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 action, which is a significant regulatory action under EO
12866, is likely to have a significant effect on the supply,
distribution, or use of energy. The EPA has prepared a Statement of
Energy Effects for this action as follows. We estimate a 1 to 2 percent
change in retail electricity prices on average across the contiguous
U.S. in 2025, and a 22 to 23 percent reduction in coal-fired
electricity generation as a result of this rule. The EPA projects that
utility power sector delivered natural gas prices will increase by up
to 2.5 percent in 2030. For more information on the estimated energy
effects, please refer to the economic impact analysis for this
proposal. The analysis is available in the RIA, which is in the public
docket.

I. National Technology Transfer and Advancement Act (NTTAA)

    This rulemaking does not involve technical standards.

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.
See, section VIII.A of this preamble where the EPA summarizes the
public health and welfare impacts from GHG emissions that were detailed
in the 2009 Endangerment Finding under CAA section 202(a)(1).\1068\ As
part of the Endangerment Finding, the Administrator considered climate
change risks to minority populations and low-income populations,
finding that certain parts of the population may be especially
vulnerable based on their characteristics or 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 XII.F and XII.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.
---------------------------------------------------------------------------

    \1068\ ``Endangerment and Cause or Contribute Findings for
Greenhouse Gases Under Section 202(a) of the Clean Air Act,'' 74 FR
66496 (Dec. 15, 2009) (``Endangerment Finding'').
---------------------------------------------------------------------------

    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 that 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 populations and low-
income populations in the U.S.\1069\ 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 provide new information on how some
communities of color (more specifically, populations defined jointly by
ethnic/racial characteristics and geographic location) may be uniquely
vulnerable to climate change health impacts in the U.S. 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 populations 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, well-
being, and ways of life of indigenous peoples in the U.S.
---------------------------------------------------------------------------

    \1069\ 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. https://www.ipcc.ch/report/ar5/wg2/.
    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. https://www.ipcc.ch/report/ar5/wg2/.
---------------------------------------------------------------------------

    As the scientific literature presented above and as the 2009
Endangerment Finding illustrates, low income populations and some
communities of color are especially vulnerable to the health and other
adverse impacts of climate change. The EPA believes that communities
will benefit from this final rulemaking because this action directly
addresses the impacts of climate change

by limiting GHG emissions through the establishment of CO2
emission guidelines for existing affected fossil fuel-fired EGUs.
    In addition to reducing CO2 emissions, the guidelines
finalized in this rulemaking would reduce other emissions from affected
EGUs that reduce generation due to higher adoption of EE and RE. These
emission reductions will include SO2 and NOX,
which form ambient PM2.5 and ozone in the atmosphere, and
HAP, such as mercury and hydrochloric acid. In the final rule revising
the annual PM2.5 NAAQS,\1070\ the EPA identified low-income
populations as being a vulnerable population for experiencing adverse
health effects related to PM exposures. Low-income populations have
been generally found to have a higher prevalence of pre-existing
diseases, limited access to medical treatment, and increased
nutritional deficiencies, which can increase this population's
susceptibility to PM-related effects.\1071\ In areas where this
rulemaking reduces exposure to PM2.5, ozone, and
methylmercury, low-income populations will also benefit from such
emissions reductions. The RIA for this rulemaking, included in the
docket for this rulemaking, provides additional information regarding
the health and ecosystem effects associated with these emission
reductions.
---------------------------------------------------------------------------

    \1070\ ``National Ambient Air Quality Standards for Particulate
Matter, Final Rule,'' 78 FR 3086 (Jan. 15, 2013).
    \1071\ U.S. Environmental Protection Agency (U.S. EPA). 2009.
Integrated Science Assessment for Particulate Matter (Final Report).
EPA-600-R-08-139F. National Center for Environmental Assessment--RTP
Division. December. Available on the Internet at <http://cfpub.epa.gov/ncea/cfm/recordisplay.cfm?deid=216546>.
---------------------------------------------------------------------------

    Additionally, as outlined in the community and environmental
justice considerations section IX of this preamble, the EPA has taken a
number of actions to help ensure that this action will not have
potential disproportionately high and adverse human health or
environmental effects on overburdened communities. The EPA consulted
its May 2015, Guidance on Considering Environmental Justice During the
Development of Regulatory Actions, when determining what actions to
take.\1072\ As described in the community and environmental justice
considerations section of this preamble the EPA also conducted a
proximity analysis, which is available in the docket of this rulemaking
and is discussed in section IX. Additionally, as outlined in sections I
and IX of this preamble, the EPA has engaged with communities
throughout this rulemaking and has devised a robust outreach strategy
for continual engagement throughout the implementation phase of this
rulemaking.
---------------------------------------------------------------------------

    \1072\ Guidance on Considering Environmental Justice During the
Development of Regulatory Actions. http://epa.gov/environmentaljustice/resources/policy/considering-ej-in-rulemaking-guide-final.pdf. May 2015.
---------------------------------------------------------------------------

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 a ``major rule'' as
defined by 5 U.S.C. 804(2).

XIII. Statutory Authority

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

List of Subjects in 40 CFR Part 60

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

    Dated: August 3, 2015.
Gina McCarthy,
Administrator.
    For the reasons stated in the preamble, title 40, chapter I, part
60 of the Code of the Federal Regulations is 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. Add subpart UUUU to read as follows:

Subpart--UUUU Emission Guidelines for Greenhouse Gas Emissions and
Compliance Times for Electric Utility Generating Units

Sec.

Introduction

60.5700 What is the purpose of this subpart?
60.5705 Which pollutants are regulated by this subpart?
60.5710 Am I affected by this subpart?
60.5715 What is the review and approval process for my State plan?
60.5720 What if I do not submit a plan or my plan is not approvable?
60.5725 In lieu of a State plan submittal, are there other
acceptable option(s) for a State to meet its CAA section 111(d)
obligations?
60.5730 Is there an approval process for a negative declaration
letter?
60.5735 What authorities will not be delegated to State, local, or
tribal agencies?
60.5736 Will the EPA impose any sanctions?
60.5737 What is the Clean Energy Incentive Program and how do I
participate?

State and Multi-State Plan Requirements

60.5740 What must I include in my federally enforceable State or
multi-State plan?
60.5745 What must I include in my final plan submittal?
60.5750 Can I work with other States to develop a multi-State plan?
60.5760 What are the timing requirements for submitting my plan?
60.5765 What must I include in an initial submittal if requesting an
extension for a final plan submittal?
60.5770 What schedules, performance periods, and compliance periods
must I include in my plan?
60.5775 What emission standards must I include in my plan?
60.5780 What State measures may I rely upon in support of my plan?
60.5785 What is the procedure for revising my plan?
60.5790 What must I do to meet my plan obligations?

Emission Rate Credit Requirements

60.5795 What affected EGUs qualify for generation of ERCs?
60.5800 What other resources qualify for issuance of ERCs?
60.5805 What is the process for the issuance of ERCs?
60.5810 What applicable requirements are there for an ERC tracking
system?

Mass Allocations Requirements

60.5815 What are the requirements for State allocation of allowances
in a mass-based program?
60.5820 What are my allowance tracking requirements?
60.5825 What is the process for affected EGUs to demonstrate
compliance in a mass-based program?

Evaluation Measurement and Verification Plans and Monitoring and
Verification Reports

60.5830 What are the requirements for EM&V plans for eligible
resources?
60.5835 What are the requirements for M&V reports for eligible
resources?

Applicability of Plans to Affected EGUs

60.5840 Does this subpart directly affect EGU owners and operators
in my State?
60.5845 What affected EGUs must I address in my State plan?
60.5850 What EGUs are excluded from being affected EGUs?
60.5855 What are the CO2 emission performance rates for
affected EGUs?
60.5860 What applicable monitoring, recordkeeping, and reporting

requirements do I need to include in my plan for affected EGUs?

Recordkeeping and Reporting Requirements

60.5865 What are my recordkeeping requirements?
60.5870 What are my reporting and notification requirements?
60.5875 How do I submit information required by these emission
guidelines to the EPA?

Definitions

60.5880 What definitions apply to this subpart?
Table 1 to Subpart UUUU of Part 60--CO2 Emission
Performance Rates (Pounds of CO2 per Net MWh)
Table 2 to Subpart UUUU of Part 60--Statewide Rate-based
CO2 Emission Goals (Pounds of CO2 per Net MWh)
Table 3 to Subpart UUUU of Part 60--Statewide Mass-based
CO2 Emission Goals (Short Tons of CO2)
Table 4 to Subpart UUUU of Part 60--Statewide Mass-based
CO2 Emission Goals plus New Source CO2
Emission Complement (Short Tons of CO2)

Introduction

Sec.  60.5700  What is the purpose of this subpart?

    This subpart establishes emission guidelines and approval criteria
for State or multi-State plans that establish emission standards
limiting greenhouse gas (GHG) emissions from an affected steam
generating unit, integrated gasification combined cycle (IGCC), or
stationary combustion turbine. An affected steam generating unit, IGCC,
or stationary combustion turbine shall, for the purposes of this
subpart, be referred to as an affected EGU. These emission guidelines
are developed in accordance with section 111(d) of the Clean Air Act
and subpart B of this part. To the extent any requirement of this
subpart is inconsistent with the requirements of subparts A or B of
this part, the requirements of this subpart will apply.

Sec.  60.5705  Which pollutants are regulated by this subpart?

    (a) The pollutants regulated by this subpart are greenhouse gases.
The emission guidelines for greenhouse gases established in this
subpart are expressed as carbon dioxide (CO2) emission
performance rates and equivalent statewide CO2 emission
goals.
    (b) PSD and Title V Thresholds for Greenhouse Gases.
    (1) For the purposes of Sec.  51.166(b)(49)(ii), with respect to
GHG emissions from 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) and in any State Implementation
Plan (SIP) approved by the EPA that is interpreted to incorporate, or
specifically incorporates, Sec.  51.166(b)(48) of this chapter.
    (2) For the purposes of Sec.  52.21(b)(50)(ii), with respect to GHG
emissions from facilities regulated in the plan, 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 Sec.  70.2 of this chapter, with respect to
greenhouse gas emissions from facilities regulated in the plan, 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 Sec.  70.2 of this chapter.
    (4) For the purposes of Sec.  71.2, with respect to greenhouse gas
emissions from facilities regulated in the plan, 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 Sec.  71.2 of this chapter.

Sec.  60.5710  Am I affected by this subpart?

    If you are the Governor of a State in the contiguous United States
with one or more affected EGUs that commenced construction on or before
January 8, 2014, you must submit a State or multi-State plan to the
U.S. Environmental Protection Agency (EPA) that implements the emission
guidelines contained in this subpart. If you are the Governor of a
State in the contiguous United States with no affected EGUs for which
construction commenced on or before January 8, 2014, in your State, you
must submit a negative declaration letter in place of the State plan.

Sec.  60.5715  What is the review and approval process for my plan?

    The EPA will review your plan according to Sec.  60.27 except that
under Sec.  60.27(b) the Administrator will have 12 months after the
date the final plan or plan revision (as allowed under Sec.  60.5785)
is submitted, to approve or disapprove such plan or revision or each
portion thereof. If you submit an initial submittal under Sec.
60.5765(a) in lieu of a final plan submittal the EPA will follow the
procedure in Sec.  60.5765(b).

Sec.  60.5720  What if I do not submit a plan or my plan is not
approvable?

    (a) If you do not submit an approvable plan the EPA will develop a
Federal plan for your State according to Sec.  60.27. The Federal plan
will implement the emission guidelines contained in this subpart.
Owners and operators of affected EGUs not covered by an approved plan
must comply with a Federal plan implemented by the EPA for the State.
    (b) After a Federal plan has been implemented in your State, it
will be withdrawn when your State submits, and the EPA approves, a
final plan.

Sec.  60.5725  In lieu of a State plan submittal, are there other
acceptable option(s) for a State to meet its CAA section 111(d)
obligations?

