As a result of these requirements and considerations, the EPA is
finalizing certain requirements for multi-state plan modifications. A
multi-state plan modification may be submitted to the EPA at any time.
However, an approved multi-state plan modification may only take effect
at the beginning of a new interim or final plan performance period.
These requirements are necessary to ensure that the emission
performance rates or state rate-based or mass-based CO2
goals in the emission guidelines are achieved. In addition, such
requirements for the timing of the effective date of multi-state plan
modifications are necessary for coordination of the implementation of
multi-state plans, especially where such plans include a multi-state
emission trading approach. This approach is also consistent with the
approach the EPA is proposing for the implementation of federal plan,
where relevant for a state(s).
    The EPA solicited comment on whether, for new projections of
emission performance included in a submitted plan modification, the
projection methods, tools, and assumptions used should match those used
for the projection in the original demonstration of plan performance,
or should be updated to reflect the latest data and assumptions, such
as assumptions for current and future economic conditions and
technology cost and performance. Comments received on this topic were
generally supportive of allowing the use of updated data in state plan
modifications, citing that states should have the ability to determine
whether the original data and assumptions or updated data and
assumptions are appropriate. The EPA is finalizing that new projections
of emission performance, the projection methods, tools, and assumptions
do not have to match those used for the projection in the original
demonstration of plan performance; they can be updated to reflect the
latest data and assumptions, such as assumptions for current and future
economic conditions and technology cost and performance.
    As discussed in more detail in section VIII.G.2, the final rule has
several measures to ensure that it does not interfere with the
industry's ability to maintain reliability. One such measure is that if
a state cannot address a reliability issue in accordance with an
approved state plan, the state can submit a request to the EPA to
modify the state plan. See section VIII.G.2 for a more detailed
discussion of this issue.
    The EPA is not finalizing any circumstances under which a state may
or may not revise its state plan, with the exception that a state may
not revise its state plan in a way that results in the affected EGU or
EGUs not meeting the requisite CO2 emission performance
levels.
    b. Modifications to interim and final CO2 emission
goals.
    As discussed in section VII, the final rule specifies that the
state interim and final CO2 emission goals for affected EGUs
in a state may be adjusted to address changes within a state's fleet of
affected EGUs. If these changes occur before a state submits its
initial submittal or final plan, the state should indicate in its
submittal the circumstance that necessitates the goal adjustment and
the revised interim or final CO2 emission goal. If the
circumstances occur after a state has an approved plan, a state must
submit a modification to its approved plan. The plan revision submittal
must indicate the circumstance that necessitates the goal adjustment,
the revised interim and/or final CO2 emission goal, and the
adjustments to the enforceable measures in the plan.
8. Plan Templates and Electronic Submittal
    The EPA is finalizing the requirement that submissions related to
this program

be submitted electronically. Specifically, that includes negative
declarations, state plan submittals (including any supporting materials
that are part of a state plan submittal), any plan revisions, and all
reports required by the state plan. The rule provides that files that
are submitted to the EPA in an electronic format may be maintained by
states in an electronic format. The submission of the information by
the authorized official must be in a non-editable format. In addition
to the non-editable version, the EPA is also requiring that all plan
components designated as federally enforceable must be submitted in an
editable version as well, as discussed below.
    a. Submittal of an editable version of federally enforceable plan
components.
    To ensure that the EPA has the ability to identify, evaluate,
merge, update and track federally enforceable plan components in a
timely and comprehensive manner, the EPA is requiring states to submit
an editable copy of the specific plan components in their submittals
that are designated as federally enforceable, either effective upon the
EPA plan approval or as a state plan backstop measure. The editable
version is in addition to the non-editable version. Examples of
editable file formats include Microsoft Word, Apple Pages and
WordPerfect.
    b. Revisions to an approved plan.
    States shall provide the EPA with both a non-editable and editable
copy of any submitted revision to existing approved federally
enforceable plan components, including state plan backstop measures.
The editable copy of any such submitted plan revision must indicate the
changes made, if any, to the existing approved federally enforceable
plan components, using a mechanism such as redline/strikethrough. This
approach to identifying the changes made to the existing federally
enforceable plan components is consistent with the criteria for
determining the completeness of SIP submissions set forth in Section
2.1(d) of Appendix V to 40 CFR part 51.
    c. Electronic submittal.
    It is the EPA's experience that electronic submittal of information
has increased the ease and efficiency of data submittal and data
accessibility. The EPA is developing the SPeCS, a web accessible
electronic system to support this requirement that will be accessed at
the EPA's Central Data Exchange (CDX) (http://www.epa.gov/cdx/). The
EPA will pre-register authorized officials and plan preparers in CDX.
See section VIII.E.2 for additional information on the pre-registration
process for authorized officials and plan preparers. Detailed
instructions for accessing CDX and SPeCS will be outlined in the
``111(d) SPeCS User Guide: How to submit state 111(d) plan material to
EPA'' which will be available on the EPA's Clean Power Plan Toolbox for
States. The EPA will provide SPeCS training for states prior to the
state plan submittal due date.
    Once in CDX, SPeCS can be selected from the Active Program Service
List. The preparer (e.g., state representative compiling a state plan
submittal) assembles the submission package. The preparer can upload
files and complete electronic forms. However, the preparer may not
formally submit and sign packages. Only registered authorized officials
may submit and sign for the state with the exception of draft
submittals. The EPA's intent is to allow submittal of draft plans or
parts of plans for early EPA review prior to formal submission by the
authorized official and will allow preparers, as well as authorized
officials, to submit draft documents. The authorized official will be
able to assemble submission packages and will be able to modify
submission packages that a preparer has assembled. The key difference
between the preparer and the authorized official is that the authorized
official can submit and sign a package for formal EPA review using an
electronic signature. In the case of a multi-state plan, each
participating state's authorized official must provide an electronic
signature.
    The process has been designed to be compliant with the Cross-Media
Electronic Reporting Rule (CROMERR), under 40 CFR part 3, which
provides the legal framework for electronic reporting under all of the
EPA's environmental regulations. The framework includes criteria for
assuring that the electronic signature is legally associated with an
electronic document for the purpose of expressing the same meaning and
intention as would a handwritten signature if affixed to an equivalent
paper document. In other words, the electronic signature is as equally
enforceable as a paper signature. For more information on CROMERR, see
the Web site: http://www.epa.gov/cromerr/. States who claim that a
state plan submittal or supporting documentation includes confidential
business information (CBI) must submit that information on a compact
disc, flash drive, or other commonly used electronic storage media to
the EPA. The electronic media must be clearly marked as CBI and mailed
to U.S. EPA/OAQPS/CORE CBI Office, Attention: State and Local Programs
Group, MD C539-01, 4930 Old Page Rd., Durham, NC 27703.
    The EPA received a number of comments on the electronic submittal
of state plans. Some commenters preferred the option to submit
electronically rather than the requirement to do so. In the final rule,
for the reasons discussed below, the EPA is requiring electronic
submittal of state plans and not allowing alternate options for plan
submittal (e.g. paper submittal).
    Requiring electronic submittal is in keeping with current trends in
data availability and will result in less burden on the regulated
community. Electronic submittal will facilitate two-way business
communication between states and the EPA, will guide states through the
submittal process to ensure submission of all required plan components,
and will enable states to submit proposed plans to the EPA
electronically for early EPA comments. Electronic submittal will also
facilitate, expedite and promote national consistency in the EPA's
review of state plans and promote transparency by providing
stakeholder-specific access to updated information on state plan status
and posting of plan requirements for viewing by the public, government
regulators and regulated entities. The EPA recently implemented an
electronic submittal process for SIPs under CAA section 110 and
continues to explore opportunities to increase the ease and efficiency
with which states and the regulated community can meet regulatory data
submittal requirements. In summary, the EPA believes electronic
submittal will be enormously beneficial in terms of improving
coordination and cooperation between the EPA and its state partners in
developing approvable state plans. We note, however, that there may be
some circumstances where having paper copies of the plan is needed to
facilitate public engagement, and encourage states to take those
considerations into account.
    d. Plan templates.
    In the proposal, the EPA requested comment on the creation of
templates for initial submittals and final state plan submittals.
Multiple commenters requested the EPA provide state plan templates. One
commenter requested templates for different plan designs (e.g. a mass-
based trading framework, a rate-based trading framework, multi-state
compliance and a utility-based portfolio approach) and for specific
plan components (e.g. how to incorporate a state RE standard and an EE
program into a state plan, how to assess the emission reductions
delivered by RE and EE). The EPA has determined that the broad range of
approaches states may take in preparing individual or multi-state plans
makes the

development of specific templates challenging and likely not useful to
states. However, concurrent with this final rule, the EPA is proposing
model rules for both rate- and mass-based programs in conjunction with
the proposed federal plan. These effectively can serve as a template
for states when preparing their state plan submittals. The EPA will
continue extensive outreach to states and work closely with them on the
need for additional tools and guidance to facilitate the development of
approvable state plans.
9. Legal Basis Regarding State Plan Process
    CAA section 111(d)(1) requires the EPA to promulgate procedures
``similar'' to those in section 110 under which states adopt and submit
CAA section 111(d) plans. The EPA has interpreted this provision
previously in the implementing regulations found in 40 CFR part 60
subpart B. As discussed above, the EPA intends that planned revisions
to the part 60 implementing regulations will clarify (among other
things) whether certain procedures are appropriate for the EPA's action
on CAA section 111(d) state plans, and if so, precisely how those
procedures should apply. The EPA is proposing these revisions to the
CAA section 111(d) implementing regulations in the notice of proposed
rulemaking for the federal plan being issued concurrently with this
final rule. In this section we discuss the legal basis for procedures
that the EPA is finalizing in this action: Initial submittals,
extensions, and plan revisions.
    First, by using the ambiguous word ``similar,'' Congress delegated
authority to the EPA to determine precisely what procedures would
govern 111(d) plans. ``Similar'' does not have an identical meaning as
the word ``same.'' One definition of ``similar'' is ``having likeness
or resemblance, especially in a general way.'' The American College
Dictionary 1127 (C.L. Barnhart, ed. 1970). On the other hand, ``same''
is defined as ``alike in kind, degree, quality; that is, identical'' or
``unchanged in character.'' Id. at 1073.
    Had Congress intended that the procedures for section 111(d) plans
be indistinguishable from those in section 110, Congress knew how to
say so. See, e.g., 36 U.S.C. 2352(b)(2)(B) (``same procedures''). And
had Congress intended that the procedures for section 111(d) plans be
as close as possible to those in section 110, Congress knew how to say
that. See, e.g., 38 U.S.C. 4325(c) (agency ``shall ensure, to the
maximum extent practicable, that the procedures are similar to''
certain other procedures). Therefore, Congress must have intended to
give the EPA leeway to create procedures for section 111(d) state plans
that somewhat vary from those in section 110, so long as the section
111(d) procedures are reasonably tied to the purpose and text of
section 111(d). In other words, ``similar'' creates a gap in the
statute that the EPA may reasonably fill.
    a. Initial submittals and extensions.
    Initial submittals in this instance are a reasonable gap-filling
procedural step. As explained in our proposal, certain aspects of
section 111(d) plan development for these particular guidelines warrant
our creation of this procedural step, even though section 110 does not
provide for initial submittals. As explained above, though, we are not
bound under section 111(d)(1) to follow exactly the same procedures.
    With respect to the timing of initial submittals, final submittals,
and extensions, we note that section 111 does not prescribe any
particular deadlines, instead leaving it to EPA's discretion to
establish ``similar'' procedures to section 110. The implementing
regulations for section 111(d) plans require state plans to be
submitted within 9 months of finalization of emission guidelines.
Section 110(a)(1) provides that states should adopt and submit SIPs
that provide for implementation, maintenance, and enforcement of the
NAAQS within 3 years, or such shorter period as the Administrator may
prescribe.\847\ As further explained in Section VIII.E., the EPA is
providing states with up to 3 years to submit a final plan under this
rule, contingent upon the grant of an extension through an initial
submittal due by September 6, 2016. Section 110(a)(1) does not provide
any particular factors for the Administrator to consider in prescribing
a shorter period. Thus, the EPA's prescription of a shorter period for
either an initial submittal or a final plan submittal is consistent
with the discretion granted in section 110(a)(1). We further discuss
why the September 6, 2016 initial submittal deadline is reasonable in
Section VIII.E., and such deadline is achievable by states seeking to
submit a final plan within 3 years. We also note that section 110(b)
provides for extensions of 2 years for plans to implement secondary
NAAQS, that other provisions in part D provide for extensions of due
dates of attainment plans in certain circumstances, and that the
section 111(d) implementing regulations provide for extensions
generally. We conclude, in view of the above discussion of ``similar,''
that the approach of initial submittals and extensions of due dates as
proposed are reasonable procedures that, while not identical to the
procedures in section 110, are still similar.
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    \847\ Under this grant of authority to prescribe shorter
deadlines, the EPA has in a number of occasions required SIPs to be
submitted in 1 year.
---------------------------------------------------------------------------

