(Roman et al., 2008) \341\ as a characterization of uncertainty
regarding the PM2.5-mortality relationship. For the ozone
co-benefits, we present the results as a range reflecting the use of
several different concentration-response functions for mortality, with
the lower end of the range based on a function from Bell et al. (2004)
\342\ and the upper end based on a function from Levy et al.
(2005).\343\ Similar to PM2.5, the range of ozone co-
benefits does not capture the full range of inherent uncertainty.
---------------------------------------------------------------------------

    \339\ Krewski D.; M. Jerrett; R.T. Burnett; R. Ma; E. Hughes; Y.
Shi, et al. 2009. Extended Follow-up and Spatial Analysis of the
American Cancer Society Study Linking Particulate Air Pollution and
Mortality. Health Effects Institute. (HEI Research Report number
140). Boston, MA: Health Effects Institute.
    \340\ Lepeule, J.; F. Laden; D. Dockery; J. Schwartz. 2012.
``Chronic Exposure to Fine Particles and Mortality: An Extended
Follow-Up of the Harvard Six Cities Study from 1974 to 2009.''
Environmental Health Perspective, 120(7), July, pp. 965-970.
    \341\ Roman, H., et al. 2008. ``Expert Judgment Assessment of
the Mortality Impact of Changes in Ambient Fine Particulate Matter
in the U.S.'' Environmental Science & Technology, Vol. 42, No. 7,
February, pp. 2268-2274.
    \342\ Bell, M.L., et al. 2004. ``Ozone and Short-Term Mortality
in 95 U.S. Urban Communities, 1987-2000.'' Journal of the American
Medical Association, 292(19), pp. 2372-8.
    \343\ Levy, J.I., S.M. Chemerynski, and J.A. Sarnat. 2005.
``Ozone exposure and mortality: an empiric bayes metaregression
analysis.'' Epidemiology. 16(4): p. 458-68.
---------------------------------------------------------------------------

    In this analysis, the EPA assumes that the health impact function
for fine particles is without a threshold. This is based on the
conclusions of EPA's Integrated Science Assessment for Particulate
Matter,\344\ which evaluated the substantial body of published
scientific literature, reflecting thousands of epidemiology,
toxicology, and clinical studies that documents the association between
elevated PM2.5

concentrations and adverse health effects, including increased
premature mortality. This assessment, which was twice reviewed by the
EPA's independent Science Advisory Board, concluded that the scientific
literature consistently finds that a no-threshold model most adequately
portrays the PM-mortality concentration-response relationship.
---------------------------------------------------------------------------

    \344\ U.S. Environmental Protection Agency. 2009. Integrated
Science Assessment for Particulate Matter (Final Report). Research
Triangle Park, NC: National Center for Environmental Assessment, RTP
Division. (EPA document number EPA-600-R-08-139F, December).
Available at: <http://cfpub.epa.gov/ncea/cfm/recordisplay.cfm?deid=216546>.
---------------------------------------------------------------------------

    In general, we are more confident in the magnitude of the risks we
estimate from simulated PM2.5 concentrations that coincide
with the bulk of the observed PM concentrations in the epidemiological
studies that are used to estimate the benefits. Likewise, we are less
confident in the risk we estimate from simulated PM2.5
concentrations that fall below the bulk of the observed data in these
studies.
    For this analysis, policy-specific air quality data are not
available,\345\ and thus, we are unable to estimate the percentage of
premature mortality associated with this specific rule's emission
reductions at each PM2.5 level. As a surrogate measure of
mortality impacts, we provide the percentage of the population exposed
above the lowest measured PM2.5 level (LML) in each of the
studies from which we obtained concentration-response functions for
PM2.5 mortality, using the estimates of PM2.5
from the source apportionment modeling used to calculate the benefit-
per-ton estimates for the EGU sector. Using the Krewski et al. (2009)
study, 93 percent of the population is exposed to annual mean
PM2.5 levels at or above the LML of 5.8 micrograms per cubic
meter ([mu]g/m\3\). Using the Lepeule et al. (2012) study, 67 percent
of the population is exposed above the LML of 8 [mu]g/m\3\. It is
important to note that baseline exposure is only one parameter in the
health impact function, along with baseline incidence rates,
population, and change in air quality. Therefore, caution is warranted
when interpreting the LML assessment for this rule because these
results are not consistent with results from rules that had air quality
modeling.
---------------------------------------------------------------------------

    \345\ In addition, site-specific emission reductions will depend
upon how states implement the guidelines.
---------------------------------------------------------------------------

    Every benefit analysis examining the potential effects of a change
in environmental protection requirements is limited, to some extent, by
data gaps, model capabilities (such as geographic coverage) and
uncertainties in the underlying scientific and economic studies used to
configure the benefit and cost models. Despite these uncertainties, we
believe the air quality co-benefit analysis for this rule provides a
reasonable indication of the expected health benefits of the air
pollution emission reductions for the illustrative compliance options
for the proposed standards under a set of reasonable assumptions. This
analysis does not include the type of detailed uncertainty assessment
found in the 2012 PM2.5 National Ambient Air Quality
Standard (NAAQS) RIA (U.S. EPA, 2012) because we lack the necessary air
quality input and monitoring data to conduct a complete benefits
assessment. In addition, using a benefit-per-ton approach adds another
important source of uncertainty to the benefits estimates. The 2012
PM2.5 NAAQS benefits analysis provides an indication of the
sensitivity of our results to various assumptions.
    We note that the monetized co-benefits estimates shown here do not
include several important benefit categories, including exposure to
SO2, NOX, and hazardous air pollutants (e.g.,
mercury and hydrogen chloride), as well as ecosystem effects and
visibility impairment. Although we do not have sufficient information
or modeling available to provide monetized estimates for this rule, we
include a qualitative assessment of these unquantified benefits in the
RIA for these proposed amendments.
    For more information on the benefits analysis, please refer to the
RIA for this rule, which is available in the rulemaking docket.

XI. Statutory and Executive Order Reviews

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

    Under Section 3(f)(1) of Executive Order 12866 (58 FR 51735,
October 4, 1993), this action is an ``economically significant
regulatory action'' because it is likely to have an annual effect on
the economy of $100 million or more or adversely affect in a material
way the economy, a sector of the economy, productivity, competition,
jobs, the environment, public health or safety, or state, local, or
tribal governments or communities. The $100 million threshold can be
triggered by either costs or benefits, or a combination of them.
Accordingly, the EPA submitted this action to OMB for review under
Executive Orders 12866 and 13563 (76 FR 3821, January 21, 2011), and
any changes made in response to OMB recommendations have been
documented in the docket for this action.
    The EPA also prepared an analysis of the potential costs and
benefits associated with this action. This analysis is contained in the
RIA for this proposed rule. A copy of the analysis is available in the
docket for this action.
    Consistent with EO 12866 and EO 13563, the EPA estimated the costs
and benefits for illustrative compliance approaches of implementing the
proposed guidelines. This proposal sets goals to reduce CO2
emissions from the electric power industry. Actions taken to comply
with the proposed guidelines will also reduce the emissions of directly
emitted PM2.5, sulfur dioxide (SO2) and nitrogen
oxides (NOX). The benefits associated with these PM,
SO2 and NOX reductions are referred to as co-
benefits, as these reductions are not the primary objective of this
rule.
    The EPA has used the social cost of carbon estimates presented in
the 2013 Technical Support Document: Technical Update of the Social
Cost of Carbon for Regulatory Impact Analysis Under Executive Order
12866 (2013 SCC TSD) to analyze CO2 climate impacts of this
rulemaking. We refer to these estimates, which were developed by the
U.S. government, as ``SCC estimates.'' The SCC is an estimate of the
monetary value of impacts associated with a marginal change in
CO2 emissions in a given year. The four SCC estimates are
associated with different discount rates (model average at 2.5 percent
discount rate, 3 percent, and 5 percent; 95th percentile at 3 percent),
and each increases over time. In this summary, the EPA provides the
estimate of climate benefits associated with the SCC value deemed to be
central in the SCC TSD: The model average at 3% discount rate. For the
regional compliance approach, the EPA estimates that in 2020 this
Option 1 proposal will yield monetized climate benefits (in 2011$) of
approximately $17 billion (3 percent model average). The air pollution
health co-benefits in 2020 are estimated to be $16 billion to $37
billion (2011$) for a 3 percent discount rate and $15 billion to $34
billion (2011$) for a 7 percent discount rate. The annual, illustrative
compliance costs estimated by IPM and inclusive of demand side energy
efficiency program and participant costs and MRR costs, are
approximately $5.5 billion (2011$) in 2020. The quantified net benefits
(the difference between monetized benefits and costs) in 2020 are
estimated to be $28 billion to $49 billion assuming a regional
compliance approach (2011$) using a 3 percent discount rate (model
average). This range of net benefits is estimated to be $27 billion to
$50 billion assuming a state compliance approach (2011$)

using a 3 percent discount rate (model average). Table 18 shows the
climate benefits, health co-benefits, cost and net benefits for Option
1 in 2020 for state and regional compliance approaches. Table 19 shows
similar estimates for 2030.
    For Option 1 in 2030 assuming a regional compliance approach, the
EPA estimates this proposal will yield monetized climate benefits (in
2011$) of approximately $30 billion (3 percent, model average). The air
pollution health co-benefits in 2030 are estimated to be $25 billion to
$59 billion (2011$) for a 3 percent discount rate and $23 billion to
$54 billion (2011$) for a 7 percent discount rate. The annual
illustrative compliance costs estimated using IPM, inclusive of a
demand-side energy efficiency program and participant costs and MRR
costs, are approximately $7.3 billion (2011$) in 2030. The quantified
net benefits (the difference between monetized benefits and costs) in
2030 are estimated to be $48 billion to $82 billion (2011$) using a 3
percent discount rate (model average). The EPA estimates that this
proposal will yield monetized climate benefits (in 2011$) of
approximately $31 billion (3 percent, model average) for Option 1 state
compliance approach in 2030. The air pollution health co-benefits in
2030 are estimated to be $27 billion to $62 billion (2011$) for a 3
percent discount rate and $24 billion to $56 billion (2011$) for a 7
percent discount rate. The annual illustrative compliance costs
estimated using IPM, inclusive of demand side energy efficiency program
and participant costs and MRR costs, are approximately $8.8 billion
(2011$) in 2030. The quantified net benefits (the difference between
monetized benefits and costs) in 2030 are estimated to be $49 billion
to $84 billion (2011$) using a 3 percent discount rate (model average)
assuming a state compliance approach. Based upon the foregoing
discussion, it remains clear that the benefits of the proposal Option 1
are substantial and far exceed the costs.

