA
believes that electric power companies will choose to build new fossil
fuel-fired electric utility steam generating units or natural gas-fired
stationary combustion turbines that comply with the regulatory
requirements of the final rule because of existing and expected market
conditions. In addition, as previously stated, the EPA expects few
fossil fuel-fired electric utility steam generating units or natural
gas-fired stationary combustion turbines to trigger the NSPS
modification or reconstruction provisions in the period of analysis.
Thus, this 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 (NTTAA) and 1 CFR
Part 51

    This final action involves technical standards. The EPA has decided
to use 10 voluntary consensus standards (VCS) in the final rule.
    One VCS, American National Standards Institute (ANSI) Standard
C12.20, ``American National Standard for Electricity Meters--0.2 and
0.5 Accuracy Classes,'' is cited in the final rule to assure consistent
monitoring of electric output. This standard establishes the physical
aspects and acceptable performance criteria for 0.2 and 0.5 accuracy
class electricity meters. This standard is available at http://www.ansi.org or by mail at American National Standards Institute
(ANSI), 25 W. 43rd Street, 4th Floor, New York, NY 10036.
    Six VCS, ASTM Methods D388-99, ``Standard Classification of Coals
by Rank''; D396-98, ``Standard Specification for Fuel Oils''; D975-08a,
``Standard Specification for Diesel Fuel Oils''; D3699-08, ``Standard
Specification for Kerosine''; D6751-11b,

``Standard Specification for Biodiesel Fuel Blend Stock (B100) for
Middle Distillate Fuels''; and D7467-10, ``Standard Specification for
Diesel Fuel Oil, Biodiesel Blend (B6 to B20)'' are cited in the final
rule to identify the different fuel types. ASTM D388 covers the
classification of coals by rank, that is, according to their degree of
metamorphism, or progressive alteration, in the natural series from
lignite to anthracite. ASTM D396 covers grades of fuel oil intended for
use in various types of fuel-oil-burning equipment under various
climatic and operating conditions. These include Grades 1 and 2 (for
use in domestic and small industrial burners), Grade 4 (heavy
distillate fuels or distillate/residual fuel blends used in commercial/
industrial burners equipped for this viscosity range), and Grades 5 and
6 (residual fuels of increasing viscosity and boiling range, used in
industrial burners). ASTM D975 covers seven grades of diesel fuel oils
based on grade, sulfur content, and volatility. These grades range from
Grade No. 1-D S15 (a special-purpose, light middle distillate fuel for
use in diesel engine applications requiring a fuel with 15 ppm sulfur
(maximum) and higher volatility than that provided by Grade No. 2-D S15
fuel) to Grade No. 4-D (a heavy distillate fuel, or a blend of
distillate and residual oil, for use in low- and medium-speed diesel
engines in applications involving predominantly constant speed and
load). ASTM D3699 covers two grades of kerosene suitable for use in
critical kerosene burner applications: No. 1-K (a special low-sulfur
grade kerosene suitable for use in non-flue-connected kerosene burner
appliances and for use in wick-fed illuminating lamps) and No. 2-K (a
regular grade kerosene suitable for use in flue-connected burner
appliances and for use in wick-fed illuminating lamps). ASTM D6751
covers biodiesel (B100) Grades S15 and S500 for use as a blend
component with middle distillate fuels. ASTM D7467 covers fuel blend
grades of 6 to 20 volume percent biodiesel with the remainder being a
light middle or middle distillate diesel fuel, collectively designated
as B6 to B20. These standards are available at http://www.astm.org or
by mail at ASTM International, 100 Barr Harbor Drive, P.O. Box CB700,
West Conshohocken, PA 19428-2959.
    Two VCS, American Society of Mechanical Engineers (ASME)
Performance Test Codes PTC 22-2014, ``Performance Test Codes on Gas
Turbines'' and PTC 46-1996, ``Performance Test Codes on Overall Plant
Performance'' are cited in the final rule for their guidance on
measuring the performance of stationary combustion turbines. PTC-22
provides directions and rules for conduct and report of results of
thermal performance tests for open cycle simple cycle combustion
turbines. The object is to determine the thermal performance of the
combustion turbine when operating at test conditions, and correcting
these test results to specified reference conditions. PTC 22 provides
explicit procedures for the determination of the following performance
results: corrected power, corrected heat rate (efficiency), corrected
exhaust flow, corrected exhaust energy, and corrected exhaust
temperature. Tests may be designed to satisfy different goals,
including absolute performance and comparative performance. The
objective of PTC 46 is to provide uniform test methods and procedures
for the determination of the thermal performance and electrical output
of heat-cycle electric power plants and combined heat and power units
(PTC 46 is not applicable to simple cycle combustion turbines). Test
results provide a measure of the performance of a power plant or
thermal island at a specified cycle configuration, operating
disposition and/or fixed power level, and at a unique set of base
reference conditions. PTC 46 provides explicit procedures for the
determination of the following performance results: corrected net
power, corrected heat rate, and corrected heat input. These standards
are available at http://www.asme.org or by mail at American Society of
Mechanical Engineers (ASME), Two Park Avenue, New York, NY 10016-5990.
    One VCS, International Organization for Standardization method ISO
2314:2009, ``Gas Turbines--Acceptance Tests'' is cited in the final
rule for its guidance on determining performance characteristics of
stationary combustion turbines. ISO 2314 specifies guidelines and
procedures for preparing, conducting and reporting thermal-acceptance
tests in order to determine and/or verify electrical power output,
mechanical power, thermal efficiency (heat rate), turbine exhaust gas
energy and/or other performance characteristics of open-cycle simple
cycle combustion turbines using combustion systems supplied with
gaseous and/or liquid fuels as well as closed-cycle and semi-closed-
cycle simple cycle combustion turbines. It can also be applied to
simple cycle combustion turbines in combined cycle power plants or in
connection with other heat recovery systems. ISO 2314 includes
procedures for the determination of the following performance
parameters, corrected to the reference operating parameters: electrical
or mechanical power output (gas power, if only gas is supplied),
thermal efficiency or heat rate; and combustion turbine engine exhaust
energy (optionally exhaust temperature and flow). This standard is
available at http://www.iso.org/iso/home.htm or by mail at
International Organization for Standardization (ISO), 1, ch. de la
Voie-Creuse, Case postale 56, CH-1211 Geneva 20, Switzerland.
    Since no EPA Methods were used, there was no need for a NTTAA
search. The rule also requires use of appendices A, B, D, F and G to 40
CFR part 75 and the procedures under 40 CFR 98.33; these appendices
contain standards that have already been reviewed under the NTTAA.

