cannot be addressed within the range of actions or mechanisms
encompassed in an approved state plan, the state can submit a plan
revision to the EPA to amend its plan. In such a circumstance, the
state plan may need to be adjusted to enable affected EGUs to continue
to meet final rule requirements without causing an otherwise
unmanageable reliability threat. In all cases the plan revision must
still ensure the affected EGUs meet the emission performance level set
out in the 111(d) final rule. Whether or not these circumstances occur
will depend in part upon how each state designs its state plan. States
that design plans with a high level of flexibility, such as market-
based plans or multi-state plans, are less likely to face a potential
conflict between state plan requirements and the maintenance of
reliability. States that participate in multi-state programs will be
better able to weather unexpected reliability risks.
    Events not anticipated at the time of the final plan submittal--
such as the retirement of a large low- or zero-emitting unit--may
trigger the request for state plan revisions. It may also be the case
that affected EGU-specific emission standards in a state plan are
proving to be too inflexible to allow the plan to accommodate market or
other changes in the power sector. In such instances, there should be a
lead time between the announced retirement of the unit and the need to
amend the state plan. Therefore, the state should be able to utilize
the revisions process that the EPA provides.
    The EPA will review a plan revision per the implementing regulation
requirements of 40 CFR part 60.28. If the state's request for a state
plan revision must be addressed in an expedited manner to assure a
reliable supply of electricity, the state must document the risks to
reliability that would be addressed by the plan revision by providing
the EPA with a separate analysis of the reliability risk from the ISO/
RTO or other planning authority. This analysis should be accompanied by
a statement from the ISO/RTO or other planning/reliability authority
that there are no practicable alternative resolutions to the
reliability risk. In this case, the EPA will conduct an expedited
review of the state plan revision.\869\
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    \869\ The EPA will still undertake notice and comment rulemaking
per the requirements of the Administrative Procedures Act when
acting on such state plan revision, but intends to prioritize review
of plan revisions needed to address reliability concerns.
---------------------------------------------------------------------------

    e. Reliability safety valve.
    In this section we describe a reliability safety valve, available
to states with affected EGUs providing reliability-critical generation
in emergency circumstances. Specifically and as discussed below the
reliability safety valve provides i) a 90-day period during which the
affected EGU will not be required to meet the emission standard
established for it under the state plan but rather will meet an
alternative standard, and ii) a period beginning after the initial 90
days during which the reliability-critical affected EGU may be required
to continue to operate under an alternative standard rather than under
the original state plan emission standard, as needed in light of the
emergency circumstances, and the state must during this period revise
its plan to accommodate changes

needed to respond to ongoing reliability requirements. Any emissions in
excess of the applicable state goals or performance rates occurring
after the initial 90-day period must be accounted for and offset.
    Many commenters expressed concerns that a serious, unforeseen event
could occur during the final rule implementation period that would
require immediate reliability-critical responses by system operators
and affected EGUs that would result in unplanned or unauthorized
emissions increases. After reviewing the comments, we believe that it
is highly unlikely that there would be a conflict between activities
undertaken under an approved state plan and the maintenance of electric
reliability, except in the case of a state plan that puts relatively
inflexible requirements on specific EGUs. While some have pointed out
that severe weather or other short-term events could potentially
conflict with state plans, we note that most of those events are of
short duration and would not require major--if any--adjustments to
emission standards for affected EGUs or to state plans. For example,
during an event like the extreme cold experienced in periods of the
winter of 2013-2014, affected EGUs may need to run at a higher level
for a short period of time to accommodate increased demand and/or
short-term unavailability of other generators. However, because
compliance by affected EGUs will be demonstrated over 2-3 years, such a
short-term event would not cause affected EGUs to be out of compliance
with their applicable emission standards. States can also ensure that
this is true by developing plans that allow adequate compliance
flexibility to accommodate such short-term events. We note that we have
included in this final rule a number of different features designed to
facilitate emissions trading between and among EGUs on an interstate
basis--and have done so, in no small part, in response to comments from
states and stakeholders seeking to put in place or operate under state-
level and interstate emissions trading regimes. Affected EGUs operating
in those circumstances and operating, in addition, subject to state
plans that incorporate flexible glide paths and trading would be able
to accommodate an unanticipated reliability event.
    We recognize, however, that affected EGUs operating in a state with
a relatively inflexible state plan could face unanticipated system
emergencies that could cause a severe stress on the electricity system
for a length of time such that the requirements in that state's plan
may not be achievable by certain affected EGUs without posing an
otherwise unmanageable risk to reliability. In particular, there could
be extremely serious events, outside the control of affected EGUs, that
would require an affected EGU or EGUs operating under an inflexible
state plan to temporarily operate under modified emission standards to
respond to this kind of reliability concern. Examples of such an event
could include, a catastrophic event that damages critical or vulnerable
equipment necessary for reliable grid operation; a major storm that
floods and causes severe damage to a large NGCC plant so that it must
shut down; or a nuclear unit that must cease generating unexpectedly
and therefore other affected EGUs need to run so as to exceed their
requirements under the approved state plan. This is not an all-
inclusive list, but the examples illustrate several key attributes of
the kinds of circumstances in which the reliability safety valve would
apply. First, the event creating the reliability emergency would be
unforeseeable, brought about by an extraordinary, unanticipated,
potentially catastrophic event. Second, the relief provided would be
for EGUs compelled to operate for purposes of providing generation
without which the affected electricity grid would face some form of
failure. Third, the EGU or EGUs in question would be subject to the
requirements of a state plan that imposes emissions constraints such
that the EGU or EGUs' operation in response to the reliability
emergency resulted in levels of emissions that violated those
constraints. We do not anticipate that EGUs operating under a plan that
permitted emissions trading would meet these criteria.
    The final guidelines provide a reliability safety valve for these
types of situations. If an emergency situation arises, the state must
submit an initial notification to the appropriate EPA regional office
within 48 hours that it is necessary to modify the emission standards
for a reliability-critical affected EGU or EGUs for up to an initial 90
days. The notification must include a full description, to the extent
it is known at the time, of the emergency situation that is being
addressed. It must also identify with particularity the affected EGU or
EGUs that are required to run to assure reliability. It must also
specify the modified emission standards at which the affected EGU or
EGUs will operate. The EPA will consider this notification to be an
approved short-term modification to the state plan, allowing the EGU to
operate at an emission standard that is an alternative to the emission
standard originally specified in the relevant state plan, subject to
confirmation by the further documentation described below.\870\
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    \870\ The EPA reserves the right to review such notification,
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 original approved state plan
emission standards.
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    Within 7 days of submitting the initial notification, the state
must submit a second notification providing documentation to the
appropriate EPA regional office that includes a full description of the
reliability concern and why an unforeseen, emergency situation that
threatens reliability requires the affected EGU or EGUs to operate
under modified emission standards (including discussion of why the
flexibilities provided under the state's plan are insufficient to
address the concern). The state must also describe in its documentation
how it is coordinating or will coordinate with relevant reliability
coordinators and planning authorities to alleviate the problem in an
expedited manner, and indicate the maximum time that the state
anticipates the affected EGU or EGUs will need to operate in a manner
inconsistent with its or their obligations under the state's approved
plan, and the modified emission standards or levels at which the
affected EGU or EGUs will be operating at during this period if it has
changed from the initial notification. The documentation must also
include a written concurrence from the relevant reliability coordinator
and/or planning authority confirming the existence of the imminent
reliability threat and supporting the temporary modification request or
an explanation of why this kind of concurrence cannot be provided.
Additionally, if the relevant planning authority has conducted a
system-wide or other analysis of the reliability concern, the state
must include that information in its request. If the state fails to
submit this documentation on a timely basis, the EPA will notify the
state, which must then notify the affected EGU(s) that they must
operate or resume operations under the original approved state plan
emission standards.
    It is important to note that the affected EGUs must continue to
monitor and report their emissions and generation pursuant to
requirements in this final rule and under the state plan during any
short-term modification. For the duration of the up to 90-day short-
term modification, the emissions of the affected EGU or EGUs that
exceed their obligations under the approved state

plan will not be counted against the state's overall goal or emission
performance rate for affected EGUs. Such a modification will not alter
or abrogate any other obligations under the approved state plan.
    During this short-term modification period, the EPA expects that
the source, the state and the relevant reliability coordinator and/or
planning authority will assess whether the reliability issue can be
addressed in a way that would allow the EGU or EGUs to resume operating
under the original approved state plan within the 90-day period or
whether revisions to the state plan need to be made to address the
unexpected circumstances for the longer term (the unexpected
unavailability of a nuclear unit, for example).
    The EPA recognizes that an emergency may persist past 90 days. At
least 7 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 that the EGU or
EGUs can resume meeting the original emission standards established in
the state plan prior to the short-term modification.
    If there still is a serious, ongoing reliability issue at the end
of the short-term modification period that necessitates the EGU or EGUs
to emit beyond the amount allowed under the state plan, the state must
provide to the EPA a notification that it will be submitting a state
plan revision and submit the plan revision as expeditiously as
possible, specifying in the notice the date by which the revision will
be submitted. The state must document the ongoing emergency with a
second written concurrence from the relevant reliability coordinator
and/or planning authority confirming the continuing urgent need for the
EGU or EGUs to operate beyond the requirements of the state plan and
that there is no other reasonable way of addressing the ongoing
reliability emergency but for the EGU or EGUs to operate under an
alternative emission standard than originally approved under the state
plan. In this event, the EPA will work with the state on a case-by-case
basis to identify an emission standard for the affected EGU or EGUs for
the period before a new state plan revision is approved. After the
initial 90-day period, any excess emissions beyond what is authorized
in the original approved state plan will count against the state's
overall goal or emission performance rate for affected EGUs.
    The EPA intends for this reliability safety valve to be used only
in exceptional situations. In addition, this reliability safety valve
applies only to this final rule and has no effect on CAA requirements
to which the state or the affected EGUs are otherwise subject. As
discussed earlier, we are providing states with the flexibility to
design programs that allow affected EGUs to meet compliance obligations
while responding to reliability needs, even in emergency situations.
This flexibility means that a conflict between the requirements of the
state plan and maintenance of reliability should be extremely rare. We
recognize, however, that a state with an inflexible plan could be faced
with more than one emergency and in this case the reliability safety
valve may be used more than once. If the state finds that a second
reliability emergency arises that conflicts with the state plan, the
state must submit a revision to its state plan so that the state plan
is flexible enough to assure that such conflicts do not recur and that
the state is providing for the implementation of the standards of
performance for affected EGUs as required by the CAA.
    f. Coordination among federal partners.
    The EPA, DOE, and FERC have agreed to coordinate efforts to help
ensure continued reliable electricity generation and transmission
during the implementation of the final rule. The three agencies have
developed a coordination strategy that reflects their joint
understanding of how they will work together to monitor final rule
implementation, share information, and resolve any difficulties that
may be encountered. This strategy is based on the successful working
relationship that the three agencies established in their joint effort
to work together to monitor reliability during MATS implementation.
    g. Analyses of the reliability impacts of the proposal.
    The EPA appreciates that a large number of entities from many
different industry perspectives have published reports and analysis
with respect to electric reliability and the 111(d) proposed rule. We
take concerns about reliability very seriously, and we appreciate the
attention given to this issue in the comments and shared with us in
public forums. It is important to note that these studies were
conducted prior to promulgation of this final rule, and thus were only
able to consider electric reliability with respect to the proposal. The
EPA has made changes and improvements to the proposal in response to
comments and new information, and some of the changes are relevant to
the final rule's potential effect on electric reliability. One notable
change pertains to the start of the interim period, which is now 2022
rather than 2020. Another important change to the final rule is a more
gradual phase-in of the BSER for affected EGUs over the interim period
(from 2022 through 2029). The final rule also provides considerable
flexibility and multiple pathways to states, including allowing their
EGUs to use multi-state trading and other approaches, which would allow
essential units to continue to meet their compliance obligation while
generating even at unplanned but reliability-critical levels. In
addition, we have included in the final rule a reliability safety valve
provision that can be utilized in certain emergency situations. These
changes, in addition to already existing industry mechanisms and
planning requirements, will help to ensure that industry will be able
to maintain electric reliability. The EPA is confident that the final
rule will cut harmful electric power plant pollution while maintaining
a reliable electric grid because the final rule provides industry with
the time and flexibility needed to continue its current and ongoing
planning and investing to modernize and upgrade the electric power
system.
    In June of 2015, M.J. Bradley & Associates issued a report that
enumerated a set of useful guiding principles for studying and
evaluating the reliability impacts of the final rule.\871\ The report
enumerated six principles: (1) A study should be transparent about the
assumptions and data used; (2) a study should accurately reflect the
existing status of the grid in its modeling assumptions; (3) a study
should clearly identify the base case and not confuse what will happen
as a result of the final rule with what would have happened anyway; (4)
where possible, a study should contain sensitivities and probabilities
as they are looking into the future which is necessarily uncertain; (5)
a study should reflect the flexibility provided to states to allow them
to design compliance approaches to maximize reliability; and (6) a
study should provide realistic and reliability-focused results. These
principles are helpful to keep in mind when reviewing recent studies.
---------------------------------------------------------------------------