  Table 18--Summary of the Monetized Benefits, Compliance Costs and Net
               Benefits for Proposed Option 1 in 2020 \a\
                           [Billions of 2011$]
------------------------------------------------------------------------
                               3% Discount rate      7% Discount rate
------------------------------------------------------------------------
                  Option 1 Regional Compliance Approach
------------------------------------------------------------------------
Climate benefits \b\.........                     $17.
                              ------------------------------------------
Air pollution health co-       $16 to $37......  $15 to $34
 benefits \c\.
Total Compliance Costs \d\...  $5.5............  $5.5
Net Monetized Benefits \e\...  $28 to $49......  $26 to $45
------------------------------------------------------------------------
Non-monetized Benefits.......  Direct exposure to SO2 and NO2.
                               1.3 tons of Hg.
                               Ecosystem Effects.
                               Visibility impairment.
------------------------------------------------------------------------
                   Option 1 State Compliance Approach
------------------------------------------------------------------------
Climate benefits \b\.........                     $18.
                              ------------------------------------------
Air pollution health co-       $17 to $40......  $15 to $36
 benefits \c\.
Total Compliance Costs \d\...  $7.5............  $7.5
Net Monetized Benefits \e\...  $27 to $50......  $26 to $46
------------------------------------------------------------------------
Non-monetized Benefits.......  Direct exposure to SO2 and NO2.
                               1.5 tons of Hg.
                               Ecosystem Effects.
                               Visibility impairment.
------------------------------------------------------------------------
\a\ All estimates are for 2020, and are rounded to two significant
  figures, so figures may not sum.
\b\ The climate benefit estimate in this summary table reflects global
  impacts from CO2 emission changes and does not account for changes in
  non-CO2 GHG emissions. Also, different discount rates are applied to
  SCC than to the other estimates because CO2 emissions are long-lived
  and subsequent damages occur over many years. The benefit estimates in
  this table are based on the average SCC estimated for a 3 percent
  discount rate; however, we emphasize the importance and value of
  considering the full range of SCC values. As shown in the RIA, climate
  benefits are also estimated using the other three SCC estimates (model
  average at 2.5 percent discount rate, 3 percent, and 5 percent; 95th
  percentile at 3 percent). The SCC estimates are year-specific and
  increase over time.
\c\ The air pollution health co-benefits reflect reduced exposure to
  PM2.5 and ozone associated with emission reductions of directly
  emitted PM2.5, SO2 and NOX. The range reflects the use of
  concentration-response functions from different epidemiology studies.
  The reduction in premature fatalities each year accounts for over 90
  percent of total monetized co-benefits from PM2.5 and ozone. These
  models assume that all fine particles, regardless of their chemical
  composition, are equally potent in causing premature mortality because
  the scientific evidence is not yet sufficient to allow differentiation
  of effect estimates by particle type.
\d\ Total costs are approximated by the illustrative compliance costs
  estimated using the Integrated Planning Model for the proposed option
  and a discount rate of approximately 5 percent. This estimate includes
  monitoring, recordkeeping, and reporting costs and demand side energy
  efficiency program and participant costs.
\e\ The estimates of net benefits in this summary table are calculated
  using the global social cost of carbon at a 3 percent discount rate
  (model average). The RIA includes combined climate and health
  estimates based on these additional discount rates.

 Table 19--Summary of the Monetized Benefits, Compliance Costs, and Net
               Benefits for Proposed Option 1 in 2030 \a\
                           [Billions of 2011$]
------------------------------------------------------------------------
                               3% Discount rate      7% Discount rate
------------------------------------------------------------------------
                  Option 1 Regional Compliance Approach
------------------------------------------------------------------------
Climate benefits \b\.........                     $30.
------------------------------------------------------------------------
Air pollution health co-       $25 to $59......  $23 to $54
 benefits \c\.
Total Compliance Costs \d\...  $7.3............  $7.3
Net Monetized Benefits \e\...  $48 to $82......  $46 to $77
------------------------------------------------------------------------

Non-monetized Benefits.......  Direct exposure to SO2 and NO2.
                               1.7 tons of Hg and 580 tons of HCl.
                               Ecosystem Effects.
                               Visibility impairment.
------------------------------------------------------------------------
                   Option 1 State Compliance Approach
------------------------------------------------------------------------
Climate benefits \b\.........                     $31.
                              ------------------------------------------
Air pollution health co-       $27 to $62......  $24 to $56
 benefits \c\.
Total Compliance Costs \d\...  $8.8............  $8.8
Net Monetized Benefits \e\...  $49 to $84......  $46 to $79
------------------------------------------------------------------------
Non-monetized Benefits.......  Direct exposure to SO2 and NO2.
                               2.1 tons of Hg and 590 tons of HCl.
                               Ecosystem Effects.
                               Visibility impairment.
------------------------------------------------------------------------
\a\ All estimates are for 2030, and are rounded to two significant
  figures, so figures may not sum.
\b\ The climate benefit estimate in this summary table reflects global
  impacts from CO2 emission changes and does not account for changes in
  non-CO2 GHG emissions. Also, different discount rates are applied to
  SCC than to the other estimates because CO2 emissions are long-lived
  and subsequent damages occur over many years. The benefit estimates in
  this table are based on the average SCC estimated for a 3 percent
  discount rate; however, we emphasize the importance and value of
  considering the full range of SCC values. As shown in the RIA, climate
  benefits are also estimated using the other three SCC estimates (model
  average at 2.5 percent discount rate, 3 percent, and 5 percent; 95th
  percentile at 3 percent). The SCC estimates are year-specific and
  increase over time.
\c\ The air pollution health co-benefits reflect reduced exposure to
  PM2.5 and ozone associated with emission reductions of directly
  emitted PM2.5, SO2 and NOX. The range reflects the use of
  concentration-response functions from different epidemiology studies.
  The reduction in premature fatalities each year accounts for over 90
  percent of total monetized co-benefits from PM2.5 and ozone. These
  models assume that all fine particles, regardless of their chemical
  composition, are equally potent in causing premature mortality because
  the scientific evidence is not yet sufficient to allow differentiation
  of effect estimates by particle type.
\d\ Total costs are approximated by the illustrative compliance costs
  estimated using the Integrated Planning Model for the proposed option
  and a discount rate of approximately 5 percent. This estimate includes
  monitoring, recordkeeping, and reporting costs and demand side energy
  efficiency program and participant costs.
\e\ The estimates of net benefits in this summary table are calculated
  using the global social cost of carbon at a 3 percent discount rate
  (model average). The RIA includes combined climate and health
  estimates based on these additional discount rates.

    The estimated costs and benefits for the regulatory alternative--
Option 2 regional and state compliance approaches are shown in Tables
20 and 21. As these tables reflect, net benefits in 2020 are estimated
to be $22 to $40 billion (3 percent discount rate) and $21 to $37
billion (7 percent discount rate) for Option 2 assuming regional
compliance. These Option 2 net benefit estimates become $22 to $40
billion (3 percent discount rate) and $20 to $37 billion (7 percent
discount rate) with the state compliance approach. In 2025, net
benefits are estimated to be $31 billion to $54 billion (3 percent
discount rate) and $29 billion to $50 billion (7 percent discount rate)
assuming a regional compliance approach and $31 billion to $55 billion
(3 percent discount rate) and $29 billion to $51 billion (7 percent
discount rate) assuming a state compliance approach.
    The EPA could not monetize important benefits of proposed Option 1
and regulatory alternative Option 2. Unquantified benefits include
climate benefits from reducing emissions of non-CO2
greenhouse gases and co-benefits from reducing exposure to
SO2, NOX, and hazardous air pollutants (e.g.,
mercury and hydrogen chloride), as well as ecosystem effects and
visibility impairment.