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

    Executive Order 12898 (59 FR 7629; February 16, 1994) establishes
federal executive policy on environmental justice. Its main provision
directs federal agencies, to the greatest extent practicable and
permitted by law, to make environmental justice part of their mission
by identifying and addressing, as appropriate, disproportionately high
and adverse human health or environmental effects of their programs,
policies, and activities on minority populations and low-income
populations in the U.S. The EPA defines environmental justice as the
fair treatment and meaningful involvement of all people regardless of
race, color, national origin, or income with respect to the
development, implementation, and enforcement of environmental laws,
regulations, and policies. The EPA has this goal for all communities
and persons across this Nation. It will be achieved when everyone
enjoys the same degree of protection from environmental and health
hazards and equal access to the decision-making process to have a
healthy environment in which to live, learn, and work.
    Leading up to this rulemaking the EPA summarized the public health
and welfare effects of GHG emissions in its 2009 Endangerment Finding.
As part of the Endangerment Finding, the Administrator considered
climate change risks to minority or low-income populations, finding
that certain parts of the population may be especially vulnerable based
on their circumstances. Populations that were found to be particularly
vulnerable to

climate change risks include the poor, the elderly, the very young,
those already in poor health, the disabled, those living alone, and/or
indigenous populations dependent on one or a few resources. See
Sections XIV.F and G, above, where the EPA discusses Consultation and
Coordination with Tribal Governments and Protection of Children. The
Administrator placed weight on the fact that certain groups, including
children, the elderly, and the poor, are most vulnerable to climate-
related health effects.
    The record for the 2009 Endangerment Finding summarizes the strong
scientific evidence in the major assessment reports by the U.S. Global
Change Research Program (USGCRP), the Intergovernmental Panel on
Climate Change (IPCC), and the National Research Council (NRC) of the
National Academies that the potential impacts of climate change raise
environmental justice issues. These reports concluded that poor
communities can be especially vulnerable to climate change impacts
because they tend to have more limited adaptive capacities and are more
dependent on climate-sensitive resources such as local water and food
supplies. In addition, Native American tribal communities possess
unique vulnerabilities to climate change, particularly those impacted
by degradation of natural and cultural resources within established
reservation boundaries and threats to traditional subsistence
lifestyles. Tribal communities whose health, economic well-being, and
cultural traditions depend upon the natural environment will likely be
affected by the degradation of ecosystem goods and services associated
with climate change. The 2009 Endangerment Finding record also
specifically noted that Southwest native cultures are especially
vulnerable to water quality and availability impacts. Native Alaskan
communities are already experiencing disruptive impacts, including
coastal erosion and shifts in the range or abundance of wild species
crucial to their livelihoods and well-being.
    The most recent assessments continue to strengthen scientific
understanding of climate change risks to minority and low-income
populations in the United States.\581\ The new assessment literature
provides more detailed findings regarding these populations'
vulnerabilities and projected impacts they may experience. In addition,
the most recent assessment reports provides new information on how some
communities of color may be uniquely vulnerable to climate change
health impacts in the United States. These reports find that certain
climate change related impacts--including heat waves, degraded air
quality, and extreme weather events--have disproportionate effects on
low-income and some communities of color, raising environmental justice
concerns. Existing health disparities and other inequities in these
communities increase their vulnerability to the health effects of
climate change. In addition, assessment reports also find that climate
change poses particular threats to health, wellbeing, and ways of life
of indigenous peoples in the United States.
---------------------------------------------------------------------------

    \581\ Melillo, Jerry M., Terese (T.C.) Richmond, and Gary W.
Yohe, Eds., 2014: Climate Change Impacts in the United States: The
Third National Climate Assessment. U.S. Global Change Research
Program, 841 pp.
    IPCC, 2014: Climate Change 2014: Impacts, Adaptation, and
Vulnerability. Part A: Global and Sectoral Aspects. Contribution of
Working Group II to the Fifth Assessment Report of the
Intergovernmental Panel on Climate Change [Field, C.B., V.R. Barros,
D.J. Dokken, K.J. Mach, M.D. Mastrandrea, T.E. Bilir, M. Chatterjee,
K.L. Ebi, Y.O. Estrada, R.C. Genova, B. Girma, E.S. Kissel, A.N.
Levy, S. MacCracken, P.R. Mastrandrea, and L.L. White (eds.)].
Cambridge University Press, 1132 pp.
    IPCC, 2014: Climate Change 2014: Impacts, Adaptation, and
Vulnerability. Part B: Regional Aspects. Contribution of Working
Group II to the Fifth Assessment Report of the Intergovernmental
Panel on Climate Change [Barros, V.R., C.B. Field, D.J. Dokken, M.D.
Mastrandrea, K.J. Mach, T.E. Bilir, M. Chatterjee, K.L. Ebi, Y.O.
Estrada, R.C. Genova, B. Girma, E.S. Kissel, A.N. Levy, S.
MacCracken, P.R. Mastrandrea, and L.L. White (eds.)]. Cambridge
University Press, 688 pp.
---------------------------------------------------------------------------

    As the scientific literature presented above and in the
Endangerment Finding illustrates, low income communities and some
communities of color are especially vulnerable to the health and other
adverse impacts of climate change.
    The EPA believes the human health or environmental risk addressed
by this final action will not have potential disproportionately high
and adverse human health or environmental effects on minority, low-
income or indigenous populations. The final rule limits GHG emissions
from newly constructed, modified, and reconstructed fossil fuel-fired
electric utility steam generating units and newly constructed and
modified stationary combustion turbines by establishing national
emission standards for CO2.
    The EPA has determined that the final rule will not result in
disproportionately high and adverse human health or environmental
effects on minority, low-income or indigenous populations because the
rule is not anticipated to notably affect the level of protection
provided to human health or the environment. The EPA believes that
electric power companies will choose to build new fossil fuel-fired
electric utility steam generating units and natural gas-fired
stationary combustion turbines that comply with the regulatory
requirements of the final rule because of existing and expected market
conditions. The EPA does not project any new coal-fired steam
generating units without CCS to be built and expects that any newly
built natural gas-fired stationary combustion turbines will meet the
standards. In addition, as previously stated, the EPA expects few
fossil fuel-fired electric utility steam generating units or natural
gas-fired stationary combustion turbines to trigger the NSPS
modification or reconstruction provisions in the period of analysis.
This final rule will ensure that, to whatever extent there are newly
constructed, modified, and reconstructed EGUs, they will use the best
performing technologies to limit emissions of CO2.