    Some commenters argued that the 1-year period for initial
submittals and, even assuming an extension, the additional 1- to 2-year
period for final submittals were unreasonably short, particularly in
light of the possibility that some state legislatures might need to act
to provide adequate legal authority for these particular plans. We are
not finalizing the 1-year extension for single state submittals, and we
have addressed concerns about legal authority for the initial
submittals by allowing states to identify remaining legislative action
in those submittals.
    With respect to the overall period of up to 3 years for submittals,
we continue to find it reasonable and consistent with other deadlines
in the CAA. First, section 110(a)(1) requires states to submit a plan
for implementation, maintenance, and enforcement of new NAAQS within 3
years of promulgation of that NAAQS. This is true even if the EPA
promulgates a NAAQS for a previously non-criteria pollutant. In that
case, it is possible and even likely that at least some state agencies
will lack statutory authority to regulate the new pollutant.
Nonetheless, Congress dictated that states should submit section
110(a)(1) plans within 3 years.
    Furthermore, we note that under subpart 1 of Part D of Title 1,
attainment plans are generally due no later than 3 years after
designation of a nonattainment area, and under other subparts of Part
D, plans are due even more quickly. For example, under subpart 4,
attainment plans for particulate matter are generally due 18 months
after designation, and under subpart 5, the same deadline applies for
attainment plans for sulfur oxides, nitrogen dioxide and lead.
Developing attainment plans may or may not require states to seek
additional legislative authority, but certainly in terms of complexity
they are similar to section 111(d) plans for this guideline. In
general, attainment plans must contain (among other things) a
comprehensive inventory of sources of the relevant pollutant and its
precursors (which in populated areas can be very numerous), control
measures for those sources (including individualized control measures
for the larger sources), and modeled demonstrations of

attainment (which in some instances requires photochemical grid
modeling). Thus, it is reasonable to have the same timeline for these
section 111(d) plans as Congress generally provided for attainment
plans in section 172(b).
    b. State plan modifications.
    Section 110(l) provides for states to revise their SIPs, as does 40
CFR 60.28 for section 111(d) plans. Section 110(l) also sets out a
standard for revisions: It prohibits the EPA from approving a SIP
revision that would interfere with any applicable requirement
concerning attainment or reasonable further progress, or any other
applicable requirement of the CAA. Under the existing section 111(d)
implementing regulations, the Administrator will disapprove section
111(d) plan revisions as unsatisfactory when they do not meet the
requirements of subpart B to part 60. See 40 CFR 60.27(c)(3). However,
the implementing regulations do not set forth a substantive standard
like that in section 110(l).
    Section 111(d)(1) does not mention revisions (except indirectly
through the reference to section 110) and, therefore, does not
explicitly provide any substantive requirements for them. There is,
therefore, a gap in the statute that the EPA may reasonably fill, since
many stakeholders commented on the desirability of states being able to
modify their plans, and the EPA agrees. It is reasonable, at a minimum,
that the state plan as revised should continue to provide for
implementation and enforcement of the standards of performance, and to
achieve the CO2 emission performance rates or state
CO2 emission performance goal. This is analogous to the
substantive requirements of section 110(l), which as explained above
for section 110(a)(2), we may consider in determining how to reasonably
fill statutory gaps for section 111(d) plans.
    In our proposal, we stated that certain revisions to state plans
under these emission guidelines, those that revised enforceable
measures for affected EGUs, should satisfy some additional conditions.
First, the state should demonstrate that the plan continues to achieve
the CO2 emission performance rates or state CO2
emission performance goal. We proposed that this demonstration might be
simple for minor revisions, but for major revisions a more complete
demonstration may be required. We are finalizing this proposal. As
legal basis for this position, we note that a demonstration is
necessary to show that a state plan provides for implementation of
standards of performance that achieve the CO2 emission
performance rates or state CO2 emission performance goal,
and as explained above we can reasonably require the same of revisions.
    It is also reasonable to tailor the requirements of the
demonstration to the magnitude of the revision. The EPA has taken a
similar approach to tailoring the requirements for a technical
demonstration that, under section 110(l), a SIP revision does not
interfere with any applicable requirement concerning attainment of the
NAAQS. If a SIP revision does not relax the stringency of any SIP
measure, then the demonstration is simple. If the SIP revision does
relax the stringency of SIP measures, then a qualitative or
quantitative analysis may be necessary to show non-interference,
depending on the nature of the revision, the current air quality in the
area, and other factors.
    Finally, we proposed that revisions ``should not result in reducing
the required emission performance for affected EGUs specified in the
original approved plan. In other words, no `backsliding' on overall
plan emission performance through a plan modification would be
allowed.'' 79 FR 34917/1. We received adverse comments that this
standard did not have a basis in section 111(d). According to
commenters, since the standard for EPA approval of a section 111(d)
plan is whether the plan is satisfactory in establishing and providing
for implementation and enforcement of standards of performance that
achieve the emission performance rates or goal, the same standard
should apply to revisions. In other words, the standard for revisions
should be whether the plan as revised is satisfactory. We believe that
our proposal was unclear as to this point, and we agree that the
standard for revisions should be the same as for submittals. We have
finalized this position.

F. State Plan Performance Demonstrations

    This section describes state plan requirements related to
compliance periods, monitoring and reporting for affected EGUs; plan
performance demonstrations; consequences if the CO2 emission
performance rates or state CO2 emission goals are not met;
and out-year requirements.
1. Compliance Periods, Monitoring and Reporting Requirements for
Affected EGUs
    For plans that include emission standards on affected EGUs, the EGU
emission standards for the interim period must have schedules of
compliance for each interim step 1, 2 and 3 for the calendar years
2022-2024, 2025-2027 and 2028-2029, respectively. For the final period,
EGUs must have emission standards that have schedules of compliance for
each 2 calendar years starting in 2030 (i.e., 2030-2031, 2032-2033,
2034-2035, etc.). If a backstop is triggered for a state measures plan,
the schedule of compliance for the federally enforceable emission
standards must begin no later than 18 months after the backstop is
triggered and end at the end of the same compliance period. For
example, if a backstop is triggered on July 1, 2025, the compliance
period for the backstop emission standards must begin no later than
January 1, 2027, and end on December 31, 2027. The next compliance
period for the backstop emission standards would be January 1, 2028-
December 31, 2029.
    In the June 2014 proposal, the EPA proposed that the appropriate
averaging time for any rate-based emission standard for affected EGUs
be no longer than 12 months within a plan performance period and no
longer than 3 years for a mass-based standard. The EPA solicited
comments on longer and shorter averaging times for emission standards
included in state plans. The EPA received comments stating that the
proposed 12-month averaging was too short and that there was no reason
why the compliance period under a rate-based plan should be different
from a mass-based plan. Comments stated that a multi-year averaging
period is appropriate for rate-based and mass-based plans to account
for variations that can occur in a single year, allowing operators the
flexibility they need to manage unforeseen events. The commenters also
recommended that the final rule use discrete 3-year periods for
compliance reconciliation instead of the rolling-average approach
proposed.
    The EPA has considered all comments received on this matter and is
finalizing the compliance periods specified above, which respond to the
comments by applying to both rate- and mass-based programs, providing
compliance periods longer than 1 year, and establishing block
compliance periods rather than a rolling average approach. We agree
with comments that longer averaging periods allow for operational and
seasonal variability to even out. The EPA finalizes that states can
choose to set shorter compliance periods for their emission standards
but none that are longer than the compliance periods the EPA is
finalizing in this rulemaking. If a state chooses to set shorter
compliance periods, we urge them to make efforts to be cognizant of
other deadlines facing EGUs to assure that there will not be

conflicts. The EPA recognizes that the compliance periods provided for
in this rulemaking are longer than those historically and typically
specified in CAA rulemakings. ``The time over which [the compliance
standards] extend should be as short term as possible and should
generally not exceed one month.'' See e.g., June 13, 1989 ``Guidance on
Limiting Potential to Emit in New Source Permitting'' and January 25,
1995 ``Guidance on Enforceability Requirements for Limiting Potential
to Emit through SIP and Sec.  112 Rules and General Permits.'' However,
the EPA has determined that the longer compliance periods provided for
in this rulemaking are acceptable in the context of this specific
rulemaking because of the unique characteristics of this rulemaking,
including that CO2 is long-lived in the atmosphere, and this
rulemaking is focused on performance standards related to those long-
term impacts. The distinction between these unique characteristics and
the EPA's general practice regarding compliance periods is bolstered by
the EPA guidance on appropriate averaging periods for emission
limitations in NAAQS implementation. For example, the EPA guidance has
stated that in implementation of the ozone standards, which have a
short averaging period, the averaging period for VOC emission
limitations should be correspondingly short. See 51 FR 43857. A longer
averaging period for VOC emission limitations (VOCs are one of the key
precursors to ozone formation) can allow spikes in emissions that
adversely impact ambient air and violate the short term ozone
standards. This is precisely the opposite of the unique characteristics
cited above: the long-lived persistence of CO2 in the
stratosphere and the intent of these guidelines to address the long-
term impacts.
    State plans must contain requirements for tracking and reporting
actual plan performance during implementation, which includes reporting
of CO2 emissions from affected EGUs. Affected EGUs must
comply with emissions monitoring and reporting requirements that are
largely incorporated from 40 CFR part 75 monitoring and reporting
requirements. The majority of affected EGUs are already familiar with
the reporting requirements of part 75, and because of this, the EPA has
chosen to streamline the applicable reporting requirements for affected
EGUs under the state plans in the final rule. States must require all
affected EGUs to monitor and report hourly CO2 emissions and
net energy output (including total net MWh output that is comprised of
generation, and where applicable, useful thermal output converted to
net MWhs) on a quarterly basis in accordance with 40 CFR part 75. Note
that this requirement applies for all types of state plans, regardless
of whether the state chooses the option of the CO2 emission
performance rates, a state rate-based CO2 emission goal, or
a state mass-based CO2 emission goal.
    In the June 2014 proposal, the EPA proposed that state plans must
include monitoring, reporting and recordkeeping requirements for useful
energy output from affected EGUs. Multiple commenters questioned
whether gross rather than net electrical production should be reported
by affected EGUs and recommended that the EPA should utilize gross
rather than net generation. Many commenters recommended electricity be
reported in the form used in the 111(b) rules for consistency between
reporting requirements and simplification of calculation of emission
limitations between new and old sources. Commenters also stated that to
the extent the EPA seeks to provide guidance to states regarding its
preferred monitoring and reporting procedures, the EPA should encourage
states to avoid imposing additional monitoring and reporting burdens by
taking advantage of the monitoring requirements that already exist to
the greatest extent possible. For example, the commenters noted that
the 40 CFR part 75 monitoring procedures used to comply with other
programs, such as the Title IV Acid Rain Program, provide much of the
data that would be needed to demonstrate compliance under the rule.
Comments stated that the June 2014 proposal appeared to mandate a
monitoring approach that would eliminate key flexibilities provided in
the part 75 regulations, thus requiring utilities to maintain separate
document collection and reporting procedures and potentially
eliminating important alternative monitoring options intended to ensure
representative, cost-effective monitoring approaches are available. The
commenters asked the EPA to revise its proposal to make clear that the
procedures established under part 75 will suffice or explain the need
for any exceptions. Commenters indicated that the rule should require
all affected EGUs to monitor CO2 emissions and net hourly
electric output under 40 CFR part 75, and report the data using the
EPA's Emission Collection and Monitoring Plan System (ECMPS) assuring a
more uniform monitoring and reporting process for all EGUs. The EPA
believes that the final monitoring and reporting requirements (via
ECMPS) address the issue of duplicative requirements and alleviate
concern about lost flexibility raised by commenters.
2. Plan Performance Demonstrations
    The state plan must include emission performance checks, and for
state measures plans, periodic program implementation milestones. The
state plan must provide for tracking of emission performance, and for
measures to be implemented if the emission performance of affected EGUs
in the state does not meet the applicable CO2 emission
performance rates or state CO2 emission goal during a
performance period.
    As discussed above in section VII, the agency is finalizing
CO2 emission performance rates or state-specific
CO2 emission goals that represent emission levels to be
achieved by 2030 and emission levels to be achieved over the 2022-2029
interim period, and over three interim steps of 2022-2024, 2025-2027
and 2028-2029. A state may choose to define different interim step
emission levels for achieving its required 2022-2029 average
performance rate. The EPA recognizes the importance of ensuring that,
during the 8-year interim period (2022-2029) for the interim
performance rates or interim state goal, a state is making steady
progress toward achieving the required level of emission performance.
For both emission standards plans and state measures plans, the final
rule requires periodic checks on overall emission performance leading
to corrective measures or implementation of the backstop, if necessary,
as described in section VIII.F.3 below. States must demonstrate that
the interim steps were achieved at the end of the first two interim
step periods.
    In 2032 and every 2 years thereafter, states must demonstrate that
affected EGUs achieved the final performance rates or state goal on
average or cumulatively, as appropriate, during each 2-year reporting
period (i.e., 2030-31, 2032-33, 2034-2035 etc.). The multi-year
performance periods for measuring actual plan performance against the
performance rates or state goals allow states some flexibility that
accounts for seasonal operation of affected EGUs, and inclusion of RE
and demand-side EE efforts.
    For a rate-based plan, emission performance is an average
CO2 emission rate for affected EGUs representing cumulative
CO2 emissions for affected EGUs over the course of each
reporting period divided by cumulative MWh