 Table 20--Summary of the Monetized Benefits, Compliance Costs, and Net
                Benefits for Proposed Option 2 in 2020 a
                           [Billions of 2011$]
------------------------------------------------------------------------
                               3% Discount rate      7% Discount rate
------------------------------------------------------------------------
                  Option 2 Regional Compliance Approach
------------------------------------------------------------------------
Climate benefits \b\.........                     $13.
                              ------------------------------------------
Air pollution health co-       $13 to $31......  $12 to $28
 benefits \c\.
Total Compliance Costs \d\...  $4.3............  $4.3
Net Monetized Benefits \e\...  $22 to $40......  $21 to $37
------------------------------------------------------------------------
Non-monetized Benefits.......  Direct exposure to SO2 and NO2.
                               0.9 tons of Hg.
                               Ecosystem Effects.
                               Visibility impairment.
------------------------------------------------------------------------

                   Option 2 State Compliance Approach
------------------------------------------------------------------------
Climate benefits \b\.........                     $14.
------------------------------------------------------------------------
Air pollution health co-       $14 to $32......  $12 to $29
 benefits \c\.
Total Compliance Costs \d\...  $5.5............  $5.5
Net Monetized Benefits \e\...  $22 to $40......  $20 to $37
------------------------------------------------------------------------
Non-monetized Benefits.......  Direct exposure to SO2 and NO2.
                               1.2 tons of Hg.
                               Ecosystem Effects.
                               Visibility impairment.
------------------------------------------------------------------------
\a\ All estimates are for 2020, and are rounded to two significant
  figures, so figures may not sum.
\b\ The climate benefit estimate in this summary table reflects global
  impacts from CO2 emission changes and does not account for changes in
  non-CO2 GHG emissions. Also, different discount rates are applied to
  SCC than to the other estimates because CO2 emissions are long-lived
  and subsequent damages occur over many years. The benefit estimates in
  this table are based on the average SCC estimated for a 3 percent
  discount rate; however, we emphasize the importance and value of
  considering the full range of SCC values. As shown in the RIA, climate
  benefits are also estimated using the other three SCC estimates (model
  average at 2.5 percent discount rate, 3 percent, and 5 percent; 95th
  percentile at 3 percent). The SCC estimates are year-specific and
  increase over time.
\c\ The air pollution health co-benefits reflect reduced exposure to
  PM2.5 and ozone associated with emission reductions of directly
  emitted PM2.5, SO2 and NOX. The range reflects the use of
  concentration-response functions from different epidemiology studies.
  The reduction in premature fatalities each year accounts for over 90
  percent of total monetized co-benefits from PM2.5 and ozone. These
  models assume that all fine particles, regardless of their chemical
  composition, are equally potent in causing premature mortality because
  the scientific evidence is not yet sufficient to allow differentiation
  of effect estimates by particle type.
\d\ Total costs are approximated by the illustrative compliance costs
  estimated using the Integrated Planning Model for the proposed option
  and a discount rate of approximately 5 percent. This estimate includes
  monitoring, recordkeeping and reporting costs and demand side energy
  efficiency program and participant costs.
\e\ The estimates of net benefits in this summary table are calculated
  using the global social cost of carbon at a 3 percent discount rate
  (model average). The RIA includes combined climate and health
  estimates based on these additional discount rates.

 Table 21--Summary of the Monetized Benefits, Compliance Costs, and Net
                Benefits for Proposed Option 2 in 2025 a
                           [Billions of 2011$]
------------------------------------------------------------------------
                               3% Discount rate      7% Discount rate
------------------------------------------------------------------------
                  Option 2 Regional Compliance Approach
------------------------------------------------------------------------
Climate benefits \b\.........                     $18.
                              ------------------------------------------
Air pollution health co-       $17 to $40......  $16 to $36
 benefits \c\.
Total Compliance Costs \d\...  $4.5............  $4.5
Net Monetized Benefits \e\...  $31 to $54......  $29 to $50
------------------------------------------------------------------------
Non-monetized Benefits.......  Direct exposure to SO2 and NO2.
                               1.3 tons of Hg.
                               Ecosystem Effects.
                               Visibility impairment.
------------------------------------------------------------------------
                   Option 2 State Compliance Approach
------------------------------------------------------------------------
Climate benefits \b\.........                     $19.
                              ------------------------------------------
Air pollution health co-       $18 to $41......  $16 to $37
 benefits \c\.
Total Compliance Costs \d\...  $5.5............  $5.5
Net Monetized Benefits \e\...  $31 to $55......  $29 to $51
------------------------------------------------------------------------
Non-monetized Benefits.......  Direct exposure to SO2 and NO2.
                               1.7 tons of Hg.
                               Ecosystem Effects.
                               Visibility impairment.
------------------------------------------------------------------------
\a\ All estimates are for 2025, and are rounded to two significant
  figures, so figures may not sum.
\b\ The climate benefit estimate in this summary table reflects global
  impacts from CO2 emission changes and does not account for changes in
  non-CO2 GHG emissions. Also, different discount rates are applied to
  SCC than to the other estimates because CO2 emissions are long-lived
  and subsequent damages occur over many years. The benefit estimates in
  this table are based on the average SCC estimated for a 3 percent
  discount rate; however, we emphasize the importance and value of
  considering the full range of SCC values. As shown in the RIA, climate
  benefits are also estimated using the other three SCC estimates (model
  average at 2.5 percent discount rate, 3 percent, and 5 percent; 95th
  percentile at 3 percent). The SCC estimates are year-specific and
  increase over time.
\c\ The air pollution health co-benefits reflect reduced exposure to
  PM2.5 and ozone associated with emission reductions of directly
  emitted PM2.5, SO2 and NOX. The range reflects the use of
  concentration-response functions from different epidemiology studies.
  The reduction in premature fatalities each year accounts for over 90
  percent of total monetized co-benefits from PM2.5 and ozone. These
  models assume that all fine particles, regardless of their chemical
  composition, are equally potent in causing premature mortality because
  the scientific evidence is not yet sufficient to allow differentiation
  of effect estimates by particle type.
\d\ Total costs are approximated by the illustrative compliance costs
  estimated using the Integrated Planning Model for the proposed option
  and a discount rate of approximately 5 percent. This estimate includes
  monitoring, recordkeeping and reporting costs and demand side energy
  efficiency program and participant costs.
\e\ The estimates of net benefits in this summary table are calculated
  using the global social cost of carbon at a 3 percent discount rate
  (model average). The RIA includes combined climate and health
  estimates based on these additional discount rates.

    The analysis done in support of this proposal shows that the
emission reductions, benefits, and costs for the illustrative
compliance approaches for the proposed Option 1 (and regulatory
alternative Option 2) are larger if states choose to comply on an
individual basis, compared to the illustrative regional compliance
approach. The regional approach allows for more flexibility across
states, which results in slightly fewer emission reductions and

lower overall costs. Net benefits (the difference between benefits and
costs) are roughly equivalent under the regional and state compliance
approaches.
    In evaluating the impacts of the proposed guidelines, we analyzed a
number of uncertainties, for example evaluating different potential
spatial approaches to state compliance (i.e., state and regional) and
in the estimated benefits of reducing carbon dioxide and other air
pollutants. For a further discussion of key evaluations of uncertainty
in the regulatory analyses for this proposed rulemaking, see the RIA
included in the docket.

B. Paperwork Reduction Act

    The information collection requirements in this proposed rule have
been submitted for approval to the Office of Management and Budget
(OMB) under the Paperwork Reduction Act, 44 U.S.C. 3501 et seq. The
Information Collection Request (ICR) document prepared by the EPA has
been assigned the EPA ICR number 2503.01.
    The information collection requirements are based on the
recordkeeping and reporting burden associated with developing,
implementing, and enforcing a state plan to limit CO2
emissions from existing sources in the power sector. These
recordkeeping and reporting requirements are specifically authorized by
CAA section 114 (42 U.S.C. 7414). All information submitted to the EPA
pursuant to the recordkeeping and reporting requirements for which a
claim of confidentiality is made is safeguarded according to agency
policies set forth in 40 CFR part 2, subpart B.
    The annual burden for this collection of information for the states
(averaged over the first 3 years following promulgation of this
proposed action) is estimated to be a range of 316,217 hours at a total
annual labor cost of $22,381,044, to 633,001 hours at a total annual
labor cost of $44,802,243. The lower bound estimate reflects the
assumption that some states already have energy efficiency and
renewable energy programs in place. The higher bound estimate reflects
the assumption that no states have energy efficiency and renewable
energy programs in place. The total annual burden for the federal
government (averaged over the first 3 years following promulgation of
this proposed action) is estimated to be 53,300 hours at a total annual
labor cost of $2,958,005. Burden means the total time, effort, or
financial resources expended by persons to generate, maintain, retain,
or disclose or provide information to or for a federal agency. This
includes the time needed to review instructions; develop, acquire,
install, and utilize technology and systems for the purposes of
collecting, validating, and verifying information, processing and
maintaining information, and disclosing and providing information;
adjust the existing ways to comply with any previously applicable
instructions and requirements; train personnel to be able to respond to
a collection of information; search data sources; complete and review
the collection of information; and transmit or otherwise disclose the
information.
    An agency may not conduct or sponsor, and a person is not required
to respond to a collection of information unless it displays a
currently valid OMB control number. The OMB control numbers for the
EPA's regulations are listed in 40 CFR part 9 and 48 CFR chapter 15.
    To comment on the agency's need for this information, the accuracy
of the provided burden estimates, and any suggested methods for
minimizing respondent burden, the EPA has established a public docket
for this rule, which includes this ICR, under Docket ID Number EPA-HQ-
OAR-2013-0602. Submit any comments related to the ICR to the EPA and to
OMB. See the ADDRESSES section at the beginning of this notice for
where to submit comments to the EPA. Send comments to OMB at the Office
of Information and Regulatory Affairs, Office of Management and Budget,
725 17th Street, NW., Washington, DC 20503, Attention: Desk Office for
the EPA. Since OMB is required to make a decision concerning the ICR
between 30 and 60 days after June 18, 2014, a comment to OMB is best
assured of having its full effect if OMB receives it by July 18, 2014.
The final rule will respond to any OMB or public comments on the
information collection requirements contained in this proposal.