    \871\ M.J. Bradley & Associates, Guiding Principles for
Reliability Assessments Under EPA's Clean Power Plan (June 3, 2015),
available at http://www.mjbradley.com/node/295.
---------------------------------------------------------------------------

    NERC published its analyses of the proposed rule in November 2014
and again in April 2015.\872\ The EPA

appreciates NERC's attention to, and interest in, the proposed rule.
However, we note that like some other studies, NERC assumes
considerably less flexibility than actually is provided to states and
EGUs in this final rule. The final rule provides states with
considerable time and latitude in designing plans that are tailored to
the system in which their EGUs operate, which should be reflected in
any reliability analysis. Also, the NERC study does not fully reflect
the current electric grid. For example, the amount of RE generation
that NERC assumes for 2020 is similar to levels of generation that we
see today whereas projections for 2020 are considerably higher.\873\
Further, NERC conflates retirements that may happen as a result of the
rule with those that are already planned. The Brattle Group has also
reviewed NERC's November 2014 initial analysis of the proposed rule,
noting that it is important to distinguish between concerns about the
building blocks and reliability concerns about compliance with state
plans.\874\ The Brattle Group concluded that there are real world
solutions to NERC's concerns. These include making use of the many
flexible options available to states under the rule to mitigate
reliability risks.
---------------------------------------------------------------------------

    \872\ North American Electric Reliability Corporation, Potential
Reliability Impacts of EPA's Proposed Clean Power Plan (Nov. 5,
2014), available at http://www.nerc.com/news/Pages/Reliability-Review-of-Proposed-Clean-Power-Plan-Identifies-Areas-for-Further-Study,-Makes-Recommendations-for-Stakeholders.aspx; North American
Electric Reliability Corporation, Potential Reliability Impact of
EPA's Proposed Clean Power Plan: Phase 1 (Apr. 21, 2015), available
at http://www.nerc.com/news/Pages/Assessment-Uses-Scenario-Analysis-to-Identify-Potential-Reliability-Risks-from-Proposed-Clean-Power-Plan.aspx.
    \873\ EIA, Annual Energy Outlook 2015, with Projections to 2040,
April 2015, available at http://www.eia.gov/forecasts/aeo/pdf/0382(2015).pdf.
    \874\ Brattle Group, EPA's Clean Power Plan and Reliability,
Assessing NERC's Initial Reliability Review (Feb. 2015), available
at http://info.aee.net/hs-fs/hub/211732/file-2486162659-pdf/PDF/EPAs-Clean-Power-Plan-Reliability-Brattle.pdf?t=1434398407867.
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    Multiple ISOs/RTOs also provided analyses of the proposed rule,
including MISO, PJM, ERCOT, and SPP.\875\ For example, MISO conducted
an analysis of coal units at risk for retirement, finding that 14 GW of
coal may be at risk.\876\ SPP performed a resource adequacy analysis
that assumes planned retirements plus the EPA's projected retirements,
but did not similarly account for the building of new generation
capacity.\877\ While we appreciate MISO's and SPP's concerns regarding
retirements and the potential that reserves will fall below reserve
requirement levels, it is important to consider the many ways in which
states can develop plans that account for their potential reliability
concerns. The final rule continues to give states significant
flexibility in how they comply with requirements, including both BSER
measures and measures that were not included in the determination of
the BSER as a means to comply. For example, demand-side EE measures can
greatly assist states and affected EGUs in meeting the standards and/or
state plan. Many studies assume that state plans will simply apply the
BSER and do not recognize the large number of compliance approaches and
opportunities that states and affected EGUs have available to them. The
Analysis Group recently analyzed reliability considerations in MISO as
the region considers how to comply with the final rule.\878\ The
Analysis Group found that despite the large amount of coal-fired
generating capacity that will likely be retired in MISO in the coming
years, the entities responsible for electric system reliability in MISO
are prepared to collaboratively address any reliability issues that
arise and that there is a ``strong tool kit for managing `Essential
Reliability Services' needed to assure high-quality electric service.''
\879\
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    \875\ See MISO, Analysis of EPA's Proposal to Reduce
CO2 Emissions from Existing Units (Nov. 12, 2014),
available at https://www.misoenergy.org/Library/Repository/Communication%20Material/EPA%20Regulations/AnalysisofEPAProposalReduceCO2Emissions.pdf; PJM, PJM
Interconnection Economic Analysis of the EPA Clean Power Plan
Proposal (Mar. 2, 2015), report listed at http://www.pjm.com/documents/reports.aspx; SPP, SPP's Reliability Impact Assessment of
the EPA's Proposed Clean Power Plan, (Oct. 8, 2014), available at
http://www.spp.org/publications/CPP%20Reliability%20Analysis%20Results%20Final%20Version.pdf; ERCOT,
ERCOT Analysis of the Clean Power Plan (Nov. 17, 2014), available
athttp://www.ercot.com/content/news/presentations/2014/ERCOTAnalysis-ImpactsCleanPowerPlan.pdf; and
    \876\ MISO, Analysis of EPA's Proposal to Reduce CO2
Emissions from Existing Units, at 14 (Nov. 12, 2014), available at
https://www.misoenergy.org/Library/Repository/Communication%20Material/EPA%20Regulations/AnalysisofEPAProposalReduceCO2Emissions.pdf.
    \877\ SPP, SPP's Reliability Impact Assessment of the EPA's
Proposed Clean Power Plan, (Oct. 8, 2014), available at http://www.spp.org/publications/CPP%20Reliability%20Analysis%20Results%20Final%20Version.pdf.
    \878\ Analysis Group, Electric System Reliability and EPA's
Clean Power Plan: The Case of MISO (June 8, 2015), available at
http://www.analysisgroup.com/uploadedfiles/content/insights/publishing/analysis_group_clean_power_plan_miso_reliability.pdf.
    \879\ Analysis Group, Electric System Reliability and EPA's
Clean Power Plan: The Case of MISO, at 2 (June 8, 2015), available
at http://www.analysisgroup.com/uploadedfiles/content/insights/publishing/analysis_group_clean_power_plan_miso_reliability.pdf.
---------------------------------------------------------------------------

    ERCOT also performed an analysis, modeling numerous scenarios.\880\
ERCOT stated that its modeling identified two potential reliability
problems--impacts of units retiring and increased levels of renewable
generation on the ERCOT grid.\881\ As noted above, the final rule gives
additional time for compliance, providing needed time to obtain new or
replacement generation necessary as some existing generators retire.
Moreover, affected EGUs needed for reliability should be able to employ
the flexibilities afforded to them as they seek lower and zero-emitting
generation. Finally, we note that ERCOT has a history of notable
success in integrating RE into its electric grid, giving ERCOT
significant expertise regarding challenges that may arise with the
addition of new RE in order to comply with the final rule. In fact, a
recent Brattle Group report used ERCOT as a case study for how to
effectively integrate a large number of RE into the electric grid.\882\
---------------------------------------------------------------------------

    \880\ ERCOT, ERCOT Analysis of the Clean Power Plan (Nov. 17,
2014), available at http://www.ercot.com/content/news/presentations/2014/ERCOTAnalysis-ImpactsCleanPowerPlan.pdf.
    \881\ ERCOT, ERCOT Analysis of the Clean Power Plan, at 9 (Nov.
17, 2014), available at http://www.ercot.com/content/news/presentations/2014/ERCOTAnalysis-ImpactsCleanPowerPlan.pdf.
    \882\ Brattle Group, Integrating Renewable Energy Into the
Electricity Grid: Case Studies Showing How System Operators are
Maintaining Reliability (June 2015), available at http://info.aee.net/integrating-renewable-energy-into-the-electricity-grid.
---------------------------------------------------------------------------

    PJM conducted its own analysis at the request of the Organization
of PJM States (OPSI).\883\ This analysis is consistent with many of the
M.J. Bradley guiding principles. PJM designed various scenarios to
capture the impact of the proposed rule under a series of assumptions.
Because the EPA had not yet issued the final rule, PJM cautioned
against using the report as a reliability analysis or predictor of the
future. PJM stated that, since 2007, PJM's capacity markets have helped
to attract 35,000 MWs of additional generation. Even though 26,000 MWs
will retire between 2009 and 2016, the PJM capacity market has procured
sufficient resources to maintain reliability.
---------------------------------------------------------------------------

    \883\ PJM, PJM Interconnection Economic Analysis of the EPA
Clean Power Plan Proposal (Mar. 2, 2015), report listed at http://www.pjm.com/documents/reports.aspx.
---------------------------------------------------------------------------

    WECC also produced a study which is part of a longer-term, phased
effort.\884\ The assumptions, methodology, and limitations were all
clearly presented, and there was extensive involvement by a range of
stakeholders. WECC stated that it is embarking on a phased-study
process that seeks to ``provide the industry with unbiased and

independent analysis of this issue.'' \885\ WECC concluded that the
effects of the proposal on resource adequacy may be minimal but that
resource adequacy cannot be fully assessed without realistic and/or
proposed compliance scenarios.\886\
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    \884\ WECC, EPA Clean Power Plan: Phase I--Preliminary Technical
Report (Sept. 19, 2014), available at https://www.wecc.biz/_layouts/15/WopiFrame.aspx?sourcedoc=/Reliability/140912_EPA-111(d)_PhaseI_Tech-Final.pdf&action=default&DefaultItemOpen=1.
    \885\ WECC, EPA Clean Power Plan: Phase I--Preliminary Technical
Report, at 1 (Sept. 19, 2014), available at https://www.wecc.biz/_layouts/15/WopiFrame.aspx?sourcedoc=/Reliability/140912_EPA-111(d)_PhaseI_Tech-Final.pdf&action=default&DefaultItemOpen=1.
    \886\ WECC, EPA Clean Power Plan: Phase I--Preliminary Technical
Report, at 30 (Sept. 19, 2014), available at https://www.wecc.biz/_layouts/15/WopiFrame.aspx?sourcedoc=/Reliability/140912_EPA-111(d)_PhaseI_Tech-Final.pdf&action=default&DefaultItemOpen=1.
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    Analysis Group analyzed the proposed rule, finding that it provides
states and affected EGUs with a wide range of options and operational
discretion that can prevent reliability issues while also reducing
carbon pollution and costs.\887\ Analysis Group noted that some of the
concerns raised by stakeholders about the proposed rule assume
``inflexible implementation, are based upon worst-case scenarios, and
assume that policy makers, regulators, and market participants will
stand on the sidelines until it is far too late to act'' to ensure
reliability.\888\ It stated that these assumptions are not consistent
with past actions.
---------------------------------------------------------------------------

    \887\ Analysis Group, Electric System Reliability and EPA's
Clean Power Plan Tools and Practices (Feb. 2015), available at
http://www.analysisgroup.com/uploadedfiles/content/insights/publishing/electric_system_reliability_and_epas_clean_power_plan_tools_and_practices.pdf.
    \888\ Analysis Group, Electric System Reliability and EPA's
Clean Power Plan Tools and Practices, at ES-3 (Feb. 2015), available
at http://www.analysisgroup.com/uploadedfiles/content/insights/publishing/electric_system_reliability_and_epas_clean_power_plan_tools_and_practices.pdf.
---------------------------------------------------------------------------