K. Congressional Review Act (CRA)

    This final action is subject to the CRA, and the EPA will submit a
rule report to each House of the Congress and to the Comptroller
General of the United States. This action is not a ``major rule'' as
defined by 5 U.S.C. 804(2).

XV. Withdrawal of Proposed Standards for Certain Modified Sources

    In this action, as discussed above in Sections IV and VI, the EPA
is issuing final standards of performance for affected fossil fuel-
fired steam generating EGUs that implement modifications resulting in
an increase of CO2 emissions (in lb/hr) of more than 10
percent. In addition, the EPA is withdrawing the proposed standards of
performance for emissions of carbon dioxide (CO2) from
modified fossil fuel-fired EGUs not covered by those final standards.
Specifically, the EPA is withdrawing the proposed standards for fossil
fuel-fired steam generating EGUs that implement modifications resulting
in an increase of CO2 emissions (in lb/hr) of less than or
equal to 10 percent. A detailed rationale for the withdrawal of these
proposed standards is provided in Section VI above.
    The EPA is also, in this action, withdrawing proposed standards for
modified stationary combustion turbines. A detailed rationale for the
withdrawal of these proposed standards is provided in Section IX above.
    The proposed standards for modified fossil fuel-fired EGUs that the
EPA is withdrawing in this action were published in the Federal
Register on June 18, 2014 (79 FR 34960).

XVI. 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, Incorporation by reference, 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: August 3, 2015.
Gina McCarthy,
Administrator.
    For the reasons stated in the preamble, title 40, chapter I, parts
60, 70, 71, and 98 of the Code of the Federal Regulations are 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.

0
2. Section 60.17 is amended by:
0
a. Redesignating paragraphs (d) through (t) as paragraphs (e) through
(u) and adding paragraph (d);
0
b. In newly redesignated paragraph (g), further redesignating paragraph
(g)(15) as paragraph (g)(17) and adding paragraphs (g)(15) and (16);
0
c. In newly redesignated paragraph (h), revising paragraphs (h)(37),
(42), (46), (138), (187), and (190); and
0
c. In newly redesignated paragraph (m), further redesignating paragraph
(m)(1) as paragraph (m)(2) and adding paragraph (m)(1).
    The revisions and additions read as follows:

Sec.  60.17  Incorporations by reference.

* * * * *
    (d) The following material is available for purchase from the
American National Standards Institute (ANSI), 25 W. 43rd Street, 4th
Floor, New York, NY 10036, Telephone<PHONE_NUMBER>, and is also
available at the following Web site: http://www.ansi.org.
    (1) ANSI No. C12.20-2010 American National Standard for Electricity
Meters--0.2 and 0.5 Accuracy Classes (Approved August 31, 2010), IBR
approved for Sec.  60.5535(d).
    (2) [Reserved]
* * * * *
    (g) * * *
    (15) ASME PTC 22-2014, Gas Turbines: Performance Test Codes,
(Issued December 31, 2014), IBR approved for Sec.  60.5580.
    (16) ASME PTC 46-1996, Performance Test Code on Overall Plant
Performance, (Issued October 15, 1997), IBR approved for Sec.  60.5580.
* * * * *
    (h) * * *
    (37) ASTM D388-99 (Reapproved 2004) [epsiv]1 Standard
Classification of Coals by Rank, IBR approved for Sec. Sec.  60.41,
60.45(f), 60.41Da, 60.41b, 60.41c, 60.251, and 60.5580.
* * * * *
    (42) ASTM D396-98, Standard Specification for Fuel Oils, IBR
approved for Sec. Sec.  60.41b, 60.41c, 60.111(b), 60.111a(b), and
60.5580.
* * * * *
    (46) ASTM D975-08a, Standard Specification for Diesel Fuel Oils,
IBR approved for Sec. Sec.  60.41b 60.41c, and 60.5580.
* * * * *
    (138) ASTM D3699-08, Standard Specification for Kerosine, including
Appendix X1, (Approved September 1, 2008), IBR approved for Sec. Sec.
60.41b, 60.41c, and 60.5580.
* * * * *
    (187) ASTM D6751-11b, Standard Specification for Biodiesel Fuel
Blend Stock (B100) for Middle Distillate Fuels, including Appendices X1
through X3, (Approved July 15, 2011), IBR approved for Sec. Sec.
60.41b, 60.41c, and 60.5580.
* * * * *
    (190) ASTM D7467-10, Standard Specification for Diesel Fuel Oil,
Biodiesel Blend (B6 to B20), including Appendices X1 through X3,
(Approved August 1, 2010), IBR approved for Sec. Sec.  60.41b, 60.41c,
and 60.5580.
* * * * *
    (m) * * *
    (1) ISO 2314:2009(E), Gas turbines-Acceptance tests, Third edition
(December 15, 2009), IBR approved for Sec.  60.5580.
* * * * *

0
3. Part 60 is amended by adding subpart TTTT to read as follows:
Subpart TTTT--Standards of Performance for Greenhouse Gas Emissions for
Electric Generating Units

Applicability

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

Emission Standards

60.5515 Which pollutants are regulated by this subpart?
60.5520 What CO2 emissions standard must I meet?

General Compliance Requirements

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

Monitoring and Compliance Determination Procedures

60.5535 How do I monitor and collect data to demonstrate compliance?
60.5540 How do I demonstrate compliance with my CO[ihel2] emissions
standard and determine excess emissions?