C. Regulatory Flexibility Act

    The Regulatory Flexibility Act (RFA) generally requires an agency
to prepare a regulatory flexibility analysis of any rule subject to
notice and comment rulemaking requirements under the Administrative
Procedure Act or any other statute unless the agency certifies that the
rule will not have a significant economic impact on a substantial
number of small entities. Small entities include small businesses,
small organizations, and small governmental jurisdictions.
    For purposes of assessing the impacts of this rule on small
entities, small entity is defined as:
    (1) A small business that is defined by the SBA's regulations at 13
CFR 121.201 (for the electric power generation industry, the small
business size standard is an ultimate parent entity with less than 750
employees. The NAICS codes for the affected industry are in Table 22
below);
    (2) A small governmental jurisdiction that is a government of a
city, county, town, school district or special district with a
population of less than 50,000; and
    (3) A small organization that is any not-for-profit enterprise
which is independently owned and operated and is not dominant in its
field.

                            Table 22--Potentially Regulated Categories and Entities a
----------------------------------------------------------------------------------------------------------------
                                   NAICS
            Category                Code               Examples of potentially regulated entities \a\
----------------------------------------------------------------------------------------------------------------
Industry.......................     221112  Fossil fuel electric power generating units.
State/Local Government.........   221112 b  Fossil fuel electric power generating units owned by municipalities.
----------------------------------------------------------------------------------------------------------------
\a\ Include NAICS categories for source categories that own and operate electric power generating units
  (includes boilers and stationary combined cycle combustion turbines).
\b\ State or local government-owned and operated establishments are classified according to the activity in
  which they are engaged.

    After considering the economic impacts of this proposed rule on
small entities, I certify that this action will not have a significant
economic impact on a substantial number of small entities.
    The proposed rule will not impose any requirements on small
entities. Specifically, emission guidelines

established under CAA section 111(d) do not impose any requirements on
regulated entities and, thus, will not have a significant economic
impact upon a substantial number of small entities. After emission
guidelines are promulgated, states establish standards on existing
sources, and it is those state requirements that could potentially
impact small entities. Our analysis here is consistent with the
analysis of the analogous situation arising when the EPA establishes
NAAQS, which do not impose any requirements on regulated entities. As
here, any impact of a NAAQS on small entities would only arise when
states take subsequent action to maintain and/or achieve the NAAQS
through their state implementation plans. See American Trucking Assoc.
v. EPA, 175 F.3d 1029, 1043-45 (D.C. Cir. 1999) (NAAQS do not have
significant impacts upon small entities because NAAQS themselves impose
no regulations upon small entities).
    Nevertheless, the EPA is aware that there is substantial interest
in the proposed rule among small entities (municipal and rural electric
cooperatives). As detailed in Section III.A of this preamble, the EPA
has conducted an unprecedented amount of stakeholder outreach on
setting emission guidelines for existing EGUs. While formulating the
provisions of the proposed rule, the EPA considered the input provided
over the course of the stakeholder outreach. Section III.B of this
preamble describes the key messages from stakeholders. In addition, as
described in the RFA section of the preamble to the proposed standards
of performance for GHG emissions from new EGUs (79 FR 1499-1500,
January 8, 2014), the EPA conducted outreach to representatives of
small entities while formulating the provisions of the proposed
standards. Although only new EGUs would be affected by those proposed
standards, the outreach regarded planned actions for new and existing
sources. We invite comments on all aspects of the proposal and its
impacts, including potential impacts on small entities.

D. Unfunded Mandates Reform Act

    This proposed action does not contain a federal mandate that may
result in expenditures of $100 million or more for state, local, and
tribal governments, in the aggregate, or the private sector in any one
year. Specifically, the emission guidelines proposed under CAA section
111(d) do not impose any direct compliance requirements on regulated
entities, apart from the requirement for states to develop state plans.
The burden for states to develop state plans in the 3-year period
following promulgation of the rule was estimated and is listed in
Section IX B., above, but this burden is estimated to be below $100
million in any one year. Thus, this proposed rule is not subject to the
requirements of section 202 or section 205 of the Unfunded Mandates
Reform Act (UMRA).
    This proposed rule is also not subject to the requirements of
section 203 of UMRA because it contains no regulatory requirements that
might significantly or uniquely affect small governments.
    In light of the interest among governmental entities, the EPA
initiated consultations with governmental entities while formulating
the provisions of the proposed standards for new EGUs. Although only
new EGUs would be affected by those proposed standards, the outreach
regarded planned actions for new and existing sources. As described in
the UMRA discussion in the preamble to the proposed standards of
performance for GHG emissions from new EGUs (79 FR 1500-1501, January
8, 2014), the EPA consulted with the following 10 national
organizations representing state and local elected officials: (1)
National Governors Association; (2) National Conference of State
Legislatures, (3) Council of State Governments, (4) National League of
Cities, (5) U.S. Conference of Mayors, (6) National Association of
Counties, (7) International City/County Management Association, 8)
National Association of Towns and Townships, (9) County Executives of
America, and 10) Environmental Council of States. On February 26, 2014,
the EPA re-engaged with those governmental entities to provide a pre-
proposal update on the emission guidelines for existing EGUs and
emission standards for modified and reconstructed EGUs.
    While formulating the provisions of these proposed emission
guidelines, the EPA also considered the input provided over the course
of the extensive stakeholder outreach conducted by the EPA (see
Sections III.A. and III.B. of this preamble).

E. Executive Order 13132, Federalism

    Under Executive Order 13132, the EPA may not issue an action that
has federalism implications, that imposes substantial direct compliance
costs, and that is not required by statute, unless the federal
government provides the funds necessary to pay the direct compliance
costs incurred by state and local governments, or the EPA consults with
state and local officials early in the process of developing the
proposed action.
    The EPA has concluded that this action may have federalism
implications, because it may impose substantial direct compliance costs
on state or local governments, and the federal government will not
provide the funds necessary to pay those costs. As discussed in the
Supporting Statement found in the docket for this rulemaking, the
development of state plans will entail many hours of staff time to
develop and coordinate programs for compliance with the proposed rule,
as well as time to work with state legislatures as appropriate, and
develop a plan submittal.
    The EPA consulted with state and local officials early in the
process of developing the proposed action to permit them to have
meaningful and timely input into its development. As described in the
Federalism discussion in the preamble to the proposed standards of
performance for GHG emissions from new EGUs (79 FR 1501, January 8,
2014), the EPA consulted with state and local officials in the process
of developing the proposed standards for newly constructed EGUs. This
outreach regarded planned actions for new, reconstructed, modified and
existing sources. The EPA invited the following 10 national
organizations representing state and local elected officials to a
meeting on April 12, 2011, in Washington DC: (1) National Governors
Association; (2) National Conference of State Legislatures, (3) Council
of State Governments, (4) National League of Cities, (5) U.S.
Conference of Mayors, (6) National Association of Counties, (7)
International City/County Management Association, (8) National
Association of Towns and Townships, (9) County Executives of America,
and (10) Environmental Council of States. These 10 organizations
representing elected state and local officials have been identified by
the EPA as the ``Big 10'' organizations appropriate to contact for
purpose of consultation with elected officials. On February 26, 2014,
the EPA re-engaged with those governmental entities to provide a pre-
proposal update on the emission guidelines for existing EGUs and
emission standards for modified and reconstructed EGUs. In addition,
extensive stakeholder outreach conducted by the EPA allowed state
leaders, including governors, environmental commissioners, energy
officers, public utility commissioners, and air directors,
opportunities to engage with EPA officials and provide input regarding
reducing carbon pollution from power plants.
    A detailed Federalism Summary Impact Statement (FSIS) describing
the

most pressing issues raised in pre-proposal and post-proposal comments
will be forthcoming with the final rule, as required by section 6(b) of
Executive Order 13132. In the spirit of Executive Order 13132, and
consistent with the EPA's policy to promote communications between the
EPA and state and local governments, the EPA specifically solicits
comment on this proposed action from State and local officials.

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

    This action does not have tribal implications, as specified in
Executive Order 13175 (65 FR 67249, November 9, 2000). It would not
impose substantial direct compliance costs on tribal governments that
have affected EGUs located in their area of Indian country. Tribes are
not required to, but may, develop or adopt CAA programs. Tribes are not
required to develop plans to implement the guidelines under CAA section
111(d) for affected EGUs. To the extent that a tribal government seeks
and attains treatment in a manner similar to a state (TAS) status for
that purpose and is delegated authority for air quality planning
purposes, these proposed emission guidelines would require that
planning requirements be met and emission management implementation
plans be executed by the tribes. The EPA is aware of three coal-fired
EGUs and one natural gas-fired EGU located in Indian country but is not
aware of any affected EGUs that are owned or operated by tribal
entities. The EPA notes that this proposal does not directly impose
specific requirements on EGU sources, including those located in Indian
country, such as the three coal-fired EGUs and one natural gas-fired
EGU, but provides guidance to any tribe with delegated authority to
address CO2 emissions from EGU sources found subject to
section 111(d) of the CAA. Thus, Executive Order 13175 does not apply
to this action.
    The EPA conducted outreach to tribal environmental staff and
offered consultation with tribal officials in developing this action.
Because the EPA is aware of tribal interest in this proposed rule,
prior to the April 13, 2012 proposal (77 FR 22392-22441), the EPA
offered consultation with tribal officials early in the process of
developing the proposed regulation to permit them to have meaningful
and timely input into its development. The EPA's consultation regarded
planned actions for new and existing sources. In addition, on April 15,
2014, prior to proposal, the EPA met with Navajo Energy Development
Group officials. For this proposed action for existing EGUs, a tribe
that has one or more affected EGUs located in its area of Indian
country \346\ would have the opportunity, but not the obligation, to
establish a CO2 performance standard and a CAA section
111(d) plan for its area of Indian country.
---------------------------------------------------------------------------