    We appreciate the time that multiple entities took to analyze and
consider the potential impacts of the proposed rule. As we issue the
final rule and states draft plans to implement the rule, we look
forward to further analysis by these and other groups. Such analysis
can provide states with needed resources to help them design state
plans that will augment the efforts of the industry to maintain
electric reliability.
3. Consideration of Effects on Employment and Economic Development
    States in designing their state plans should consider the effects
of their plans on employment and overall economic development to assure
that the opportunities for economic growth and jobs that the plans
offer are manifest. To the extent possible, states should try to assure
that any communities that can be expected to experience job losses can
also take advantage of the opportunities for job growth or otherwise
transition to healthy, sustainable economic growth. The EPA's
illustrative analysis indicates that there may be some additional job
losses in sectors related to coal extraction and generation that are
attributable to implementation of this rule. At the same time, the
EPA's illustrative analysis indicates that there may be new jobs in the
utility power sector associated with both improving the efficiency of
fossil fuel-fired power plants, construction and operation of new
natural gas-fired and RE production, and actions to increase demand-
side EE. Consideration of these effects in the context of the
particulars of the state plan can help states craft plans that, to the
extent possible, meet multiple environmental, economic, and workforce
development goals.
    The Partnerships for Opportunity and Workforce and Economic
Revitalization (POWER) Initiative is a new interagency effort led by
the Economic Development Administration in the Department of Commerce.
POWER was launched to respond to current trends in the power sector:
``The United States is undergoing a rapid energy transformation,
particularly in the power sector. This transformation is producing
cleaner air and healthier communities, and spurring new jobs and
industries. At the same time, it is impacting workers and communities
who have relied on the coal industry as a source of good jobs and
economic prosperity, particularly in Appalachia, where competition with
other coal basins provides additional pressure.'' \889\ The POWER
Initiative aligns, leverages, and targets economic and workforce
development assistance to communities and workers affected by changes
in the coal industry and the utility power sector. The POWER Initiative
is competitively awarding planning assistance and implementation grants
with funding from the Department of Commerce, Department of Labor,
Small Business Administration, and the Appalachian Regional Commission
to partnerships anchored in impacted communities. These grants will
help communities organize themselves, develop comprehensive strategic
plans that chart their economic future, and execute coordinated
economic and workforce development activities based on their strategic
plans.\890\
---------------------------------------------------------------------------

    \889\ http://www.eda.gov/power/.
    \890\ https://www.whitehouse.gov/the-press-office/2015/03/27/fact-sheet-partnerships-opportunity-and-workforce-and-economic-revitaliz.
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    In addition to POWER, however, the EPA encourages states to use
economic and labor market analysis to identify where they can deploy
strategies to: (1) Provide a range of employment and training
assistance to workers, and economic development assistance to
communities affected by the rapid changes underway in the power sector
and closely related industries, to diversify their economies, attract
new sources of investment, and create new jobs; and (2) mobilize
existing education and training resources, including those of community
and technical colleges and registered apprenticeship programs, to
ensure that both incumbent and new workers are trained for the skills
necessary to meet employer demand for new workers in the utility,
construction and related sectors, that such training includes career
pathways for members of low-income communities and other vulnerable
communities to attain employment in these sectors, and that such
training results in validated skill certifications for workers.
4. Workforce Considerations
    Some stakeholders commented that, to ensure that emission
reductions are realized, it is important that construction, operations
and other skilled work undertaken pursuant to state plans is performed
to specifications, and is effective, safe, and timely. A good way to
ensure a highly proficient workforce is to require that workers have
been certified by: (1) An apprenticeship program that is registered
with the U.S. DOL, Office of Apprenticeship or a state apprenticeship
program approved by the DOL; (2) a skill certification aligned with the
U.S. DOE Better Building Workforce Guidelines and validated by a third
party accrediting body recognized by DOE; or (3) other skill
certification validated by a third party accrediting body.
5. Tenth Amendment Legal Considerations
    Some commenters have raised concerns that the emission guidelines
and requirements for 111(d) state plans violate principles of
federalism embodied in the U.S. Constitution, particularly the Tenth
Amendment. These commenters claim that states will be
unconstitutionally ``coerced'' or ``commandeered'' into taking certain
actions in order to avoid the prospect of either a federal 111(d) plan
applying to sources in the state, or of losing federal funds.
    We disagree on both fronts. First, the prospect of a federal plan
applying to sources in a state does not ``coerce'' or

``commandeer'' that state into submitting its own satisfactory plan.
Far from violating principles of federalism, this rule provides states
with the initial opportunity to submit a satisfactory state plan, and
provides states flexibility in developing that plan. If a state
declines to take advantage of that opportunity, affected EGUs in that
state will instead be subject to a federal plan that satisfies
statutory requirements.\891\ This approach is consistent with ordinary
cooperative federalism regimes that federal courts have routinely
upheld against Tenth Amendment challenges.\892\
---------------------------------------------------------------------------

    \891\ Among other things, a federal plan will implement
standards of performance subject to specific statutory requirements.
See 42 U.S.C. 7411(a)(1). The APA and CAA would prohibit the
imposition of any federal plan that is ``arbitrary, capricious, an
abuse of discretion, or otherwise not in accordance with law.'' 5
U.S.C. 706(2)(a). Particularly given these independent constraints
on the EPA's authority with respect to any potential federal plan,
the prospect of any such plan would not commandeer states or coerce
them into submitting their own state plans.
    \892\ See, e.g., Hodel v. Va. Surface Mining & Reclamation
Ass'n, Inc., 452 U.S. 264, 283-93 (1981); Texas v. EPA, 726 F.3d
180, 196-97 (D.C. Cir. 2013) (noting that ``Supreme Court precedent
repeatedly affirm[s] the constitutionality of federal statutes that
allow States to administer federal programs but provide for direct
federal administration if a State chooses not to administer it'').
---------------------------------------------------------------------------

    Second, states that decline to take certain actions under this rule
will not face the prospect of sanctions, such as withdrawn federal
highway funds. CAA section 111 does not contain sanctions provisions,
and we are finalizing revisions to these emission guidelines making
explicit that the EPA will not withhold federal funds from a state on
account of that state's failure to submit or implement an approvable
111(d) state plan.
    Some commenters pointed to section 110(m) as a possible source of
the EPA's sanction authority.\893\ Section 110(m) grants the EPA
discretionary authority to withhold some federal highway funds under
certain conditions. However, section 110(m) requires the EPA to adopt
regulations to ``establish criteria for exercising'' this discretionary
authority, and the only EPA regulations implementing section 110(m)
apply to SIPs submitted under section 110.\894\
---------------------------------------------------------------------------

    \893\ Other commenters point to CAA section 179 as a possible
direct source of this sanctions authority. However, the mandatory
sanctions outlined in section 179 clearly apply only in the contexts
of nonattainment SIPs and responses to SIP Calls made under CAA
section 110(k)(5). See 42 U.S.C. 7509(a).
    \894\ 40 CFR 52.30 (defining ``plan or plan item'').
---------------------------------------------------------------------------

    The EPA never intended to even imply that we would contemplate
using this authority to encourage state participation in this rule
under section 111. To the contrary, we believe that imposition of a
federal plan rather than sanctions is the appropriate path in the
context of this program. Accordingly, regardless of whether the EPA
could theoretically apply discretionary sanctions against states in the
section 111(d) context, the final rule forbids the agency from
exercising any such authority. We have included in this rule a
provision that prohibits the agency from imposing sanctions in the
event that a state fails to submit or implement a satisfactory plan
under this rule. As states consider whether to take advantage of the
opportunity to develop state plans, they can be assured that the EPA
will not withdraw federal funding should they decline to participate.
6. Title VI
    States that are recipients of EPA financial assistance must comply
with all federal nondiscrimination statutes that together prohibit
discrimination on the bases of race, color, national origin (including
limited-English proficiency), disability, sex and age. These laws
include: Title VI of the Civil Rights Act of 1964; Section 504 of the
Rehabilitation Act of 1973; Section 13 of the Federal Water Pollution
Control Act Amendments of 1972; Title IX of the Education Act
Amendments of 1972; and the Age Discrimination Act of 1975. Compliance
with these nondiscrimination statutes is a recipient's separate and
distinct obligation from compliance with environmental regulations. In
other words, all recipients are required to ensure that all aspects of
their state plans do not violate any of the federal nondiscrimination
statutes, including Title VI.
    The EPA's Office of Civil Rights (OCR) is responsible for carrying
out compliance with these federal nondiscrimination statutes and does
so through a variety of means including: Complaint investigation;
agency-initiated compliance reviews; pre-grant award assurances and
audits; and technical assistance and outreach activities. Anyone who
believes that any of the federal nondiscrimination laws enforced by OCR
have been violated by a recipient of EPA financial assistance may file
an administrative complaint with the EPA's OCR.

H. Resources for States To Consider in Developing Plans

    As part of the stakeholder outreach and comment processes, the EPA
asked states what the agency could do to facilitate state plan
development and implementation. In addition, after the comment period
closed, the EPA continued to consult with state organizations including
the Association of Air Pollution Control Agencies (AAPCA),
Environmental Council of the States (ECOS), National Association of
Clean Air Agencies (NACAA), National Association of Regulatory Utility
Commissioners (NARUC), National Association of State Energy Officials
(NASEO) and the National Governors Association (NGA).
    Some states indicated that they wanted the EPA to create resources
to assist with state plan development, especially resources related to
accounting for RE and demand-side EE in state plans. They requested
clear methodologies for estimating emission reductions from RE and
demand-side EE policies and programs so that these could be included as
part of their compliance strategies. Stakeholders said that these tools
and metrics should build upon the EPA's ``Roadmap for Incorporating
Energy Efficiency/Renewable Energy Policies and Programs into State and
Tribal Implementation Plans,'' as well as the State Energy Efficiency
Action Network's ``Energy Efficiency Program Impact Evaluation Guide.''
In addition, stakeholders requested clear guidance on how to measure
the impacts of RE and demand-side EE programs using established EM&V
protocols.
    The EPA also heard that states would like guidance on plan
development to be released at the same time as this final rule. This
guidance should include allowable programs and policies for compliance,
examples of compliance pathways, clear information on multi-state plan
development, and identification of tools.
    As a result of this feedback, in consultation with U.S. DOE and
other federal agencies, the EPA continued to refine its toolbox of
decision support resources at: http://www2.epa.gov/www2.epa.gov/cleanpowerplantoolbox. The site includes information on regulatory
requirements, including state plan guidance and state plan decision
support. The state plan guidance section serves as a central repository
for the final emission guidelines, RIA, guidance documents, TSDs and
other supporting materials. The state plan decision support section
includes information to help states evaluate different approaches and
measures they might consider as they initiate plan development. This
section includes, for example, a summary of existing state climate and
RE and demand-side EE policies and programs, information on electric
utility actions that reduce CO2, and tools and information
to estimate

the emissions impact of RE and demand-side EE programs.
    The EPA notes that our inclusion of a measure in the toolbox does
not mean that a state plan must include that measure. In fact,
inclusion of measures provided at the Web site does not necessarily
imply the approvability of an approach or method for use in a state
plan. States will need to demonstrate that any measure included in a
state plan meets all relevant criteria and adequately addresses
elements of the plan components discussed in section VIII.D of this
preamble.