energy output \848\ from affected EGUs over the reporting period, with
rate adjustments for qualifying measures, such as RE and demand-side EE
measures. For a mass-based plan, emission performance is total tons of
CO2 emitted by affected EGUs over the reporting period.
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    \848\ For EGUs that produce both electric energy output and
other useful energy output, there would also be a credit for non-
electric output, expressed in MWh.
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    For emission standards plans, as discussed in section VIII.D, the
state must submit a report to the EPA containing the emissions
performance comparison for each reporting period no later than the July
1 following the end of each reporting period (i.e., by July 1, 2025;
July 1, 2028; July 1, 2030; July 1, 2032; and so on). As discussed in
section VIII.D, the emission comparison required in the July 1, 2030
report must compare the actual emissions from affected EGUs over the
interim period (2022-2029) with the interim CO2 emission
performance rates or state CO2 emission goal. The report is
not required to include a comparison for the interim step 3 period, but
must include the actual emissions from affected EGUs during the interim
step 3 period.
    The EPA notes that for certain types of emission standards plans,
with mass-based emission standards in the form of an emission budget
trading program, achievement of a state's mass-based CO2
goal (including interim step goals and final goal) will be assessed by
the EPA based on compliance by affected EGUs with their emission
standards under the program, rather than CO2 emissions
during a specific interim step period or final period. This approach is
limited to plans with emission budget trading programs where compliance
by affected EGUs with the emission standards will ensure that, on a
cumulative basis, the state interim and final mass-based CO2
goals are achieved.\849\ This approach allows for CO2
allowance banking across plan performance periods, including from the
interim period to the final period. As a result, CO2
emissions by affected EGUs could differ from the state mass-based
CO2 goal during an individual plan performance period, but
on a cumulative basis CO2 emissions from affected EGUs would
not exceed what is allowable if the interim and final CO2
goals are achieved.
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    \849\ Emission budget trading programs in such plans establish
CO2 emission budgets equal to or less than the state mass
CO2 goal, as specified for the interim plan performance
period (including specified levels in interim steps 1 through 3) and
the final 2-year plan performance periods.
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    Also as discussed in section VIII.D, states that choose a state
measures plan must submit an annual report no later than July 1
following the end of each calendar year in the interim period. This
annual report must include the status of the implementation of
programmatic state measures milestones identified in the state plan
submittal. The annual report that follows the end of each reporting
period (i.e., 2022-2024, 2025-2027, and 2028-2029) must also include an
emissions performance comparison for the reporting period, as described
above for the emission standards plan. As discussed in section VIII.D,
the emission comparison required in the July 1, 2030 report must
compare the actual emissions from affected EGUs over the interim period
(2022-2029) with the interim CO2 emission performance rates
or state CO2 emission goal. The report is not required to
include a comparison for the interim step 3 period, but must include
the actual emissions from affected EGUs during the interim step 3
period. Beginning with the final period of 2030 and onward, states
using a state measures plan must submit a biennial report no later than
July 1 following the end of each reporting period with an emission
performance comparison for each reporting period, consistent with the
reporting requirements for emission standards plans.
    In the June 2014 proposal, the EPA proposed that a state report is
due to the EPA no later than July 1 of the year immediately following
the end of each reporting period. The EPA requested comment on the
appropriate frequency of reporting of the different proposed reporting
elements, considering both the goals of minimizing unnecessary burdens
on states and ensuring program effectiveness. In particular, the agency
requested comment on whether full reports containing all of the
elements should only be required every 2 years rather than annually and
whether these reports should be submitted electronically, to streamline
transmission.
    The EPA mainly received adverse comments for requiring annual state
reporting; commenters stated that this requirement was too burdensome
for both states and the EPA. Commenters also requested that the EPA
extend the due date of the annual report from July 1 to at least
December 31. Commenters stated that because of the timing of current
data collection and the need to leave time to organize and submit the
reports, allowing only 6 months after the close of the year is
problematic. Commenters asked that the EPA consider reducing the amount
of data required if annual reporting was required.
    Considering the comments received and the goals of minimizing
unnecessary burdens on states and ensuring program effectiveness, the
EPA has reduced the frequency of reporting of emissions data to every 3
years for the first two interim steps and every 2 years thereafter.
However, the EPA is finalizing that state reports are due to the EPA no
later than July 1 following the end of each reporting period. The EPA
believes states can design their state plans to receive the data and
information needed for these reports in a timely manner so that this
requirement can be met. Furthermore, some of the state reporting
requirements, such as reporting of EGU emissions, can be met through
existing reporting mechanisms (ECMPS) and would not place additional
burdens on states.
3. Consequences if Actual Emission Performance Does Not Meet the
CO2 Emission Performance Rates or State CO2
Emission Goal
    The EPA recognizes that, under certain scenarios, an approved state
plan might fail to achieve a level of emission performance that meets
the emission guidelines or the level of performance established in a
state plan for an interim milestone. Despite successful implementation
of certain types of plans, emissions under the plan could turn out to
be higher than projected at the time of plan approval because actual
conditions vary from assumptions used when projecting emission
performance. Emissions also could theoretically exceed projections
because affected entities under a state plan did not fulfill their
responsibilities, or because the state did not fulfill its
responsibilities.
    The final rule specifies the consequences in the event that actual
emission performance under a state plan does not meet, or is not on
track to meet, the applicable interim and interim step CO2
emission performance rates or state goals in 2022-2029, or does not
meet the applicable final CO2 emission performance rates or
state CO2 emission goal in 2030-2031 or later. The
determination that a state is not on track to meet the applicable
interim goal or interim step goals in 2022-2029 or the applicable final
goal in 2030-2031 or later, or the CO2 emission performance
rates, will be made through the actual performance checks to be
included in state reports of performance data described in section
VIII.D.2.a above.
    For emission standards plans, the final rule specifies that
corrective measures must be enacted once triggered. Corrective measures
apply

only to emission standard plans in which full compliance by affected
EGUs would not necessarily lead to achievement of the emission
performance rates or CO2 emission goals.\850\ For such
plans, corrective measures are triggered if actual CO2
emission performance by affected EGUs is deficient by 10 percent or
more relative to the specified level of emission performance in the
state plan for the step 1 or step 2 interim performance periods.
Corrective measures also are triggered if actual emission performance
fails to meet the specified level in the plan for the 8-year interim
period 2022-2029, or for any 2-year final goal performance period
(beginning in 2030). In such cases, the state report must include a
notification to the EPA that corrective measures have been triggered.
If, in the event of such an exceedance, the EPA determines that
corrective measures have been triggered and the state has failed to
notify the EPA, the EPA will inform the affected EGUs that corrective
measures have been triggered.\851\
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    \850\ To be specific, corrective measures requirements apply to
all emission standard plan designs that do not mathematically assure
that the plan performance level will be achieved when all affected
EGUs are in compliance with their emission standards, regardless of
electricity production and electricity mix. Corrective measures
requirements apply, for example, to emission standards plans that
include standards on affected EGUs that differ from the emission
performance rates in the guidelines. Backstop requirements apply to
state measures plans.
    \851\ The EPA notes that as part of the proposed federal plan
rulemaking, it is proposing a regulatory mechanism to call plans in
the instances of substantial inadequacy to meet applicable
requirements or failure to implement an approved plan.
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    When corrective measures are triggered, if the state plan does not
already contain corrective measures, the state must submit to the EPA a
plan revision including corrective measures that adjust requirements or
add new measures. The corrective measures must both ensure future
achievement of the CO2 emission performance rates or state
CO2 emission goal and achieve additional emission reductions
to offset any emission performance shortfall that occurred during a
performance period. The shortfall must be made up as expeditiously as
practicable. The state plan revision submission must explain how the
corrective measures both make up for the shortfall and address the
state plan deficiency that caused the shortfall. The state must submit
the revised plan to the EPA as expeditiously as practicable and within
24 months after submitting the state report indicating the exceedance.
The 24-month time period allows time to identify corrective measures
and make rule changes through state regulatory processes. The EPA will
then act on the plan revision within 12 months, consistent with other
plan revisions and with the timing for final plan submittals originally
submitted by states. The state must implement corrective measures
within 6 months of the EPA's approval of a plan revision adding them.
    For states using the state measures approach, the EPA is finalizing
the backstop requirement as described in section VIII.C.3 of this
preamble. As discussed in section VIII.D.2, the determination that a
state using the state measures approach is not on track to meet the
applicable interim goal or interim step goals in 2022-2029, or the
applicable final goal in 2030-2031 or later, is based on checks that
must be included in state reports that must be submitted annually
during the interim period and biennially during the final period. The
state must annually report on its progress in meeting its programmatic
state measures milestones during the interim period. In addition, the
state must report actual emission performance checks, similar to the
requirements discussed above for emission standards plans, in 2025,
2028, 2030, and every 2 years thereafter. If, at the time of the state
report to the EPA, the state did not meet the programmatic state
measures milestones for the reporting period, or the performance check
shows that the plan's actual CO2 emission performance
warrants implementation of backstop requirements,\852\ the state must
include in the state report a notification to the EPA that the backstop
has been triggered. If, in the event of such an exceedance, the EPA
determines that the backstop has been triggered and the state has
failed to notify the EPA, the EPA will inform the affected EGUs that
the backstop has been triggered.\853\
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    \852\ As explained in section VIII.C.3.b., state measures plans
must require the backstop to take effect if actual CO2
emission performance fails to meet the level of emission performance
specified in the plan over the 8-year interim performance period
(2022-2029), or for any 2-year final goal performance period. The
plan also must require the backstop to take effect if actual
emission performance is deficient by 10 percent or more relative to
the performance levels that the state has chosen to specify in its
plan for the interim step 1 period (2022-2024) or the interim step 2
period (2025-2027).
    \853\ The EPA notes that as part of the proposed federal plan
rulemaking, it is proposing a regulatory mechanism to call plans in
the instances of substantial inadequacy to meet applicable
requirements or failure to implement an approved plan.
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    For multi-state plans, corrective measure or backstop provisions
would be required for the same plan approaches for which those
provisions are required in individual state plans. For multi-state
plans using plan approaches to which corrective measures or backstop
requirements apply, all states that are party to the multi-state plan
would be subject to corrective action or backstop requirements, and
requirements to make up the past CO2 emission performance
shortfall, if those requirements were triggered. This is because multi-
state plans are joint plans (even if created through separate state
submittals). That would not be the case for coordinated individual
state plans linked through interstate ERC or emission allowance
trading. In the case of coordinated individual state plans, for plan
types subject to corrective measure or backstop requirements, the state
where the CO2 emission performance deficiency occurs would
be required to implement corrective measures or backstop requirements
for affected EGUs, as applicable, and remedy the past CO2
emission performance shortfall.
    Multiple commenters requested that corrective measures not be
required in the case of a catastrophic, uncontrollable event. We
recognize that there are potential system emergencies that cannot be
anticipated that could cause a severe stress on the electricity system
for a length of time such that the multi-year requirements in a state
plan may not be achievable by certain affected EGUs without posing an
otherwise unmanageable risk to reliability. We are finalizing a
reliability safety valve, which includes an initial period of up to 90
days during which a reliability-critical affected EGU or EGUs will not
be required to meet the emission standard established for it under the
state plan but rather will meet an alternative standard. While the
initial 90-day period is in use, 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 and will not be counted as an exceedance that
would otherwise trigger corrective measures under an emission standard
plan type or an exceedance that would trigger a backstop under a state
measures plan type. Use of the reliability safety valve will not alter
or abrogate any other obligations under the approved state plan. After
the initial period of up to 90 days, the reliability-critical affected
EGU is required to continue to operate under the original state plan
emission standard or an alternative standard as part of the