Notifications, Reports, and Records

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

Other Requirements and Information

60.5570 What parts of the general provisions apply to my affected
EGU?
60.5575 Who implements and enforces this subpart?
60.5580 What definitions apply to this subpart?
Table 1 of Subpart TTTT of Part 60--CO2 Emission
Standards for Affected Steam Generating Units and Integrated
Gasification Combined Cycle Facilities that Commenced Construction
after January 8, 2014 and Reconstruction or Modification after June
18, 2014
Table 2 of Subpart TTTT of Part 60--CO2 Emission
Standards for Affected Stationary Combustion Turbines that Commenced
Construction after January 8, 2014 and Reconstruction after June 18,
2014 (Net Energy Output-based Standards Applicable as Approved by
the Administrator)
Table 3 to Subpart TTTT of Part 60--Applicability of Subpart A of
Part 60 (General Provisions) to Subpart TTTT

Applicability

Sec.  60.5508  What is the purpose of this subpart?

    This subpart establishes emission standards and compliance
schedules for the control of greenhouse gas (GHG) emissions from a
steam generating unit,

IGCC, or a stationary combustion turbine that commences construction
after January 8, 2014 or commences modification or reconstruction after
June 18, 2014. An affected steam generating unit, IGCC, or stationary
combustion turbine shall, for the purposes of this subpart, be referred
to as an affected EGU.

Sec.  60.5509  Am I subject to this subpart?

    (a) Except as provided for in paragraph (b) of this section, the
GHG standards included in this subpart apply to any steam generating
unit, IGCC, or stationary combustion turbine that commenced
construction after January 8, 2014 or commenced reconstruction after
June 18, 2014 that meets the relevant applicability conditions in
paragraphs (a)(1) and (2) of this section. The GHG standards included
in this subpart also apply to any steam generating unit or IGCC that
commenced modification after June 18, 2014 that meets the relevant
applicability conditions in paragraphs (a)(1) and (2) of this section.
    (1) Has a base load rating greater than 260 GJ/h (250 MMBtu/h) of
fossil fuel (either alone or in combination with any other fuel); and
    (2) Serves a generator or generators capable of selling greater
than 25 MW of electricity to a utility power distribution system.
    (b) You are not subject to the requirements of this subpart if your
affected EGU meets any of the conditions specified in paragraphs (b)(1)
through (10) of this section.
    (1) Your EGU is a steam generating unit or IGCC that is currently
and always has been subject to a federally enforceable permit condition
limiting annual net-electric sales to no more than one-third of its
potential electric output or 219,000 MWh, whichever is greater.
    (2) Your EGU is capable of combusting 50 percent or more non-fossil
fuel and is also subject to a federally enforceable permit condition
limiting the annual capacity factor for all fossil fuels combined of 10
percent (0.10) or less.
    (3) Your EGU is a combined heat and power unit that is subject to a
federally enforceable permit condition limiting annual net-electric
sales to no more than either 219,000 MWh or the product of the design
efficiency and the potential electric output, whichever is greater.
    (4) Your EGU serves a generator along with other steam generating
unit(s), IGCC, or stationary combustion turbine(s) where the effective
generation capacity (determined based on a prorated output of the base
load rating of each steam generating unit, IGCC, or stationary
combustion turbine) is 25 MW or less.
    (5) Your EGU is a municipal waste combustor that is subject to
subpart Eb of this part.
    (6) Your EGU is a commercial or industrial solid waste incineration
unit that is subject to subpart CCCC of this part.
    (7) Your EGU is a steam generating unit or IGCC that undergoes a
modification resulting in an hourly increase in CO2
emissions (mass per hour) of 10 percent or less (2 significant
figures). Modified units that are not subject to the requirements of
this subpart pursuant to this subsection continue to be existing units
under section 111 with respect to CO2 emissions standards.
    (8) Your EGU is a stationary combustion turbine that is not capable
of combusting natural gas (e.g., not connected to a natural gas
pipeline).
    (9) 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 January 8, 2014.
    (10) 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 January 8, 2014.

Emission Standards

Sec.  60.5515  Which pollutants are regulated by this subpart?

    (a) The pollutants regulated by this subpart are greenhouse gases.
The greenhouse gas standard in this subpart is in the form of a
limitation on emission of carbon dioxide.
    (b) PSD and title V thresholds for greenhouse gases. (1) For the
purposes of 40 CFR 51.166(b)(49)(ii), with respect to GHG emissions
from 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 Sec.  51.166(b)(48) of this chapter and in any SIP
approved by the EPA that is interpreted to incorporate, or specifically
incorporates, Sec.  51.166(b)(48).
    (2) For the purposes of 40 CFR 52.21(b)(50)(ii), with respect to
GHG emissions from 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 Sec.  52.21(b)(49) of this chapter.
    (3) For the purposes of 40 CFR 70.2, with respect to greenhouse gas
emissions from 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 the purposes of 40 CFR 71.2, with respect to greenhouse gas
emissions from 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.

Sec.  60.5520  What CO2 emission standard must I meet?

    (a) For each affected EGU subject to this subpart, you must not
discharge from the affected EGU any gases that contain CO2
in excess of the applicable CO2 emission standard specified
in Table 1 or 2 of this subpart, consistent with paragraphs (b), (c),
and (d) of this section, as applicable.
    (b) Except as specified in paragraphs (c) and (d) of this section,
you must comply with the applicable gross energy output standard, and
your operating permit must include monitoring, recordkeeping, and
reporting methodologies based on the applicable gross energy output
standard. For the remainder of this subpart (for sources that do not
qualify under paragraphs (c) and (d) of this section), where the term
``gross or net energy output'' is used, the term that applies to you is
``gross energy output.''
    (c) As an alternate to meeting the requirements in paragraph (b) of
this section, an owner or operator of a stationary combustion turbine
may petition the Administrator in writing to comply with the alternate
applicable net energy output standard. If the Administrator grants the
petition, beginning on the date the Administrator grants the petition,
the affected EGU must comply with the applicable net energy output-
based standard included in this subpart. Your operating permit must
include monitoring, recordkeeping, and reporting methodologies based on
the applicable net energy output standard. For the remainder of this
subpart, where the term ``gross or net energy output'' is used, the
term that applies to you is ``net energy output.'' Owners or