I. Considerations for CO2 Emission Reduction Measures That Occur at
Affected EGUs

    This section describes a range of emission reduction actions that
may be taken at affected EGUs that reduce CO2 emissions from
an affected EGU and/or improve its CO2 emission rate, and
the accounting treatment for these actions in a state plan. Some of
these actions do not necessitate additional accounting, monitoring or
reporting requirements. Such actions are discussed in section VIII.I.1
below, and include heat rate improvements, fuel switching from one
fossil fuel to another, integration of RE into EGU operations, and
combined heat and power (CHP) expansion or retrofit. Other actions,
however, do necessitate additional accounting, monitoring, or reporting
requirements. These include use of CCS, CCU and biomass, as discussed
in section VIII.I.2 below.
    The discussion in this section applies for both rate-based and
mass-based plans. Additional accounting considerations for mass-based
plans are discussed in section VIII.J. Additional accounting
considerations for rate-based plans, including how actions that
substitute for generation from affected EGUs or avoid the need for
generation from affected EGUs may be used in a state plan to adjust the
CO2 emission rate of an affected EGU, are discussed in
section VIII.K.
1. Actions Without Additional Accounting and Reporting Requirements
    Many actions will reduce the reported CO2 emissions or
CO2 emission rate of an affected EGU, without the need for
additional accounting or monitoring and reporting requirements beyond
the required CEMS tracking of actual stack CO2 emissions and
tracking of actual energy output.\895\ The effect of these actions will
result in changes in reported CO2 emissions and/or energy
output by an affected EGU. These actions include:
---------------------------------------------------------------------------

    \895\ Monitoring and reporting requirements for affected EGU
CO2 emissions and useful energy output are addressed in
section VIII.F.
---------------------------------------------------------------------------

     heat rate improvements;
     fuel switching to a fossil fuel with lower carbon
content (e.g., from coal to natural gas);
     integrated RE; \896\ and
---------------------------------------------------------------------------

    \896\ ``Integrated RE'' refers to RE that is directly
incorporated into the mechanical systems and operation of the EGU.
An example is a solar thermal energy system used to preheat boiler
feedwater. Such approaches reduce the amount of fossil fuel heat
input per unit of useful energy output.
---------------------------------------------------------------------------

     CHP, including retrofit of an affected EGU to a CHP
configuration, or revising the useful energy outputs (electrical and
thermal) at an affected EGU already operating in a CHP
configuration.\897\
---------------------------------------------------------------------------

    \897\ The emission reduction potential from CHP stems from the
unit using less fuel for producing useful electrical and thermal
outputs than would be required to run separate electrical and
thermal units. The emission reduction would depend on the type of
affected EGU and available steam hosts in the vicinity of the
affected EGU. A conventional combustion turbine generator, for
example, converted into a CHP unit could effectively result in a
reduction of 25 percent or more in the reported CO2
emission rate. The potential retrofitte EGU CHP market consists of
converted simple cycle turbines, older steam plants in urban areas,
and combined cycle units near beneficial thermal loads.

    Heat rate improvements, fuel switching, integrating RE and CHP
would not require any additional accounting or monitoring and
reporting, because under the emission guidelines affected EGUs are
already required to monitor and report CO2 emissions at the
stack level, and to monitor and report useful energy outputs. Stack
monitoring would reflect reductions in CO2 emissions from
efficiency improvements, changes in fuel use (including incorporation
of RE), and other on-site changes.
2. Actions With Additional Accounting and Reporting Requirements
    Certain actions that may be taken at an affected EGU to reduce
CO2 emissions, specifically application of CCS and CCU, and
use of biomass, require additional accounting and reporting.
    a. Application of CCS. Affected EGUs may utilize retrofit CCS
technology to reduce reported stack CO2 emissions from the
EGU.\898\ Affected EGUs that apply CCS under a state plan must meet the
same monitoring, recordkeeping and reporting requirements for
sequestered CO2 as new units that implement CCS to meet
final standards of performance under CAA section 111(b) for new
EGUs.\899\ Specifically, the final CAA section 111(b) rule for new
sources requires that, if a new affected EGU uses CCS to meet the
applicable CO2 emission limit, the EGU must report in
accordance with 40 CFR part 98 subpart PP (Suppliers of Carbon
Dioxide), and the captured CO2 must be injected at a
facility or facilities that report in accordance with 40 CFR part 98
subpart RR (Geologic Sequestration of Carbon Dioxide).\900,901\ See 40
CFR 60.5555(f). Taken together, these requirements ensure that the
amount of captured and sequestered CO2 will be tracked as
appropriate at project- and national-levels, and that the status of the
CO2 in its sequestration site will be monitored, including
air-side monitoring and reporting. As detailed in the preamble for the
CAA section 111(b) standards for new EGUs, the EPA found that there is
ample evidence that CCS is technically feasible and that partial CCS
can be implemented at a new fossil fuel-fired steam generating EGU at a
cost that is reasonable and that is consistent with the cost of other
dispatchable, non-NGCC generating options. In the June 2014 proposal,
the EPA noted that CCS technology at existing EGUs would entail
additional considerations beyond those at issue for newly constructed
EGUs. Specifically, the cost of integrating a retrofit CCS system into
an existing facility may be expected to be substantial, and some
existing EGUs may have space limitations and thus may not be able to
accommodate the expansion needed to install the equipment to implement
CCS. Further, the EPA noted that aggregated costs of applying CCS as a
component of the BSER for the large number of existing fossil fuel-
fired steam EGUs would be substantial and would be expected to affect
the cost and potentially the supply of electricity on a national basis.
Because there are lower-cost systems of emission reduction available to
reduce emissions from existing plants, the EPA

did not propose nor finalize CCS as a component of the BSER for
existing EGUs.
---------------------------------------------------------------------------

    \898\ Addition of retrofit CCS technology should not trigger CAA
section 111(b) applicability for modified or reconstructed sources.
Pollution control projects do not trigger NSPS modifications and
addition of CCS technology does not count toward the capital costs
of reconstruction for NSPS.
    \899\ Standards of Performance for Greenhouse Gas Emissions from
New, Modified, and Reconstructed Stationary Sources: Electric
Utility Generating Units.
    \900\ The final CAA section 111(b) rule finalizes amendments to
subpart PP reporting requirements, specifically requiring that the
following pieces of information be reported: (1) The electronic GHG
Reporting Tool identification (e-GGRT ID) of the EGU facility from
which CO2 was captured, and (2) the e-GGRT ID(s) for, and
mass of CO2 transferred to, each GS site reporting under
subpart RR. As noted, the final 111(b) rule also requires that any
affected EGU unit that captures CO2 to meet the
applicable emission limit must transfer the captured CO2
to a facility that reports under 40 CFR part 98 subpart RR.
    \901\ Under final requirements in the CAA 111(b) NSPS, any well
receiving CO2 captured from an affected EGU, be it a
Class VI or Class II well, must report under subpart RR. A UIC Class
II well's regulatory status does not change because it receives such
CO2, nor does it change by virtue of reporting under
subpart RR.
---------------------------------------------------------------------------

    However, the EPA noted that CCS may be a viable CO2
mitigation technology at some existing sources and that it would be
available to states and to sources as a compliance option. Numerous
commenters agreed with the EPA's proposed determination that CCS
technology is not part of the BSER building blocks for existing EGUs.
Other commenters opposed inclusion of CCS requirements in state plans
and provided specific reasons why CCS would not be applicable in
certain states. Many commenters felt that CCS technology is not
adequately demonstrated and is not economically practical at this time.
Other commenters argued that CCS is an available technology and that it
can be implemented at more EGUs than predicted by EPA modeling.
    Some commenters noted that there are opportunities to reduce the
cost of CCS implementation by selling the captured CO2 for
use in Enhanced Oil Recovery (EOR) operations. One commenter expressed
concern that federal requirements under the Greenhouse Gas Reporting
Program--specifically the requirement (mentioned above) to report under
40 CFR part 98 subpart RR--would foreclose, rather than encourage, the
use of captured CO2 for EOR. The EPA received similar public
comments on the CAA 111(b) proposal for new EGUs. The EPA disagrees
with the commenters' assertions and addressed those in the preamble for
the final standards of performance and in the Response-to-Comments
(RTC) document for the CAA 111(b) NSPS rulemaking. The EPA noted that
the cost of compliance with subpart RR is not significant enough to
offset the potential revenue for the EOR operator from the sale of
produced oil for CCS projects that are reliant on EOR. The costs
associated with subpart RR are relatively modest, especially in
comparison with revenues from an EOR field.
    After consideration of the variety of comments we received on this
issue, we are confirming our proposal that CCS is not an element of the
BSER, but it is an available compliance measure for a state plan. EGUs
implementing CCS would need to follow reporting requirements
established in the final CAA section 111(b) rule for new affected EGUs.
    b. Application of CCU.
    The EPA received comments suggesting that carbon capture and
utilization (CCU) technologies should also be allowed as a
CO2 emission rate adjustment measure for affected EGUs.
    Potential alternatives to storing CO2 in geologic
formations are emerging and may offer the opportunity to offset the
cost of CO2 capture. For example, captured anthropogenic
CO2 may be stored in solid carbonate materials such as
precipitated calcium carbonate (PCC) or magnesium or calcium carbonate,
bauxite residue carbonation, and certain types of cement through
mineralization. The carbonate materials produced can be tailored to
optimize performance in specific industrial and commercial
applications. For example, these carbonate materials have been used in
the construction industry and, more recently and innovatively, in
cement production processes to replace Portland cement.
    The Skyonics Skymine[supreg] project, which opened its
demonstration project in October 2014, is an example of captured
CO2 being used in the production of carbonate products. This
plant converts CO2 into commercial products. It captures
over 75,000 tons of CO2 annually from a San Antonio, Texas,
cement plant and converts the CO2 into other products
including sodium carbonate and sodium bicarbonate.\902\ Other
companies--including Calera \903\ and New Sky \904\--also offer
commercially available technology for the beneficial use of captured
CO2. These processes can be utilized in a variety of
industrial applications--including at fossil fuel-fired power plants.
---------------------------------------------------------------------------

    \902\ http://skyonic.com/technologies/skymine.
    \903\ http://www.calera.com/beneficial-reuse-of-co2/process.html.
    \904\ http://www.newskyenergy.com/index.php/products/carboncycle.
---------------------------------------------------------------------------

    However, consideration of how these emerging alternatives could be
used to meet CO2 emission performance rates or state
CO2 emission goals would require a better understanding of
the ultimate fate of the captured CO2 and the degree to
which the method permanently isolates the captured CO2 or
displaces other CO2 emissions from the atmosphere.
    Several commenters also suggested that algae-based CCU (i.e., the
use of algae to convert captured CO2 to useful products--
especially biofuels) should be recognized for its potential to reduce
emissions from existing fossil-fueled EGUs.
    Unlike geologic sequestration, there are currently no uniform
monitoring and reporting mechanisms to demonstrate that these
alternative end uses of captured CO2 result in overall
reductions of CO2 emissions to the atmosphere. As these
alternative technologies are developed, the EPA is committed to working
collaboratively with stakeholders to evaluate the efficacy of
alternative utilization technologies, to address any regulatory
hurdles, and to develop appropriate monitoring and reporting protocols
to demonstrate CO2 reductions.
    In the meantime, state plans may allow affected EGUs to use
qualifying CCU technologies to reduce CO2 emissions that are
subject to an emission standard, or those that are counted when
demonstrating achievement of the CO2 emission performance
rates or a state rate-based or mass-based CO2 emission.
State plans 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. The EPA would then review
the appropriateness and basis for the analysis and the verification
requirements in the course of its review of the state plan.
    c. Application of biomass co-firing and repowering.
    The EPA received multiple comments supporting the use of biomass
feedstocks as a means of reducing CO2 emissions within state
plans. Several commenters also asserted that states should be able to
determine how biomass can be used in their plans. Additionally, the EPA
received a range of comments regarding the valuation of CO2
emissions from biomass combustion. Some argued that all biomass
feedstocks should be considered ``carbon neutral,'' while others
maintained that only the full stack emissions from biomass combustion
should be counted. As discussed in the next section, the revised
Framework for Assessing Biogenic Carbon Dioxide for Stationary Sources
\905\ and 2012 Science Advisory Board peer review of the 2011 Draft
Framework find that it is not scientifically valid to assume that all
biogenic feedstocks are ``carbon neutral, but that the net biogenic
CO2 atmospheric contribution of different biomass feedstocks
can vary and depends on various factors, including feedstock type and
characteristics, production practices, and, in some cases, the
alternative fate of the feedstock.\906\ Other comments focused on the
use of sustainably-derived agricultural and forest biomass feedstocks,
including stakeholders who

supported and those against such feedstocks as approvable elements, and
those who wanted further definition of these feedstocks. As discussed
above and in more detail below, these final guidelines provide that
states can include qualified biomass in their plans and include
provisions for how qualified biomass feedstocks or feedstock categories
will be determined. The EPA will review the appropriateness and basis
for determining qualified biomass feedstocks or feedstock categories in
its review of the approvability of a state plan.
---------------------------------------------------------------------------