reliability safety valve, and the state must revise its plan to
accommodate changes needed to respond to ongoing reliability
requirements and to ensure than any emissions excess of the applicable
state goals or performance rates occurring after the initial period of
up to 90 days are accounted for and offset. See section VIII.G.2.e of
this preamble.
    Multiple commenters supported the inclusion of strong enforcement
measures for ensuring the interim and final goals are met, including
the required use of corrective measures when triggered. Other
commenters provided feedback as to the percentage that actual emission
performance would need to exceed the level of emission performance
specified in the statewide plan to trigger corrective measures. Some
commenters supported the trigger that we are finalizing (actual
emissions or emission rate performance that is 10 percent or more than
the specified level of emission performance in the state plan for the
interim step 1 or step 2 performance periods), while some recommended a
lower or higher trigger.
    The agency is finalizing the trigger at the level of 10 percent for
the interim step 1 or step 2 performance periods. Ten percent is a
reasonable level to ensure that when deficiencies in state plan
performance begin to emerge, corrective measures (or backstop
requirements) will be implemented promptly to avoid emissions
shortfalls (or minimize the extent of shortfalls) relative to the 8-
year interim goal and the final goal, which reflect the BSER. The 10
percent figure also provides latitude for a state's emission
improvement trajectory during the interim period to deviate a bit from
its planned path without triggering these requirements, as the state
initiates or ramps up programs to meet the 8-year interim goal and
final goal.
    The EPA requested comment on whether the agency should promulgate a
mechanism under CAA section 111(d) similar to the SIP call mechanism in
CAA section 110. Under this approach, after the agency makes a finding
of the plan's failure to achieve the CO2 emission
performance rates or state CO2 emission goal during a
performance period, the EPA would require the state to cure the
deficiency with a new plan within a specified period of time. If the
state still lacked an approved plan by the end of that time period, the
EPA would have the authority to promulgate a federal plan under CAA
section 111(d)(2)(A). 79 FR 34830, 34908/1-2 (June 18, 2014).
    The EPA intends that planned revisions to the part 60 implementing
regulations will clarify (among other things) whether the EPA has
authority to call for plan revisions under section 111(d) when a
state's plan is not complying with the requirements of this guideline,
and if so, precisely what procedures should apply. The EPA is proposing
these revisions to the 111(d) implementing regulations in the notice of
proposed rulemaking for the federal plan. The EPA is not taking final
action now on this issue or the related change to the implementing
regulations.
    a. Legal basis for corrective measures.
    The EPA discussed the concept of corrective measures in our 1992
General Preamble for the Implementation of Title I of the CAA
Amendments of 1990. 57 FR 13498 (Apr. 16, 1992). The General Preamble
sets out four general principles that apply to all SIPs, ``including
those involving emissions trading, marketable permits and allowances.''
Id. at 13568. The fourth principle, accountability, means (among other
things) that ``the SIP must contain means . . . to track emission
changes at sources and provide for corrective action if emissions
reductions are not achieved according to the plan.'' In the General
Preamble, we noted that Part D of Title I explicitly provided for this
in certain instances by requiring milestones and contingency measures.
    Some commenters noted that the contingency measures explicitly
required by part D are required to be adopted in the attainment plan
and ready to implement when a milestone is not achieved or the area
fails to attain the relevant NAAQS. These commenters therefore
concluded that corrective measures for 111(d) plans should likewise
already be adopted in the 111(d) plan and ready to implement. We
disagree. Under Part D, contingency measures are not expected to fully
bring the area into attainment. In fact, this would not be possible
given the difficulty of predicting in advance exactly what measures
would be needed to fully attain. A better analogue in Part D for the
corrective measures in these guidelines is the primary way Part D
addresses failure to attain: The state is required to revise its plan
in various ways within a certain time in order to bring about
attainment. See, e.g., section 179(d). This is analogous to what we are
requiring for corrective measures. Thus, part D contingency measures
are unlike the corrective measures in this rule.
    However, the requirement to revise an attainment plan in response
to failure to attain differs somewhat from the corrective measures in
these guidelines. Under these guidelines, the corrective measures must
make up the difference by which the plan fell short of the goal,
including any prior shortfall that had accumulated if the plan fell
short of the goal in prior years. There is no corresponding requirement
in attainment planning to increase the stringency of the plan by an
amount that somehow makes up for any shortfall in attainment from prior
years; instead the revised plan must demonstrate attainment going
forward, and other more stringent requirements (such as requirements
for best available control measures) may be triggered.
    This distinction is the natural result of the difference between
these guidelines and NAAQS attainment planning. In this case, we are
finalizing guidelines representing technology-based standards for a
pollutant with cumulative and long-lasting effects. If a plan falls
short of a performance goal, then in effect the standards of
performance in the plan have failed to reflect the BSER over the
corresponding period. Due to the cumulative effects of CO2,
it is possible to remedy this failure by requiring the plan to be
revised in such a way that the standards of performance in the revised
plan will reflect the BSER over the cumulative plan period, and this
can be done by requiring the revised plan to make up the shortfall from
the previous period. In short, the flexibility that these guidelines
provide should not come at the cost of allowing the standards of
performance to reflect less than the BSER over the long run.\854\
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    \854\ Similar considerations apply to the requirement under the
state measures approach to revise the plan to make up the shortfall.
---------------------------------------------------------------------------

    Some commenters noted that 111(d) does not contain explicit
provisions regarding corrective measures, and they therefore inferred
that the EPA is not authorized to require them. That inference is
mistaken. The requirement for 111(d) plans to ``provide for
implementation and enforcement'' of the standards of performance is
ambiguous and does not directly speak to whether corrective measures
should or should not be required. There is therefore a gap for the EPA
to fill. While the discussion above about Part D does not independently
provide any authority to fill this gap, the fact that Congress created
a scheme with stages of planning in Part D suggests that it would be
reasonable, if appropriate, to fill this gap in 111(d) in a similar
way.
    In this guideline, it is appropriate for emission standards plans
to fill this gap with corrective measures if triggered. There are two
ways an emission standards plan can provide for implementation of
standards of performance that achieve the CO2

emission performance rates or requisite state CO2 emission
performance goal. First, the state can set emission standards that
necessarily achieve the performance rates or goal, even if the affected
EGUs in the future vary in their relative amounts of electricity
generated. Second, the state can set emission standards that are
demonstrated to achieve the performance rates or goal based on
assumptions about the relative amounts of electricity generated, but
which may turn out to not actually achieve the goal even if all
affected EGUs comply. This is analogous to an attainment plan that
demonstrated attainment by the applicable attainment date, but due to
unpredicted economic changes actually failed to attain. In this second
case, the EPA interprets the ambiguous language ``provide for
implementation . . . of standards of performance'' in the context of
achieving the performance rate or emissions goal, to mean that at the
time the plan is submitted it must contain some mechanism to check the
progress of the plan and correct course. The EPA has determined that,
for this particular rule, the minimum mechanism is the set of
milestones and provisions for corrective measures specified in this
rule. Indeed, not requiring corrective measures in the case of
deficient plan performance would undercut the viability of state plan
options other than emission standard plans with uniform rates applied
to all affected EGUs within the state.
4. Out-Year Requirements: Maintaining or Improving the Level of
Emission Performance Required by the Emission Guidelines
    The agency is determining CO2 emission performance rates
and state CO2 emission goals for affected EGU emission
performance based on application of the BSER during specified time
periods. This raises the question of whether affected EGU emission
performance should be maintained at the 2030 level--or instead should
be further improved--once the final CO2 emission performance
rate or state CO2 emission goal is met in 2030. This
involves questions of performance rate and goal-setting as well as
questions about state planning. The EPA believes that Congress either
intended the emission performance improvements required under CAA
section 111(d) to be maintained or, through silence, authorized the EPA
to reasonably require maintenance. Other CAA section 111(d) emission
guidelines set emission limits that do not expire. Therefore, the EPA
is finalizing that the level of emission performance for affected EGUs
represented by the final CO2 emission performance rates or
state CO2 emission goal must continue to be maintained in
the years after 2030.
    As noted above, the state plan must demonstrate that plan measures
are projected to achieve the final emission performance level by 2030.
In addition, the state plan must identify requirements that continue to
apply after 2030 and are likely to maintain affected EGU emission
performance meeting the final goal. The state plan would be considered
to provide for maintenance of emission performance consistent with the
final goal if the plan measures used to demonstrate projected
achievement of the final goal by 2030 will continue in force and not
sunset. After implementation, the state is required to compare actual
plan performance against the final goal on a 2-year average basis
starting in 2030, and to implement corrective measures or a backstop if
triggered.
    In the proposal, the EPA noted that ``CAA section 111(b)(1)(B)
calls for the EPA, at least every eight years, to review and, if
appropriate, revise federal standards of performance for new sources''
in order to assure regular updating of performance standards as
technical advances provide technologies that are cleaner or less
costly. The proposal ``requests comment on the implications of this
concept, if any, for CAA section 111(d).'' 79 FR 34830, 34908/3 (June
18, 2014).
    We acknowledge the obligation to review section 111(b) standards as
stated. The EPA is not finalizing any position with respect to any
implications of this concept for section 111(d). We are promulgating
rules for section 111(d) state plans that will establish standards of
performance for existing sources to which a section 111(b) standard of
performance would apply if such sources were new sources, within the
definition in section 111(a)(2) of ``new source.'' It is not necessary
to address at this time whether subsequent review and/or appropriate
revision of the corresponding section 111(b) standard of performance
have any implications for review and/or revision of this rule.
    a. Legal basis for maintaining emission performance.
    In the proposal, the EPA proposed ``that the level of emission
performance for affected EGUs represented by the final goal should
continue to be maintained.'' The EPA explained that ``Congress either
intended the emission performance improvements required under CAA
section 111(d) to be permanent or, through silence, authorized the EPA
to reasonably require permanence. Other CAA section 111(d) emission
guidelines set emission limits to be met permanently.'' 79 FR 34830,
34908/2 (June 18, 2014). We also requested comment on whether ``we
should establish BSER-based state performance goals that extend further
into the future (e.g. beyond the proposed planning period), and if so,
what those levels of improved performance should be.'' Id. at 34908/3.
    We received adverse comment on establishing BSER-based state
performance goals beyond the proposed planning period. Commenters
argued that we did not have a sufficient basis at this time to
determine what those future goals should be. We agree and have decided
not to establish such goals. We are finalizing, though, that the level
of emission performance for affected EGUs represented by the final goal
should continue to be maintained, for the reasons given in our proposal
and quoted above.
    The general structure of the CAA supports our interpretation.
Section 111(d) plans establish standards of performance that reflect
the BSER, a technology-based standard. Generally speaking, in the
future technology will only improve, and correspondingly the CAA does
not provide explicit processes to relax technology-based standards. In
contrast, the provisions in Part D of title I that address attainment
of health-based standards, the NAAQS, explicitly provide that once the
NAAQS are attained, emission reduction measures may be relaxed so long
as the NAAQS are maintained. The absence in section 111(d) of explicit
provisions for future relaxation of emission reduction measures, as
compared to Part D, supports our interpretation that the emission
reductions continue to be on-going after the CO2 emission
performance rates or state CO2 emission goals are achieved
in 2030. This is consistent with our past practice for section 111(d)
rules, which do not contain any provision that in the future removes or
relaxes the promulgated guidelines. In light of the persistence of
CO2 as a pollutant and its long-term impacts, it is
particularly critical in these guidelines to explicitly provide for
continuing emission reductions.