    A State may meet its CAA section 111(d) obligations only by
submitting a final State or multi-State plan submittal or a negative
declaration letter (if applicable).

Sec.  60.5730  Is there an approval process for a negative declaration
letter?

    No. The EPA has no formal review process for negative declaration
letters. Once your negative declaration letter has been received, the
EPA will place a copy in the public docket and publish a notice in the
Federal Register. If, at a later date, an affected EGU for which
construction commenced on or before January 8, 2014 is found in your
State, you will be found to have failed to submit a final plan as
required, and a Federal plan implementing the emission guidelines
contained in this subpart, when promulgated by the EPA, will apply to
that affected EGU until you submit, and the EPA approves, a final State
plan.

Sec.  60.5735  What authorities will not be delegated to State, local,
or tribal agencies?

    The authorities that will not be delegated to State, local, or
tribal agencies are specified in paragraphs (a) and (b) of this
section.
    (a) Approval of alternatives, not already approved by this subpart,
to the CO2 emission performance rates in Table 1 to this
subpart established under Sec.  60.5855.
    (b) Approval of alternatives, not already approved by this subpart,
to the CO2 emissions goals in Tables 2, 3 and 4 to this
subpart established under Sec.  60.5855.

Sec.  60.5736  Will the EPA impose any sanctions?

    No. The EPA will not withhold any existing federal funds from a
State on account of a State's failure to submit, implement, or enforce
an approvable plan or plan revision, or to meet any other requirements
under this subpart or subpart B of this part.

Sec.  60.5737  What is the Clean Energy Incentive Program and how do I
participate?

    (a) This subpart establishes the Clean Energy Incentive Program
(CEIP). Participation in this program is optional. The program enables
States to award early action emission rate credits (ERCs) and
allowances to eligible renewable energy (RE) or demand-side energy
efficiency (EE) projects that generate megawatt hours (MWh) or reduce
end-use energy demand during 2020 and/or 2021. Eligible projects are
those that:
    (1) Are located in or benefit a state that has submitted a final
state plan that includes requirements establishing its participation in
the CEIP; and
    (2) Commence construction in the case of RE, or commence operation
in the case of demand-side EE, following the submission of a final
state plan to the EPA, or after September 6, 2018 for a state that
chooses not to submit a final state plan by that date; and either
    (3) Generate metered MWh from any type of wind or solar resources;
or
    (4) Result in quantified and verified electricity savings (MWh)
through demand-side EE implemented in low-income communities.
    (b) The EPA will award matching ERCs or allowances to States that
award early action ERCs or allowances, up to a match limit equivalent
to 300 million tons of CO2 emissions. The awards will be
executed as follows:
    (1) For RE projects that generate metered MWh from wind or solar
resources: For every two MWh generated, the project will receive one
early action ERC (or the equivalent number of allowances) from the
State, and the EPA will provide one matching ERC (or the equivalent
number of allowances) to the State to award to the project.
    (2) For EE projects implemented in low-income communities: For
every two MWh in end-use demand savings achieved, the project will
receive two early action ERCs (or the equivalent number of allowances)
from the State, and the EPA will provide two matching ERCs (or the
equivalent number of allowances) to the State to award to the project.
    (c) You may participate in this program by including in your State
plan a mechanism that enables issuance of early action ERCs or
allowances by the State to parties effectuating reductions in the
calendar years 2020 and/or 2021 in a manner that would have no impact
on the emission performance of affected EGUs required to meet rate-
based or mass-based emission standards during the performance periods.
This mechanism is not required to account for matching ERCs or
allowances that may be issued to the State by the EPA.
    (d) If you are submitting an initial submittal by September 6,
2016, and you intend to participate in the CEIP, you must include a
non-binding statement of intent to participate in the program. If you
are submitting a final plan by September 6, 2016, and you intend to
participate in the CEIP, your State plan must either include
requirements establishing the necessary infrastructure to implement
such a program and authorizing your affected EGUs to use early action
allowances or ERCs as appropriate, or you must include a non-binding
statement of intent as part of your supporting documentation and revise
your plan to include the appropriate requirements at a later date.
    (e) If you intend to participate in the CEIP, your final State
plan, or plan revision if applicable, must require that projects
eligible under this program be evaluated, monitored, and verified, and
that resulting ERCs or allowances be issued, per applicable
requirements of the State plan approved by the EPA as meeting Sec.
60.5805 through Sec.  60.5835.

State and Multi-State Plan Requirements

Sec.  60.5740  What must I include in my federally enforceable State or
multi State plan?

    (a) You must include the components described in paragraphs (a)(1)
through (5) of this section in your plan submittal. The final plan must
meet the requirements and include the information required under Sec.
60.5745.
    (1) Identification of affected EGUs. Consistent with Sec.
60.25(a), you must identify the affected EGUs covered by your plan and
all affected EGUs in your State that meet the applicability criteria in
Sec.  60.5845. In addition, you must include an inventory of
CO2 emissions from the affected EGUs during the most recent
calendar year for which data is available prior to the submission of
the plan.
    (2) Emission standards. You must include an identification of all
emission standards for each affected EGU according to Sec.  60.5775,
compliance periods for each emission standard according to Sec.
60.5770, and a demonstration that the emission standards, when taken
together, achieve the applicable CO2 emission performance
rates or CO2 emission goals described in Sec.  60.5855.
Allowance systems are an acceptable form of emission standards under
this subpart.
    (i) Your plan does not need to include corrective measures
specified in paragraph (a)(2)(ii) of this section if your plan:
    (A) Imposes emission standards on all affected EGUs that, assuming
full compliance by all affected EGUs, mathematically assure achievement
of the CO2 emission performance rates in the plan for each
plan period;
    (B) Imposes emission standards on all affected EGUS that, assuming
full compliance by all affected EGUs, mathematically assure achievement
of the CO2 emission goals; or
    (C) Imposes emission standards on all affected EGUs that, assuming
full compliance by all affected EGUs, in conjunction with applicable
requirements under state law for EGUs subject to subpart TTTT of this
subpart, assuming the applicable requirements under state law are met
by all EGUs subject to subpart TTTT of this subpart, achieve the
applicable mass-based CO2 emission goals plus new source
CO2 emission complement allowed for in Sec.  60.5790(b)(5).
    (ii) If your plan does not meet the requirements of (a)(2)(i) or
(iii) of this section, your plan must include the requirement for
corrective measures to be implemented if triggered. Upon triggering
corrective measures, if you do not already have them included in your
approved State plan, you must submit corrective measures to EPA for
approval as a plan revision per the requirements of Sec.  60.5785(c).
These corrective measures must ensure that the interim period and final
period CO2 emission performance rates or CO2
emission goals are achieved by your affected EGUs, as applicable, and
must achieve additional emission reductions to offset any emission
performance shortfall. Your plan must include the requirement that
corrective measures be triggered and implemented according to
paragraphs (a)(2)(ii)(A) through (H) of this section.
    (A) Your plan must include a trigger for an exceedance of an
interim step 1 or interim step 2 CO2 emission performance
rate or CO2 emission goal by 10 percent or greater, either
on average or cumulatively (if applicable).
    (B) Your plan must include a trigger for an exceedance of an
interim step 1 goal or interim step 2 goal of 10 percent or greater
based on either reported CO2 emissions with applied plus or
minus net allowance export or import adjustments (if applicable), or
based on the adjusted CO2 emission rate (if applicable).
    (C) Your plan must include a trigger for a failure to meet an
interim period goal based on reported CO2 emissions with
applied plus or minus net allowance export or import adjustments

(if applicable), or based on the adjusted CO2 emission rate
(if applicable).
    (D) Your plan must include a trigger for a failure to meet the
interim period or any final reporting period CO2 emission
performance rate or CO2 emission goal, either on average or
cumulatively (as applicable).
    (E) Your plan must include a trigger for a failure to meet any
final reporting period goal based on reported CO2 emissions
with applied plus or minus net allowance export or import adjustments
(if applicable).
    (F) Your plan must include a trigger for a failure to meet the
interim period CO2 emission performance rate or
CO2 emission goal based on the adjusted CO2
emission rate (if applicable).
    (G) Your plan must include a trigger for a failure to meet any
final reporting period CO2 emission performance rate or
CO2 emission goal based on the adjusted CO2
emission rate (if applicable).
    (H) A net allowance import adjustment represents the CO2
emissions (in tons) equal to the number of net imported CO2
allowances. This adjustment is subtracted from reported CO2
emissions. Under this adjustment, such allowances must be issued by a
state with an emission budget trading program that only applies to
affected EGUs (or affected EGUs plus EGUs covered by subpart TTTT of
this part as applicable). A net allowance export adjustment represents
the CO2 emissions (in tons) equal to the number of net
exported CO2 allowances. This adjustment is added to
reported CO2 emissions.
    (iii) If your plan relies upon State measures, in addition to or in
lieu of emission standards on your affected EGUs, then the final State
plan must include the requirements in paragraph (a)(3) of this section
and the submittal must include the information listed in Sec.
60.5745(a)(6).
    (iv) If your plan requires emission standards in addition to
relying upon State measures, then you must demonstrate that the
emission standards and State measures, when taken together, result in
the achievement of the applicable mass-based CO2 emission
goal described in Sec.  60.5855 by your State's affected EGUs.
    (3) State measures backstop. If your plan relies upon State
measures, you must submit, as part of the plan in lieu of the
requirements in paragraph (a)(2)(i) and (ii) of this section, a
federally enforceable backstop that includes emission standards for
affected EGUs that will be put into place, if there is a triggering
event listed in paragraph (a)(3)(i) of this section, within 18 months
of the due date of the report required in Sec.  60.5870(b). The
emission standards on the affected EGUs as part of the backstop must be
able to meet either the CO2 emission performance rates or
mass-based or rate-based CO2 emission goal for your State
during the interim and final periods. You must either submit, along
with the backstop emission standards, provisions to adjust the emission
standards to make up for the prior emission performance shortfall, such
that no later plan revision to modify the emission standards is
necessary in order to address the emission performance shortfall, or
you must submit, as part of the final plan, backstop emission standards
that assure affected EGUs would achieve your State's CO2
emission performance rates or emission goals during the interim and
final periods, and then later submit appropriate revisions to the
backstop emission standards adjusting for the shortfall through the
State plan revision process described in Sec.  60.5785. The backstop
must also include the requirements in paragraphs (a)(3)(i) through
(iii) of this section, as applicable.
    (i) You must include a trigger for the backstop to go into effect
upon:
    (A) A failure to meet a programmatic milestone;
    (B) An exceedance of 10 percent or greater of an interim step 1
goal or interim step 2 goal based on reported CO2 emissions,
with applied plus or minus net allowance export or import adjustments
(if applicable);
    (C) A failure to meet the interim period goal based on reported
CO2 emissions, with applied plus or minus net allowance
export or import adjustments (if applicable); or
    (D) A failure to meet any final reporting period goal based on
reported CO2 emissions, with applied plus or minus net
allowance export or import adjustments (if applicable).
    (ii) You may include in your plan any additional triggers so long
as they do not reduce the stringency of the triggers required under
paragraph (a)(3)(i) of this section.
    (iii) You must include a schedule for implementation of the
backstop once triggered, and you must identify all necessary State
administrative and technical procedures for implementing the backstop.
    (4) Identification of applicable monitoring, reporting, and
recordkeeping requirements for each affected EGU. You must include in
your plan all applicable monitoring, reporting and recordkeeping
requirements for each affected EGU and the requirements must be
consistent with or no less stringent than the requirements specified in
Sec.  60.5860.
    (5) State reporting. You must include in your plan a description of
the process, contents, and schedule for State reporting to the EPA
about plan implementation and progress, including information required
under Sec.  60.5870.
    (i) You must include in your plan a requirement for a report to be
submitted by July 1, 2021, that demonstrates that the State has met, or
is on track to meet, the programmatic milestone steps indicated in the
timeline required in Sec.  60.5770.
    (b) You must follow the requirements of subpart B of this part and
demonstrate that they were met in your State plan. However, the
provisions of Sec.  60.24(f) shall not apply.