    \346\ The EPA is aware of at least four affected EGUs located in
Indian country: Two on Navajo lands, the Navajo Generating Station
and the Four Corners Generating Station; one on Ute lands, the
Bonanza Generating Station; and one on Fort Mojave lands, the South
Point Energy Center. The affected EGUs at the first three plants are
coal-fired EGUs. The fourth affected EGU is an NGCC facility.
---------------------------------------------------------------------------

    Consultation letters were sent to 584 tribal leaders. The letters
provided information regarding the EPA's development of both the NSPS
and emission guidelines for fossil fuel-fired EGUs and offered
consultation. No tribes have requested consultation. Tribes were
invited to participate in the national informational webinar held
August 27, 2013. In addition, a consultation/outreach meeting was held
on September 9, 2013, with tribal representatives from some of the 584
tribes. The EPA also met with tribal environmental staff via National
Tribal Air Association teleconferences on July 25, 2013, and December
19, 2013. In those teleconferences, the EPA provided background
information on the GHG emission guidelines to be developed and a
summary of issues being explored by the agency. Tribes have expressed
varied points of view. Some tribes raised concerns about the impacts of
the regulations on EGUs and the subsequent impact on jobs and revenue
for their tribes. Other tribes expressed concern about the impact the
regulations would have on the cost of water to their communities as a
result of increased costs to the EGU that provide energy to transport
the water to the tribes. Other tribes raised concerns about the impacts
of climate change on their communities, resources, life ways and
hunting and treaty rights. The tribes were also interested in the scope
of the guidelines being considered by the agency (e.g., over what time
period, relationship to state and multi-state plans) and how tribes
will participate in these planning activities. In addition, the EPA
held a series of listening sessions prior to development of this
proposed action. In 2013, tribes participated in a session with the
state agencies, as well as a separate session with tribes.
    During the public comment period for this proposal, the EPA will
hold meetings with tribal environmental staff to inform them of the
content of this proposal, as well as offer further consultation with
tribal elected officials where it is appropriate. We specifically
solicit comment from tribal officials on this proposed rule.

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

    The EPA interprets EO 13045 (62 FR 19885, April 23, 1997) as
applying to those regulatory actions that concern health or safety
risks, such that the analysis required under section 5-501 of the Order
has the potential to influence the regulation. This action is not
subject to EO 13045 because it does not involve decisions on
environmental health or safety risks that may disproportionately affect
children. The EPA believes that the CO2 emission reductions
resulting from implementation of the proposed guidelines, as well as
substantial ozone and PM2.5 emission reductions as a co-
benefit, would further improve children's health.

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

    Executive Order 13211 (66 FR 28355; May 22, 2001) requires the EPA
to prepare and submit a Statement of Energy Effects to the
Administrator of the Office of Information and Regulatory Affairs, OMB,
for actions identified as ``significant energy actions.'' This action,
which is a significant regulatory action under EO 12866, is likely to
have a significant effect on the supply, distribution, or use of
energy. We have prepared a Statement of Energy Effects for this action
as follows. We estimate a 4 to 7 percent increase in retail electricity
prices, on average, across the contiguous U.S. in 2020, and a 16 to 22
percent reduction in coal-fired electricity generation as a result of
this rule. The EPA projects that electric power sector delivered
natural gas prices will increase by about 8 to 12 percent in 2020. For
more information on the estimated energy effects, please refer to the
economic impact analysis for this proposal. The analysis is available
in the RIA, which is in the public docket.

I. National Technology Transfer and Advancement Act

    Section 12(d) of the National Technology Transfer and Advancement
Act (NTTAA) of 1995 (Pub. L. 104-113; 15 U.S.C. 272 note) directs the
EPA to use Voluntary Census Standards (VCS) in its regulatory and
procurement activities unless to do so would be inconsistent with
applicable law or

otherwise impractical. Voluntary consensus standards are technical
standards (e.g., materials specifications, test methods, sampling
procedures, business practices) developed or adopted by one or more
voluntary consensus bodies. The NTTAA directs the EPA to provide
Congress, through annual reports to OMB, with explanations when an
agency does not use available and applicable VCS. This proposed
rulemaking does not involve technical standards.
    The EPA welcomes comments on this aspect of the proposed rulemaking
and specifically invites the public to identify potentially-applicable
VCS and to explain why such standards should be used in this action.

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

    Executive Order 12898 (59 FR 7629, February 16, 1994) establishes
federal executive policy on environmental justice. Its main provision
directs federal agencies, to the greatest extent practicable and
permitted by law, to make environmental justice part of their mission
by identifying and addressing, as appropriate, disproportionately high
and adverse human health or environmental effects of their programs,
policies and activities on minority populations and low-income
populations in the U.S.
    Section II.A of this preamble summarizes the public health and
welfare impacts from GHG emissions that were detailed in the 2009
Endangerment Finding under CAA section 202(a)(1).\347\ As part of the
Endangerment Finding, the Administrator considered climate change risks
to minority or low-income populations, finding that certain parts of
the population may be especially vulnerable based on their
circumstances. These include the poor, the elderly, the very young,
those already in poor health, the disabled, those living alone, and/or
indigenous populations dependent on one or a few resources. The
Administrator placed weight on the fact that certain groups, including
children, the elderly, and the poor, are most vulnerable to climate-
related health effects.
---------------------------------------------------------------------------

    \347\ ``Endangerment and Cause or Contribute Findings for
Greenhouse Gases Under Section 202(a) of the Clean Air Act,'' 74 FR
66,496 (Dec. 15, 2009) (``Endangerment Finding'').
---------------------------------------------------------------------------

    Strong scientific evidence that the potential impacts of climate
change raise environmental justice issues is found in the major
assessment reports by the U.S. Global Change Research Program (USGCRP),
the Intergovernmental Panel on Climate Change (IPCC), and the National
Research Council (NRC) of the National Academies, summarized in the
record for the Endangerment Finding. Their conclusions include that
poor communities can be especially vulnerable to climate change impacts
because they tend to have more limited adaptive capacities and are more
dependent on climate-sensitive resources such as local water and food
supplies. In addition, Native American tribal communities possess
unique vulnerabilities to climate change, particularly those on
established reservations that are restricted to reservation boundaries
and therefore have limited relocation options. Tribal communities whose
health, economic well-being, and cultural traditions depend upon the
natural environment will likely be affected by the degradation of
ecosystem goods and services associated with climate change. Southwest
native cultures are especially vulnerable to water quality and
availability impacts. Native Alaskan communities are likely to
experience disruptive impacts, including shifts in the range or
abundance of wild species crucial to their livelihoods and well-being.
The most recent assessments continue to strengthen scientific
understanding of climate change risks to minority and low-income
populations.
    This proposed rule would limit GHG emissions by establishing
CO2 emission guidelines for existing fossil fuel-fired EGUs.
In addition to reducing CO2 emissions, implementing the
proposed rule would reduce other emissions from EGUs that become
dispatched less frequently due to their relatively low energy
efficiency. These emission reductions will include SO2 and
NOx, which form ambient PM2.5 and ozone in the atmosphere,
and hazardous air pollutants (HAP), such as mercury and hydrochloric
acid. In the final rule revising the annual PM2.5
NAAQS,\348\ the EPA identified persons with lower socioeconomic status
as an at-risk population for experiencing adverse health effects
related to PM exposures. Persons with lower socioeconomic status have
been generally found to have a higher prevalence of pre-existing
diseases, limited access to medical treatment, and increased
nutritional deficiencies, which can increase this population's risk to
PM-related and ozone-related effects.\349\ Therefore, in areas where
this rulemaking reduces exposure to PM2.5, ozone, and
methylmercury, persons with low socioeconomic status would also
benefit. The RIA for this rulemaking, included in the docket for this
rulemaking, provides additional information regarding the health and
ecosystem effects associated with these emission reductions.
---------------------------------------------------------------------------

    \348\ ``National Ambient Air Quality Standards for Particulate
Matter, Final Rule,'' 78 FR 3086 (Jan. 15, 2013).
    \349\ U.S. Environmental Protection Agency (U.S. EPA). 2009.
Integrated Science Assessment for Particulate Matter (Final Report).
EPA-600-R-08-139F. National Center for Environmental Assessment--RTP
Division. December. Available on the Internet at <http://cfpub.epa.gov/ncea/cfm/recordisplay.cfm?deid=216546>.
---------------------------------------------------------------------------