G. Additional Considerations for State Plans

1. Consideration of a Facility's ``Remaining Useful Life'' and ``Other
Factors''
    This section discusses the way in which the final emission
guidelines address the CAA section 111(d)(1)

provision requiring the Administrator, in promulgating 111(d)
regulations, to ``permit the State in applying a standard of
performance to any particular source under a [111(d)] plan . . . to
take into consideration, among other factors, the remaining useful life
of the existing source to which such standard applies.''
    The final guidelines permit a state, in developing its state plan,
to fully consider and take into account the remaining useful life of an
affected EGU and other factors in establishing the requirements that
apply to that EGU, as discussed further below. Therefore, consideration
of facility-specific factors and in particular, remaining useful life,
does not justify a state making further adjustments to the performance
rates or aggregate emission goal that the guidelines define for
affected EGUs in a state and that must be achieved by the state plan.
Thus, these guidelines do not provide for states to make additional
goal adjustments based on remaining useful life and other facility-
specific factors because they can fully consider these factors in
designing their plans.
    a. Statutory and regulatory backdrop.
    This section describes the statutory and existing regulatory
background concerning facility-specific considerations in
implementation of section 111(d).
    Section 111(d)(1)(A) requires states to submit a plan that
``establishes standards of performance'' for existing sources. Under
section 111(d)(1)(B), the plan must also ``provide for implementation
and enforcement of such standards of performance.'' Finally, the last
sentence of section 111(d)(1) provides: ``Regulations of the
Administrator under this paragraph shall permit the State in applying a
standard of performance to any particular source under a plan submitted
under this paragraph to take into consideration, among other factors,
the remaining useful life of the existing source to which such standard
applies.''
    The EPA's 1975 implementing regulations \855\ addressed a number of
facility-specific factors that might affect requirements for an
existing source under section 111(d). Those regulations provide that
for designated pollutants, standards of performance in state plans must
be as stringent as the EPA's emission guidelines. Deviation from the
standard might be appropriate where the state demonstrates with respect
to a specific facility (or class of facilities):
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    \855\ 40 FR 53340 (Nov. 17, 1975).
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    (1) Unreasonable cost of control resulting from plant age,
location, or basic process design;
    (2) Physical impossibility of installing necessary control
equipment; or
    (3) Other factors specific to the facility (or class of facilities)
that make application of a less stringent standard or final compliance
time significantly more reasonable.
    This provision was amended in 1995 (60 FR 65387, December 19,
1995), and is now prefaced with the language ``Unless otherwise
specified in the applicable subpart on a case-by-case basis for
particular designated facilities or classes of facilities.'' 40 CFR
60.24(f).
    b. Our proposal regarding the implementing regulations.
    Our proposal stated that the reference to ``[u]nreasonable cost of
control resulting from plant age'' in 60.24(f) ``implements'' the
statutory provision on remaining useful life. We also stated that the
implementing regulations ``provide the EPA's default structure for
implementing the remaining useful life provision of CAA section
111(d).'' We noted that the prefatory language ``unless otherwise
specified in the applicable subpart'' gives the EPA discretion to alter
the extent to which the implementing rules applied if appropriate for a
particular source category and guidelines. We requested comment on our
analysis of the existing implementing regulations and any implications
for our regulatory text in respect to how these guidelines relate to
those regulations.
    Commenters stated, among other things, that the sentence concerning
``remaining useful life'' was added in the 1977 CAA Amendments and that
therefore it could not be said that provisions from the 1975
implementing regulations ``implement'' the sentence. The EPA does not
think as a general matter that it is necessarily impossible that a pre-
statutory amendment rule could continue to serve as a reasonable
implementation of a post-statutory amendment provision. However, we
also think it is appropriate, as we suggested in the June 2014
proposal, to specify in the applicable subpart for these guidelines
that the provisions in 60.24(f) should not apply to the class of
facilities covered by these guidelines. As a result, regardless of
whether the implementing regulations appropriately implement the
``remaining useful life'' provision in general, the relevant
consideration is that, as we now explain, these particular guidelines
``permit the State in applying a standard of performance to any
particular source under a plan submitted under this paragraph to take
into consideration, among other factors, the remaining useful life of
the existing source to which such standard applies.''
    c. How these emission guidelines permit states to consider
remaining useful life and other facility-specific factors.
    The EPA notes that, in general, the implementing regulation
provisions for remaining useful life and other facility-specific
factors are relevant for emission guidelines in which the EPA specifies
a presumptive standard of performance that must be fully and directly
implemented by each individual existing source within a specified
source category. Such guidelines are similar to a CAA section 111(b)
standard in their form. For example, the EPA emission guidelines for
sulfuric acid plants, phosphate fertilizer plants, primary aluminum
plants, Kraft pulp plants, and municipal solid waste landfills specify
emission limits for sources.\856\ In the case of such emission
guidelines, some individual sources, by virtue of their age or other
unique circumstances, may warrant special accommodation.
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    \856\ See ``Phosphate Fertilizer Plants; Final Guideline
Document Availability,'' 42 FR 12022 (Mar. 1, 1977); ``Standards of
Performance for New Stationary Sources; Emission Guideline for
Sulfuric Acid Mist,'' 42 FR 55796 (Oct. 18, 1977); ``Kraft Pulp
Mills, Notice of Availability of Final Guideline Document,'' 44 FR
29828 (May 22, 1979); ``Primary Aluminum Plants; Availability of
Final Guideline Document,'' 45 FR 26294 (Apr. 17, 1980); ``Standards
of Performance for New Stationary Sources and Guidelines for Control
of Existing Sources: Municipal Solid Waste Landfills, Final Rule,''
61 FR 9905 (Mar. 12, 1996).
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    In these final guidelines for state plans to limit CO2
from affected EGUs, however, the agency does not specify presumptive
performance rates that each individual EGU is to achieve in the absence
of trading. Instead, these guidelines provide collective performance
rates for two classes of affected EGUs (steam generating units and
stationary combustion turbines), and give states the alternative of
developing plans to achieve a state emission goal for the collective
group of all affected EGUs in a state. Providing states with the
ability to consider facility-specific factors such as remaining useful
life in designing their state plans is one of the fundamental reasons
that the EPA designed the final rule in this way. In addition, the
significant revisions since proposal to address achievability concerns
(e.g., moving the start date from 2020 to 2022, and other changes in
interim and final state goals summarized in the next section) will help
to ensure that states in practice can consider remaining useful life
and other facility-specific factors in setting EGU requirements. Of
course, EGUs vary considerably in age, so remaining useful life is
potentially

relevant to regulation of some units and not others.
    The guidelines capitalize on the inherent flexibility offered by
the CO2 emission performance rates and by the state
CO2 emission goals approach, allowing states flexibility on
the form of the EGU standards that they include in CAA section 111(d)
plans. A state could select a form of standards (e.g., marketable
credits or permits, retirement of certain older facilities after their
useful life, etc.) that avoids or diminishes concerns about facility-
specific factors such as remaining useful life. If a state adopted the
CO2 emission performance rates for fossil fuel-fired
electric utility steam generating units and stationary combustion
turbines in conjunction with rate-based trading, though, the state
would be taking remaining useful life into consideration by allowing
affected EGUs to comply using ERCs. In effect, under a trading program
with repeating compliance periods, a facility with a short remaining
useful life has a total outlay that is proportionately smaller than a
facility with a long remaining useful life, simply because the first
facility would need to comply for fewer compliance periods and would
need proportionately fewer ERCs than the second facility. Buying ERCs
would avoid excessive up-front capital expenditures that might be
unreasonable for a facility with a short remaining useful life, and
would reduce the potential for stranded assets.
    In addition to providing states with flexibility on the form of the
standards of performance in their plans, the guidelines leave to each
state the design of the specific requirements that fall on each
affected EGU in applying those standards. To the extent that an
emission standard that a state may wish to adopt for affected EGUs
raises facility-specific issues, the state may make adjustments to a
particular facility's requirements on facility-specific grounds, so
long as any such adjustments are reflected (along with any necessary
compensating emission reductions to meet the state goal) in the state's
CAA section 111(d) plan submission.
    Finally, we note that these guidelines permit states to use a rate
or mass CO2 emission goal, and that each of these pathways
allow states multiple design choices. Under either pathway states can
take into consideration remaining useful life and seek to avoid
stranded assets.
    The EPA believes that this approach to permitting states to
consider remaining useful life is appropriate because it reflects, and
is compatible with, the interconnected nature of the electricity
system.
    Although this discussion emphasizes state flexibility on plan
design, it is important to note that the main intended beneficiaries of
state flexibility are the affected EGUs themselves. As a key case in
point, the EPA has endeavored to craft the final guidelines to support
and facilitate state plans that include trading systems, including
interstate trading systems that can help EGUs continue to operate with
the flexibility that they currently enjoy on regional grid levels.
    Trading can provide affected EGUs that have a limited remaining
useful life with the flexibility to comply through purchasing
allowances or ERCs, thereby avoiding major capital expenditures that
would create long-term debt. By buying allowances or ERCs, affected
EGUs with a limited remaining useful life contribute to achieving
emission reductions from the source category during the years that they
operate. During its lifetime, a facility with a short remaining useful
life will need fewer total credits or allowances than an otherwise
comparable facility with a long remaining useful life, but the
annualized cost to the two facilities is the same.\857\
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    \857\ Trading of course has other benefits beyond helping to
address remaining useful life concerns. For example, trading can
lower costs of achieving a given level of emission reduction and can
provide economic incentives for innovation and development of
cleaner technologies.
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    In part to help states address remaining useful life
considerations, the final guidelines facilitate state plans that employ
trading in multiple ways:

     By allowing trading under emission standards plans and
state measures plans, and under rate-based plans and mass-based
plans;
     By defining national EGU performance rates that make it
easier for states to set up rate-based trading regimes that allow
for interstate trading of ERCs;
     By clearly defining the requirements for mass-based and
rate-based trading systems to ensure their integrity; and
     By providing information on potential allocation
approaches for mass-based trading.