Sec.  60.5745  What must I include in my final plan submittal?

    (a) In addition to the components of the plan listed in Sec.
60.5740, a final plan submittal to the EPA must include the information
in paragraphs (a)(1) through (13) of this section. This information
must be submitted to the EPA as part of your final plan submittal but
will not be codified as part of the federally enforceable plan upon
approval by EPA.
    (1) You must include a description of your plan approach and the
geographic scope of the plan (i.e., State or multi-State, geographic
boundaries related to the plan elements), including, if applicable,
identification of multi-State plan participants.
    (2) You must identify CO2 emission performance rates or
equivalent statewide CO2 emission goals that your affected
EGUs will achieve. If the geographic scope of your plan is a single
State, then you must identify CO2 emission performance rates
or emission goals according to Sec.  60.5855. If your plan includes
multiple States and you elect to set CO2 emission goals, you
must identify CO2 emission goals calculated according to
Sec.  60.5750.
    (i) You must specify in the plan submittal the CO2
emission performance rates or emission goals that affected EGUs will
meet for the interim period, each interim step, and the final period
(including each final reporting period) pursuant to Sec.  60.5770.
    (ii) [Reserved]
    (3) You must include a demonstration that the affected EGUs covered
by the plan are projected to achieve the CO2 emission
performance rates or CO2 emission goals described in Sec.
60.5855.
    (4) You must include a demonstration that each affected EGU's
emission standard is quantifiable, non-

duplicative, permanent, verifiable, and enforceable according to Sec.
60.5775.
    (5) If your plan includes emission standards on your affected EGUs
sufficient to meet either the CO2 emission performance rates
or CO2 emission goals, you must include in your plan
submittal the information in paragraphs (a)(5)(i) through (v) of this
section as applicable.
    (i) If your plan applies separate rate-based CO2
emission standards for affected EGUs (in lbs CO2/MWh) that
are equal to or lower than the CO2 emission performance
rates listed in Table 1 of this subpart or uniform rate-based
CO2 emission standards equal to or lower than the rate-based
CO2 emission goals listed in Table 2 of this subpart, then
no additional demonstration is required beyond inclusion of the
emission standards in the plan.
    (ii) If a plan applies rate-based emission standards to individual
affected EGUs at a lbs CO2/MWh rate that differs from the
CO2 emission performance rates in Table 1 of this subpart or
the State's rate-based CO2 emission goal in Table 2 of this
subpart, then a further demonstration is required that the application
of the CO2 emission standards will achieve the
CO2 emission performance rates or State rate-based
CO2 emission goal. You must demonstrate through a projection
that the adjusted weighted average CO2 emission rate of
affected EGUs, when weighted by generation (in MWh), will be equal to
or less than the CO2 emission performance rates or the rate-
based CO2 emission goal. This projection must address the
interim period and the final period. The projection in the plan
submittal must include the information listed in paragraph (a)(5)(v) of
this section and in addition the following:
    (A) An analysis of the change in generation of affected EGUs given
the compliance costs and incentives under the application of different
emission rate standards across affected EGUs in a State;
    (B) A projection showing how generation is expected to shift
between affected EGUs and across affected EGUs and non-affected EGUs
over time;
    (C) Assumptions regarding the availability and anticipated use of
the MWh of electricity generation or electricity savings from eligible
resources that can be issued ERCs;
    (D) The specific calculation (or assumption) of how eligible
resource MWh of electricity generation or savings are being used in the
projection to adjust the reported CO2 emission rate of
affected EGUs;
    (E) If a state plan provides for the ability of renewable energy
resources located in states with mass-based plans to be issued ERCs,
consideration in the projection that such resources must meet
geographic eligibility requirements, consistent with Sec.  60.5800(a);
and
    (F) Any other applicable assumptions used in the projection.
    (iii) If a plan establishes mass-based emission standards for
affected EGUs that cumulatively do not exceed the State's EPA-specified
mass CO2 emission goal, then no additional demonstration is
required beyond inclusion of the emission standards in the plan.
    (iv) If a plan applies mass-based emission standards to individual
affected EGUs that cumulatively exceed the State's EPA-specified mass
CO2 emission goal, then you must include a demonstration
that your mass-based emission program will be designed such that
compliance by affected EGUs would achieve the State mass-based
CO2 emission goals. This demonstration includes the
information listed in paragraph (a)(5)(v) of this section.
    (v) Your plan demonstration to be included in your plan submittal,
if applicable, must include the information listed in paragraphs
(a)(5)(v)(A) through (L) of this section.
    (A) A summary of each affected EGU's anticipated future operation
characteristics, including:
    (1) Annual generation;
    (2) CO2 emissions;
    (3) Fuel use, fuel prices (when applicable), fuel carbon content;
    (4) Fixed and variable operations and maintenance costs (when
applicable);
    (5) Heat rates; and
    (6) Electric generation capacity and capacity factors.
    (B) An identification of any planned new electric generating
capacity.
    (C) Analytic treatment of the potential for building unplanned new
electric generating capacity.
    (D) A timeline for implementation of EGU-specific actions (if
applicable).
    (E) All wholesale electricity prices.
    (F) A geographic representation appropriate for capturing impacts
and/or changes in the electric system.
    (G) A time period of analysis, which must extend through at least
2031.
    (H) An anticipated electricity demand forecast (MWh load and MW
peak demand) at the State and regional level, including the source and
basis for these estimates, and, if appropriate, justification and
documentation of underlying assumptions that inform the development of
the demand forecast (e.g., annual economic and demand growth rate or
population growth rate).
    (I) A demonstration that each emission standard included in your
plan meets the requirements of Sec.  60.5775.
    (J) Any ERC or emission allowance prices, when applicable.
    (K) An identification of planning reserve margins.
    (L) Any other applicable assumptions used in the projection.
    (6) If your plan relies upon State measures, in addition to or in
lieu of the emission standards required by paragraph Sec.
60.5740(a)(2), the final State plan submittal must include the
information under paragraphs (a)(5)(v) and (a)(6)(i) through (v) of
this section.
    (i) You must include a description of all the State measures the
State will rely upon to achieve the applicable CO2 emission
goals required under Sec.  60.5855(e), the projected impacts of the
State measures over time, the applicable State laws or regulations
related to such measures, and identification of parties or entities
subject to or implementing such State measures.
    (ii) You must include the schedule and milestones for the
implementation of the State measures. If the State measures in your
plan submittal rely upon measures that do not have a direct effect on
the CO2 emissions measured at an affected EGU's stack, you
must also demonstrate how the minimum emission, monitoring and
verification (EM&V) requirements listed under Sec.  60.5795 that apply
to those programs and projects will be met.
    (iii) You must demonstrate that federally enforceable emission
standards for affected EGUs in conjunction with any State measures
relied upon for your plan, are sufficient to achieve the mass-based
CO2 emission goal for the interim period, each interim step
in that interim period, the final period, and each final reporting
period. In addition, you must demonstrate that each emission standard
included in your plan meets the requirements of Sec.  60.5775 and each
State measure included in your plan submittal meets the requirements of
Sec.  60.5780.
    (iv) You must include a CO2 performance projection of
your State measures that shows how the measures, whether alone or in
conjunction with any federally enforceable CO2 emission
standards for affected EGUs, will result in the achievement of the
future CO2 performance at affected EGUs. Elements of this
projection must include those specified in paragraph (a)(5)(v) of this
section, as applicable, and the following for the interim period and
the final period:

    (A) A baseline demand and supply forecast as well as the underlying
assumptions and data sources of each forecast;
    (B) The magnitude of energy and emission impacts from all measures
included in the plan and applicable assumptions;
    (C) An identification of State-enforceable measures with
electricity savings and RE generation, in MWh, expected for individual
and collective measures and any assumptions related to the
quantification of the MWh, as applicable.
    (7) Your plan submittal must include a demonstration that the
reliability of the electrical grid has been considered in the
development of your plan.
    (8) Your plan submittal must include a timeline with all the
programmatic milestone steps the State intends to take between the time
of the State plan submittal and January 1, 2022 to ensure the plan is
effective as of January 1, 2022.
    (9) Your plan submittal must adequately demonstrate that your State
has the legal authority (e.g., through regulations or legislation) and
funding to implement and enforce each component of the State plan
submittal, including federally enforceable emission standards for
affected EGUs, and State measures as applicable.
    (10) Your State plan submittal must demonstrate that each interim
step goal required under Sec.  60.5855(c), will be met and include in
its supporting documentation, if applicable, a description of the
analytic process, tools, methods, and assumptions used to make this
demonstration.
    (11) Your plan submittal must include certification that a hearing
required under Sec.  60.23(c)(1) on the State plan was held, a list of
witnesses and their organizational affiliations, if any, appearing at
the hearing, and a brief written summary of each presentation or
written submission, pursuant to the requirements of Sec.  60.23(d) and
(f).
    (12) Your plan submittal must include documentation of any
conducted community outreach and community involvement, including
engagement with vulnerable communities.
    (13) Your plan submittal must include supporting material for your
plan including:
    (i) Materials demonstrating the State's legal authority and funding
to implement and enforce each component of its plan, including
emissions standards and/or State measures that the plan relies upon;
    (ii) Materials supporting that the CO2 emission
performance rates or CO2 emission goals will be achieved by
affected EGUs identified under the plan, according to paragraph (a)(3)
of this section;
    (iii) Materials supporting any calculations for CO2
emission goals calculated according to Sec.  60.5855, if applicable;
and
    (iv) Any other materials necessary to support evaluation of the
plan by the EPA.
    (b) You must submit your final plan to the EPA electronically
according to Sec.  60.5875.

Sec.  60.5750  Can I work with other States to develop a multi-State
plan?

    A multi-State plan must include all the required elements for a
plan specified in Sec.  60.5740(a). A multi-State plan must meet the
requirements of paragraphs (a) and (b) of this section.
    (a) The multi-State plan must demonstrate that all affected EGUs in
all participating States will meet the CO2 emission
performance rates listed in Table 1 of this subpart or an equivalent
CO2 emission goal according to paragraphs (a)(1) or (2) of
this section. States may only follow the procedures in (a)(1) or (2) if
they have functionally equivalent requirements meeting Sec.  60.5775
and Sec.  60.5790 included in their plans.
    (1) For States electing to demonstrate performance with a
CO2 emission rate-based goal, the CO2 emission
goals identified in the plan according to Sec.  60.5855 will be an
adjusted weighted (by net energy output) average lbs CO2/MWh
emission rate to be achieved by all affected EGUs in the multi-State
area during the plan periods; or
    (2) For States electing to demonstrate performance with a
CO2 emission mass-based goal, the CO2 emission
goals identified in the multi-State plan according to Sec.  60.5855
will be total mass CO2 emissions by all affected EGUs in the
multi-State area during the plan periods, representing the sum of all
individual mass CO2 goals for states participating in the
multi-state plan.
    (b) Options for submitting a multi-State plan include the
following:
    (1) States participating in a multi-State plan may submit one
multi-State plan submittal on behalf of all participating States. The
joint submittal must be signed electronically, according to Sec.
60.5875, by authorized officials for each of the States participating
in the multi-State plan. In this instance, the joint submittal will
have the same legal effect as an individual submittal for each
participating State. The joint submittal must address plan components
that apply jointly for all participating States and components that
apply for each individual State in the multi-State plan, including
necessary State legal authority to implement the plan, such as State
regulations and statutes.
    (2) States participating in a multi-State plan may submit a single
plan submittal, signed by authorized officials from each participating
State, which addresses common plan elements. Each participating State
must, in addition, provide individual plan submittals that address
State-specific elements of the multi-State plan.
    (3) States participating in a multi-State plan may separately make
individual submittals that address all elements of the multi-State
plan. The plan submittals must be materially consistent for all common
plan elements that apply to all participating States, and also must
address individual State-specific aspects of the multi-State plan. Each
individual State plan submittal must address all required plan
components in Sec.  60.5740.
    (c) A State may elect to participate in more than one multi-State
plan. If your State elects to participate in more than one multi-State
plan then you must identify in the State plan submittal required under
Sec.  60.5745, the subset of affected EGUs that are subject to the
specific multi-State plan or your State's individual plan. An affected
EGU can only be subject to one plan.
    (d) A State may elect to allow its affected EGUs to interact with
affected EGUs in other States through mass-based trading programs or a
rate-based trading program without entering into a formal multi-State
plan allowed for under this section, so long as such programs are part
of an EPA-approved state plan and meet the requirements of paragraphs
(d)(1) and (2) of this section, as applicable.
    (1) For States that elect to do mass-based trading under this
option the State must indicate in its plan that its emission budget
trading program will be administered using an EPA-approved (or EPA-
administered) emission and allowance tracking system.
    (2) For States that elect to use a rate-based trading program which
allows the affected EGUs to use ERCs from other State rate-based
trading programs, the plan must require affected EGUs within their
State to comply with emission standards equal to the sub-category
CO2 emission performance rates in Table 1 of this subpart.