    While there will be many locations with improved air quality for
PM2.5, ozone, and HAP, there may also be EGUs whose
emissions of one or more of these pollutants or their precursors
increase as a result of the proposed emission guidelines for existing
fossil fuel-fired EGUs. This may occur at EGUs that become dispatched
more intensively than in the past because they become more energy
efficient. The EPA has considered the potential for such increases and
the environmental justice implications of such increases.
    As we noted in the NSR discussion in this preamble, as part of a
state's CAA section 111(d) plan, the state may require an affected EGU
to undertake a physical or operational changes to improve the unit's
efficiency that result in an increase in the unit's dispatch and an
increase in the unit's annual emissions of GHGs and/or other regulated
pollutants. A state can take steps to avoid increased utilization of
particular EGUs and thus avoid any significant increases in emissions
including emissions of other regulated pollutants whose environmental
effects would be more localized around the affected EGU. To the extent
that states take this path, there would be no new environmental justice
concerns in the areas near such EGUs. For any EGUs that make
modifications that do trigger NSR permitting, the applicable local,
state, or federal permitting program will ensure that there are no new
NAAQS violations and that no existing NAAQS violations are made worse.
For those EGUs in a permitting situation for which the EPA is the
permit reviewing authority, the EPA will consider environmental justice
issues as required by Executive Order 12898.
    In addition to some EGUs possibly being required by a state to make
modifications for increased energy efficiency, another effect of the
proposed CO2 emission guidelines for existing fossil fuel-
fired EGUs would be

increased utilization of other, unmodified EGUs with relatively low GHG
emissions per unit of electrical output, in particular high efficiency
gas-fired EGUs. Because such EGUs would not have been modified
physically nor changed their method of operation, they would not be
subject to review in the NSR permitting program. Such plants would have
more hours in the year in which they operate and emit pollutants,
including pollutants whose environmental effects if any would be
localized rather than global as is the case with GHG emissions. Changes
in utilization already occur now as demands for and sources of
electrical energy evolve, but the proposed CO2 emission
guidelines for existing fossil fuel-fired EGUs can be expected to cause
more such changes. Because gas-fired EGUs emit essentially no mercury,
increased utilization would not increase methylmercury concentrations
in their vicinities. Increased utilization generally would not cause
higher peak concentrations of PM2.5, NOx, or ozone around
such EGUs than is already occurring because peak hourly or daily
emissions generally would not change, but increased utilization may
make periods of relatively high concentrations more frequent. It should
be noted that the gas-fired sources that are likely to become
dispatched more frequently than at present have very low emissions of
primary particulate matter, SO2 and HAP per unit of
electrical output, such that local (or regional) air quality for these
pollutants is likely to be affected very little. For natural gas-fired
EGUS, the EPA found that regulation of HAP emissions ``is not
appropriate or necessary because the impacts due to HAP emissions from
such units are negligible based on the results of the study documented
in the utility RTC.'' \350\ In studies done by DOE/NETL comparing cost
and performance of coal- and NG-fired generation, they assumed
SO2, PM (and Hg) emissions to be ``negligible.'' Their
studies predict NOx emissions from a NGCC unit to be approximately 10
times lower than a subcritical or supercritical coal-fired boiler. Many
are also very well controlled for emission of NOx through the
application of after combustion controls such as selective catalytic
reduction, although not all gas-fired sources are so equipped.
Depending on the specificity of the state CAA section 111(d) plan, the
state may be able to predict which EGUs and communities may be in this
type of situation and to address any concerns about localized
NO2 concentrations in the design of the CAA section 111(d)
program, or separately from the CAA section 111(d) program but before
its implementation. In any case, existing tracking systems will allow
states and the EPA to be aware of the EGUs whose utilization has
increased most significantly, and thus to be able to prioritize our
efforts to assess whether air quality has changed in the communities in
the vicinity of such EGUs. There are multiple mechanisms in the CAA to
address situations in which air quality has degraded significantly. In
conclusion, this proposed rule would result in regional and national
pollutant reductions; however, there likely would also be some
locations with more times during the year of relatively higher
concentrations of pollutants with potential for effects on localized
communities than would be experienced in the absence of the proposed
rule. The EPA cannot exactly predict how emissions from specific EGUs
would change as an outcome of the proposed rule due to the state-led
implementation. Therefore, the EPA has concluded that it is not
practicable to determine whether there would be disproportionately high
and adverse human health or environmental effects on minority, low
income, or indigenous populations from this proposed rule.
---------------------------------------------------------------------------

    \350\ 65 FR 79831.
---------------------------------------------------------------------------

    In order to provide opportunities for meaningful involvement early
on in the rule making process, the EPA has hosted webinars and
conference calls on August 27, 2013, and September 9, 2013, on the
proposed rule specifically for environmental justice communities and
has taken all comments and suggestions into consideration in the design
of the emission guidelines.
    The public is invited to submit comments or identify peer-reviewed
studies and data that assess effects of exposure to the pollutants
addressed by this proposal.

XII. Statutory Authority

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

List of Subjects in 40 CFR Part 60

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

    Dated: June 2, 2014.
Gina McCarthy,
Administrator.
    For the reasons stated in the preamble, title 40, chapter I, part
60 of the Code of the Federal Regulations is proposed to be amended as
follows:

PART 60--STANDARDS OF PERFORMANCE FOR NEW STATIONARY SOURCES

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

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

0
2. Section 60.27 is amended by revising paragraph (b) to read as
follows:

Sec.  60.27  Actions by the Administrator.

* * * * *
    (b) After receipt of a plan or plan revision, the Administrator
will propose the plan or revision for approval or disapproval. The
Administrator will, within four months after the date required for
submission of a plan or plan revision, approve or disapprove such plan
or revision or each portion thereof, except as provided in Sec.
60.5715.
* * * * *
0
3. Add subpart UUUU to read as follows:

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

Sec.

Introduction

60.5700 What is the purpose of this subpart?
60.5705 What pollutants are regulated by this subpart?
60.5710 Am I affected by this subpart?
60.5715 What is the review and approval process for my state plan?
60.5720 What if I do not submit a plan or my plan is not approvable?
60.5725 In lieu of a state plan submittal, are there other
acceptable option(s) for a state to meet its section 111(d)
obligations?
60.5730 Is there an approval process for a negative declaration
letter?
60.5735 What authorities will not be delegated to state, local, or
tribal agencies?

State Plan

60.5740 What must I include in my state plan?
60.5745 Can I work with other states to develop a multi-state plan?
60.5750 Can I include existing requirements, programs, and measures
in my state plan?
60.5755 What are the timing requirements for submitting my state
plan?
60.5760 What must I include in an initial submittal in lieu of a
complete state plan?

60.5765 What are the state rate-based CO2 emission
performance goals?
60.5770 What is the procedure for converting my state rate-based
CO2 emission performance goal to a mass-based
CO2 emissions performance goal?
60.5775 What schedules, performance periods, and compliance periods
must I include in my state plan?
60.5780 What emission standards and enforcing measures must I
include in my plan?
60.5785 What is the procedure for revising my state plan?

Applicability of State Plans to Affected EGUs

60.5790 Does this subpart directly affect EGU owners and operators
in my state?
60.5795 What affected EGUs must I address in my state plan?
60.5800 What affected EGUs are exempt from my state plan?
60.5805 What applicable monitoring, recordkeeping, and reporting
requirements do I need to include in my state plan for affected
EGUs?

Recordkeeping and Reporting Requirements

60.5810 What are my state recordkeeping requirements?
60.5815 What are my state reporting requirements?

Definitions

60.5820 What definitions apply to this subpart?
Table 1 to Subpart UUUU of Part 60--State Rate-based CO2
Emission Performance Goals (Pounds of CO2 Per Net MWh)

Introduction

Sec.  60.5700  What is the purpose of this subpart?

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

Sec.  60.5705  What pollutants are regulated by this subpart?

    (a) The pollutants regulated by this subpart are greenhouse gases.
    (b) The greenhouse gas regulated by this subpart is carbon dioxide
(CO2).

Sec.  60.5710  Am I affected by this subpart?

    If you are the Administrator of an air quality program in a state
with one or more affected EGUs that commenced construction on or before
January 8, 2014, you must submit a state plan to the U.S. Environmental
Protection Agency (EPA) that implements the emission guidelines
contained in this subpart. You must submit a negative declaration
letter in place of the state plan if there are no affected EGUs for
which construction commenced on or before January 8, 2014 in your
state.

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

    The EPA will review your state plan according to Sec.  60.27 except
that under Sec.  60.27(b) the Administrator will have twelve months
after the date required for submission of a plan or plan revision to
approve or disapprove such plan or revision or each portion thereof. If
you submit a request for extension under Sec.  60.5760(a) in lieu of a
complete state plan the EPA will follow the procedure in Sec.
60.5760(b).

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

    If you do not submit an approvable state plan the EPA will develop
a Federal plan for your state according to Sec.  60.27 to implement the
emission guidelines contained in this subpart. Owners and operators of
affected entities not covered by an approved state plan must comply
with a Federal plan implemented by the EPA for the state. The Federal
plan is an interim action and will be automatically withdrawn when your
state plan is approved.

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

    A state may meet its CAA section 111(d) obligations only by
submitting a complete state plan or a negative declaration letter (if
applicable).

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

    No. The EPA has no formal review process for negative declaration
letters. Once your negative declaration letter has been received, the
EPA will place a copy in the public docket and publish a notice in the
Federal Register. If, at a later date, an affected EGU for which
construction commenced on or before January 8, 2014 is found in your
state, a Federal plan implementing the emission guidelines contained in
this subpart would automatically apply to that affected EGU until your
state plan is approved.

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

    The authorities that will not be delegated to State, local, or
tribal agencies are specified in paragraph (a) of this section.
    (a) Approval of alternatives, not already approved by this subpart,
to the emissions performance goals in Table 1 to this subpart
established under Sec.  60.5755.
    (b) [Reserved]

State Plan

Sec.  60.5740  What must I include in my state plan?