    In addition, the EPA is separately proposing model trading rules
for rate-based and mass-based trading to assist states with design of
these programs in the section 111(d) context.
    d. Why remaining useful life and other facility-specific factors do
not warrant adjustments in the guidelines' performance rates and state
goals.
    Under the final guidelines, remaining useful life and other
facility-specific considerations do not provide a basis for adjusting
the CO2 emission performance rates, or the state's rate-
based or mass-based CO2 emission goals, nor do they affect
the state's obligation to develop and submit an approvable CAA section
111(d) plan that adopts the CO2 emission performance rates
or achieves the goal by the applicable deadline. After considering
public comments discussed below and in the response to comments
document, the EPA has retained this aspect of the proposed rule for the
reasons described below.
    As noted above, the final guidelines provide aggregate emission
goals for affected EGUs in each state, in addition to the
CO2 emission performance rates. The guidelines also reflect
a number of changes from proposal to address concerns about
achievability of proposed state goals that were raised in public
comments, many of which were explicitly prompted by consideration of
the remaining useful life issue. The result is to afford states with
broad flexibility to design requirements for affected EGUs to achieve
the CO2 emission performance rates or state CO2
emission goals in ways that avoid requiring major capital expenditures,
or imposing unreasonable costs, on those affected EGUs that have a
limited remaining useful life. State plans may use any combination of
the emissions reduction methods represented by the building blocks, and
may also choose to employ emission reduction methods that were not
assumed in calculating state goals.
    To be more specific, the EPA notes that a state is not required to
achieve the same level of emission reductions with respect to any one
building block as assumed in the EPA's BSER analysis. A state may use
any combination of measures, including those not specifically factored
into the BSER by the EPA. The EPA has estimated reasonable rather than
maximum possible implementation levels for each building block in order
to establish EGU emission rates and state goals that are achievable
while allowing states to take advantage of the flexibility to pursue
some building blocks more aggressively, and others less aggressively,
than is reflected in the agency's computations, according to each
state's needs and preferences. The guidelines provide further
flexibility by allowing state plans to use emission reduction methods
not reflected in the BSER. A description of multiple emission reduction
methods is provided in sections VIII.I-K.
    e. Response to key comments on remaining useful life.
    In response to the proposed guidelines, some commenters said that
the proposed state goals were

unachievable and therefore too stringent to provide states, as a
practical matter, with the flexibility to consider remaining useful
life for individual units. These commenters said the result would be
premature retirements and stranded assets.
    In the final guidelines, the EPA has addressed the comments about
lack of practical flexibility to consider remaining useful life by
revising key elements of the guidelines in ways that will ensure that
the CO2 emission performance rates and state CO2
emission goals are achievable considering cost. At the same time, the
final guidelines maintain the broad flexibility of each state to design
its own compliance pathway, taking into account any facility-level
concerns--including remaining useful life--in designing EGU
requirements.
    The changes to the BSER and goal-setting methodologies include:

 Starting the interim goal period in 2022 rather than 2020,
which allows more lead time for states and regulated entities and
helps to ensure that the interim goal is achievable
 Revising the goal-setting formula and the state goals
themselves
 Updating analyses of achievable levels of improvement
through the building blocks that together represent the BSER, while
keeping them at reasonable, rather than maximum, levels (thus
creating headroom which can, and is intended to, help to accommodate
the range of ages of different facilities)
 Providing an explicit phase-in schedule for meeting the
revised interim goals, while also allowing a state the option of
choosing its own emission reduction trajectory

    The final guidelines also contain changes to avoid certain
inconsistencies between the goal-setting methodology and accounting of
reductions under state plans that could have made state goals less
achievable for some states.
    Together, the changes described above help to ensure that the
CO2 emission performance rates and state CO2
emission goals established in the final guidelines are achievable, and
leave states with the practical ability to issue rules that take into
account the remaining useful life of affected EGU.
    As explained in the Legal Memorandum accompanying this rule, the
EPA believes that Congress intended the remaining useful life provision
to provide a mechanism for states to avoid the imposition of
unreasonable retrofit costs on existing sources with relatively short
remaining useful lives, a scenario that could result in stranded
assets. However, commenters on the proposed rule raised a different
stranded assets concern not primarily related to retrofit costs--a
concern that the proposed rule could cause changes in economic
competitiveness of particular EGUs that would prompt their retirement
before the end of their economically useful lives. These commenters
said the proposed state goals were so stringent that states would have
no choice but to adopt requirements that would result in retirements of
coal-fired capacity that had been built relatively recently or had
recently made pollution control investments. In response to these
comments, the EPA has conducted a stranded assets analysis which
demonstrates that the CO2 emission performance rates and
state goals in the final guidelines provide sufficient flexibility to
states to address stranded asset concerns. The EPA shares the goal of
minimizing stranded assets. Although nothing in section 111(d)
explicitly bars a guideline that results in some facilities becoming
uneconomic before the end of their useful lives, the EPA nonetheless
has striven to design the guidelines so as to give states flexibility
to develop plans that include, for example, differential treatment of
affected EGUs or opportunities to rely on emissions trading, to allow
power companies to recover their investments in generation units.
    For purposes of the stranded assets analysis, the EPA considered a
potential ``stranded asset'' to be an investment in a coal-fired EGU
(or in a capital-intensive pollution control installed at such an EGU)
that retires before it is fully depreciated. Book life is the period
over which long-lived assets are depreciated for financial reporting
purposes. The agency estimated typical book life by researching
financial statements of utility and merchant generation companies in
filings to the Securities and Exchange Commission. The agency estimated
the book life of coal-fired EGUs to be 40 years, and assumed a 20-year
book life for pollution control retrofits. The book life of coal-fired
EGUs (coal steam and IGCC) is twice as long as the debt life and the
depreciation schedule used for federal tax purposes. Although the book
life for environmental retrofits is often 15 years, the agency
conservatively assumed 20 years in this analysis.
    The analysis examined coal generation in the three large regional
interconnections of the U.S. The analysis found that in both 2025 and
2030, for each region, the amount of 2012 coal generation included in
the final guidelines' emission performance rate calculation--
specifically, the generation remaining after the BSER calculation--is
greater than the amount of 2012 generation from coal-fired EGUs that
are not fully depreciated in those years under the book life
assumptions described above. This shows that the final rule allows
flexibility for states to preserve these units as part of their plans.
    To put this analysis in perspective: The EPA's role is to set
emission guidelines that meet the statutory requirements, which
includes consideration of cost in identifying the BSER, as the EPA has
done in these guidelines. States have a broad degree of flexibility to
design plans to achieve the rates in the emission guidelines in a
manner that meets their policy priorities, including ensuring cost-
effective compliance. Although not a required component of the EPA's
consideration of cost, this analysis shows that the CO2
emission performance rates in the final guidelines can be met without
the retirement of affected EGUs before the end of their book life, and
without the retirement of affected EGUs before the end of the book life
of capital-intensive pollution control retrofits installed on those
EGUs. Thus, according to this analysis, the CO2 emission
performance rates and state CO2 emission goals need not
result in stranded assets. The EPA recognizes that power plant
economics are determined by many aspects of markets that are outside of
the EPA's control, such as wholesale power prices and capacity prices,
and that the compliance path of least cost may involve retiring assets
that have not fully depreciated. Nonetheless, this analysis further
demonstrates the extent of flexibility available to states in designing
their plans to best serve the policy priorities of the state. Details
are available in a memorandum to the docket.\858\
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    \858\ Memorandum to Clean Power Plan Docket titled ``Stranded
Assets Analysis'' dated July 2015.
---------------------------------------------------------------------------

    Several commenters said that the statute does not authorize the EPA
to require other facilities to achieve greater reductions to compensate
for a facility that warrants relief based on remaining useful life. One
said that consideration of remaining useful life and other relevant
factors is a one-way ratchet that provides relief to sources that
cannot achieve the BSER, and that the EPA turns that approach on its
head by prohibiting a state from providing such relief to a specific
facility unless it can identify another facility to ``punish'' by
requiring additional emissions reductions to offset that relief.
    The EPA disagrees with these comments, which proceed from an
incorrect premise. The EPA is not determining a BSER-based emission
level achievable by each individual facility without trading, and then

requiring better-than-BSER from some facilities to make up for worse-
than-BSER performance that a state authorizes for other facilities
because of a short remaining useful life. Rather, as previously noted,
the guidelines set CO2 emission performance rates and state
CO2 emission goals that represent the average or aggregate
emission level achievable by affected EGUs based on regional average
estimates of the impact of applying the BSER to collective groupings of
affected EGUs.\859\ In estimating the amount of improvement achievable
through each building block (e.g., improvement in heat rate or amount
of generation shift to lower-emitting EGUs), the EPA has estimated the
average level achievable by EGUs in a region rather than attempting to
estimate the level achievable by each and every affected EGU in the
absence of trading. Thus, the fact that an individual facility may be
unable, for example, to achieve the average level of heat rate
improvement assumed in goal-setting is consistent with the EPA's
analysis, and does not undermine the EPA's determination of
CO2 emission performance rates and state CO2
emission goals. The Legal Memorandum discusses additional reasons that
the agency disagrees with comments that the guideline must permit
adjustments in the guidelines' CO2 emission performance
rates and state CO2 emission goals based on remaining useful
life considerations.
---------------------------------------------------------------------------

    \859\ The EPA expects that states that choose to adopt the
national CO2 emission performance rates for all of their
EGUs would permit ERC trading, rather than requiring each facility
to meet the applicable rate without trading. In effect, the presence
of trading means that the EGU performance rates can be achieved by
each EGU involved in trading.
---------------------------------------------------------------------------

    An additional reason that the EPA believes that consideration of
remaining useful life and other facility-specific factors does not
warrant adjustments to state goals is that the design of the guidelines
does not mandate that states impose requirements that would call for
substantial capital investments at affected EGUs late in their useful
life. Multiple methods are available for reducing emissions from
affected EGUs that do not involve capital investments by the owner/
operator of an affected EGU. For example, generation shifts among
affected EGUs, and addition of new RE generating capacity do not
generally involve capital investments by the owner/operator at an
affected EGU. Additional emission reduction methods available to states
that do not entail significant capital costs at affected EGUs are
discussed elsewhere in this preamble.
    Heat rate improvements at affected EGUs may require capital
investments. However, states have flexibility to design their plan
requirements; they are not required to mandate heat rate improvements
at plants that have limited remaining useful life. In fact, a state can
choose whether or not to require heat rate improvements at all. The
agency also notes that capital expenditures for heat rate improvements
would be much smaller than capital expenditures required for example,
for purchase and installation of scrubbers to remove SO2; a
fleet-wide average cost for heat rate improvements based primarily on
best practices at coal-fired generating units would not likely exceed
$100/kW, compared with a typical SO2 wet scrubber cost of
$500/kW (costs vary with unit size).\860\ Even if a state did choose to
adopt requirements for heat rate improvements, the proposed guidelines
would allow states to regulate affected EGUs through flexible
regulatory approaches that do not require affected EGUs to incur large
capital costs (e.g., averaging and trading programs). Under the EPA's
final approach--establishing state goals and providing states with
flexibility in plan design--states have flexibility to make exactly the
kind of judgments necessary to avoid requiring capital investments that
would result in stranded assets.
---------------------------------------------------------------------------

    \860\ Heat rate improvement methods and related capital costs
are discussed in the GHG Mitigation Measures TSD; SO2
scrubber capital costs are from the documentation for the EPA's IPM
Base Case v5.13, Chapter 5, Table 5-3, available at http://www.epa.gov/airmarkets/documents/ipm/Chapter_5.pdf.
---------------------------------------------------------------------------