Sec.  60.5760  What are the timing requirements for submitting my plan?

    (a) You must submit a final plan with the information required
under Sec.  60.5745 by September 6, 2016, unless you are submitting an
initial submittal,

allowed under Sec.  60.5765, in lieu of a final State plan submittal,
according to paragraph (b) of this section.
    (b) For States seeking a two year extension for a final plan
submittal, you must include the information in Sec.  60.5765(a) in an
initial submittal by September 6, 2016, to receive an extension to
submit your final State plan submittal by September 6, 2018.
    (c) You must submit all information required under paragraphs (a)
and (b) of this section according to the electronic reporting
requirements in Sec.  60.5875.

Sec.  60.5765  What must I include in an initial submittal if
requesting an extension for a final plan submittal?

    (a) You must sufficiently demonstrate that your State is able to
undertake steps and processes necessary to timely submit a final plan
by the extended date of September 6, 2018, by addressing the following
required components in an initial submittal by September 6, 2016, if
requesting an extension for a final plan submittal:
    (1) An identification of final plan approach or approaches under
consideration and a description of progress made to date on the final
plan components;
    (2) An appropriate explanation of why the State requires additional
time to submit a final plan by September 6, 2018; and
    (3) A demonstration or description of the opportunity for public
comment on the initial submittal and meaningful engagement with
stakeholders, including vulnerable communities, during the time in
preparation of the initial submittal and the plans for engagement
during development of the final plan.
    (b) You must submit an initial submittal allowed in paragraph (a)
of this section, information required under paragraph (c) of this
section (only if a State elects to submit an initial submittal to
request an extension for a final plan submittal), and a final State
plan submittal according to Sec.  60.5870. If a State submits an
initial submittal, an extension for a final State plan submittal is
considered granted and a final State plan submittal is due according to
Sec.  60.5760(b) unless a State is notified within 90 days of the EPA
receiving the initial submittal that the EPA finds the initial
submittal does not meet the requirements listed in paragraph (a) of
this section. If the EPA notifies the State that the initial submittal
does not meet such requirements, the EPA will also notify the State
that it has failed to submit the final plan required by September 6,
2016.
    (c) If an extension for submission of a final plan has been
granted, you must submit a progress report by September 6, 2017. The
2017 report must include the following:
    (1) A summary of the status of each component of the final plan,
including an update from the 2016 initial submittal and a list of which
final plan components are not complete.
    (2) A commitment to a plan approach (e.g., single or multi-State,
rate-based or mass-based emission performance level, rate-based or
mass-based emission standards), including draft or proposed legislation
and/or regulations.
    (3) An updated comprehensive roadmap with a schedule and milestones
for completing the final plan, including any updates to community
engagement undertaken and planned.

Sec.  60.5770  What schedules, performance periods, and compliance
periods must I include in my plan?

    (a) The affected EGUs covered by your plan must meet the
CO2 emission requirements required under Sec.  60.5855 for
the interim period, interim steps, and the final reporting periods
according to paragraph (b) of this section. You must also include in
your plan compliance periods for each affected EGU regulated under the
plan according to paragraphs (c) and (d) of this section.
    (b) Your plan must require your affected EGUs to achieve each
CO2 emission performance rate or CO2 emission
goal, as applicable, required under Sec.  60.5855 over the periods
according to paragraphs (b)(1) through (3) of this section.
    (1) The interim period.
    (2) Each interim step.
    (3) Each final reporting period.
    (c) The emission standards for affected EGUs regulated under the
plan must include the following compliance periods:
    (1) For the interim period, affected EGUs must have emission
standards that have compliance periods that are no longer than each
interim step and are imposed for the entirety of the interim step
either alone or in combination.
    (2) For the final period, affected EGUs must have emission
standards that have compliance periods that are no longer than each
final reporting period and are imposed for the entirety of the final
reporting period either alone or in combination.
    (3) Compliance periods for each interim step and each final
reporting period may take forms shorter than specified in this
regulation, provided the schedules of compliance collectively end on
the same schedule as each interim step and final reporting period.
    (d) If your plan relies upon State measures in lieu of or in
addition to emission standards for affected EGUs regulated under the
plan, then the performance periods must be identical to the compliance
periods for affected EGUs listed in paragraphs (c)(1) through (3) of
this section.

Sec.  60.5775  What emission standards must I include in my plan?

    (a) Emission standard(s) for affected EGUs included under your plan
must be demonstrated to be quantifiable, verifiable, non-duplicative,
permanent, and enforceable with respect to each affected EGU. The plan
submittal must include the methods by which each emission standard
meets each of the following requirements in paragraphs (b) through (f)
of this section.
    (b) An affected EGU's emission standard is quantifiable if it can
be reliably measured in a manner that can be replicated.
    (c) An affected EGU's emission standard is verifiable if adequate
monitoring, recordkeeping and reporting requirements are in place to
enable the State and the Administrator to independently evaluate,
measure, and verify compliance with the emission standard.
    (d) An affected EGU's emission standard is non-duplicative with
respect to a State plan if it is not already incorporated as an
emission standard in another State plan unless incorporated in multi-
State plan.
    (e) An affected EGU's emission standard is permanent if the
emission standard must be met for each compliance period, unless it is
replaced by another emission standard in an approved plan revision, or
the State demonstrates in an approvable plan revision that the emission
reductions from the emission standard are no longer necessary for the
State to meet its State level of performance.
    (f) An affected EGU's emission standard is enforceable if:
    (1) A technically accurate limitation or requirement and the time
period for the limitation or requirement are specified;
    (2) Compliance requirements are clearly defined;
    (3) The affected EGUs responsible for compliance and liable for
violations can be identified;
    (4) Each compliance activity or measure is enforceable as a
practical matter; and
    (5) The Administrator, the State, and third parties maintain the
ability to enforce against violations (including if an affected EGU
does not meet its emission standard based on its

emissions, its allowances if it is subject to a mass-based emission
standard, or its ERCs if it is subject to a rate-based emission
standard) and secure appropriate corrective actions, in the case of the
Administrator pursuant to CAA sections 113(a)-(h), in the case of a
State, pursuant to its plan, State law or CAA section 304, as
applicable, and in the case of third parties, pursuant to CAA section
304.

Sec.  60.5780  What State measures may I rely upon in support of my
plan?

    You may rely upon State measures in support of your plan that are
not emission standard(s) on affected EGUs, provided those State
measures meet the requirements in paragraph (a) of this section.
    (a) Each State measure is quantifiable, verifiable, non-
duplicative, permanent, and enforceable with respect to each affected
entity (e.g., entities other than affected EGUs with no federally
enforceable obligations under a State plan), and your plan supporting
materials include the methods by which each State measure meets each of
the following requirements in paragraphs (a)(1) through (5) of this
section.
    (1) A State measure is quantifiable with respect to an affected
entity if it can be reliably measured in a manner that can be
replicated.
    (2) A State measure is verifiable with respect to an affected
entity if adequate monitoring, recordkeeping and reporting requirements
are in place to enable the State to independently evaluate, measure,
and verify compliance with the State measure.
    (3) A State measure is non-duplicative with respect to an affected
entity if it is not already incorporated as a State measure or an
emission standard in another State plan or State plan supporting
material unless incorporated in a multi-State plan.
    (4) A State measure is permanent with respect to an affected entity
if the State measure must be met for at least each compliance period,
or unless either it is replaced by another State measure in an approved
plan revision, or the State demonstrates in an approved plan revision
that the emission reductions from the State measure are no longer
necessary for the State's affected EGUs to meet their mass-based
CO2 emission goal.
    (5) A State measure is enforceable against an affected entity if:
    (i) A technically accurate limitation or requirement and the time
period for the limitation or requirement are specified;
    (ii) Compliance requirements are clearly defined;
    (iii) The affected entities responsible for compliance and liable
for violations can be identified;
    (iv) Each compliance activity or measure is enforceable as a
practical matter; and
    (v) The State maintains the ability to enforce violations and
secure appropriate corrective actions.
    (b) [Reserved]

Sec.  60.5785  What is the procedure for revising my plan?

    (a) EPA-approved plans can be revised only with approval by the
Administrator. The Administrator will approve a plan revision if it is
satisfactory with respect to the applicable requirements of this
subpart and any applicable requirements of subpart B of this part,
including the requirement in Sec.  60.5745(a)(3) to demonstrate
achievement of the CO2 emission performance rates or
CO2 emission goals in Sec.  60.5855. If one (or more) of the
elements of the plan set in Sec.  60.5740 require revision with respect
to achieving the CO2 emission performance rates or
CO2 emission goals in Sec.  60.5855, a request must be
submitted to the Administrator indicating the proposed revisions to the
plan to ensure the CO2 emission performance rates or
CO2 emission goals are met. In addition, the following
provisions in paragraphs (b) through (d) of this section may apply.
    (b) You may submit revisions to a plan to adjust CO2
emission goals according to Sec.  60.5855(d).
    (c) If your State is required to submit a notification according to
Sec.  60.5870(d) indicating a triggering of corrective measures as
described in Sec.  60.5740(a)(2)(i) and your plan does not already
include corrective measures to be implemented if triggered, you must
revise your State plan to include corrective measures to be
implemented. The corrective measures must ensure achievement of the
CO2 emission performance rates or State CO2
emission goal. Additionally, the corrective measures must achieve
additional CO2 emission reductions to offset any
CO2 emission performance shortfall relative to the overall
interim period or final period CO2 emission performance rate
or State CO2 emission goal. The State plan revision
submission must explain how the corrective measures both make up for
the shortfall and address the State plan deficiency that caused the
shortfall. The State must submit the revised plan and explanation to
the EPA within 24 months after submitting the State report required in
Sec.  60.5870(a) indicating the CO2 emission performance
deficiency in lieu of the requirements of Sec.  60.28(a). The State
must implement corrective measures within 6 months of the EPA's
approval of a plan revision adding them. The shortfall must be made up
as expeditiously as practicable.
    (d) If your plan relies upon State measures, your backstop is
triggered under Sec.  60.5740(a)(3)(i), and your State measures plan
backstop does not include a mechanism to make up the shortfall, you
must revise your backstop emission standards to make up the shortfall.
The shortfall must be made up as expeditiously as practicable.
    (e) Reliability Safety Valve:
    (1) In order to trigger a reliability safety valve, you must notify
the EPA within 48 hours of an unforeseen, emergency situation that
threatens reliability, such that your State will need a short-term
modification of emission standards under a State plan for a specified
affected EGU or EGUs. The EPA will consider the notification in Sec.
60.5870(g)(1) to be an approved short-term modification to the State
plan without needing to go through the full State plan revision process
if the State provides a second notification to the EPA within seven
days of the first notification. The short-term modification under a
reliability safety valve allows modification to emission standards
under the State plan for an affected EGU or EGUs for an initial period
of up to 90 days. During that period of time, the affected EGU or EGUs
will need to comply with the modified emission standards identified in
the initial notification required under Sec.  60.5870(g)(1) or amended
in the second notification required under Sec.  60.5870(g)(2). For the
duration of the up to 90-day short-term modification, the
CO2 emissions of the affected EGU or EGUs that exceed their
obligations under the originally approved State plan will not be
counted against the State's CO2 emission performance rate or
CO2 emission goal. The EPA reserves the right to review any
such notification required under Sec.  60.5870(g), and, in the event
that the EPA finds such notification is improper, the EPA may disallow
the short-term modification and affected EGUs must continue to operate
under the approved State plan emission standards. As described more
fully in Sec.  60.5870(g)(3), at least seven days before the end of the
initial 90-day reliability safety valve period, the State must notify
the appropriate EPA regional office whether the reliability concern has
been addressed and the affected EGU or EGUs can resume meeting the
original emission standards established in the State plan prior to the
short-term modification or whether a

serious, ongoing reliability issue necessitates the affected EGU or
EGUs emitting beyond the amount allowed under the State plan.
    (2) Plan revisions submitted pursuant to Sec.  60.5870(g)(3) must
meet the requirements for State plan revisions under Sec.  60.5785(a).