    \905\ www.epa.gov/climatechange/downloads/Framework-for-Assessing-Biogenic-CO2-Emissions.pdf.
    \906\ www.epa.gov/climatechange/ghgemissions/biogenic-emissions.html.
---------------------------------------------------------------------------

    (1) Considerations for use of biomass in state plans.
    The EPA recognizes that the use of some biomass-derived fuels can
play a role in controlling increases of CO2 levels in the
atmosphere. The use of some kinds of biomass has the potential to offer
a wide range of environmental benefits, including carbon benefits.
However, these benefits can typically only be realized if biomass
feedstocks are sourced responsibly and attributes of the carbon cycle
related to the biomass feedstock are taken into account.
    In November 2014, the agency released a second draft of the
technical report, Framework for Assessing Biogenic Carbon Dioxide for
Stationary Sources. The revised Framework, and the EPA's Science
Advisory Board (SAB) peer review of the 2011 Draft Framework, finds
that it is not scientifically valid to assume that all biogenic
feedstocks are ``carbon neutral'' and that the net biogenic
CO2 atmospheric contribution of different biogenic
feedstocks generally depends on various factors related to feedstock
characteristics, production, processing and combustion practices, and,
in some cases, what would happen to that feedstock and the related
biogenic emissions if not used for energy production.\907\ The revised
Framework also found that the production and use of some biogenic
feedstocks and subsequent biogenic CO2 emissions from
stationary sources will not inevitably result in increased levels of
CO2 to the atmosphere, unlike CO2 emissions from
combustion of fossil fuels.
---------------------------------------------------------------------------

    \907\ Specifically, the SAB found that ``There are circumstances
in which biomass is grown, harvested and combusted in a carbon
neutral fashion but carbon neutrality is not an appropriate a priori
assumption; it is a conclusion that should be reached only after
considering a particular feedstock's production and consumption
cycle. There is considerable heterogeneity in feedstock types,
sources and production methods and thus net biogenic carbon
emissions will vary considerably.'' www.epa.gov/climatechange/ghgemissions/biogenic-emissions.html.
---------------------------------------------------------------------------

    The SAB peer review panel agreed that the use of biomass feedstocks
derived from the decomposition of biogenic waste in landfills, compost
facilities or anaerobic digesters did not constitute a net contribution
of biogenic CO2 emissions to the atmosphere. And further,
information considered in preparing the second draft of the Framework,
including the SAB peer review and stakeholder input, supports the
finding that use of waste-derived feedstocks \908\ and certain forest-
derived industrial byproducts (such as those without alternative
markets) are likely to have minimal or no net atmospheric contributions
of biogenic CO2 emissions, or even reduce such impacts, when
compared with an alternate fate of disposal.
---------------------------------------------------------------------------

    \908\ Types of waste-derived biogenic feedstocks may include:
Landfill gas generated through the decomposition of MSW in a
landfill; biogas generated from the decomposition of livestock
waste, biogenic MSW, and/or other food waste in an anaerobic
digester; biogas generated through the treatment of waste water, due
to the anaerobic decomposition of biological materials; livestock
waste; and the biogenic fraction of MSW at waste-to-energy
facilities.
---------------------------------------------------------------------------

    In addition, as detailed in the President's Climate Action
Plan,\909\ part of the strategy to address climate change includes
efforts to protect and restore our forests, as well as other critical
landscapes including grasslands and wetlands, in the face of a changing
climate. This country's forests currently play a critical role in
addressing carbon pollution, removing more than 13 percent of total
U.S. GHG emissions each year.\910\ Conservation and sustainable
management can help ensure our forests and other lands will continue to
remove carbon from the atmosphere while also improving soil and water
quality, reducing wildfire risk and enhancing forests' resilience in
the face of climate change.
---------------------------------------------------------------------------

    \909\ www.whitehouse.gov/sites/default/files/image/president27sclimateactionplan.pdf.
    \910\ www.epa.gov/climatechange/Downloads/ghgemissions/US-GHG-Inventory-2015-Chapter-6-Land-Use-Land-Use-Change-and-Forestry.pdf.
---------------------------------------------------------------------------

    Many states have recognized the importance of forests and other
lands for climate resilience and mitigation, and have developed a
variety of sustainable forestry policies, RE incentives and standards,
and GHG accounting procedures. Some states, for example Oregon and
California, have programs that recognize the multiple benefits that
forests provide, including biodiversity and ecosystem services
protection as well as climate change mitigation through carbon storage.
Oregon has several programs focused on best forest management practices
and sustainability, including the Oregon Indicators of Sustainable
Forests, that promote environmentally, economically and socially
sustainable management of state forests. California's Forest Practice
Regulations support sustained production of high-quality timber while
considering ecological, economic and social values, and the state's
Greenhouse Gas Reduction Fund provides resources for forestry projects
to improve forest health, maintain carbon storage and avoid GHG
emissions from pests, wildfires and conversion to non-forest uses.
    Several states focus on sustainable bioenergy, as seen with the
sustainability requirements for eligible biomass in the Massachusetts
RPS, which, among other requirements, limits old growth forest
harvests. Many states employ complementary programs that together work
to address sustainable forestry practices. For example, Wisconsin uses
a state forest sustainability framework that provides a common system
to measure the sustainability of the state's public and private
forests, in conjunction with a series of voluntary best management
guideline manuals for sustainable woody biomass and agriculturally-
derived biomass. In addition to state-specific programs, some states
also actively participate in sustainable forest management or
certification programs through third-party entities such as the
Sustainable Forestry Initiative (SFI) and the Forest Stewardship
Council (FSC). For example, in addition to other state sustainability
programs, New York has certified more than 780,000 acres of state
forestland to both SFI and FSC's sustainable forest management
programs. SFI and FSC have certified more than 63 and 35 million acres
of forestland across the U.S., respectively.
    These examples demonstrate how states already use diverse
strategies to promote sustainable forestry and agricultural management
while realizing their unique economic, environmental and RE goals. As
states evaluate options for meeting the emission guidelines, they may
consider how sustainably-derived biomass and sustainable forestry and
agriculture programs, such as the examples highlighted above, may help
them control increases of CO2 levels in the atmosphere. In
addition, the EPA's work on assessing biogenic CO2 emissions
from stationary sources may also help inform states' efforts to assess
the role of different biogenic

feedstocks in their plans and broader climate strategies.\911\
---------------------------------------------------------------------------

    \911\ As highlighted in a November 2014 memorandum to the EPA's
Regional Air Division Directors. www.epa.gov/climatechange/ghgemissions/biogenic-emissions.html.
---------------------------------------------------------------------------

    The EPA is engaging in a second round of targeted peer review on
the revised Framework with the SAB in 2015.\912\ As part of this
technical process, and as the EPA and states implement these emission
guidelines, the EPA will continue to assess and closely monitor overall
bioenergy demand and associated landscape conditions for changes that
might have negative impacts on public health or the environment.
---------------------------------------------------------------------------

    \912\ www.epa.gov/sab.
---------------------------------------------------------------------------

    (2) Additional considerations and requirements for biomass fuels.
    The EPA anticipates that some states may consider the use of
certain biomass-derived fuels used in electricity generation as a way
to control increases of CO2 levels in the atmosphere, and
will include them as part of their state plans to meet the emission
guidelines. Not all forms of biomass are expected to be approvable as
qualified biomass (i.e., biomass that can be considered as an approach
for controlling increases of CO2 levels in the atmosphere).
Affected EGUs may use qualified biomass in order to control or reduce
CO2 emissions that are subject to an emission standard
requirement, or those that are counted when demonstrating achievement
of the CO2 emission performance rates or a state rate-based
or mass-based CO2 emission goal.
    State plan submissions must describe the types of biomass that are
being proposed for use under the state plan and how those proposed
feedstocks or feedstock categories should be considered as ``qualified
biomass'' (i.e., a biomass feedstock that is demonstrated as a method
to control increases of CO2 levels in the atmosphere). The
submission must also address the proposed valuation of biogenic
CO2 emissions (i.e., the proposed portion of biogenic
CO2 emissions from use of the biomass feedstock that would
not be counted when demonstrating compliance with an emission standard,
or when demonstrating achievement of the CO2 emission
performance rates or a state rate-based or mass-based CO2
emission goal).
    With regard to assessing qualified biomass proposed in state plans,
the EPA generally acknowledges the CO2 and climate policy
benefits of waste-derived biogenic feedstocks and certain forest- and
agriculture-derived industrial byproduct feedstocks, based on the
conclusions supported by a variety of technical studies, including the
revised Framework for Assessing Biogenic Carbon Dioxide for Stationary
Sources. The use of such waste-derived and certain industrial byproduct
biomass feedstocks would likely be approvable as qualified biomass in a
state plan when proposed with measures that meet the biomass
monitoring, reporting and verification requirements discussed below and
other measures as required elsewhere in these emission guidelines.
    Given the importance of sustainable land management in achieving
the carbon goals of the President's Climate Action Plan, sustainably-
derived agricultural and forest biomass feedstocks may also be
acceptable as qualified biomass in a state plan, if the state-supplied
analysis of proposed qualified feedstocks or feedstock categories can
adequately demonstrate that such feedstocks or feedstock categories
appropriately control increases of CO2 levels in the
atmosphere and can adequately monitor and verify feedstock sources and
related sustainability practices. Information in the revised Framework,
the second SAB peer review process, and the state and third party
programs highlighted in the previous section can assist states when
considering the role of qualified biomass in state plan submittals.
    Regardless of what biomass feedstocks are proposed, state plans
must specify how biogenic CO2 emissions will be monitored
and reported, and identify specific EM&V, tracking and auditing
approaches for qualified biomass feedstocks. As discussed in section
VIII.D.2, state plan submittals must include CO2 emission
monitoring, reporting and recordkeeping measures. In the case of
sustainably-derived forest- and agriculture-derived feedstocks, this
will also include measures for verifying feedstock type, origin and
associated sustainability practices. Section VIII.K describes how state
plan submittals must specify the requirements and procedures that EM&V
measures must meet. As discussed in section VIII.K, the EPA is
addressing potential EM&V measures for qualified biomass in EPA's model
trading rule and draft EM&V guidance, such as measures that would
ensure that biomass-related biogenic CO2 benefits are
quantifiable, verifiable, non-duplicative, permanent and enforceable.
    State plan submittals must ensure that all biomass used meets the
state plan requirements for qualified biomass and associated biogenic
CO2 benefits, such as using robust, independent third party
verification and establishing measures to maintain transparency,
including disclosure of relevant documentation and reports. State plan
submittals must include measures for tracking and auditing performance
to ensure that biomass used meets the state plan requirements for
qualified biomass and associated biogenic CO2 benefits.
Details on how to adjust CO2 rates through the use of
qualified biomass feedstocks are provided in section VIII.K.1.
    The EPA will review the appropriateness and basis for proposed
qualified biomass and biomass treatment determinations and related
accounting, monitoring and reporting measures in the course of its
review of a state plan. The EPA's determination that a state plan
satisfactorily proves that proposed biomass fuels qualify would be
based in part on whether the plan submittal demonstrates that proposed
state measures for qualified biomass and related biogenic
CO2 benefits are quantifiable, verifiable, enforceable, non-
duplicative and permanent. The EPA recognizes that CCS technology
(described above in section VIII.I.2.a) could be applied in conjunction
with the use of qualified biomass.
    (3) Biomass co-firing.
    Affected EGUs may use qualified biomass co-fired with fossil fuels
at an affected EGU. As discussed above in this section, not all forms
of biomass are expected to be approvable and states should propose
biomass feedstocks and treatment of biogenic CO2 emissions
in state plans, along with supporting analysis where applicable. The
EPA will review the appropriateness and basis for such determinations
and accounting measures in the course of its review of a state plan.
    An affected EGU using qualified biomass as a fuel must monitor and
report both its overall CO2 emissions and its biogenic
CO2 emissions. If biomass is to be used as means to control
increases of CO2 levels in the atmosphere in a state plan,
the plan must specify requirements for reporting biogenic
CO2 emissions from affected EGUs.
    (4) Biomass repowering.
    Affected EGUs could fully repower to use primarily qualified
biomass. The characteristics of affected EGUs, as discussed in section
IV.D, include the use of at least 10 percent fossil fuel for
applicability of these emission guidelines. An EGU repowering with at
least 90 percent biomass fuels instead of fossil fuels becomes a non-
affected