    (a) You must include the elements described in paragraphs (a)(1)
through (11) of this section in your state plan.
    (1) Identification of affected entities, including an inventory of
CO2 emissions from affected EGUs during the most recent
calendar year prior to the submission of the plan for which data is
available.
    (2) A description of plan approach and the geographic scope of a
plan (state or multi-state), including, if relevant, identification of
multi-state plan participants and geographic boundaries related to plan
elements.
    (3) Identification of the state emission performance level for
affected entities that will be achieved through implementation of the
plan.
    (i) The plan must specify the average emissions performance that
the plan will achieve for the following periods:
    (A) The 10 year interim plan performance period of 2020 through
2029.
    (B) The single projection year of 2030.
    (ii) The identified emission performance level for each plan
performance period in paragraph (a)(3)(i) of this section must be
equivalent to or better than the levels of the rate-based
CO2 emission performance goals in Table 1 of this Subpart
for affected entities in your state. The emission performance levels
may be in either a rate-based form or a mass based form which is
calculated according to Sec.  60.5770. The CO2 emission
performance level specified must include either of the following as
applicable:
    (A) For a rate-based CO2 emission performance level, the
identified level must represent the CO2 emissions rate, in
pounds of CO2 per MWh of net energy output that will be
achieved by affected entities.
    (B) For a mass-based CO2 emission performance level, the
identified level of performance must represent the total tons of
CO2 that will be emitted by affected entities during each
plan performance period.

    (iii) For the interim plan performance period you must identify the
emission performance levels anticipated under the plan during each year
2020 through 2029.
    (4) A demonstration that the plan is projected to achieve each of
the state's emission performance levels for affected entities according
to paragraph (a)(3) of this section.
    (5) Identification of emission standards for each affected entity,
compliance periods for each emission standard, and demonstration that
the emission standards are, when taken together, sufficiently
protective to meet the state emissions performance level.
    (6) A demonstration that each emission standard is quantifiable,
non-duplicative, permanent, verifiable, and enforceable with respect to
an affected entity.
    (7) If your state plan does not require achievement of the full
level of required emission performance, and the identified interim
increments of performance in paragraph (a)(3)(iii) of this section,
through emission limits on EGUs, the plan must specify the following:
    (i) Program implementation milestones (e.g., start of an end-use
energy efficiency program, retirement of an affected EGU, or increase
in portfolio requirements under a renewable portfolio standard) and
milestone dates that are appropriate to the requirements, programs, and
measures included in the plan.
    (ii) Corrective measures that will be implemented in the event that
the comparison required by Sec.  60.5815(b) of projected versus actual
emissions performance of affected entities shows that actual emissions
performance is greater than 10 percent in excess to projected plan
performance for the period described in Sec.  60.5775(c)(1), and a
process and schedule for implementing such corrective measures.
    (8) Identification of applicable monitoring, reporting, and
recordkeeping requirements for each affected entity. If applicable,
these requirements must be consistent with the requirements specified
in Sec.  60.5810.
    (9) Description of the process, contents, and schedule for annual
state reporting to the EPA about plan implementation and progress
including information required under Sec.  60.5815.
    (10) Certification that the hearing on the state plan was held, a
list of witnesses and their organizational affiliations, if any,
appearing at the hearing, and a brief written summary of each
presentation or written submission.
    (11) Supporting material including:
    (i) Materials demonstrating the state's legal authority to carry
out each component of its plan, including emissions standards;
    (ii) Materials supporting the projected emissions performance level
that will be achieved by affected entities under the plan, according to
paragraph (a)(4) of this section;
    (iii) Materials supporting the projected mass-based emission
performance goal, calculated pursuant to Sec.  60.5770, if applicable;
and
    (iv) Materials necessary to support evaluation of the plan by the
EPA.
    (b) You must follow the requirements of subpart B of this part
(Adoption and Submittal of state plans for Designated Facilities) and
demonstrate that they were met in your state plan.

Sec.  60.5745  Can I work with other states to develop a multi-state
plan?

    A multi-state plan may be submitted, provided it is signed by
authorized officials for each of the states participating in the multi-
state plan. In this instance, the joint submittal will have the same
legal effect as an individual submittal for each participating state. A
multi-state plan will include all the required elements for a single-
state plan specified in Sec.  60.5740(a). A multi-state plan, if
submitted by a state, must:
    (a) Demonstrate CO2 emission performance jointly for all
affected entities in all states participating in the multi-state plan,
as follows:
    (1) For states demonstrating performance based on the
CO2 emission rate, the level of performance identified in
the multi-state plan pursuant to Sec.  60.5740(a)(3) will be a weighted
(by net energy output) average lb CO2/MWh emission rate to
be achieved by all affected EGUs in the multi-state area during the
plan performance period; or
    (2) For states demonstrating performance based on mass
CO2 emissions, the level of performance identified in the
multi-state plan pursuant to 60.5740(a)(3) will be total CO2
emissions by all affected EGUs in the multi-state area during the plan
performance period.
    (b) Assign among states, according to a formula in the multi-state
plan, avoided CO2 emissions resulting from emission
standards contained in the plan, from affected entities in states
participating in the multi-state plan.

Sec.  60.5750  Can I include existing requirements, programs, and
measures in my state plan?

    (a) Yes, you may include existing requirements, programs and
measures in your plan according to paragraphs (b) through (d) of this
section.
    (b) Existing state programs, requirements, and measures, may
qualify for use in demonstrating that a state plan achieves the
required level of emission performance specified in a plan, according
to Sec.  60.5740(a)(3).
    (c) Existing state programs, requirements, and measures, may
qualify for use in projecting that a state plan will achieve the
required level of emission performance specified in a plan, according
to Sec.  60.5740(a)(4).
    (d) Emission impacts of existing programs, requirements, and
measures that occur during a plan performance period may be recognized
in meeting or projecting CO2 emission performance by
affected EGUs according to Sec.  60.5740(a)(3) and (4), as long as they
meet the following requirements:
    (1) Actions taken pursuant to an existing state program,
requirement, or measure, such as compliance with a regulatory
obligation or initiation of an action related to a program or measure,
must occur after June 18, 2014; and
    (2) The existing state program, requirement, or measure, and any
related actions taken pursuant to such program, requirement, or
measure, meet the applicable requirements pursuant to Sec.  60.5740(a)
and Sec.  60.5780.

Sec.  60.5755  What are the timing requirements for submitting my state
plan?

    (a) You must submit your state plan with the information in Sec.
60.5740 by June 30, 2016 unless you are submitting a request for
extension according to paragraphs (b) or (c) of this section.
    (b) For a state seeking a one year extension for a complete plan
submittal you must include the information in Sec.  60.5760(a) in a
submittal by June 30, 2016 to receive an extension to submit your
complete state plan by June 30, 2017.
    (c) For states in a multi-state plan seeking a two year extension
for a complete plan submittal you must include the information in Sec.
60.5760(a) in a submittal by June 30, 2016 to receive an extension to
submit your complete multi-state plan by June 30, 2018.

Sec.  60.5760  What must I include in an initial submittal in lieu of a
complete state plan?

    (a) You must include the following required elements in an initial
submittal in lieu of a complete state plan:
    (1) A description of the plan approach and progress made to date in
developing each of the plan elements in Sec.  60.5740;
    (2) An initial projection of the level of emission performance that
will be achieved under the complete plan;
    (3) A commitment by the state to maintain existing state programs
and

measures that limit or avoid CO2 emissions from affected
entities (e.g., renewable energy standards, unit-specific limits on
operation or fuel utilization), which must at a minimum apply during
the interim period prior to state submission and EPA approval of a
complete plan, and must continue to apply in lieu of a complete plan if
one is ultimately not submitted and approved;
    (4) Justification of why additional time is needed to submit a
complete plan;
    (5) A comprehensive roadmap for completing the plan, including
process, analytical methods and schedule (including milestones)
specifying when all necessary plan components will be complete (e.g.,
projection of emission performance; implementing legislation,
regulations and agreements; necessary approvals);
    (6) Identification of existing and future programs, requirements,
and measures the state intends to include in the plan;
    (7) If a multi-state plan is being developed, an executed
agreement(s) with other states (e.g., MOU) participating in the
development of the multistate plan; and
    (8) A commitment to submit a complete plan by June 30, 2017, for a
single-state plan, or June 30, 2018, for a multi-state plan, and
actions the state will take to show progress in addressing incomplete
plan components prior to submittal of the complete plan.
    (9) A description of all steps the state has already taken in
furtherance of actions needed to finalize a complete plan.
    (10) Evidence of an opportunity for public comment and a response
to any significant comments received on issues relating to the
approvability of the initial plan.
    (b) You must submit either a complete state plan or an initial
submittal by June 30, 2016. Where an initial submittal is submitted in
lieu of a complete state plan the due date of a complete state plan
will be June 30, 2017, for a single-state plan, or June 30, 2018, for a
multi-state plan unless a state is notified within 60 days of the EPA
receiving the initial submittal in paragraph (a) of this section that
the EPA finds the initial submittal does not meet the requirements
listed in paragraph (a) of this section.

Sec.  60.5765  What are the state rate-based CO2 emissions
performance goals?

    (a) The annual average state rate-based CO2 emission
performance goals for the interim performance periods of 2020 through
2029, and the final 2030 and thereafter period are respectively listed
in Table 1 of this Subpart. The state rate-based CO2
emission performance goal may be converted to a mass-based emission
performance goal according to Sec.  60.5770.
    (b)[Reserved]

Sec.  60.5770  What is the procedure for converting my state rate-based
CO2 emission performance goal to a mass-based CO2
emissions performance goal?

    (a) If the plan adopts a mass-based goal according to Sec.
60.5740(a)(3), the plan must identify the mass-based goal, in tons of
CO2 emitted by affected EGUs over the plan performance
period, and include a description of the analytic process, tools,
methods, and assumptions used to convert from the rate-based goal for
the state identified in Table 1 of this Subpart to an equivalent mass-
based goal. The conversion process must include following requirements:
    (1) The process, tools, methods, and assumptions used in the
conversion of the rate-based goal must be included in your state plan
according to Sec.  60.5740(a)(11).
    (2) The material supporting the conversion of the rate-based goal,
including results, data, and descriptions, must be include in a state
plan according to Sec.  60.5740(a)(11).
    (3) The conversion must represent the tons of CO2
emissions that are projected to be emitted by affected EGUs, in the
absence of emission standards contained in the plan, if the affected
EGUs were to perform at an average lb CO2/MWh rate equal to
the rate-based goal for the state identified in Table 1 of this
Subpart.
    (b) [Reserved]

Sec.  60.5775  What schedules, performance periods, and compliance
periods must I include in my state plan?