Sec.  60.5790  What must I do to meet my plan obligations?

    (a) To meet your plan obligations, you must demonstrate that your
affected EGUs are complying with their emission standards as specified
in Sec.  60.5740, and you must demonstrate that the emission standards
on affected EGUs, alone or in conjunction with any State measures, are
resulting in achievement of the CO2 emission performance
rates or statewide CO2 emission goals by affected EGUs using
the procedures in paragraphs (b) through (d) of this section. If your
plan requires the use of allowances for your affected EGUs to comply
with their mass-based emission standards, you must follow the
requirements under paragraph (b) of this section and Sec.  60.5830. If
your plan requires the use of ERCs for your affected EGUs to comply
with their rate-based emission standards, you must follow the
requirements under paragraphs (c) and (d) of this section and
Sec. Sec.  60.5795 through 60.5805.
    (b) If you submit a plan that sets a mass-based emission trading
program for your affected EGUs, the State plan must include emission
standards and requirements that specify the allowance system, related
compliance requirements and mechanisms, and the emission budget as
appropriate. These requirements must include those listed in paragraphs
(b)(1) through (5) of this section.
    (1) CO2 emission monitoring, reporting, and
recordkeeping requirements for affected EGUs.
    (2) Requirements for State allocation of allowances consistent with
Sec.  60.5815.
    (3) Requirements for tracking of allowances, from issuance through
submission for compliance, consistent with Sec.  60.5820.
    (4) The process for affected EGUs to demonstrate compliance
(allowance ``true-up'' with reported CO2 emissions)
consistent with Sec.  60.5825.
    (5) Requirements that address potential increased CO2
emissions from new sources, beyond the emissions expected from new
sources if affected EGUs were given emission standards in the form of
the subcategory-specific CO2 emission performance rates. You
may meet this requirement by requiring one of the options under
paragraphs (b)(5)(i) through (iii) of this section.
    (i) You may include, as part of your plan's supporting
documentation, requirements enforceable as a matter of State law
regulating CO2 emissions from EGUs covered by subpart TTTT
of this part under the mass-based CO2 goal plus new source
CO2 emission complement applicable to your State in Table 4
of this subpart. If you choose this option, the term ``mass-based
CO2 goal plus new source CO2 emission
complement'' shall apply rather than ``CO2 mass-based goal''
and the term ``CO2 emission goal'' shall include ``mass-
based CO2 goal plus new source CO2 emission
complement'' in these emission guidelines.
    (ii) You may include requirements in your State plan for emission
budget allowance allocation methods that align incentives to generate
to affected EGUs or EGUs covered by subpart TTTT of this part that
result in the affected EGUs meeting the mass-based CO2
emission goal;
    (iii) You may submit for the EPA's approval, an equivalent method
which requires affected EGUs to meet the mass-based CO2
emission goal. The EPA will evaluate the approvability of such an
alternative method on a case by case basis.
    (c) If you submit a plan that sets rate-based emission standards on
your affected EGUs, to meet the requirements of Sec.  60.5775, you must
follow the requirements in paragraphs (c)(1) through (4) of this
section.
    (1) You must require the owner or operator of each affected EGU
covered by your plan to calculate an adjusted CO2 emission
rate to demonstrate compliance with its emission standard by factoring
stack emissions and any ERCs into the following equation:
[GRAPHIC] [TIFF OMITTED] TR23OC15.005

Where:
CO2 emission rate = An affected EGU's adjusted
CO2 emission rate that will be used to determine
compliance with the applicable CO2 emission standard.
MCO2 = Measured CO2 mass in units of pounds
(lbs) summed over the compliance period for an affected EGU.
MWhop = Total net energy output over the compliance
period for an affected EGU in units of MWh.
MWhERC = ERC replacement generation for an affected EGU
in units of MWh (ERCs are denominated in whole integers as specified
in paragraph (d) of this section).

    (2) Your plan must specify that an ERC qualifies for the compliance
demonstration specified in paragraph (c)(1) of this section if the ERC
meets the requirements of paragraphs (c)(2)(i) through (iv) of this
section.
    (i) An ERC must have a unique serial number.
    (ii) An ERC must represent one MWh of actual energy generated or
saved with zero associated CO2 emissions.
    (iii) An ERC must only be issued to an eligible resource that meets
the requirements of Sec.  60.5800 or to an affected EGU that meets the
requirements of Sec.  60.5795 and must only be issued by a State or its
State agent through an EPA-approved ERC tracking system that meets the
requirements of Sec.  60.5810, or by the EPA through an EPA-
administered tracking system.
    (iv) An ERC must be surrendered and retired only once for purpose
of compliance with this regulation through an EPA-approved ERC tracking
system that meets the requirements of Sec.  60.5810, or by the EPA
through an EPA-administered tracking system.
    (3) Your plan must specify that an ERC does not qualify for the
compliance demonstration specified in paragraph (c)(1) of this section
if it does not meet the requirements of paragraph (c)(2) of this
section or if any State has used that same ERC for purposes of
demonstrating achievement of a CO2 emission performance rate
or CO2 emission goal. The plan must additionally include
provisions that address requirements for revocation or adjustment that
apply if an ERC issued by the State is subsequently found to have been
improperly issued.
    (4) Your plan must include provisions either allowing for or
restricting banking of ERCs between compliance periods for affected
EGUs, and provisions not allowing any borrowing of any ERCs from future
compliance periods by affected EGUs or eligible resources.

Emission Rate Credit Requirements

Sec.  60.5795  What affected EGUs qualify for generation of ERCs?

    (a) For issuance of ERCs to the affected EGUs that generate them,
the plan must specify the accounting method and process for ERC
issuance. For plans that require that affected EGUs meet a rate-based
CO2 emission goal, where all affected EGUs have identical
emission standards, you must specify the accounting method listed in
paragraph (a)(1) of this section for generating ERCs. For plans that
require affected EGUs to meet the CO2 emission performance
rates or CO2 emission goals where affected EGUs have
emission standards that are not equal for all affected EGUs, you must
specify the accounting methods listed in paragraphs (a)(1) and (2) of
this section for generating ERCs.
    (1) You must include the calculation method for determining the
number of ERCs, denominated in MWh, that may be generated by and issued
to an affected EGU that is in compliance with its emission standard,
based on the difference between its emission standard and its reported
CO2 emission rate for the compliance period; and
    (2) You must include the calculation method for determining the
number of ERCs, denominated in MWh, that may be issued to affected EGUs
that meet the definition of a stationary combustion turbine based on
the displaced emissions from affected EGUs not meeting the definition
of a stationary combustion turbine, resulting from the difference
between its annualized net energy output in MWh for the calendar
year(s) in the compliance period and its net energy output in MWh for
the 2012 calendar year (January 1, 2012, through December 31, 2012).
    (b) Any ERCs generated through the method described as required by
paragraph (a)(2) of this section must not be used by any affected EGUs
other than steam generating units or IGCCs to demonstrate compliance as
prescribed under Sec.  60.5790(c)(1).
    (c) Any states in a multi-State plan that requires the use of ERCs
for affected EGUs to comply with their emission standards must have
functionally equivalent requirements pursuant to paragraphs (a)(1) and
(2) of this section for generating ERCs.

Sec.  60.5800  What other resources qualify for issuance of ERCs?

    (a) ERCs may only be issued for generation or savings produced on
or after January 1, 2022, to a resource that qualifies as an eligible
resource because it meets each of the requirements in paragraphs (a)(1)
through (4) of this section.
    (1) Resources qualifying for eligibility only include resources
that increased installed electrical generation nameplate capacity, or
implemented new electrical savings measures, on or after January 1,
2013. If a resource had a nameplate capacity uprate, ERCs may be issued
only for the difference in generation between its uprated nameplate
capacity and its nameplate capacity prior to the uprate. ERCs must not
be issued for generation for an uprate that followed a derate that
occurred on or after January 1, 2013. A resource that is relicensed or
receives a license extension is considered existing capacity and is not
an eligible resource, unless it receives a capacity uprate as a result
of the relicensing process that is reflected in its relicensed permit.
In such a case, only the difference in nameplate capacity between its
relicensed permit and its prior permit is eligible to be issued ERCs.
    (2) The resource must be connected to, and deliver energy to or
save electricity on, the electric grid in the contiguous United States.
    (3) The resource must be located in either:
    (i) A State whose affected EGUs are subject to rate-based emission
standards pursuant to this regulation; or
    (ii) A State with a mass-based CO2 emission goal, and
the resource can demonstrate (e.g., through a power purchase agreement
or contract for delivery) that the electricity generated is delivered
with the intention to meet load in a State with affected EGUs which are
subject to rate-based emission standards pursuant to this regulation,
and was treated as a generation resource used to serve regional load
that included the State whose affected EGUs are subject to rate-based
emission standards. Notwithstanding any other provision of paragraph
(a)(4) of this section, the only type of eligible resource in the State
with mass-based emission standards is renewable generating technologies
listed in (a)(4)(i) of this section.
    (4) The resource falls into one of the following categories of
resources:
    (i) Renewable electric generating technologies using one of the
following renewable energy resources: Wind, solar, geothermal, hydro,
wave, tidal;
    (ii) Qualified biomass;
    (iii) Waste-to-energy (biogenic portion only);
    (iv) Nuclear power;
    (v) A non-affected combined heat and power (CHP) unit, including
waste heat power;
    (vi) A demand-side EE or demand-side management measure that saves
electricity and is calculated on the basis of quantified ex post
savings, not ``projected'' or ``claimed'' savings; or
    (vii) A category identified in a State plan and approved by the EPA
to generate ERCs.
    (b) Any resource that does not meet the requirements of this
subpart or an approved State plan cannot be issued ERCs for use by an
affected EGU with its compliance demonstration required under Sec.
60.5790(c).
    (c) ERCs may not be issued to or for any of the following:
    (1) New, modified, or reconstructed EGUs that are subject to
subpart TTTT of this part, except CHP units that meet the requirements
of a CHP unit under paragraph (a);
    (2) EGUs that do not meet the applicability requirements of
Sec. Sec.  60.5845 and 60.5850, except CHP units that meet the
requirements of a CHP unit under paragraph (a);
    (3) Measures that reduce CO2 emissions outside the
electric power sector, including, for example, GHG offset projects
representing emission reductions that occur in the forestry and
agriculture sectors, direct air capture, and crediting of
CO2 emission reductions that occur in the transportation
sector as a result of vehicle electrification; and
    (4) Any measure not approved by the EPA for issuance of ERCs in
connection with a specific State plan.
    (d) You must include the appropriate requirements in paragraphs
(d)(1) through (3) of this section for an applicable eligible resource
in your plan.
    (1) If qualified biomass is an eligible resource, the plan must
include a description of why the proposed feedstocks or feedstock
categories should qualify as an approach for controlling increases of
CO2 levels in the atmosphere as well as the proposed
valuation of biogenic CO2 emissions. In addition, for
sustainably-derived agricultural and forest biomass feedstocks, the
state plan must adequately demonstrate that such feedstocks
appropriately control increases of CO2 levels in the
atmosphere and methods for adequately monitoring and verifying these
feedstock sources and related sustainability practices. For all
qualified biomass feedstocks, plans must specify how biogenic
CO2 emissions will be monitored and reported, and identify
specific EM&V, tracking and auditing approaches.
    (2) If waste-to-energy is an eligible resource, the plan must
assess both the