EGU.\913\ An EGU repowering with less than 90 percent biomass would
remain an affected EGU and therefore need to propose biomass feedstocks
and treatment of biogenic CO2 emissions in state plans,
along with supporting analysis where applicable.
---------------------------------------------------------------------------

    \913\ For such an EGU to be considered non-affected, the EGU
must be subject to a federally enforceable or practically
enforceable condition, expressed in (for example) a construction
permit or otherwise, that limits the amount of fossil fuel that may
be used to 10 percent or less.
---------------------------------------------------------------------------

J. Additional Considerations and Requirements for Mass-Based State
Plans

    This section discusses considerations and requirements for
different types of mass-based state plans. This includes mass-based
state plans using emission budget trading programs, and coordination
among such programs where states retain individual mass CO2
emission goals. CAA section 111(d) requires states to submit, in part,
a plan that establishes standards of performance for affected EGUs
which reflect the BSER. The state plan must be satisfactory with
respect to this requirement in order for the EPA to approve the plan.
As previously described, states meet the statutory requirements of
111(d) and the requirements of the final emission guidelines by
establishing emission standards for affected EGUs that meet the
performance rates, which reflect the application of BSER as determined
by the EPA. This final rule allows states to alternatively establish
emission standards that meet rate-based or mass-based goals. The state
goals must be equivalent to the performance rates in order to reflect
the application of the BSER as required by the statute and the final
emission guidelines. Therefore, a state choosing a mass-based
implementation must address leakage as part of its mass-based plan in
order to satisfactorily establish emission standards for affected EGUs
that reflect the BSER as set by the EPA.
1. Accounting for CO2 Emission Reduction Measures in Mass-
Based State Plans
    As discussed in section VIII.I, measures that occur at affected
EGUs will result in CO2 emission reductions that are
automatically accounted for in reported CO2 emissions. Other
measures that provide substitute generation for affected EGUs or avoid
the need for generation from affected EGUs, such as demand-side EE, are
automatically accounted for under a mass-based plan to the extent that
these measures reduce reported CO2 emissions from affected
EGUs. Unlike under a rate-based plan, no additional accounting is
necessary in order to recognize these emission reductions.
2. Use of Emission Budget Trading Programs
    This section addresses the use of emission budget trading programs
in a mass-based state plan, including provisions required for such
programs and the design of such programs in the context of a state
plan. This includes program design approaches that ensure achievement
of a state mass-based CO2 emission goal (or mass-based
CO2 goal plus new source CO2 emission complement)
(section VIII.J.2.b), as well as how states can use emission budget
trading programs with broader source coverage and other flexibility
features in a state plan, such as the programs currently implemented by
California and the RGGI participating states (section VIII.J.2.c).
Section VIII.J.2.d addresses other considerations for the design of
emission budget trading programs that states may want to consider, such
as allowance allocation approaches. Section VIII.J.3 addresses multi-
state coordination among emission budget trading programs used in
states that retain their individual state mass-based CO2
goals.
    a. State plan provisions required for a mass-based emission budget
trading program approach.
    For a mass-based emission trading program approach, the state plan
would include as its federally enforceable emission standards
requirements that specify the emission budget and related compliance
requirements and mechanisms. These requirements would include:
CO2 emission monitoring, reporting, and recordkeeping
requirements for affected EGUs; provisions for state allocation of
allowances; provisions for tracking of allowances, from issuance
through submission for compliance; and the process for affected EGUs to
demonstrate compliance (allowance ``true-up'' with reported
CO2 emissions). Mass-based emission standards that take the
form of an emission budget trading program must be quantifiable,
verifiable, enforceable, non-duplicative and permanent. These
requirements are described in more detail at section VIII.D.2.
    Where a state plan establishes mass-based emission standards for
affected EGUs only, the emission standards and the implementing and
enforcing measures may be included in the state plan as the full set of
requirements implementing the emission budget trading program. Where an
emission budget trading program in a state plan addresses affected EGUs
and other fossil fuel-fired EGUs or emission sources, pursuant to the
approaches described in sections VIII.J.2.b-d below, the requirements
that must be included in the state plan are the federally enforceable
emission standards in the state plan that apply specifically to
affected EGUs, and the requirements that specifically require affected
EGUs to participate in and comply with the requirements of the emission
budget trading program. This includes the requirement for an affected
EGU to surrender emission allowances equal to reported CO2
emissions, and meet monitoring and reporting requirements for
CO2 emissions, among other requirements. These requirements
may be submitted as part of the federally enforceable state plan
through mechanisms with the appropriate legal authority and effect,
such as state regulations, Title V permit requirements for affected
EGUs, and other possible instruments that impose these requirements
specifically with respect to affected EGUs. Under this approach, the
full set of regulations establishing the emission budget trading
program that applies to affected EGUs and other fossil fuel-fired EGUs
and other emission sources (if relevant) must be described as
supporting documentation in the state plan submittal for EPA to
evaluate the approvability of the plan by determining whether the
affected EGUs will achieve the requisite goal.
    b. Requirement for emission budget trading programs to address
potential leakage.
    In Section VII.D, the EPA specifies that potential emission leakage
must be addressed in a state plan with mass-based emission standards.
The EPA received comments suggesting various solutions to this concern,
such as the inclusion of new sources under the rule and quantitative
adjustments to mass CO2 goals for affected EGUs. In response
to this issue, the EPA has sought to give states flexibility in how
they meet this requirement and base the acceptable solutions on what
will best suit a state's unique characteristics and state plan
structure.
    To address the potential for emission leakage to new sources under
a mass-based plan approach, which could prevent a mass-based program
from successfully achieving a mass-based CO2 goal consistent
with BSER, the EPA is requiring that a state submitting a plan that is
designed to meet a state mass-based CO2 goal for affected
EGUs demonstrate that the plan addresses and mitigates the risk of
potential emission leakage to new sources. The following

options provide sufficient demonstration that potential emission
leakage has been addressed in a mass-based state plan: \914\

    \914\ The first two options need not be mutually exclusive; they
can both be implemented as part of a mass-based plan.

    1. Regulate new non-affected fossil EGUs as a matter of state
law in conjunction with emission standards for affected EGUs in a
mass-based plan. If a state adopts an EPA-provided mass budget \915\
that includes the state mass-based CO2 goal for affected
EGUs plus a new source CO2 emission complement, this
option could be presumptively approvable.
---------------------------------------------------------------------------

    \915\ In Table 14, we have provided a mass budget for each state
that includes the state mass-based CO2 goal and a
projection for a new source CO2 emission complement.
---------------------------------------------------------------------------

    2. Use allocation methods in the state plan that counteract
incentives to shift generation from affected EGUs to unaffected
fossil-fired sources. If a state adopts allowance set-aside
provisions exactly as they are outlined in the finalized model rule,
this option could be presumptively approvable.
    3. Provide a demonstration in the state plan, supported by
analysis, that emission leakage is unlikely to occur due to unique
state characteristics or state plan design elements that address and
mitigate the potential for emission leakage.

    In the first option, states may choose to regulate new non-affected
fossil fuel-fired EGUs, as a matter of state law, in conjunction with
federally enforceable emission standards for affected EGUs under a
mass-based plan. This regulation of both new and existing sources, as
part of a state plan approach, is conceptually analogous to a method
that has been adopted by the mass-based systems adopted by California
and the RGGI participating states. To address potential emission
leakage under this option, the mass-based plan includes federally
enforceable emission standards for affected EGUs, and the supporting
documentation for the plan describes state-enforceable regulations for,
at a minimum, all new grid-connected fossil fuel-fired EGUs that meet
the applicability standards for EGUs subject to CAA section 111(b).
States have the option of regulating a wider array of sources if they
choose, as a matter of state law.
    For this option, a state must adopt, as a matter of state law, a
mass CO2 emission budget of sufficient size to cover both
affected EGUs under the existing source mass CO2 goal
provided in this final rule, along with sufficient CO2
emission tonnage to cover projected new sources. There are two pathways
that states can use for adopting such an emission budget that applies
to both affected EGUs and new sources. The EPA is providing a mass
budget for each state that account for the state's mass CO2
goal for affected EGUs and a complementary emission budget for new
sources, referred to as the new source CO2 emission
complement. States that both adopt the EPA-provided mass budget, based
on the state mass-based CO2 goal for affected EGUs plus the
new source CO2 emission complement, and regulate new sources
under this emission budget as a matter of state law, in conjunction
with federally enforceable emission standards for affected EGUs as part
of the mass-based state plan may be able to submit a presumptively
approvable plan. Such a plan would include federally enforceable
emission standards for affected EGUs, and in the supporting
documentation of the plan, would describe that the state is regulating
new sources under a mass CO2 emission budget that is equal
to or less than the state mass-based CO2 goal for affected
EGUs plus the EPA-specified CO2 emission complement, in
conjunction with the federally enforceable emission standards for
affected EGUs. If the state plan is designed to achieve the EPA
provided mass budget, plan performance will be evaluated based on
whether the existing affected EGUs, regulated under the federally
enforceable state plan, and new sources regulated as a matter of state
law, together meet the total mass budget that includes the state's mass
CO2 goal for affected EGUs and a complementary emission
budget for new sources.
    EPA-specified mass CO2 emission budgets for each state,
including the state's mass CO2 goal and a new source
CO2 emission complement, are provided in Table 14 below. The
derivation of the new source CO2 emission complements is
explained in a TSD titled New Source Complements to Mass Goals, which
is available in the docket.
---------------------------------------------------------------------------

    \916\ The state mass CO2 goals can be found in Table
13 in section VII.

                                 Table 14--New Source Complements to Mass Goals
----------------------------------------------------------------------------------------------------------------
                                                  New source complements  (short   Mass goals \916\ + new source
                                                           tons of CO2)             complements  (short tons of
                      State                      --------------------------------              CO2)
                                                                                -------------------------------
                                                      Interim          Final          Interim          Final
----------------------------------------------------------------------------------------------------------------
Alabama.........................................         856,524         755,700      63,066,812      57,636,174
Arizona.........................................       1,424,998       2,209,446      34,486,994      32,380,197
Arkansas........................................         411,315         362,897      34,094,572      30,685,529
California......................................       2,846,529       4,413,516      53,873,603      52,823,635
Colorado........................................       1,239,916       1,922,478      34,627,799      31,822,874
Connecticut.....................................         135,410         119,470       7,373,274       7,060,993
Delaware........................................          78,842          69,561       5,141,711       4,781,386
Florida.........................................       1,753,276       1,546,891     114,738,005     106,641,595
Georgia.........................................         677,284         597,559      51,603,368      46,944,404
Idaho...........................................          94,266         146,158       1,644,407       1,639,013
Illinois........................................         818,349         722,018      75,619,224      67,199,174
Indiana.........................................         939,343         828,769      86,556,407      76,942,604
Iowa............................................         298,934         263,745      28,553,345      25,281,881
Kansas..........................................         260,683         229,997      25,120,015      22,220,822
Kentucky........................................         752,454         663,880      72,065,256      63,790,001
Louisiana.......................................         484,308         427,299      39,794,622      35,854,321
Maine...........................................          40,832          36,026       2,199,016       2,109,968
Maryland........................................         170,930         150,809      16,380,325      14,498,436
Massachusetts...................................         225,127         198,626      12,972,803      12,303,372
Michigan........................................         623,651         550,239      53,680,801      48,094,302
Minnesota.......................................         286,535         252,806      25,720,126      22,931,173