operators complying with the net output-based standard must petition
the Administrator to switch back to complying with the gross energy
output-based standard.
    (d) Stationary combustion turbines subject to a heat input-based
standard in Table 2 of this subpart that are only permitted to burn one
or more uniform fuels, as described in paragraph (d)(1) of this
section, are only subject to the monitoring requirements in paragraph
(d)(1). All other stationary combustion turbines subject to a heat
input based standard in Table 2 are subject to the requirements in
paragraph (d)(2) of this section.
    (1) Stationary combustion turbines that are only permitted to burn
fuels with a consistent chemical composition (i.e., uniform fuels) that
result in a consistent emission rate of 160 lb CO2/MMBtu or
less are not subject to any monitoring or reporting requirements under
this subpart. These fuels include, but are not limited to, natural gas,
methane, butane, butylene, ethane, ethylene, propane, naphtha,
propylene, jet fuel kerosene, No. 1 fuel oil, No. 2 fuel oil, and
biodiesel. Stationary combustion turbines qualifying under this
paragraph are only required to maintain purchase records for permitted
fuels.
    (2) Stationary combustion turbines permitted to burn fuels that do
not have a consistent chemical composition or that do not have an
emission rate of 160 lb CO2/MMBtu or less (e.g., non-uniform
fuels such as residual oil and non-jet fuel kerosene) must follow the
monitoring, recordkeeping, and reporting requirements necessary to
complete the heat input-based calculations under this subpart.

General Compliance Requirements

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

    Combustion turbines qualifying under Sec.  60.5520(d)(1) are not
subject to any requirements in this section other than the requirement
to maintain fuel purchase records for permitted fuel(s). For all other
affected sources, compliance with the applicable CO2
emission standard of this subpart shall be determined on a 12-
operating-month rolling average basis. See Table 1 or 2 of this subpart
for the applicable CO2 emission standards.
    (a) You must be in compliance with the emission standards in this
subpart that apply to your affected EGU at all times. However, you must
determine compliance with the emission standards only at the end of the
applicable operating month, as provided in paragraph (a)(1) of this
section.
    (1) For each affected EGU subject to a CO2 emissions
standard based on a 12-operating-month rolling average, you must
determine compliance monthly by calculating the average CO2
emissions rate for the affected EGU at the end of the initial and each
subsequent 12-operating-month period.
    (2) Consistent with Sec.  60.5520(d)(2), if your affected
stationary combustion turbine is subject to an input-based
CO2 emissions standard, you must determine the total heat
input in million Btus (MMBtu) from natural gas (HTIPng) and
the total heat input from all other fuels combined (HTIPo)
using one of the methods under Sec.  60.5535(d)(2). You must then use
the following equation to determine the applicable emissions standard
during the compliance period:
[GRAPHIC] [TIFF OMITTED] TR23OC15.002

Where:

CO2 emission standard = the emission standard during the
compliance period in units of lb/MMBtu.
HTIPng = the heat input in MMBtu from natural gas.
HTIPo = the heat input in MMBtu from all fuels other than
natural gas.
120 = allowable emission rate in lb of CO2/MMBtu for heat
input derived from natural gas.
160 = allowable emission rate in lb of CO2/MMBtu for heat
input derived from all fuels other than natural gas.

    (b) At all times you must operate and maintain each affected EGU,
including associated equipment and monitors, in a manner consistent
with safety and good air pollution control practice. The Administrator
will determine if you are using consistent operation and maintenance
procedures based on information available to the Administrator that may
include, but is not limited to, fuel use records, monitoring results,
review of operation and maintenance procedures and records, review of
reports required by this subpart, and inspection of the EGU.
    (c) Within 30 days after the end of the initial compliance period
(i.e., no more than 30 days after the first 12-operating-month
compliance period), you must make an initial compliance determination
for your affected EGU(s) with respect to the applicable emissions
standard in Table 1 or 2 of this subpart, in accordance with the
requirements in this subpart. The first operating month included in the
initial 12-operating-month compliance period shall be determined as
follows:
    (1) For an affected EGU that commences commercial operation (as
defined in Sec.  72.2 of this chapter) on or after October 23, 2015,
the first month of the initial compliance period shall be the first
operating month (as defined in Sec.  60.5580) after the calendar month
in which emissions reporting is required to begin under:
    (i) Section 63.5555(c)(3)(i), for units subject to the Acid Rain
Program; or
    (ii) Section 63.5555(c)(3)(ii)(A), for units that are not in the
Acid Rain Program.
    (2) For an affected EGU that has commenced COMMERCIAL operation (as
defined in Sec.  72.2 of this chapter) prior to October 23, 2015:
    (i) If the date on which emissions reporting is required to begin
under Sec.  75.64(a) of this chapter has passed prior to October 23,
2015, emissions reporting shall begin according to Sec.
63.5555(c)(3)(i) (for Acid Rain program units), or according to Sec.
63.5555(c)(3)(ii)(B) (for units that are not subject to the Acid Rain
Program). The first month of the initial compliance period shall be the
first operating month (as defined in Sec.  60.5580) after the calendar
month in which the rule becomes effective; or
    (ii) If the date on which emissions reporting is required to begin
under Sec.  75.64(a) of this chapter occurs on or after October 23,
2015, then the first month of the initial compliance period shall be
the first operating month (as defined in Sec.  60.5580) after the
calendar month in which emissions reporting is required to begin under
Sec.  63.5555(c)(3)(ii)(A).
    (3) For a modified or reconstructed EGU that becomes subject to
this subpart, the first month of the initial compliance period shall be
the first operating month (as defined in Sec.  60.5580) after the
calendar month in which emissions reporting is required to begin under
Sec.  63.5555(c)(3)(iii).