capacity to strengthen existing or implement new waste reduction,
reuse, recycling and composting programs, and measures to minimize any
potential negative impacts of waste-to-energy operations on such
programs. Additionally the plan must include a method for determining
the proportion of total MWh generation from a waste-to-energy facility
that is eligible for use in adjusting a CO2 emission rate
(i.e., that which is generated from biogenic materials).
    (3) If carbon capture and utilization (CCU) is an eligible resource
in a plan, the plan must include analysis supporting how the proposed
qualifying CCU technology results in CO2 emission mitigation
from affected EGUs and provide monitoring, reporting, and verification
requirements to demonstrate the reductions.
    (e) States and areas of Indian country that do not have any
affected EGUs, and other countries, may provide ERCs to adjust
CO2 emissions provided they are connected to the contiguous
U.S. grid and meet the other requirements for eligibility and eligible
resources and the issuance of ERCs included in these emission
guidelines, except that such States and other countries may not provide
ERCs from resources described in Sec.  60.5800(a)(4)(vi).

Sec.  60.5805  What is the process for the issuance of ERCs?

    If your plan uses ERCs your plan must include the process and
requirements for issuance of ERCs to affected EGUs and eligible
resources set forth in paragraphs (a) through (f) of this section.
    (a) Eligibility application. Your plan must require that, to
receive ERCs, the owner or operator must submit an eligibility
application to you that demonstrates that the requirements of your
State plan as approved by the EPA as meeting Sec.  60.5795 (for an
affected EGU) or Sec.  60.5800 (for an eligible resource) are met, and,
in the case of an eligible resource, includes at a minimum:
    (1) Documentation that the eligibility application has only been
submitted to you, or pursuant to an EPA-approved multi-State
collaborative approach;
    (2) An EM&V plan that meets the requirements of the State plan as
approved by the EPA as meeting Sec.  60.5830; and
    (3) A verification report from an independent verifier that
verifies the eligibility of the eligible resource to be issued an ERC
and that the EM&V plan meets the requirements of the State plan as
approved by the EPA of meeting Sec.  60.5805.
    (b) Registration. Your plan must require that any affected EGU or
eligible resource register with an ERC tracking system that meets the
requirements of Sec.  60.5810 prior to the issuance of ERCs, and your
plan must specify that you will only register an affected EGU or
eligible resource after you approve its eligibility application and
determine that the requirements of paragraph (a) of this section are
met.
    (c) M&V reports. For an eligible resource registered pursuant to
paragraph (b) of this section, your plan must require that, prior to
issuance of ERCs by you, the owner or operator must submit the
following:
    (1) An M&V report that meets the requirements of your State plan as
approved by the EPA as meeting Sec.  60.5835; and
    (2) A verification report from an independent verifier that
verifies that the requirements for the M&V report are met.
    (e) Issuance of ERCs. Your plan must specify your procedure for
issuance of ERCs based on your review of an M&V report and verification
report, and must require that ERCs be issued only on the basis of
energy actually generated or saved, and that only one ERC is issued for
each verified MWh.
    (f) Tracking system. Your plan must require that ERCs may only be
issued through an ERC tracking system approved as part of the State
plan.
    (g) Error adjustment. Your plan must include a mechanism to adjust
the number of ERCs issued if any are issued based on error (clerical,
formula input error, etc.).
    (h) Qualification status of an eligible resource. Your plan must
include a mechanism to temporarily or permanently revoke the
qualification status of an eligible resource, such that it can no
longer be issued ERCs for at least the duration that it does not meet
the requirements for being issued ERCs in your State plan.
    (i) Qualification status of an independent verifier--(1)
Eligibility. To be an independent verifier, a person must be approved
by the State as:
    (A) An independent verifier, as defined by this regulation; and
    (B) Eligible to verify eligibility applications, EM&V plans, and/or
M&V reports per the requirements of the approved State plan as meeting
Sec. Sec.  60.5830 and 60.5835 respectively.
    (2) Revocation of qualification. Your plan must include a mechanism
to temporarily or permanently revoke the qualification status of an
independent verifier, such that it can no longer verify eligibility
applications, EM&V plans or M&V reports for at least the duration of
the period it does not meet the requirements of your State plan.

Sec.  60.5810  What applicable requirements are there for an ERC
tracking system?

    (a) Your plan must include provisions for an ERC tracking system,
if applicable, that meets the following requirements:
    (1) It electronically records the issuance of ERCs, transfers of
ERCs among accounts, surrender of ERCs by affected EGUs as part of a
compliance demonstration, and retirement or cancellation of ERCs; and
    (2) It documents and provides electronic, internet-based public
access to all information that supports the eligibility of eligible
resources and issuance of ERCs and functionality to generate reports
based on such information, which must include, for each ERC, an
eligibility application, EM&V plan, M&V reports, and independent
verifier verification reports.
    (b) If approved in a State plan, an ERC tracking system may provide
for transfers of ERCs to or from another ERC tracking system approved
in a State plan, or provide for transfers of ERCs to or from an EPA-
administered ERC tracking system used to administer a Federal plan.

Mass Allocation Requirements

Sec.  60.5815  What are the requirements for State allocation of
allowances in a mass-based program?

    (a) For a mass-based trading program, a State plan must include
requirements for CO2 allowance allocations according to
paragraphs (b) through (f) of this section.
    (b) Provisions for allocation of allowances for each compliance
period prior to the beginning of the compliance period.
    (c) Provisions for allocation of set-aside allowance, if
applicable, must be established to ensure that the eligible resources
must meet the same requirements for the ERC eligible resource
requirements of Sec.  60.5800, and the State must include eligibility
application and verification provisions equivalent to those for ERCs in
Sec.  60.5805 and EM&V plan and M&V report provisions that meet the
requirements of Sec.  60.5830 and Sec.  60.5835.
    (d) Provisions for adjusting allocations if the affected EGUs or
eligible resources are incorrectly allocated CO2 allowances.
    (e) Provisions allowing for or restricting banking of allowances
between compliance periods for affected EGUs.

    (f) Provisions not allowing any borrowing of allowances from future
compliance periods by affected EGUs.

Sec.  60.5820  What are my allowance tracking requirements?

    (a) Your plan must include provisions for an allowance tracking
system, if applicable, that meets the following requirements:
    (1) It electronically records the issuance of allowances, transfers
of allowances among accounts, surrender of allowances by affected EGUs
as part of a compliance demonstration, and retirement of allowances;
and
    (2) It documents and provides electronic, internet-based public
access to all information that supports the eligibility of eligible
resources and issuance of set aside allowances, if applicable, and
functionality to generate reports based on such information, which must
include, for each set aside allowance, an eligibility application, EM&V
plan, M&V reports, and independent verifier verification reports.
    (b) If approved in a State plan, an allowance tracking system may
provide for transfers of allowances to or from another allowance
tracking system approved in a State plan, or provide for transfers of
allowances to or from an EPA-administered allowance tracking system
used to administer a Federal plan.

Sec.  60.5825  What is the process for affected EGUs to demonstrate
compliance in a mass-based program?

    (a) A plan must require an affected EGU's owners or operators to
demonstrate compliance with emission standards in a mass based program
by holding an amount of allowances not less than the tons of total
CO2 emissions for such compliance period from the affected
EGUs in the account for the affected EGU's emissions in the allowance
tracking system required under Sec.  60.5820 during the applicable
compliance period.
    (b) In a mass-based trading program a plan may allow multiple
affected EGUs co-located at the same facility to demonstrate that they
are meeting the applicable emission standards on a facility-wide basis
by the owner or operator holding enough allowances to cover the
CO2 emissions of all the affected EGUs at the facility.
    (1) If there are not enough allowances to cover the facility's
affected EGUs' CO2 emissions then there must be provisions
for determining the compliance status of each affected EGU located at
that facility.
    (2) [Reserved]

Evaluation Measurement and Verification Plans and Monitoring and
Verification Reports

Sec.  60.5830  What are the requirements for EM&V plans for eligible
resources?

    (a) If your plan requires your affected EGUs to meet their emission
standards in accordance with Sec.  60.5790, your plan must include
requirements that any EM&V plan that is submitted in accordance with
the requirements of Sec.  60.5805, in support of the issuance of an ERC
or set-aside allowance that can be used in accordance with Sec.
60.5790, must meet the EM&V criteria approved as part of your State
plan.
    (b) Your plan must require each EM&V plan to include identification
of the eligible resource.
    (c) Your plan must require that an EM&V plan must contain specific
criteria, as applicable to the specific eligible resource.
    (1) For RE resources, your plan must include requirements
discussing how the generation data will be physically measured on a
continuous basis using, for example, a revenue-quality meter.
    (2) For demand-side EE, your plan must require that each EM&V plan
quantify and verify electricity savings on a retrospective (ex-post)
basis using industry best-practice EM&V protocols and methods that
yield accurate and reliable measurements of electricity savings. Your
plan must also require each EM&V plan to include an assessment of the
independent factors that influence the electricity savings, the
expected life of the savings (in years), and a baseline that represents
what would have happened in the absence of the demand-side EE activity.
Additionally, your plan must require that each EM&V plan include a
demonstration of how the industry best-practices protocol and methods
were applied to the specific activity, project, measure, or program
covered in the EM&V plan, and include an explanation of why these
protocols or methods were selected. EM&V plans must require eligible
resources to demonstrate how all such best-practice approaches will be
applied for the purposes of quantifying and verifying MWh results.
Subsequent reporting of demand-side EE savings values must demonstrate
and explain how the EM&V plan was followed.

Sec.  60.5835  What are the requirements for M&V reports for eligible
resources?

    (a) If your plan requires your affected EGUs to meet their emission
standards in accordance with Sec.  60.5790, your plan must include
requirements that any M&V report that is submitted in accordance with
the requirements of Sec.  60.5805, in support of the issuance of an ERC
or set-aside allocation that can be used in accordance with Sec.
60.5790, must meet the requirements of this section.
    (b) Your plan must require that each M&V report include the
following:
    (1) For the first M&V report submitted, documentation that the
energy-generating resources, energy-saving measures, or practices were
installed or implemented consistent with the description in the
approved eligibility application required in Sec.  60.5805(a).
    (2) Each M&V report submitted must include the following:
    (i) Identification of the time period covered by the M&V report;
    (ii) A description of how relevant quantification methods,
protocols, guidelines, and guidance specified in the EM&V plan were
applied during the reporting period to generate the quantified MWh of
generation or MWh of energy savings;
    (iii) Documentation (including data) of the energy generation and/
or energy savings from any activity, project, measure, resource, or
program addressed in the EM&V plan, quantified and verified in MWh for
the period covered by the M&V report, in accordance with its EM&V plan,
and based on ex-post energy generation or savings; and
    (iv) Documentation of any change in the energy generation or
savings capability of the eligible resource from the description of the
resource in the approved eligibility application during the period
covered by the M&V report and the date on which the change occurred,
and/or demonstration that the eligible resource continued to meet the
requirements of Sec.  60.5800.