Mississippi.....................................         410,440         362,126      27,748,753      25,666,463
Missouri........................................         668,637         589,929      63,238,070      56,052,813
Montana.........................................         421,674         653,801      13,213,003      11,956,908
Nebraska........................................         216,149         190,706      20,877,665      18,463,444
Nevada..........................................         770,417       1,194,523      15,114,508      14,718,107
New Hampshire...................................          71,419          63,012       4,314,910       4,060,591
New Jersey......................................         313,526         276,619      17,739,906      16,876,364
New Mexico......................................         527,139         817,323      14,342,699      13,229,925
New York........................................         522,227         460,753      34,117,555      31,718,182
North Carolina..................................         692,091         610,623      57,678,116      51,876,856
North Dakota....................................         245,324         216,446      23,878,144      21,099,677
Ohio............................................         949,997         838,170      83,476,510      74,607,975
Oklahoma........................................         581,051         512,654      45,191,382      41,000,852
Oregon..........................................         453,663         703,399       9,096,826       8,822,053
Pennsylvania....................................       1,257,336       1,109,330     100,588,162      90,931,637
Rhode Island....................................          70,035          61,791       3,727,420       3,584,016
South Carolina..................................         344,885         304,287      29,314,508      26,303,255
South Dakota....................................          46,513          41,038       3,995,462       3,580,518
Tennessee.......................................         358,838         316,598      32,143,698      28,664,994
Texas...........................................       5,328,758       8,516,408     213,419,599     198,105,249
Utah............................................         981,947       1,522,500      27,548,327      25,300,693
Virginia........................................         450,039         397,063      30,030,110      27,830,174
Washington......................................         531,761         824,490      12,211,467      11,563,662
West Virginia...................................         602,940         531,966      58,686,029      51,857,307
Wisconsin.......................................         364,841         321,895      31,623,197      28,308,882
Wyoming.........................................       1,185,554       1,838,190      36,965,606      33,472,602
Lands of the Navajo Nation......................         809,562       1,255,217      25,367,354      22,955,804
Lands of the Uintah and Ouray Reservation.......          84,440         130,923       2,645,885       2,394,354
Lands of the Fort Mojave Tribe..................          37,162          57,619         648,264         646,138
                                                 ---------------------------------------------------------------
    Total.......................................      33,717,871      41,187,289   1,878,255,620   1,709,291,348
----------------------------------------------------------------------------------------------------------------

    States can, in the alternative, provide their own projections for a
new source CO2 emission complement to their mass-based
CO2 goals for affected EGUs. In the supporting documentation
for the state plan submittal, the state must specify the new source
budget, specify the analysis used to derive such a new source
CO2 emission complement, and demonstrate that under the
state plan affected EGUs in the state will meet the state mass-based
CO2 goal for affected EGUs as a result of being regulated
under the broader CO2 emission cap that applied to both
affected EGUs and new sources. Such a projection should take into
account the mass goal quantification method outlined in section VII.C
and the CO2 Emission Performance Rate and Goal Computation
TSD, including the fact that the mass-based state goals already
incorporate a significant growth in generation from historical levels.
The EPA will evaluate the approvability of the plan based on whether
the federally enforceable emission standards for affected EGUs in
conjunction with the state-enforceable regulatory requirements for new
sources will result in the affected EGUs meeting the state mass-based
CO2 goal. If, rather than designing a plan to achieve the
EPA provided mass budget, the state uses its own projections for a new
source complement and the plan is approved to meet this new source
complement, plan performance will be evaluated based on whether the
existing affected EGUs, regulated under the federally enforceable state
plan, meet the state's mass CO2 goal for affected EGUs.
    The second demonstration option allows states to use allowance
allocation methods that counteract incentives to shift generation from
affected EGUs to unaffected fossil-fired sources. These allocation
approaches must be specified in state plans as part of the provisions
for state allocation of allowances required under a mass-based plan
approach (see section VIII.J.2.a). The EPA is proposing the inclusion
of two allocation strategies as part of the mass-based approach in the
proposed federal plan and model rule: Updating output-based allocations
and an allowance set-aside that targets RE. These options are described
in more detail below. If a state were to adopt allowance set-aside
provisions exactly as they are outlined in the finalized model rule,
they could be considered presumptively approvable. The allowance
allocation alternative for addressing leakage was chosen for the
federal plan and model rule proposal because EPA does not have
authority to extend regulation of and federal enforceability to new
fossil fuel-fired sources under CAA section 111(d), and therefore we
cannot include them under a federal mass-based plan approach.
    An updating output-based allocation method allocates a portion of
the total CO2 emission budget to affected EGUs based, in
part, on their level of electricity generation in a recent period or
periods. Therefore, the total allocation to an EGU that is eligible to
receive allowances from an output-based allowance set-aside is not
fixed, but instead depends on its generation. Under this approach, each
eligible affected EGU may receive a larger allowance allocation if it
generates more. Therefore, eligible affected EGUs will have an
incentive to generate more in order to receive more allowances,
aligning their incentive to generate with new sources.
    This allocation method can be implemented through the creation of a

set-aside that reserves a subset of the total allowances available to
sources, and distributes them based upon the criteria described above.
Because the total number of allowances is limited, this allocation
approach will not exceed the overall state mass-based CO2
goal for affected EGUs. Instead, it merely modifies the distribution of
allowances in a manner designed to mitigate potential emission leakage.
    The other allocation strategy included as part of the mass-based
approach in the proposed federal plan and model rule is a set-aside of
allowances to be allocated to providers of incremental RE. A set-aside
can also be allocated to providers of demand-side EE, or to both RE and
demand-side EE. The increased availability of RE generation can serve
as another source of generation to satisfy electricity demand.
Increased demand-side EE will reduce the demand that sources need to
meet. Therefore, both RE and demand-side EE can serve to reduce the
incentive that new sources have to generate, and therefore align their
incentives with affected EGUs. Thus, increased RE and demand-side EE,
supported by a dedicated set-aside, can also serve to address potential
emission leakage.
    If a state is submitting a plan with an allocations approach that
differs from that of the finalized model rule, the state should also
provide a demonstration of how the specified allocation method will
provide sufficient incentive to counteract potential emission leakage.
    Finally, a state can provide a demonstration that emission leakage
is unlikely to occur, without implementing either of the two strategies
above, as a result of unique factors, such as the presence of existing
state policies addressing emission leakage or unique characteristics of
the state and its power sector that will mitigate the potential for
emission leakage. This demonstration must be supported by credible
analysis. The EPA will determine if the state has provided a sufficient
demonstration that potential emission leakage has already been
adequately addressed, or if additional action is required as part of
the state plan.
    Aside from the possible incentives for emission leakage addressed
in this section, there may be other potential generation incentives
across states and unit subcategories that could increase CO2
emissions, particularly in an environment where various states are
implementing a variety of state plan approaches in a shared grid
region. Some examples of these incentives, particularly those that were
specified by commenters, are discussed in section VIII.L. That section
also describes how the EPA has structured this final rule to either
prevent or minimize the potential for foregone emission reductions from
differential incentives that may result from state plan implementation.
These safeguards include placing restrictions on interstate trading
when there could be a risk of such differential incentives.
Additionally, the nature of the CO2 emission performance
rates and state rate-based CO2 goals helps to minimize these
potential effects, as does the MWh-accounting method for adjusting the
CO2 emission rates of affected EGUs under rate-based plans.
    However, without a better understanding of the different mechanisms
that states may ultimately choose to meet the emission guidelines, and
how different requirements in different states may interact, the EPA
cannot project every potential differential incentive that could lead
to a loss of CO2 emission reductions. Therefore, once
program implementation begins, the EPA will assess how emission
performance across states may be affected by the interaction of
different regulatory structures implemented through state plans. Based
upon that evaluation, the EPA will determine whether there are
potential concerns and what course of action may be appropriate to
remedy such concerns.
    c. Emission budget trading programs that ensure achievement of a
state CO2 goal.
    A mass-based emission budget trading program can be designed such
that compliance by affected EGUs will achieve the state mass-based
CO2 goal. Under this approach, a state plan would establish
CO2 emission budgets for affected EGUs during the interim
and final plan performance periods that are equal to or lower than the
applicable state mass-based CO2 goals specified in section
VII. A mass-based emission budget trading program can also be designed
such that compliance by affected EGUs in conjunction with new fossil
fuel-fired EGUs meeting applicable requirements under state law will
achieve a mass-based CO2 goal plus new source CO2
emission complement. Under this approach, a state would establish
CO2 emission budgets under state law for affected EGUs plus
new sources during the interim and final plan performance periods that
are equal to or lower than the applicable state mass-based
CO2 emission goal plus the new source CO2
emission complement specified in Table 14 in section VIII.J.2.b above,
and describe such emission budgets in the supporting documentation of
the state plan. Under either program, compliance periods for affected
EGUs (or for affected EGUs plus new fossil fuel-fired EGUs meeting
applicable requirements under state law) would also be aligned with the
interim and final plan performance periods. This approach would limit
total CO2 emissions from affected EGUs (or total
CO2 emissions from affected EGUs and new fossil fuel-fired
EGUs meeting applicable requirements under state law) during the
interim and final plan performance periods to an amount equal to or
less than the state's mass-based CO2 goal (or mass-based
CO2 goal plus new source CO2 emission
complement).
    Under this approach, compliance by affected EGUs with the mass-
based emission standards in a plan would ensure that the state achieves
its mass-based CO2 goal for affected EGUs (or mass-based
CO2 goal plus new source CO2 emission
complement). No further demonstration would be necessary by the state
to demonstrate that its plan would achieve the state's mass-based
CO2 goal (or mass-based CO2 goal plus new source
CO2 emission complement).
    For this type of plan, where the emission budget is equal to or
less than the state mass CO2 goal (or mass-based
CO2 goal plus new source CO2 emission
complement),\917\ the EPA would assess achievement of the state goal
based on compliance by affected EGUs with the mass-based emission
standards, rather than reported CO2 emissions by affected
EGUs during the interim plan performance periods and final plan
performance periods. This approach would allow for allowance banking
between performance periods, including the interim and final
performance periods outlined in this final rule.
---------------------------------------------------------------------------

    \917\ As specified for the interim plan performance period
(including specified levels in interim steps 1 through 3) and the
final two-year plan performance periods.
---------------------------------------------------------------------------

    Banking provisions have been used extensively in rate-based
environmental programs and mass-based emission budget trading programs.
This is because banking reduces the cost of attaining the requirements
of the regulation. The EPA has determined that the same rationale and
outcomes apply under a CO2 emission rate approach, in that
allowing banking will reduce compliance costs. Banking encourages
additional emission reductions in the near-term if economic to meet a
long-term emission rate constraint, which is beneficial due to social
preferences for environmental improvements sooner rather than later. It
is also beneficial when addressing pollutants that are long-lived in
the atmosphere, such as CO2, and where increasing
atmospheric concentration of