Monitoring and Compliance Determination Procedures

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

    (a) Combustion turbines qualifying under Sec.  60.5520(d)(1) are
not subject to any requirements in this section other than the
requirement to maintain fuel purchase records for permitted fuel(s). If
your combustion turbine uses non-uniform fuels as specified under Sec.
60.5520(d)(2), you must monitor heat input in accordance with paragraph
(c)(1) of this section, and you must monitor CO2 emissions
in accordance with either paragraph (b), (c)(2), or (c)(5) of this
section. For all other affected sources, you must prepare a monitoring
plan to quantify the hourly CO2 mass emission rate (tons/h),
in accordance with the applicable provisions in Sec.  75.53(g) and (h)
of this chapter. The electronic portion of the monitoring plan must be
submitted using the ECMPS Client Tool and must be in place prior to
reporting emissions data and/or the results of monitoring system
certification tests under this subpart. The monitoring plan must be
updated as necessary. Monitoring plan submittals must be made by the
Designated Representative (DR), the Alternate DR, or a delegated agent
of the DR (see Sec.  60.5555(c)).
    (b) You must determine the hourly CO2 mass emissions in
kilograms (kg) from your affected EGU(s) according to paragraphs (b)(1)
through (5) of this section, or, if applicable, as provided in
paragraph (c) of this section.
    (1) For an affected coal-fired EGU or for an IGCC unit you must,
and for all other affected EGUs you may, install, certify, operate,
maintain, and calibrate a CO2 continuous emission monitoring
system (CEMS) to directly measure and record hourly average
CO2 concentrations in the affected EGU exhaust gases emitted
to the atmosphere, and a flow monitoring system to measure hourly
average stack gas flow rates, according to Sec.  75.10(a)(3)(i) of this
chapter. As an alternative to direct measurement of CO2
concentration, provided that your EGU does not use carbon separation
(e.g., carbon capture and storage), you may use data from a certified
oxygen (O2) monitor to calculate hourly average
CO2 concentrations, in accordance with Sec.
75.10(a)(3)(iii) 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. Alternatively, you may
either use an appropriate fuel-specific default moisture value from
Sec.  75.11(b) or submit a petition to the Administrator under Sec.
75.66 of this chapter for a site-specific default moisture value.
    (2) For each continuous 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 A and B to part 75 of this chapter.
    (3) You must use only unadjusted exhaust gas volumetric flow rates
to determine the hourly CO2 mass emissions rate from the
affected EGU; 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.
    (4) You must select an appropriate reference method to setup
(characterize) the flow monitor and to perform the on-going RATAs, in
accordance with part 75 of this chapter. If you use a Type-S pitot tube
or a pitot tube assembly for the flow RATAs, you must calibrate the
pitot tube or pitot tube assembly; you may not use the 0.84 default
Type-S pitot tube coefficient specified in Method 2.
    (5) Calculate the hourly CO2 mass emissions (kg) as
described in paragraphs (b)(5)(i) through (iv) of this section. Perform
this calculation only for ``valid operating hours'', as defined in
Sec.  60.5540(a)(1).
    (i) Begin with the hourly CO2 mass emission rate (tons/
h), obtained either from Equation F-11 in Appendix F to part 75 of this
chapter (if CO2 concentration is measured on a wet basis),
or by following the procedure in section 4.2 of appendix F to part 75
of this chapter (if CO2 concentration is measured on a dry
basis).
    (ii) Next, multiply each hourly CO2 mass emission rate
by the EGU or stack operating time in hours (as defined in Sec.  72.2
of this chapter), to convert it to tons of CO2.
    (iii) Finally, multiply the result from paragraph (b)(5)(ii) of
this section by 909.1 to convert it from tons of CO2 to kg.
Round off to the nearest kg.
    (iv) The hourly CO2 tons/h values and EGU (or stack)
operating times used to calculate CO2 mass emissions are
required to be recorded under Sec.  75.57(e) of this chapter and must
be reported electronically under Sec.  75.64(a)(6) of this chapter. You
must use these data to calculate the hourly CO2 mass
emissions.
    (c) If your affected EGU exclusively combusts liquid fuel and/or
gaseous fuel, as an alternative to complying with paragraph (b) of this
section, you may determine the hourly CO2 mass emissions
according to paragraphs (c)(1) through (4) of this section. If you use
non-uniform fuels as specified in Sec.  60.5520(d)(2), you may
determine CO2 mass emissions during the compliance period
according to paragraph (c)(5) of this section.
    (1) If you are subject to an output-based standard and you do not
install CEMS in accordance with paragraph (b) of this section, you must
implement the applicable procedures in appendix D to part 75 of this
chapter to determine hourly EGU 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) For each measured hourly heat input rate, use Equation G-4 in
appendix G to part 75 of this chapter to calculate the hourly
CO2 mass emission rate (tons/h). 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.
    (3) For each ``valid operating hour'' (as defined in Sec.
60.5540(a)(1), multiply the hourly tons/h CO2 mass emission
rate from paragraph (c)(2) of this section by the EGU or stack
operating time in hours (as defined in Sec.  72.2 of this chapter), to
convert it to tons of CO2. Then, multiply the result by
909.1 to convert from tons of CO2 to kg. Round off to the
nearest two significant figures.
    (4) The hourly CO2 tons/h values and EGU (or stack)
operating times used to calculate CO2 mass emissions are
required to be recorded under Sec.  75.57(e) of this chapter and must
be reported electronically under Sec.  75.64(a)(6) of this chapter. You
must use these data to calculate the hourly CO2 mass
emissions.
    (5) If you operate a combustion turbine firing non-uniform fuels,
as an alternative to following paragraphs (c)(1) through (4) of this
section, you may determine CO2 emissions during the
compliance period using one of the following methods:
    (i) Units firing fuel gas may determine the heat input during the
compliance period following the procedure under Sec.  60.107a(d) and
convert this heat input to CO2 emissions using Equation G-4
in appendix G to part 75 of this chapter.
    (ii) You may use the procedure for determining CO2
emissions during the compliance period based on the use of the Tier 3
methodology under Sec.  98.33(a)(3) of this chapter.
    (d) Consistent with Sec.  60.5520, you must determine the basis of
the emissions standard that applies to your