Applicability of Plans to Affected EGUs

Sec.  60.5840  Does this subpart directly affect EGU owners or
operators in my State?

    (a) This subpart does not directly affect EGU owners or operators
in your State. However, affected EGU owners or operators must comply
with the plan that a State or States develop to implement the emission
guidelines contained in this subpart.
    (b) If a State does not submit a final plan to implement and
enforce the emission guidelines contained in this subpart, or an
initial submittal for which an extension to submit a final plan can be
granted, by September 6, 2016, or the EPA disapproves a final plan, the
EPA will implement and enforce a Federal plan, as provided in Sec.
60.5720, applicable to each affected EGU within the State that
commenced

construction on or before January 8, 2014.

Sec.  60.5845  What affected EGUs must I address in my State plan?

    (a) The EGUs that must be addressed by your plan are any affected
steam generating unit, IGCC, or stationary combustion turbine that
commenced construction on or before January 8, 2014.
    (b) An affected EGU is a steam generating unit, IGCC, or stationary
combustion turbine that meets the relevant applicability conditions
specified in paragraph (b)(1) through (3) of this section, as
applicable, except as provided in Sec.  60.5850.
    (1) Serves a generator or generators connected to a utility power
distribution system with a nameplate capacity greater than 25 MW-net
(i.e., capable of selling greater than 25 MW of electricity);
    (2) Has a base load rating (i.e., design heat input capacity)
greater than 260 GJ/hr (250 MMBtu/hr) heat input of fossil fuel (either
alone or in combination with any other fuel); and
    (3) Stationary combustion turbines that meet the definition of
either a combined cycle or combined heat and power combustion turbine.

Sec.  60.5850  What EGUs are excluded from being affected EGUs?

    EGUs that are excluded from being affected EGUs are:
    (a) EGUs that are subject to subpart TTTT of this part as a result
of commencing construction after the subpart TTTT applicability date;
    (b) Steam generating units and IGCCs that are, and always have
been, subject to a federally enforceable permit limiting annual net-
electric sales to one-third or less of its potential electric output,
or 219,000 MWh or less;
    (c) Non-fossil units (i.e., units that are capable of combusting 50
percent or more non-fossil fuel) that have always historically limited
the use of fossil fuels to 10 percent or less of the annual capacity
factor or are subject to a federally enforceable permit limiting fossil
fuel use to 10 percent or less of the annual capacity factor;
    (d) Stationary combustion turbines not capable of combusting
natural gas (e.g., not connected to a natural gas pipeline);
    (e) EGUs that are combined heat and power units that have always
historically limited, or are subject to a federally enforceable permit
limiting, annual net-electric sales to a utility distribution system to
no more than the greater of either 219,000 MWh or the product of the
design efficiency and the potential electric output;
    (f) EGUs that serve a generator along with other steam generating
unit(s), IGCC(s), 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;
    (g) EGUs that are a municipal waste combustor unit that is subject
to subpart Eb of this part; and
    (h) EGUs that are a commercial or industrial solid waste
incineration unit that is subject to subpart CCCC of this part.

Sec.  60.5855  What are the CO2 emission performance rates
for affected EGUs?

    (a) You must require, in your plan, emission standards on affected
EGUs to meet the CO2 emission performance rates listed in
Table 1 of this subpart except as provided in paragraph (b) of this
section. In addition, you must set CO2 emission performance
rates for the interim steps, according to paragraph (a)(1) of this
section, except as provided in paragraph (b) of this section.
    (1) You must set CO2 emission performance rates for your
affected EGUs to meet during the interim step periods on average and as
applicable for the two subcategories of affected EGUs.
    (2) [Reserved]
    (b) You may elect to require your affected EGUs to meet emission
standards that differ from the CO2 emission performance
rates listed in Table 1 of this subpart, provided that you demonstrate
that the affected EGUs in your State will collectively meet their
CO2 emission performance rate by achieving statewide
emission goals that are equivalent and no less stringent than the
CO2 emission performance rates listed in Table 1, and
provided that your equivalent statewide CO2 emission goals
take one of the following forms:
    (1) Average statewide rate-based CO2 emission goals
listed in Table 2 of this subpart, except as provided in paragraphs (c)
and (d); or
    (2) Cumulative statewide mass-based CO2 emission goals
listed in Table 3 of this subpart, except as provided in paragraphs (c)
and (d) of this section.
    (c) If your plan meets CO2 emission goals listed in
paragraphs (b)(1) or (2) of this section you must develop your own
interim step goals and final reporting period goal for your affected
EGUs to meet either on average (in the case of rate-based goals) or
cumulatively (in the case of mass-based goals). Additionally the
following applies if you develop your own goals:
    (1) The interim period and interim steps CO2 emission
goals must be in the same form, either both rate (in units of pounds
per net MWh) or both mass (in tons); and
    (2) You must set interim step goals that will either on average or
cumulatively meet the State's interim period goal, as applicable to a
rate-based or mass-based CO2 emission goal.
    (d) Your plan's interim period and final period CO2
emission goals required to be met pursuant to paragraph (b)(1) or (2)
of this section, may be changed in the plan only according to
situations listed in paragraphs (d)(1) through (3) of this section. If
a situation requires a plan revision, you must follow the procedures in
Sec.  60.5785 to submit a plan revision.
    (1) If your plan implements CO2 emission goals, you may
submit a plan or plan revision, allowed in Sec.  60.5785, to make
corrections to them, subject to EPA's approval, as a result of changes
in the inventory of affected EGUs; and
    (2) If you elect to require your affected EGUs to meet emission
standards to meet mass-based CO2 emission goals in your
plan, you may elect to incorporate, as a matter of state law, the mass
emissions from EGUs that are subject to subpart TTTT of this part that
are considered new affected EGUs under subpart TTTT of this part.
    (e) If your plan relies upon State measures in addition to or in
lieu of emission standards, you must only use the mass-based goals
allowed for in paragraph (b)(2) of this section to demonstrate that
your affected EGUs are meeting the required emissions performance.
    (f) Nothing in this subpart precludes an affected EGU from
complying with its emission standard or you from meeting your
obligations under the State plan.

Sec.  60.5860  What applicable monitoring, recordkeeping, and reporting
requirements do I need to include in my plan for affected EGUs?

    (a) Your plan must include monitoring for affected EGUs that is no
less stringent than what is described in (a)(1) through (8) of this
section.
    (1) The owner or operator of an affected EGU (or group of affected
EGUs that share a monitored common stack) that is required to meet
rate-based or mass-based emission standards must prepare a monitoring
plan in accordance with the applicable provisions in Sec.  75.53(g) and
(h) of this chapter, unless such a plan is already in place under
another program that requires CO2 mass emissions to be
monitored and reported according to part 75 of this chapter.
    (2) For rate-based emission standards, each compliance period shall
include

only ``valid operating hours'' in the compliance period, i.e., full or
partial unit (or stack) operating hours for which:
    (i) ``Valid data'' (as defined in Sec.  60.5880) are obtained for
all of the parameters used to determine the hourly CO2 mass
emissions (lbs). For the purposes of this subpart, substitute data
recorded under part 75 of this chapter are not considered to be valid
data; and
    (ii) The corresponding hourly net energy output value is also valid
data (Note: For operating hours with no useful output, zero is
considered to be a valid value).
    (3) For rate-based emission standards, the owner or operator of an
affected EGU must measure and report the hourly CO2 mass
emissions (lbs) from each affected unit using the procedures in
paragraphs (a)(3)(i) through (vi) of this section, except as otherwise
provided in paragraph (a)(4) of this section.
    (i) The owner or operator of an affected EGU must install, certify,
operate, maintain, and calibrate a CO2 continuous emissions
monitoring system (CEMS) to directly measure and record CO2
concentrations in the affected EGU exhaust gases emitted to the
atmosphere and an exhaust gas flow rate monitoring system according to
Sec.  75.10(a)(3)(i) of this chapter. As an alternative to direct
measurement of CO2 concentration, provided that the affected
EGU does not use carbon separation (e.g., carbon capture and storage),
the owner or operator of an affected EGU 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. However, when an O2
monitor is used this way, it only quantifies the combustion
CO2; therefore, if the EGU is equipped with emission
controls that produce non-combustion CO2 (e.g., from sorbent
injection), this additional CO2 must be accounted for, in
accordance with section 3 of appendix G to part 75 of this chapter. If
CO2 concentration is measured on a dry basis, the owner or
operator of the affected EGU must also install, certify, operate,
maintain, and calibrate a continuous moisture monitoring system,
according to Sec.  75.11(b) of this chapter. Alternatively, the owner
or operator of an affected EGU 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.
    (ii) For each ``valid operating hour'' (as defined in paragraph
(a)(2) of this section), calculate the hourly CO2 mass
emission rate (tons/hr), 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).
    (iii) 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. Multiply the
result by 2,000 lbs/ton to convert it to lbs.
    (iv) The hourly CO2 tons/hr 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), if required by a
plan. The owner or operator must use these data, or equivalent data, to
calculate the hourly CO2 mass emissions.
    (v) Sum all of the hourly CO2 mass emissions values from
paragraph (a)(3)(ii) of this section over the entire compliance period.
    (vi) For each continuous monitoring system used to determine the
CO2 mass emissions from an affected EGU, the monitoring
system 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.
    (4) The owner or operator of an affected EGU that exclusively
combusts liquid fuel and/or gaseous fuel may, as an alternative to
complying with paragraph (a)(3) of this section, determine the hourly
CO2 mass emissions according to paragraphs (a)(4)(i) through
(a)(4)(vi) of this section.
    (i) Implement the applicable procedures in appendix D to part 75 of
this chapter to determine hourly EGU heat input rates (MMBtu/hr), based
on hourly measurements of fuel flow rate and periodic determinations of
the gross calorific value (GCV) of each fuel combusted. The fuel flow
meter(s) used to measure the hourly fuel flow rates must meet the
applicable certification and quality-assurance requirements in sections
2.1.5 and 2.1.6 of appendix D to part 75 (except for qualifying
commercial billing meters). The fuel GCV must be determined in
accordance with section 2.2 or 2.3 of appendix D, as applicable.
    (ii) 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/hr).
    (iii) For each ``valid operating hour'' (as defined in paragraph
(a)(2) of this section), multiply the hourly tons/hr CO2
mass emission rate from paragraph (a)(4)(ii) 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 2,000 lbs/ton to convert it to lbs.
    (iv) The hourly CO2 tons/hr 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), if required by a
plan. You must use these data, or equivalent data, to calculate the
hourly CO2 mass emissions.
    (v) Sum all of the hourly CO2 mass emissions values (lb)
from paragraph (a)(4)(iii) of this section over the entire compliance
period.
    (vi) The owner or operator of an affected EGU 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 may use
these Fc values in the emissions calculations instead of
using the default Fc values in the Equation G-4
nomenclature.
    (5) For both rate-based and mass-based standards, the owner or
operator of an affected EGU (or group of affected units that share a
monitored common stack) must install, calibrate, maintain, and operate
a sufficient number of watt meters to continuously measure and record
on an hourly basis net electric output. Measurements must be performed
using 0.2 accuracy class electricity metering instrumentation and
calibration procedures as specified under ANSI Standards No. C12.20.
Further, the owner or operator of an affected EGU that is a combined
heat and power facility must install, calibrate, maintain and operate
equipment to continuously measure and record on an hourly basis useful
thermal output and, if applicable, mechanical output, which are used
with net electric output to determine net energy output. The owner or
operator must use the following procedures to calculate net energy
output, as appropriate for the type of affected EGU(s).
    (i) Determine Pnet the hourly net energy output in MWh.
For rate-based standards, perform this calculation only for valid
operating hours (as defined in paragraph (a)(2) of this section). For
mass-based standards, perform this calculation for all unit (or stack)
operating hours, i.e., full or partial hours in which any fuel is
combusted.
    (ii) If there is no net electrical output, but there is mechanical
or useful thermal output, either for a particular valid operating hour
(for rate-based

applications), or for a particular operating hour (for mass-based
applications), the owner or operator of the affected EGU must still
determine the net energy output for that hour.
    (iii) For rate-based applications, if there is no (i.e., zero)
gross electrical, mechanical, or useful thermal output for a particular
valid operating hour, that hour must be used 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.
    (iv) Calculate Pnet for your affected EGU (or group of
affected EGUs that share a monitored common stack) using the following
equation. All terms in the equation must be expressed in units of MWh.
To convert each hourly net energy output value reported under part 75
of this chapter to MWh, multiply by the corresponding EGU or stack
operating time.
[GRAPHIC] [TIFF OMITTED] TR23OC15.006

Where:
Pnet = Net energy output of your affected EGU for each
valid operating hour (as defined in 60.5860(a)(2)) 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)A = Electric energy used for any auxiliary loads in
MWh.
(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)(v) 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 net energy output consist of useful thermal output on a 12-
operating month rolling average basis, or 1.0 for all other affected
EGUs.