    Remaining useful life and other factors, because of their facility-
specific nature, are potentially relevant as states determine
requirements that are directly applicable to affected EGUs. If relief
is due a particular facility, the state has an available toolbox of
emission reduction methods that it can use to develop a section 111(d)
plan that will achieve the CO2 emission performance rates or
state CO2 emission goals on time. The EPA therefore
concludes that the remaining useful life of affected EGUs, and the
other facility-specific factors identified in the existing implementing
regulations, should not be regarded as a basis for adjusting the
CO2 emission performance rates or a state CO2
emission goal, and should not relieve a state of its obligation to
develop and submit an approvable plan that achieves that goal on time.
    f. Legal considerations regarding remaining useful life. Section
111(d)(1) requires the EPA in promulgating section 111(d) regulations
to ``permit the State in applying a standard of performance to any
particular source under a plan submitted under this paragraph to take
into consideration, among other factors, the remaining useful life of
the existing source to which such standard applies.'' Here, we discuss
the legal basis for determining that the emission guidelines are
consistent with this statutory requirement. For details, please see the
Legal Memorandum.
    Section 111(d)(1) only requires that EPA emission guidelines permit
states to take into account remaining useful life (among other
factors), but section 111(d)(1) does not specify how the EPA must
permit that. In other words, the meaning of the provision and the way
that the EPA is to implement it in promulgating guidelines are not
specified further in the provision. The provision is ambiguous and
capable of implementation in several ways, and therefore the EPA has
discretion to interpret and apply it. Furthermore, section 111(d)(1)
does not suggest that states must be given carte blanche to consider
remaining useful life in any way that can be imagined. As detailed
above in sections VIII.G.1.c-e, these guidelines permit states to take
into account remaining useful life in a number of reasonable ways and
thus the guidelines satisfy the statutory obligation.
    The phrase ``remaining useful life'' also appears in the visibility
provisions of section 169A. There, in determining best available
retrofit technology (BART), the state (or the EPA) must take into
consideration (among other factors) ``the remaining useful life of the
source.'' 42 U.S.C. 7491(g)(2); see also id. (g)(1) (reasonable
progress). In the context of the visibility program, we have
interpreted this provision to mean that the remaining useful life
should be considered when calculating the annualized costs of retrofit
controls. See 40 CFR Pt. 51, App. Y, IV.D.4.k.1. This annualized cost
is then used to determine a cost effectiveness, in dollars per ton of
pollutant removed on an annual basis. As a result, a technology with a
large initial capital cost that might have a reasonable cost-
effectiveness for a facility with a long remaining useful life would
have a much higher and possibly unreasonable cost-effectiveness for a
facility with a short remaining useful life.
    Although section 111(d)(1) is different than section 169A(g)(2) and
need not be interpreted in the same way, we would note (as discussed in
detail in sections VIII.G.1.c-e, section 5.11 of the Response to
Comments document, and the Legal Memorandum) that (for

example) a trading program under these section 111(d) guidelines only
requires compliance on a periodic basis and does not require any
initial capital expenditures. Thus, over the life of the facility, a
facility with a short remaining useful life will need fewer total
credits or allowances than an otherwise comparable facility with a long
remaining useful life, but the annualized cost to the two facilities is
the same. In other words, under a trading program remaining useful life
of a source is automatically accounted for in the way it is accounted
for under the visibility program.
    Some commenters stated that the EPA's interpretation of remaining
useful life is impermissible. These commenters claimed that states, if
they wish to take into account remaining useful life at one affected
EGU, must relax the stringency of the emission standard for that EGU.
Then, the state would be compelled to increase the stringency of
emission standards at other affected EGUs in order to achieve the state
performance goal. According to these commenters, section 111(d) does
not allow this outcome.
    First, the commenters are mistaken in their premise. As discussed
in section VIII.G.1, section 5.11 of the Response to Comments document,
the Legal Memorandum, and in the example immediately above, states can
impose the exact same emission standards on two affected EGUs and still
take into account remaining useful life through the availability of
trading. In other words, states need not relax an emission standard
here and strengthen an emission standard there in order to take into
account remaining useful life. Thus, these guidelines permit states to
take into account remaining useful life without any of the effects
commenters are concerned about.
    Second, even if states decide to relax emission standards at one
EGU, on the basis of remaining useful life or any other factor, nothing
in the last sentence of section 111(d)(1) prohibits these guidelines
from requiring the state plan to still meet the CO2 emission
performance rates or state CO2 emission goal. In fact, that
sentence is completely silent on the issue. Thus, the EPA has the
discretion to determine what should be the concomitant effects if a
state chooses to consider remaining useful life in a particular way. In
this case the concomitant effect of a state relaxing one emission
standard may be that the state must make up for it elsewhere in order
to meet the goal, but nothing in section 111(d)(1), including the
statutory requirement to permit consideration of remaining useful life,
prohibits that outcome.
2. Electric Reliability
    The final rule features overall flexibility, a long planning and
implementation horizon, and a wide range of options for states and
affected EGUs to achieve the CO2 emission performance rates
or state CO2 emission goal. This design reflects, among
other things, the EPA's commitment to ensuring that compliance with the
final rule does not interfere with the industry's ability to maintain
the reliability of the nation's electricity supply. Comments from
state, regional and federal reliability entities, power companies and
others, as well as consultation with the Department of Energy (DOE) and
Federal Energy Regulatory Commission (FERC), helped inform a number of
changes made in this final rule to address reliability. In addition,
FERC conducted one national and three regional technical conferences on
the proposed rule in which the EPA participated and at which the issue
of reliability was raised by numerous participants.
    As discussed throughout the preamble and TSDs, the electricity
sector is undergoing a period of intense change. While the change in
the resource mix has accelerated in recent years, wind, solar, other
RE, and EE resources have been reliably participating in the electric
sector for a number of years. Many of the potential changes to the
electric system that the final rule may encourage, such as shifts to
cleaner sources of power and efforts to reduce electricity demand, are
already well underway in the electric industry. To the extent that the
final rule accelerates these changes, there are multiple features well
embedded in the electricity system that ensure that electric system
reliability will be maintained. Electric system reliability is
continually being considered and planned for. For example, in the
Energy Policy Act of 2005, Congress added a section to the Federal
Power Act to make reliability standards mandatory and enforceable by
FERC and the North American Electric Reliability Corporation (NERC),
the Electric Reliability Organization which FERC designated and
oversees. Along with its standards development work, NERC conducts
annual reliability assessments via a 10-year forecast and winter and
summer forecasts; audits owners, operators, and users for preparedness;
and educates and trains industry personnel. Numerous other entities
such as FERC, DOE, state PUCs, ISOs/RTOs, and other planning
authorities also consider the reliability of the electric system. There
are also numerous remedies that are routinely employed when there is a
specific local or regional reliability issue. These include
transmission system upgrades, installation of new generating capacity,
calling on demand response, and other demand-side actions.
    Additionally, planning authorities and system operators constantly
consider, plan for, and monitor the reliability of the electricity
system with both a long-term and short-term perspective. Over the last
century, the electric industry's efforts regarding electric system
reliability have become multidimensional, comprehensive, and
sophisticated. Under this approach, planning authorities plan the
system to assure the availability of sufficient generation,
transmission, and distribution capacity to meet system needs in a way
that minimizes the likelihood of equipment failure.\861\ Long-term
system planning happens at both the local and regional levels with all
segments of the electric system needing to operate together in an
efficient and reliable manner. In the short-term, electric system
operators operate the system within safe operating margins and work to
restore the system quickly if a disruption occurs.\862\ Mandatory
reliability standards apply to how the bulk electric system is planned
and operated. For example, transmission operators and balancing
authorities have to develop, maintain, and implement a set of plans to
mitigate operating emergencies.\863\
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    \861\ Casazza, J. and Delea, F., Understanding Electric Power
Systems: An Overview of the Technology, the Marketplace, and
Government Regulations, IEEE Press, at 160 (2010).
    \862\ Id.
    \863\ NERC Reliability Standard EOP-001-2.1b--Emergency
Operations Planning, available at http://www.nerc.net/standardsreports/standardssummary.aspx.
---------------------------------------------------------------------------

    As the electricity market changes and new challenges emerge,
electric system regulators and industry participants make changes to
how the electric system is designed and operated to respond to these
challenges. For example, expressing reliability and rate concerns about
fuel assurance issues, FERC recently issued an order requiring ISOs/
RTOs to report on the status of their efforts to address market and
system performance associated with fuel assurance.\864\ In February of
2015, Midcontinent Independent System

Operator (MISO), California Independent System Operator Corporation
(CAISO), New York Independent System Operator (NYISO), Southwest Power
Pool (SPP), ISO New England (ISO-NE), and PJM Interconnection (PJM)
each filed a report with FERC highlighting their efforts to respond to
fuel assurance concerns.\865\ This is just one of many examples where
electric system regulators and industry participants recognize a
potential reliability issue and are proactively searching for
solutions.
---------------------------------------------------------------------------

    \864\ Centralized Capacity Markets in Regional Transmission
Organizations and Independent System Operators, 149 FERC ] 61,145
(2014). FERC generally defines fuel assurance as ``generator access
to sufficient fuel supplies and the firmness of generator fuel
arrangements''. Id. P 5.
    \865\ For example, ISO-NE and PJM each filed ``pay-for-
performance'' proposals to address fuel assurance in their regions.
FERC recently acted on ISO-NE market rule changes providing
increased market incentives in capacity, energy, and ancillary
services markets for generators to be available to meet their
obligations during reserve shortages. ISO New England Inc., 147 FERC
] 61,172 (2014). Additionally, FERC conditionally approved a PJM
``pay-for-performance'' proposal that creates a new capacity product
to provide greater assurance of delivery of energy and reserves
during emergency conditions, establishing credits for superior
performance and charges for poor performance. PJM Interconnection,
L.L.C., 151 FERC ] 61,208 (2015).
---------------------------------------------------------------------------

    The EPA's approach in this final rule is consistent with our
commitment to ensuring that compliance with the final rule does not
interfere with the industry's ability to maintain the reliability of
the nation's electricity supply. Many aspects of the final rule's
design are intended to support system reliability, especially the long
compliance period and the basic design that allows states and affected
EGUs flexibility to include a large variety of approaches and measures
to achieve the environmental goals in a way that is tailored to each
state's and utility's energy resources and policies. Despite the
flexibility built into the design of the proposal, and the long
emission reduction trajectory, many commenters expressed concerns that
the proposed rule could jeopardize electric system reliability. We note
that the EPA has received similar comments in EPA rulemakings dating as
far back as the 1970s. The EPA has always taken and continues to take
electric system reliability comments very seriously. These reoccurring
comments with regard to reliability notwithstanding, the electric
industry has done an excellent job of maintaining reliability,
including when it has had to comply with environmental rules with much
shorter compliance periods and much less flexibility than this final
rule provides. Now, more than ever, the electric industry has tools
available to maintain reliability, including mandatory and enforceable
reliability standards.\866\
---------------------------------------------------------------------------

    \866\ For example, Andrew Ott, then Executive Vice President-
Markets and current President of PJM, an RTO with a substantial
amount of coal-fired capacity and generation, discussed the success
of PJM's market design in assuring that PJM met and exceeded target
reserve margins while MATS was being implemented. See Statement of
Andrew Ott, PJM Executive Vice President-Markets, FERC Technical
Conference on Centralized Capacity Markets in Regional Transmission
Organizations and Independent System Operators, AD13-7-000, at 3, 7
(Sept. 25, 2013), available at http://www.ferc.gov/EventCalendar/EventDetails.aspx?ID=6944&CalType=&CalendarID=116&Date=09/25/2013&View=Listview. At the FERC national Clean Power Plan Technical
Conference, Michael J. Kormos, PJM Executive Vice President-
Operations, said that PJM's markets have proven, ``resilient enough
to respond to different policy initiatives . . . Whether it is the
Sulfur Dioxide Trading Program of the 1990s, the MATS rule or
individual state RPS initiatives, the markets have been able to send
the appropriate price signals that produce competitive outcomes.''
See Michael J. Kormos, PJM Executive Vice President, Statement at
FERC Technical Conference on EPA's Clean Power Plan, AD15-4-000, at
3 (Feb. 19, 2015), available at http://www.ferc.gov/CalendarFiles/20150213081650-Kormos,%20PJM.pdf.
---------------------------------------------------------------------------