affected source in accordance with either paragraph (d)(1) or (2) of
this section, as applicable:
    (1) If you operate a source subject to an emissions standard
established on an output basis (e.g., lb of CO2 per gross or
net MWh of energy output), you must install, calibrate, maintain, and
operate a sufficient number of watt meters to continuously measure and
record the hourly gross electric output or net electric output, as
applicable, from the affected EGU(s). These measurements must be
performed using 0.2 class electricity metering instrumentation and
calibration procedures as specified under ANSI Standards No. C12.20
(incorporated by reference, see Sec.  60.17). For a combined heat and
power (CHP) EGU, as defined in Sec.  60.5580, you must also install,
calibrate, maintain, and operate meters to continuously (i.e., hour-by-
hour) determine and record the total useful thermal output. For process
steam applications, you will need to install, calibrate, maintain, and
operate meters to continuously determine and record the hourly steam
flow rate, temperature, and pressure. Your plan shall ensure that you
install, calibrate, maintain, and operate meters to record each
component of the determination, hour-by-hour.
    (2) If you operate a source subject to an emissions standard
established on a heat-input basis (e.g., lb CO2/MMBtu) and
your affected source uses non-uniform heating value fuels as delineated
under Sec.  60.5520(d), you must determine the total heat input for
each fuel fired during the compliance period in accordance with one of
the following procedures:
    (i) Appendix D to part 75 of this chapter;
    (ii) The procedures for monitoring heat input under Sec.
60.107a(d);
    (iii) If you monitor CO2 emissions in accordance with
the Tier 3 methodology under Sec.  98.33(a)(3) of this chapter, you may
convert your CO2 emissions to heat input using the
appropriate emission factor in Table C-1 of part 98 of this chapter. If
your fuel is not listed in Table C-1, you must determine a fuel-
specific carbon-based F-factor (Fc) in accordance with
section 12.3.2 of EPA Method 19 of appendix A-7 to this part, and you
must convert your CO2 emissions to heat input using Equation
G-4 in appendix G to part 75 of this chapter.
    (e) Consistent with Sec.  60.5520, if two or more affected EGUs
serve a common electric generator, you must apportion the combined
hourly gross or net energy output to the individual affected EGUs
according to the fraction of the total steam load contributed by each
EGU. Alternatively, if the EGUs are identical, you may apportion the
combined hourly gross or net electrical load to the individual EGUs
according to the fraction of the total heat input contributed by each
EGU.
    (f) In accordance with Sec. Sec.  60.13(g) and 60.5520, if two or
more affected EGUs 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 in Table 1 or 2 of
this subpart, you may monitor the hourly CO2 mass emissions
at the common stack in lieu of monitoring each EGU separately. If you
choose this option, the hourly gross or net energy output (electric,
thermal, and/or mechanical, as applicable) must be the sum of the
hourly loads for the individual affected EGUs 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.  60.5520 at the common stack, each affected
EGU sharing the stack is in compliance.
    (g) In accordance with Sec. Sec.  60.13(g) and 60.5520 if the
exhaust gases from an affected EGU 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 elect
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 must determine compliance with the applicable emissions standard in
Table 1 or 2 of this subpart by summing the CO2 mass
emissions measured at the individual stacks or ducts and dividing by
the total gross or net energy output for the affected EGU.

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

    (a) In accordance with Sec.  60.5520, if you are subject to an
output-based emission standard or you burn non-uniform fuels as
specified in Sec.  60.5520(d)(2), you must demonstrate compliance with
the applicable CO2 emission standard in Table 1 or 2 of this
subpart as required in this section. For the initial and each
subsequent 12-operating-month rolling average compliance period, you
must follow the procedures in paragraphs (a)(1) through (7) of this
section to calculate the CO2 mass emissions rate for your
affected EGU(s) in units of the applicable emissions standard (i.e.,
either kg/MWh or lb/MMBtu). You must use the hourly CO2 mass
emissions calculated under Sec.  60.5535(b) or (c), as applicable, and
either the generating load data from Sec.  60.5535(d)(1) for output-
based calculations or the heat input data from Sec.  60.5535(d)(2) for
heat-input-based calculations. Combustion turbines firing non-uniform
fuels that contain CO2 prior to combustion (e.g., blast
furnace gas or landfill gas) may sample the fuel stream to determine
the quantity of CO2 present in the fuel prior to combustion
and exclude this portion of the CO2 mass emissions from
compliance determinations.
    (1) Each compliance period shall include only ``valid operating
hours'' in the compliance period, i.e., operating hours for which:
    (i) ``Valid data'' (as defined in Sec.  60.5580) are obtained for
all of the parameters used to determine the hourly CO2 mass
emissions (kg) and, if a heat input-based standard applies, all the
parameters used to determine total heat input for the hour are also
obtained; and
    (ii) The corresponding hourly gross or net energy output value is
also valid data (Note: For hours with no useful output, zero is
considered to be a valid value).
    (2) You must exclude operating hours in which:
    (i) The substitute data provisions of part 75 of this chapter are
applied for any of the parameters used to determine the hourly
CO2 mass emissions or, if a heat input-based standard
applies, for any parameters used to determine the hourly heat input; or
    (ii) An exceedance of the full-scale range of a continuous emission
monitoring system occurs for any of the parameters used to determine
the hourly CO2 mass emissions or, if applicable, to
determine the hourly heat input; or
    (iii) The total gross or net energy output (Pgross/net)
or, if applicable, the total heat input is unavailable.
    (3) For each compliance period, at least 95 percent of the
operating hours in the compliance period must be valid operating hours,
as defined in paragraph (a)(1) of this section.
    (4) You must calculate the total CO2 mass emissions by
summing the valid hourly CO2 mass emissions values from
Sec.  60.5535 for all of the valid operating hours in the compliance
period.
    (5) Sources subject to output based standards. For each valid
operating hour of the compliance period that was used in paragraph
(a)(4) of this section to calculate the total CO2 mass
emissions, you must determine Pgross/net (the corresponding
hourly gross or net energy output in MWh) according to the

procedures in paragraphs (a)(3)(i) and (ii) of this section, as
appropriate for the type of affected EGU(s). For an operating hour in
which a valid CO2 mass emissions value is determined
according to paragraph (a)(1)(i) of this section, if there is no gross
or net electrical output, but there is mechanical or useful thermal
output, you must still determine the gross or net energy output for
that hour. In addition, for an operating hour in which a valid
CO2 mass emissions value is determined according to
paragraph (a)(1)(i) of this section, but there is no (i.e., zero) gross
electrical, mechanical, or useful thermal output, you must use that
hour in the compliance determination. For hours or partial hours where
the gross electric output is equal to or less than the auxiliary loads,
net electric output shall be counted as zero for this calculation.
    (i) Calculate Pgross/net for your affected EGU using the
following equation. All terms in the equation must be expressed in
units of megawatt-hours (MWh). To convert each hourly gross or net
energy output (consistent with Sec.  60.5520) value reported under part
75 of this chapter to MWh, multiply by the corresponding EGU or stack
operating time.
[GRAPHIC] [TIFF OMITTED] TR23OC15.003