    (v) 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] TR23OC15.007

Where:
Qm = Measured steam flow in kilograms (kg) (or pounds
(lbs)) 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.

    (vi) For rate-based standards, sum all of the values of
Pnet for the valid operating hours (as defined in paragraph
(a)(2) of this section), over the entire compliance period. Then,
divide the total CO2 mass emissions for the valid operating
hours from paragraph (a)(3)(v) or (a)(4)(v) of this section, as
applicable, by the sum of the Pnet values for the valid
operating hours plus any ERC replacement generation (as shown in Sec.
60.5790(c)), to determine the CO2 emissions rate (lb/net
MWh) for the compliance period.
    (vii) For mass-based standards, sum all of the values of
Pnet for all operating hours, over the entire compliance
period.
    (6) In accordance with Sec.  60.13(g), if two or more affected EGUs
implementing the continuous emissions monitoring provisions in
paragraph (a)(2) of this section share a common exhaust gas stack and
are subject to the same emissions standard, the owner or operator may
monitor the hourly CO2 mass emissions at the common stack in
lieu of monitoring each EGU separately. If an owner or operator of an
affected EGU chooses this option, the hourly net electric output for
the common stack must be the sum of the hourly net electric output of
the individual affected EGUs and the operating time must be expressed
as ``stack operating hours'' (as defined in Sec.  72.2 of this
chapter).
    (7) In accordance with Sec.  60.13(g), if the exhaust gases from an
affected EGU implementing the continuous emissions monitoring
provisions in paragraph (a)(2) 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), the hourly CO2 mass emissions and the ``stack
operating time'' (as defined in Sec.  72.2 of this chapter) at each
stack or duct must be monitored separately. In this case, the owner or
operator of an affected EGU must determine compliance with an
applicable emissions standard by summing the CO2 mass
emissions measured at the individual stacks or ducts and dividing by
the net energy output for the affected EGU.
    (8) Consistent with Sec.  60.5775 or Sec.  60.5780, if two or more
affected EGUs serve a common electric generator, you must apportion the
combined hourly 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 net electrical load to the individual EGUs according to
the fraction of the total heat input contributed by each EGU.
    (b) For mass-based standards, the owner or operator of an affected
EGU must determine the CO2 mass emissions (tons) for the
compliance period as follows:
    (1) For each operating hour, calculate the hourly CO2
mass (tons) according to paragraph (a)(3) or (4) of this section,
except that a complete data record is required, i.e., CO2
mass emissions must be reported for each operating hour. Therefore,
substitute data values recorded under part 75 of this chapter for
CO2 concentration, stack gas flow rate, stack gas moisture
content, fuel flow rate and/or GCV shall be used in the calculations;
and
    (2) Sum all of the hourly CO2 mass emissions values over
the entire compliance period.
    (3) The owner or operator of an affected EGU must install,
calibrate, maintain, and operate a sufficient number of watt meters to
continuously

measure and record on an hourly basis net electric output. Measurements
must be performed using 0.2 accuracy class electricity metering
instrumentation and calibration procedures as specified under ANSI
Standards No. C12.20. Further, the owner or operator of an affected EGU
that is a combined heat and power facility must install, calibrate,
maintain and operate equipment to continuously measure and record on an
hourly basis useful thermal output and, if applicable, mechanical
output, which are used with net electric output to determine net energy
output (Pnet). The owner or operator must calculate net
energy output according to paragraphs (a)(5)(i)(A) and (B) of this
section.
    (c) Your plan must require the owner or operator of each affected
EGU covered by your plan to maintain the records, as described in
paragraphs (b)(1) and (2) of this section, for at least 5 years
following the date of each compliance period, occurrence, measurement,
maintenance, corrective action, report, or record.
    (1) The owner or operator of an affected EGU must maintain each
record on site for at least 2 years after the date of each compliance
period, occurrence, measurement, maintenance, corrective action,
report, or record, whichever is latest, according to Sec.  60.7. The
owner or operator of an affected EGU may maintain the records off site
and electronically for the remaining year(s).
    (2) The owner or operator of an affected EGU must keep all of the
following records, in a form suitable and readily available for
expeditious review:
    (i) All documents, data files, and calculations and methods used to
demonstrate compliance with an affected EGU's emission standard under
Sec.  60.5775.
    (ii) Copies of all reports submitted to the State under paragraph
(c) of this section.
    (iii) Data that are required to be recorded by 40 CFR part 75
subpart F.
    (iv) Data with respect to any ERCs generated by the affected EGU or
used by the affected EGU in its compliance demonstration including the
information in paragraphs (c)(2)(iv)(A) and (B) of this section.
    (A) All documents related to any ERCs used in a compliance
demonstration, including each eligibility application, EM&V plan, M&V
report, and independent verifier verification report associated with
the issuance of each specific ERC.
    (B) All records and reports relating to the surrender and
retirement of ERCs for compliance with this regulation, including the
date each individual ERC with a unique serial identification number was
surrendered and/or retired.
    (d) Your plan must require the owner or operator of an affected EGU
covered by your plan to include in a report submitted to you at the end
of each compliance period the information in paragraphs (d)(1) through
(5) of this section.
    (1) Owners or operators of an affected EGU must include in the
report all hourly CO2 emissions, for each affected EGU (or
group of affected EGUs that share a monitored common stack).
    (2) For rate-based standards, each report must include:
    (i) The hourly CO2 mass emission rate values (tons/hr)
and unit (or stack) operating times, (as monitored and reported
according to part 75 of this chapter), for each valid operating hour in
the compliance period;
    (ii) The net electric output and the net energy output
(Pnet) values for each valid operating hour in the
compliance period;
    (iii) The calculated CO2 mass emissions (lb) for each
valid operating hour in the compliance period;
    (iv) The sum of the hourly net energy output values and the sum of
the hourly CO2 mass emissions values, for all of the valid
operating hours in the compliance period;
    (v) ERC replacement generation (if any), properly justified (see
paragraph (c)(5) of this section); and
    (vi) The calculated CO2 mass emission rate for the
compliance period (lbs/net MWh).
    (3) For mass-based standards, each report must include:
    (i) The hourly CO2 mass emission rate value (tons/hr)
and unit (or stack) operating time, as monitored and reported according
to part 75 of this chapter, for each unit or stack operating hour in
the compliance period;
    (ii) The calculated CO2 mass emissions (tons) for each
unit or stack operating hour in the compliance period;
    (iii) The sum of the CO2 mass emissions (tons) for all
of the unit or stack operating hours in the compliance period;
    (iv) The net electric output and the net energy output
(Pnet) values for each unit or stack operating hour in the
compliance period; and
    (v) The sum of the hourly net energy output values for all of the
unit or stack operating hours in the compliance period.
    (vi) Notwithstanding the requirements in paragraphs (c)(3)(i)
through (c)(3)(iii) of this section, if the compliance period is a
discrete number of calendar years (e.g., one year, three years), in
lieu of reporting the information specified in those paragraphs, the
owner or operator may report:
    (A) The cumulative annual CO2 mass emissions (tons) for
each year of the compliance period, derived from the electronic
emissions report for the fourth calendar quarter of that year,
submitted to EPA under Sec.  75.64(a) of this chapter; and
    (B) The sum of the cumulative annual CO2 mass emissions
values from paragraph (c)(3)(v)(A) of this section, if the compliance
period includes multiple years.
    (4) For each affected EGU's compliance period, the report must also
include the applicable emission standard and demonstration that it met
the emission standard. An owner or operator must also include in the
report the affected EGU's calculated emission performance as a
CO2 emission rate or cumulative mass in units of the
emission standard required in Sec. Sec.  60.5790(b) through (c) and
60.5855, as applicable.
    (5) If the owner or operator of an affected EGU is complying with
an emission standard by using ERCs, they must include in the report a
list of all unique ERC serial numbers that were retired in the
compliance period, and, for each ERC, the date an ERC was surrendered
and retired and eligible resource identification information sufficient
to demonstrate that it meets the requirements of Sec.  60.5800 and
qualifies to be issued ERCs (including location, type of qualifying
generation or savings, date commenced generating or saving, and date of
generation or savings for which the ERC was issued).
    (6) If the owner or operator of an affected EGU is complying with
an emission standard by using allowances, they must include in the
report a list of all unique allowance serial numbers that were retired
in the compliance period, and, for each allowance, the date an
allowance was surrendered and retired and if the allowance was a set-
aside allowance the eligible resource identification information
sufficient to demonstrate that it meets the requirements of Sec.
60.5815(c) and qualifies to be issued set-aside allowances (including
location, type of qualifying generation or savings, date commenced
generating or saving, and date of generation or savings for which the
allowance was issued).
    (e) The owner or operator of an affected EGU must follow any
additional requirements for monitoring, recordkeeping and reporting in
a plan that are required under Sec.  60.5745(a)(4), if applicable.

    (f) If an affected EGU captures CO2 to meet the
applicable emission limit, the owner or operator must report in
accordance with the requirements of 40 CFR part 98 subpart PP and
either:
    (1) Report in accordance with the requirements of 40 CFR part 98
subpart RR, if injection occurs on-site;
    (2) Transfer the captured CO2 to an EGU or facility that
reports in accordance with the requirements of 40 CFR part 98 subpart
RR, if injection occurs off-site; or
    (3) Transfer the captured CO2 to a facility that has
received an innovative technology waiver from EPA pursuant to paragraph
(g) of this section.
    (g) Any person may request the Administrator to issue a waiver of
the requirement that captured CO2 from an affected EGU be
transferred to a facility reporting under 40 CFR part 98 subpart RR. To
receive a waiver, the applicant must demonstrate to the Administrator
that its technology will store captured CO2 as effectively
as geologic sequestration, and that the proposed technology will not
cause or contribute to an unreasonable risk to public health, welfare,
or safety. In making this determination, the Administrator shall
consider (among other factors) operating history of the technology,
whether the technology will increase emissions or other releases of any
pollutant other than CO2, and permanence of the
CO2 storage. The Administrator may test the system itself,
or require the applicant to perform any tests considered by the
Administrator to be necessary to show the technology's effectiveness,
safety, and ability to store captured CO2 without release.
The Administrator may grant conditional approval of a technology, the
approval conditioned on monitoring and reporting of operations. The
Administrator may also withdraw approval of the waiver on evidence of
releases of CO2 or other pollutants. The Administrator will
provide notice to the public of any application under this provision,
and provide public notice of any proposed action on a petition before
the Administrator takes final action.

Recordkeeping and Reporting Requirements

Sec.  60.5865  What are my recordkeeping requirements?

    (a) You must keep records of all information relied upon in support
of any demonstration of plan components, plan requirements, supporting
documentation, State measures, and the status of meeting the plan
requirements defined in the plan for each interim step and the interim