    As with numerous prior CAA regulations affecting the electric power
sector, environmental requirements for this industry are accommodated
within the existing extensive framework established by federal and
state law to ensure that electricity production and delivery are
balanced on an ongoing basis and planned sufficiently to ensure
reliability and affordability into the future. In addition, changes
that the EPA is making in this final rule respond directly to the
comments and the suggestions that we received on reliability and
provide further assurance that implementation of the final rule will
not create reliability concerns.
    First, the final rule allows significant flexibility in how the
applicable CO2 emission performance rates or the statewide
CO2 goals are met. Given the differing characteristics of
the electric grid within each state and region, there are many paths to
meeting the final rule's requirements that can be taken while
continuing to maintain a reliable electricity supply. As further
described elsewhere in section VIII, states can develop plans to meet
the CO2 emission performance rates or state CO2
emission goals by choosing from a variety of state plan types and
approaches that afford states and affected EGUs appropriate
flexibility. EE and other measures that were not included in the
determination of the BSER can strengthen a state's ability to establish
a plan to meet the CO2 emission performance rates or state
CO2 emission goals by providing a considerable amount of
headroom above the levels of the rates and goals. EE especially,
because it reduces load, can provide assurance that reliability can and
will be maintained. Additionally, the final rule offers opportunities
for trading among affected EGUs within and between states, and other
multi-state approaches that will further support electric system
reliability.
    Second, the final rule provides sufficient time to ensure system
reliability. The final rule retains the 2030 date for the final period,
which commenters largely supported as reasonable and not a concern for
reliability, and addresses one of the key issues that commenters
pointed to as a reliability-related concern by both moving the start of
the interim period from 2020 to 2022 and adjusting the interim goals to
provide a more gradual phasing-in of the initial reduction requirement
and thus a more gradual emissions reduction trajectory or glide path to
the final 2030 goals. These changes deliver on the intent of the
proposal to afford states and affected EGUs the latitude to determine
their own emissions reduction schedules over the interim period. Both
FERC's May 15, 2015 letter \867\ and the comment record made it clear
that providing sufficient time for planning and implementation is
essential to ensuring electric system reliability. The EPA has
responded by providing additional time to allow for planning and
implementation of the final rule requirements, while at the same time
allowing enough time between the beginning of the interim period and
2030 to achieve state goals or emission performance rates. We note that
the final rule does not require that all states have met their interim
goal or performance rate by 2022 but rather that they meet it on
average or cumulatively, as appropriate, during the 2022 to 2029
period.
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    \867\ On May 15, 2015, the five FERC Commissioners sent a letter
to Acting Assistant Administrator Janet McCabe regarding the EPA's
Clean Power Plan proposal. See FERC letter, available at http://ferc.gov/media/headlines/2015/ferc-letter-epa.pdf.
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    As a result of these changes, the states themselves will have a
meaningful opportunity--which, again, many commenters suggested the
timing and stringency of the proposal failed to create despite our
intent to do so--to determine the timing, cadence and sequence of
actions needed for states and sources to meet final rule requirements
while accommodating the ongoing activity needed to ensure system
reliability. The final rule provides more than 6 years before
reductions are required and an 8-year period from 2022 to 2029 to meet
interim goals. Moreover, while the final rule requires each state to
submit a plan by September 6, 2016, we recognize that some states may
need more than 1 year to complete all of the actions needed for their
final state plans, including

consideration of reliability. Therefore, states have the opportunity to
receive an extension for submitting a final plan. If the state needs
additional time to submit a final plan, then the state may submit an
initial submittal by September 6, 2016, that must address three
required components sufficiently to demonstrate that a state is able to
undertake steps and processes necessary to timely submit a final plan
by the extended date of September 6, 2018.
    Third, we are including in the final rule a requirement that each
state demonstrate in its final state plan submittal that it has
considered reliability issues in developing its plan. This was
suggested by a number of commenters, and we agree that it is a useful
element to state plan development.
    Fourth, the final rule provides a mechanism for a state to seek a
revision to its plan in order to address changes in circumstances that
could have reliability impacts if not accommodated in the plan. The
long compliance timeframe, with several interim steps, naturally
provides opportunities for states, working with their utilities and
reliability entities, to assess how implementation is proceeding,
identify unforeseen changes that may warrant plan revisions, and work
with the EPA to make necessary revisions. Similarly, the ready
availability of emissions trading as a compliance tool affords EGUs
ample flexibility to integrate compliance with both routine and
critical reliability needs.
    Fifth, in response to a variety of comments, we are providing a
reliability safety mechanism that provides a path for a state to come
to the EPA during an immediate, unforeseen, emergency situation that
threatens reliability to notify the EPA that an affected EGU or EGUs
may need to temporarily comply with modified emission standards to
respond to this kind of reliability concern.
    Sixth and finally, we are committed to maintaining an ongoing
relationship with FERC and DOE as this final rule is implemented to
help ensure continued reliable electric generation and transmission.
    We provide more details about these various elements of the final
rule, as well as other features of the rule that support system
reliability, below.

    a. Summary of key comments.

    The EPA received a number of comments regarding the proposed rule
and electric reliability. Many commenters provided specific, useful
ideas regarding changes that could be made to the proposal to
specifically address their reliability concerns. For example, many
commenters state that allowing additional time to comply could help in
meeting the final rule requirements while addressing their reliability
concerns. Some commenters suggest that additional time would allow them
to evaluate potential reliability impacts and system changes that need
to be made to comply with final rule requirements while allowing
affected EGUs time to meet interim CO2 emissions goals. The
EPA also received comment that market-based approaches have features
that could help support reliability, and therefore we should encourage
states to join or form regional market-based programs. Commenters also
stated that the EPA should require states to consult with grid
operators who would analyze the impact of state plans on reliability. A
number of commenters also suggested that the EPA should include some
sort of reliability safety valve in the final rule. We note that many
participants at the FERC technical conferences on the proposed rule
also discussed a reliability safety valve in great detail with many
suggestions for how such a reliability mechanism could be designed. The
EPA appreciates these and all the comments we received regarding the
interaction of the proposal and electric reliability. We have carefully
considered all comments, consulted further with FERC and incorporated
many of the suggested changes in this final rule.

    b. Final rule flexibility.

    In issuing this final rule, the EPA considered public comments on
the potential interaction between the proposal and electric
reliability. While we have made every effort to develop guidelines that
would allow states and utilities to steer clear of potential
reliability disruptions, a number of commenters argued that the
possibility of an unanticipated reliability event cannot be entirely
eliminated. It is important to note that there are many factors that
influence system reliability and, given the complexity of the electric
grid, electric system planners and operators likely will not completely
avoid reliability issues, even in the absence of these guidelines. The
EPA designed the final rule to ensure to the greatest extent possible
that actions taken by states and affected EGUs to comply with the final
rule do not increase potential reliability issues or complicate their
resolution. In fact, to the extent that meeting final rule requirements
results in the reduction of demand, upgrades in transmission efficiency
and infrastructure, and investment in new, more efficient technologies,
the outcome could be that the system is more robust and faces fewer
risks to electric reliability.
    One specific concern raised by many commenters is that the proposed
plan development schedule may not leave sufficient time to conduct
reliability planning between the development of state plans and the
proposed start of the interim period in 2020. To address these concerns
and to support a more effective reliability planning process, the EPA
is moving the start of the interim period from 2020 to 2022 and
adjusting the interim goals to provide a gradually phased-in initial
reduction requirement and a more gradual glide path to the final 2030
goals. This more gradual application of the BSER over the 2022-2029
interim period provides the state with substantial latitude in
selecting the emission reduction glide path for affected EGUs over that
period. As noted above, the final rule also provides states with up to
3 years to adopt and submit their final state plans, and afterwards
states can, if necessary, revise their plans, as discussed in section
VIII.E.7. This timing gives system planners and operators the
opportunity to do what they have already been doing; looking ahead to
forecast potential contingencies that pose reliability risks and
identifying those actions needed to mitigate those risks. The final
rule allows states to develop a pathway over the interim period that
reflects their own circumstances, such as reflecting planned additions
and changes in generation mix and potentially taking advantage of
opportunities for trading of credits or allowances by affected EGUs
within and between states. Because achievement of the emission rates or
goals can be demonstrated over several years, state plans can
accommodate situations where, for example, it may take time to develop
new generation, pipelines, or transmission while still providing many
options for meeting the final rule requirements and planning for the
reliability of the system.

    c. Considering reliability during state plan development process.

    Under CAA section 111(d)(1)(B), state plans must provide for the
implementation and enforcement of standards of performance for affected
EGUs. The EPA does not believe a state that establishes standards of
performance for affected EGUs without taking reliability concerns into
consideration satisfactorily provides for the implementation of such
standards of performance as required by CAA section 111(d)(1)(B), as a
serious reliability issue would disrupt the state's provision

of implementation of the state plan. Therefore, the EPA is requiring
that each state demonstrate as part of its final state plan submission
that it has considered reliability issues while developing its plan in
order to ensure that standards of performance can be implemented and
enforced as required by the CAA. If system reliability is threatened,
the ability of affected EGUs to meet the requirements of this final
rule could be compromised if they are required to operate beyond the
emission standards established in state plans in order to maintain the
reliability of the electric grid. The requirement that states consider
reliability as part of the development of state plans is therefore
designed to ensure that state plans are flexible enough to avoid this
kind of potential conflict between maintaining reliability and
providing for the implementation of emission standards for affected
EGUs as required by the CAA.
    A number of commenters, notably ISOs and RTOs, also discussed
reliability concerns in the context of state plans and pointed out that
planning and anticipation of change are among the essential ingredients
of ensuring the ongoing reliability of the electricity system. To that
end, they recommended that as states are developing state plans, their
activity include the consideration of the reliability needs of the
region in which affected EGUs operate and of the potential impact of
actions to be taken in compliance with state plans. Therefore, we are
requiring that each state demonstrate in its final state plan submittal
that it has considered reliability issues in developing its plan. One
particularly effective way in which states can make this demonstration
is by consulting with the relevant ISOs/RTOs or other planning
authorities as they develop their plans and documenting this
consultation process in their state plan submissions. If a state
chooses to consider reliability through consultation with the ISO/RTO
or other planning authority, the EPA recommends that the state request
that the planning authority review the state plan at least once during
the plan development stage and provide its assessment of any
reliability implications of the plan. Additionally, we encourage states
that are considering reliability through an ISO/RTO or other planning
authority consultation process to have a continuing dialogue with those
entities during development of their final state plan. While following
the recommendations of the planning authority would not be mandatory,
the state should document its consultation process, any response and
recommendations from the planning authority, and the state's response
to those recommendations in its final state plan submittal to the EPA.
This consultation is designed to inform how the state might adjust its
plan for meeting the CO2 reduction requirements under this
guideline; the consultation is not a basis for relaxing that
requirement. While we consider this process to be an effective way for
a state to demonstrate that it considered reliability in developing its
final state plan, a state may provide other comparable support for a
demonstration that it has considered reliability during the state plan
development process.\868\ Also as discussed elsewhere in this preamble,
the EPA encourages states to include state utility regulators and the
state energy offices in the development of the state plan. These
agencies have expertise that can help to assure that state plans
complement the state's power sector. The EPA believes that this
requirement to demonstrate consideration of reliability will provide an
effective reliability evaluation in the state plan development process.
It should further help states avoid any conflicts between state plans
and the maintenance of reliability during implementation of the state
plan and associated emission standards. Finally, we also encourage
states as they develop their plans to consider, to the extent possible,
other potential issues that may impact affected EGUs. For example, an
affected EGU may be in an ISO/RTO that puts certain deadlines on
generators that may not line up perfectly with state plan deadlines.
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    \868\ While the EPA is requiring that the states demonstrate
that they have considered reliability in developing their plans,
state plan submissions will not be evaluated substantively regarding
reliability impacts.
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    d. State plan modifications.
    If, during the implementation of a state plan, a reliability issue