the pollutant leads to increasing adverse atmospheric impacts.
    Banking also provides long-term economic signals to affected
emission sources and other market participants where actions taken
today will have economic value in helping meet tighter emission
constraints in the future, provided those emission sources expect that
the banked ERCs or emission allowances may be used for compliance in
the future. Linking short-term and long-term economic incentives, which
allows owners or operators of affected EGUs and other market
participants to assess both short-term and long-term incentives when
making decisions about compliance approaches or emission reduction
investments, reduces long-term compliance costs for affected EGUs and
ratepayer impacts. In addition, the increased temporal flexibility
provided by banking would further help address potential electric
reliability concerns, as banked ERCs can be used to meet emission
standard requirements for an affected EGU.
    d. Addressing emission budget trading programs with broader source
coverage and other flexibility features.
    As described in section VIII.C above, under the emission standards
plan type, a mass-based emission budget trading program with broader
source coverage and other flexibility features may be designed such
that compliance by affected EGUs (or compliance by affected EGUs plus
new fossil fuel-fired EGUs meeting applicable requirements under state
law) would assure achievement of the applicable state mass-based
CO2 goal (or mass-based CO2 goal plus new source
CO2 emission complement).\918\
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    \918\ Section VIII.J.2.a describes how state plan submittals
must include as requirements, or describe as part of supporting
documentation, relevant aspects of such emission budget trading
programs.
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    However, emission budget trading programs, including those
currently implemented by California and the RGGI participating states,
include a number of different design elements that functionally expand
the emission budget under certain circumstances. If a state chose, it
could apply such mass-based emission standards, in the form of an
emission budget trading program that differs in design from that
outlined in section VIII.J.2.c above. These types of emission budget
trading programs must be submitted as a part of a state measures plan
type. Where an emission budget trading program addresses affected EGUs
and other fossil fuel-fired EGUs, the requirements that must be
included in the state plan are the federally enforceable emission
standards in the state plan that apply specifically to affected EGUs,
and the requirements that specifically require affected EGUs to
participate in and comply with the requirements of the emission budget
trading program. This includes the requirement for an affected EGU to
surrender emission allowances equal to reported CO2
emissions, and meet monitoring and reporting requirements for
CO2 emissions, among other requirements. These requirements
may be submitted as part of the federally enforceable state plan
through mechanisms with the appropriate legal authority and effect,
such as state regulations, relevant Title V permit requirements for
affected EGUs, and other possible instruments that impose these
requirements specifically with respect to affected EGUs.\919\ Under
this approach, the full set of regulations establishing the emission
budget trading program that applies to affected EGUs and other fossil
fuel-fired EGUs and other emission sources (if relevant) must be
described as supporting documentation in the state plan submittal. This
structure is appropriate to ensure that states with an emission budget
trading program that addresses both affected EGUs and other fossil
fuel-fired EGUs do not inappropriately submit requirements regarding
entities other than affected EGUs for inclusion in the federally
enforceable state plan.
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    \919\ This approach for establishing federally enforceable
emission standards based on requirements for affected EGUs subject
to a broader emission budget trading program that also covers non-
affected emission sources is addressed in section VIII.J.2.d. above.
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    Such state programs could include a number of different design
elements. This includes broader program scope, where a program includes
other emission sources beyond affected EGUs subject to CAA section
111(d) and new fossil fuel-fired EGUs, such as industrial sources.
Programs might also include design elements that make allowances
available in addition to the established emission budget. This includes
project-based offset allowances or credits from GHG emission reduction
projects outside the covered sector and cost containment reserve
provisions that make additional allowances available at specified
allowance prices.\920\
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    \920\ For example, both the California and RGGI programs allow
for the use of allowances awarded to GHG offset projects to be used
to meet a specified portion of an affected emission source's
compliance obligation. The RGGI program contains a cost containment
allowance reserve that makes available additional allowances up to a
certain amount, at specified allowance price triggers.
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    In the case where an emission budget trading program contains
elements that functionally expand the emission budget in certain
circumstances, compliance by affected EGUs with the mass-based emission
standards would not necessarily ensure that CO2 emissions
from affected EGUs do not exceed the state's mass-based CO2
goal (or mass-based CO2 goal plus new source CO2
emission complement). However, states could modify such programs to
remove flexibility mechanisms that functionally expand the emission
budget, such as out-of-sector offsets and certain cost containment
reserve mechanisms, and submit the program under an emission standards
plan type.
    Where a state chooses to retain such flexibility mechanisms as part
of an emission budget trading program, the program may only be
implemented as part of a state measures plan type because these state
flexibility mechanisms would not assure CO2 emissions from
affected EGUs do not exceed the state's mass-based CO2 goal
(or mass-based CO2 goal plus new source CO2
emission complement). A description of the state measures plan type and
related requirements is provided in section VIII.C.3.
    Under this type of approach, the state would be required to include
a demonstration,\921\ in its state plan submittal, of how its state
measures, in conjunction with any emission standards on affected EGUs,
would achieve the state mass-based CO2 goal (or mass-based
CO2 goal plus new source CO2 emission
complement). This demonstration would include a projection of the total
CO2 emissions from the fleet of affected EGUs that would
occur as a result of compliance with the emission standards in the
plan. Section VIII.D.2 discusses how such demonstrations could address
design elements of emission budget trading programs with broader scope
and additional compliance flexibility mechanisms, such as those
included in the California and RGGI programs. Once the plan is
implemented, if the mass-based CO2 goal is not achieved
during a plan performance period, the backstop federally enforceable
emission standards included in the state plan that apply to affected
EGUs would be implemented, as described in section VIII.C.3.b.\922\
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    \921\ A demonstration of how a plan will achieve a state's rate-
based or mass-based CO2 goal (or mass-based
CO2 goal plus new source CO2 emission
complement) is one of the required plan components, as described in
section VIII.D.2.
    \922\ Achievement of the state mass-based CO2 goal
would be determined based solely on stack CO2 emissions
from affected EGUs. Where a state program includes the ability of an
affected emission source to use GHG offsets to meet a portion of its
allowance compliance obligation, no ``credit'' is applied to
reported CO2 emissions by the affected EGU. The use of
offset allowances or credits in such programs merely allows an
affected EGU to emit a ton of CO2 in the amount of
submitted offset allowances or credits. In all cases, there is no
adjustment applied to reported stack emissions of CO2
from an affected EGU when determining compliance with its emission
limit.

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    e. Considerations for mass-based emission budget trading programs.
    The EPA notes that while an emission budget trading program
included in an emission standards plan must be designed to achieve a
state mass-based CO2 goal (or mass-based CO2 goal
plus new source CO2 emission complement), states have wide
discretion in the design of such programs, provided the emission
standards included in the plan are quantifiable, verifiable,
enforceable, non-duplicative, and permanent.
    (1) Allowance allocation. A key example is state discretion in the
CO2 allowance allocation methods included in the
program.\923\ This includes the methods used to distribute
CO2 allowances and the parties to which allowances are
distributed. For example, if a state chose, it could include
CO2 allowance allocation provisions that provide incentives
for certain types of complementary activities, such as RE generation,
that help achieve the overall CO2 emission limit for
affected EGUs established under the program. In addition, a state could
use its allocation provisions to encourage investments in RE and
demand-side EE in low-income communities. States could also use
CO2 allowance allocation provisions to provide incentives
for early action, such as RE generation or demand-side EE savings that
occur prior to the beginning of the interim plan performance period in
2022. For example, a state could include CO2 allowance
allocation provisions where CO2 allowances are distributed
to RE generators based on MWh of RE generation that occurs prior to
2022. Such provisions might be addressed through a finite set-aside of
CO2 allowances that are available for allocation under these
provisions. This set-aside could be additional to a set-aside created
by the state for the CEIP discussed in section VIII.B.2.
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    \923\ Allowance allocation refers to the methods used to
distribute CO2 allowances to the owners or operators of
affected EGUs and/or other market participants.
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    (2) Facility-level compliance. If a state chose, it could evaluate
compliance (i.e., allowance true-up) under its emission budget trading
program at the facility level, rather than at the individual unit
level. The EPA has adopted facility-level compliance in the emission
budget-trading programs it administers, including the Acid Rain Program
(70 FR 25162), Clean Air Interstate Rule (70 FR 25162), and Cross-State
Air Pollution Rule (76 FR 48208). Under this approach, states would
still track reported unit-level CO2 emissions--while
evaluating compliance at the facility level--allowing them to track
increases and decreases of CO2 emissions at individual EGUs.
    3. Multi-state coordination: Mass-based emission trading programs.
    An individual state may provide for the use of CO2
allowances issued by another state(s) for compliance with the mass-
based emission standards in its plan. This type of state plan would
include requirements that enable affected EGUs to use allowances issued
in other states for compliance under the state's emission budget
trading program. This type of state plan must also indicate how
CO2 allowances will be tracked from issuance through use for
compliance, through either a joint tracking system, interoperable
tracking systems, or use of an EPA-administered tracking system.\924\
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    \924\ The emission standards in each individual state plan must
include requirements that address the issuance of CO2
allowances and tracking of CO2 allowances from issuance
through use for compliance. The description here addresses how those
requirements will be implemented through the use of a joint tracking
system, interoperable tracking systems, or an EPA-administered
tracking system.
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    Two different implementation approaches could be used to create
such links. A state could submit a ``ready-for-interstate-trading''
plan using an EPA-approved tracking system, but the plan would not
identify links with other states. A state could also submit a plan with
specified bilateral or multilateral links that explicitly identify
partner states.
    Interstate allowance linkages would not affect the approvability of
each state's individual plan. However, different considerations apply
for the approvability of an individual plan with such links, based on
whether the emission budget trading program in the plan applies only to
affected EGUs or includes other emission sources, and if the plan is
designed to meet a state mass-based CO2 goal for affected
EGUs only or to meet a mass-based CO2 goal plus a new source
CO2 emission complement).
    Under the first ``ready-for-interstate-trading'' implementation
approach, a state would indicate in its state plan that its emission
budget trading program will be administered using an EPA-approved (or
EPA-administered) emission and allowance tracking system.\925\ State
plans using a specified EPA-approved tracking system would be deemed by
the EPA as ready for interstate linkage upon approval of the state
plan. No additional EPA approval would be necessary for states to link
their emission budget trading programs, and affected EGUs in those
states could engage in interstate trading subsequent to EPA plan
approval.
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    \925\ The EPA would designate tracking systems that it has
determined adequately address the integrity elements necessary for
the issuance and tracking of emission allowances. Under this
approach, a state could include in its plan such a designated
tracking system, which has already been reviewed by the EPA.
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    A state would indicate in its plan submittal that its emission
budget trading system will use a specified EPA-approved tracking
system. The state would also indicate in the regulatory provisions for
its emission budget trading program that it would recognize as usable
for compliance any emission allowance issued by any other state with an
EPA-approved state plan that also uses the specified EPA-approved
tracking system.
    States could also adopt such a collaborative emission trading
approach over time (through appropriate state plan revisions if the
plan is not already structured as ready-for-interstate-trading),
without requiring all of the original participating states to revise
their EPA-approved plans.
    Under the second implementation approach, a state could specify the
other states from which it would recognize issued emission allowances
as usable for compliance with its emission budget trading program. The
state would indicate in the regulatory provisions for its emission
budget trading program that emission allowances issued in other
identified partner states may be used by affected EGUs for compliance.
Such plans must indicate how allowances will be tracked from issuance
through use for compliance, through either a joint tracking system,
interoperable tracking systems, or EPA-administered tracking system.
The EPA would assess the design and functionality of this tracking
system(s) when reviewing individual submitted state plans.
    Under this approach, states could also join such a collaborative
emission trading approach over time. However, all participating states
would need to revise their EPA-approved plans. If the expanded linkage
is among previously approved plans with mass-based emission standards,
approval of the plan revision would be limited to assessing the
functionality of the shared tracking system or interoperable tracking
systems

in order to maintain the integrity of the linked programs.\926\
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    \926\ Depending on the specific regulatory provisions in the
emission standards in their approved state plans, participating
states may also need to revise their implementing regulations (and
by extension their state plans) to accept CO2 emission
allowances issued by new partner states as usable for compliance
with their mass-based emission standards.
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    a. Considerations for linked emission budget trading programs.
    For individually submitted plans, interstate emission allowance
linkages would not affect the approvability of each state's plan.
However, approvability of an individual linked plan would differ based
on the structure of the emission budget trading program included in the
plan. These differences for plan approvability address distinctions
among programs that include only affected EGUs and programs that cover
a broader set of emission sources, as well as if the plan is designed
to meet a state mass-based CO2 goal for affected EGUs only
or to meet a mass-based CO2 goal plus a new source
CO2 emission complement. Differences in approval criteria
are necessary to ensure that each individual state plan demonstrates it
will achieve a state's mass-based CO2 emission goal for
affected EGUs (or mass-based CO2 goal plus new source
CO2 emission complement). The accounting applied to
individual plans to assess whether a state achieves its mass-based
CO2 goal (or mass-based CO2 goal plus new source
CO2 emission complement) will also differ, based on whether
an emission budget trading program includes only affected EGUs (or
affected EGUs and applicable new fossil fuel-fired EGUs) or a broader
set of emission sources. These considerations are addressed below, for
both types of emission budget trading programs.
    (1) Links among emission budget trading programs that only include
affected EGUs or affected EGUs and applicable new fossil fuel-fired
EGUs. Where the emission budget trading programs in each plan apply
only to affected EGUs subject to the final rule (or emission budget
trading programs that apply to affected EGUs under the state plan and
applicable new fossil fuel-fired EGUs under state law), and include
compliance timeframes for affected EGUs that align with the interim and