Where:

Pgross/net = In accordance with Sec.  60.5520, gross or
net energy output of your affected EGU for each valid operating hour
(as defined in Sec.  60.5540(a)(1)) 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 EGU's integrated equipment that
provides electricity or mechanical energy to the affected EGU or
auxiliary equipment in MWh.
(Pe)FW = Electric energy used to power boiler feedwater
pumps at steam generating units in MWh. Not applicable to stationary
combustion turbines, IGCC EGUs, or EGUs complying with a net energy
output based standard.
(Pe)A = Electric energy used for any auxiliary loads in
MWh. Not applicable for determining Pgross.
(Pt)PS = Useful thermal output of steam (measured
relative to SATP conditions, as applicable) that is used for
applications that do not generate additional electricity, produce
mechanical energy output, or enhance the performance of the affected
EGU. This is calculated using the equation specified in paragraph
(a)(5)(ii) of this section in MWh.
(Pt)HR = Non steam useful thermal output (measured
relative to SATP conditions, as applicable) from heat recovery that
is used for applications other than steam generation or performance
enhancement of the affected EGU in MWh.
(Pt)IE = Useful thermal output (relative to SATP
conditions, as applicable) from any integrated equipment is used for
applications that do not generate additional steam, electricity,
produce mechanical energy output, or enhance the performance of the
affected EGU in MWh.
TDF = Electric Transmission and Distribution Factor of 0.95 for a
combined heat and power affected EGU where at least on an annual
basis 20.0 percent of the total gross or net energy output consists
of electric or direct mechanical output and 20.0 percent of the
total gross or net energy output consists of useful thermal output
on a 12-operating-month rolling average basis, or 1.0 for all other
affected EGUs.

    (ii) If applicable to your affected EGU (for example, for combined
heat and power), you must calculate (Pt)PS using the
following equation:
[GRAPHIC] [TIFF OMITTED] TR23OC15.004

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 SATP conditions or the energy in the condensate return
line, as applicable) in Joules per kilogram (J/kg) (or Btu/lb).
CF = Conversion factor of 3.6 x 10\9\ J/MWh or 3.413 x 10\6\ Btu/
MWh.

    (6) Calculation of annual basis for standard. Sources complying
with energy output-based standards must calculate the basis (i.e.,
denominator) of their actual annual emission rate in accordance with
paragraph (a)(6)(i) of this section. Sources complying with heat input
based standards must calculate the basis of their actual annual
emission rate in accordance with paragraph (a)(6)(ii) of this section.
    (i) In accordance with Sec.  60.5520 if you are subject to an
output-based standard, you must calculate the total gross or net energy
output for the affected EGU's compliance period by summing the hourly
gross or net energy output values for the affected EGU that you
determined under paragraph (a)(5) of this section for all of the valid
operating hours in the applicable compliance period.
    (ii) If you are subject to a heat input-based standard, you must
calculate the total heat input for each fuel fired during the
compliance period. The calculation of total heat input for each
individual fuel must include all valid operating hours and must also be
consistent with any fuel-specific procedures specified within your
selected monitoring option under Sec.  60.5535(d)(2).
    (7) If you are subject to an output-based standard, you must
calculate the CO2 mass emissions rate for the affected
EGU(s) (kg/MWh) by dividing the total CO2 mass emissions
value calculated according to the procedures in paragraph (a)(4) of
this section by the total gross or net energy output value calculated
according to the procedures in paragraph (a)(6)(i) of this section.
Round off the result to two significant figures if the calculated value
is less than 1,000; round the result to three significant figures if
the calculated value is greater than 1,000. If you are subject to a
heat input-based standard, you must calculate the CO2 mass
emissions rate for the affected EGU(s) (lb/MMBtu) by dividing the total
CO2 mass emissions value calculated according to the
procedures in paragraph (a)(4) of this section by the total heat input
calculated according to the procedures in paragraph (a)(6)(ii) of this
section. Round off the result to two significant figures.
    (b) In accordance with Sec.  60.5520, to demonstrate compliance
with the applicable CO2 emission standard, for the initial
and each subsequent 12-operating-month compliance period, the
CO2 mass emissions rate for your affected EGU must be
determined according to the procedures specified in paragraph (a)(1)
through (7) of this section and must be less than or equal to the
applicable CO2 emissions standard in Table 1 or 2 of this
part, or the emissions standard calculated in accordance with Sec.
60.5525(a)(2).

Notification, Reports, and Records

Sec.  60.5550  What notifications must I submit and when?

    (a) You must prepare and submit the notifications specified in
Sec. Sec.  60.7(a)(1) and (3) and 60.19, as applicable to your affected
EGU(s) (see Table 3 of this subpart).

    (b) You must prepare and submit notifications specified in Sec.
75.61 of this chapter, as applicable, to your affected EGUs.

Sec.  60.5555  What reports must I submit and when?

    (a) You must prepare and submit reports according to paragraphs (a)
through (d) of this section, as applicable.
    (1) For affected EGUs that are required by Sec.  60.5525 to conduct
initial and on-going compliance determinations on a 12-operating-month
rolling average basis, you must submit electronic quarterly reports as
follows. After you have accumulated the first 12-operating months for
the affected EGU, you must submit a report for the calendar quarter
that includes the twelfth 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 (twelfth) operating month in a 12-operating-month
compliance period falls within the calendar quarter. You must calculate
each average CO2 mass emissions rate for the compliance
period according to the procedures in Sec.  60.5540. You must report