    (a) Your state plan must include a schedule of compliance for each
affected entity regulated under the plan.
    (b) Your state plan must include compliance periods, as defined in
section Sec.  60.5820, for each affected entity regulated under the
plan.
    (c) For the interim performance period of 2020-2029 your state must
meet the requirements in paragraphs (c)(1) and (2) of this section.
    (1) Your state plan must include increments of emissions
performance (either rate based or mass based with respect to the
interim level of performance set in the state plan) within the interim
performance period for every 2-rolling calendar years starting January
1, 2020 and ending in 2028 (i.e. 2020-2021, 2021-2022, 2022-2023,
etc.), unless other periods that ensure regular progress in the interim
period are approved by the Administrator.
    (2) At the end of 2029 your state must meet the interim emissions
performance level specified in Sec.  60.5740(a)(3) as averaged over the
plan performance period 2020-2029.
    (d) During the final performance period, 2030 and thereafter, your
state must meet the final emission performance level specified in Sec.
60.5740(a)(3) on a 3-calendar year rolling average starting January 1,
2030 (i.e., 2030-2032, 2031-2033, 2032-2034, etc.).
    (e) You must include the provisions of your state plan which
demonstrate progress and compliance with the requirements in this Sec.
60.5775 and Sec.  60.5740 in your state's annual report required in
Sec.  60.5815.

Sec.  60.5780  What emission standards and enforcing measures must I
include in my plan?

    (a) Your state plan shall include emission standard(s) that are
quantifiable, verifiable, non-duplicative, permanent, and enforceable
with respect to each affected entity. The plan shall include the
methods by which each emission standard meets each of the following
requirements in paragraphs (b) through (f) of this section.
    (b) An emission standard is quantifiable with respect to an
affected entity if it can be reliably measured, in a manner that can be
replicated.
    (c) An emission standard is verifiable with respect to an affected
entity if adequate monitoring, recordkeeping and reporting requirements
are in place to enable the state and the Administrator to independently
evaluate, measure, and verify compliance with the emission standard.
    (d) An emission standard is non-duplicative with respect to an
affected entity if it is not already incorporated as an emission
standard in another state plan unless incorporated in multi-state plan.
    (e) An emission standard is permanent with respect to an affected
entity if the emission standard must be met for each compliance period,
or unless it is replaced by another emission standard in an approved
plan revision, or the state demonstrates in an approved plan revision
that the emission reductions from the emission standard are no longer
necessary for the state to meet its state level of performance.
    (f) An emission standard is enforceable against an affected entity
if:
    (1) A technically accurate limitation or requirement and the time
period for

the limitation or requirement is specified;
    (2) Compliance requirements are clearly defined;
    (3) The affected entities responsible for compliance and liable for
violations can be identified;
    (4) Each compliance activity or measure is enforceable as a
practical matter; and
    (5) The Administrator and the state maintain the ability to enforce
violations and secure appropriate corrective actions pursuant to
sections 113(a) through (h) of the Act.

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

    State plans can only be revised with approval by the Administrator.
If one (or more) of the elements of the state plan set in Sec.  60.5740
require revision with respect to reaching the emission performance goal
set in Sec.  60.5765 a request may be submitted to the Administrator
indicating the proposed corrections to the state plan to ensure the
emission performance goal is met.

Applicability of State Plans to Affected EGUs

Sec.  60.5790  Does this subpart directly affect EGU owners and
operators in my state?

    (a) This subpart does not directly affect EGU owners and operators
in your state. However, EGU owners and operators must comply with the
state plan that a state develops to implement the emission guidelines
contained in this subpart.
    (b) If a state does not submit an approvable plan or initial
submittal to implement and enforce the emission guidelines contained in
this subpart by June 30, 2016, the EPA will implement and enforce a
Federal plan, as provided in Sec.  60.5740, to ensure that each
affected EGU within the state that commenced construction on or before
January 8, 2014 reaches compliance with all the provisions of this
subpart.

Sec.  60.5795  What affected EGUs must I address in my state plan?

    (a) The EGUs that must be addressed by your state plan are any
affected steam generating unit, IGCC, or stationary combustion turbine
that commences construction on or before January 8, 2014.
    (b) An affected EGU is a steam generating unit, integrated
gasification combined cycle (IGCC), or stationary combustion turbine
that meets the relevant applicability conditions specified in paragraph
(b)(1) or (2) of this section.
    (1) A steam generating unit or IGCC that has a base load rating
greater than 73 MW (250 MMBtu/h) heat input of fossil fuel (either
alone or in combination with any other fuel) and was constructed for
the purpose of supplying one-third or more of its potential electric
output and more than 219,000 MWh net-electric output to a utility
distribution system on an annual basis.
    (2) A stationary combustion turbine that has a base load rating
greater than 73 MW (250 MMBtu/h), was constructed for the purpose of
supplying, and supplies, one-third or more of its potential electric
output and more than 219,000 MWh net-electrical output to a utility
distribution system on a 3-year rolling average basis, combusts fossil
fuel for more than 10.0 percent of the heat input during a 3-year
rolling average basis and combusts over 90% natural gas on a heat input
basis on a 3-year rolling average basis.

Sec.  60.5800  What affected EGUs are exempt from my state plan?

    Affected EGUs that are exempt from your state plan include: those
that are subject to subpart TTTT as a result of commencing construction
or reconstruction after the subpart TTTT applicability date; and those
subject to subpart TTTT as a result of commencing modification or
reconstruction prior becoming subject to an applicable state plan.

Sec.  60.5805  What applicable monitoring, recordkeeping, and reporting
requirements do I need to include in my state plan for affected EGUs?

    (a) A state plan must include monitoring that is no less stringent
that what is described in (a)(1) through (6) of this section.
    (1) If an affected EGU is required to meet a rate based emission
standard they must prepare a monitoring plan in accordance with the
applicable provisions in Sec.  75.53(g) and (h) of this chapter.
    (2) An affected EGU must measure the hourly CO2 mass
emissions from each affected unit using the procedures in paragraphs
(a)(2)(i) through (v) of this section, except as provided in paragraph
(a)(3) of this section.
    (i) An affected EGU must install, certify, operate, maintain, and
calibrate a CO2 continuous emissions monitoring system
(CEMS) to directly measure and record CO2 concentrations in
the affected EGU exhaust gases emitted to the atmosphere and an exhaust
gas flow rate monitoring system according to Sec.  75.10(a)(3)(i) of
this chapter. If an affected EGU measures CO2 concentration
on a dry basis, they must also install, certify, operate, maintain, and
calibrate a continuous moisture monitoring system, according to Sec.
75.11(b) of this chapter.
    (ii) For each monitoring system an affected EGU uses to determine
the CO2 mass emissions, they must meet the applicable
certification and quality assurance procedures in Sec.  75.20 of this
chapter and Appendices B and D to part 75 of this chapter.
    (iii) An affected EGU must use a laser device to measure the
dimensions of each exhaust gas stack or duct at the flow monitor and
the reference method sampling locations prior to the initial setup
(characterization) of the flow monitor. For circular stacks, an
affected EGU must measure the diameter at three or more distinct
locations and average the results. For rectangular stacks or ducts, an
affected EGU must measure each dimension (i.e., depth and width) at
three or more distinct locations and average the results. If the flow
rate monitor or reference method sampling site is relocated, an
affected EGU must repeat these measurements at the new location.
    (iv) An affected EGU must use only unadjusted exhaust gas
volumetric flow rates to determine the hourly CO2 mass
emissions from the affected facility; an affected EGU must not apply
the bias adjustment factors described in section 7.6.5 of Appendix A to
part 75 of this chapter to the exhaust gas flow rate data.
    (v) If an affected EGU chooses to use Method 2 in Appendix A-1 to
this part to perform the required relative accuracy test audits (RATAs)
of the part 75 flow rate monitoring system, they must use a calibrated
Type-S pitot tube or pitot tube assembly. An affected EGU must not use
the default Type-S pitot tube coefficient.
    (3) If an affected EGU exclusively combusts liquid fuel and/or
gaseous fuel as an alternative to complying with paragraph (b) of this
section, they may determine the hourly CO2 mass emissions by
using Equation G-4 in Appendix G to part 75 of this chapter according
to the requirements in paragraphs (a)(3)(i) and (ii) of this section.
    (i) An affected EGU must implement the applicable procedures in
appendix D to part 75 of this chapter to determine hourly unit heat
input rates (MMBtu/h), based on hourly measurements of fuel flow rate
and periodic determinations of the gross calorific value (GCV) of each
fuel combusted.
    (ii) An affected EGU may determine site-specific carbon-based F-
factors (Fc) using Equation F-7b in section 3.3.6 of
appendix F to part 75 of this chapter, and may use these Fc
values in the

emissions calculations instead of using the default Fc
values in the Equation G-4 nomenclature.
    (4) An affected EGU must install, calibrate, maintain, and operate
a sufficient number of watt meters to continuously measure and record
on an hourly basis net electric output. Measurements must be performed
using 0.2 accuracy class electricity metering instrumentation and
calibration procedures as specified under ANSI Standards No. C12.20.
Further, an affected EGU that is a combined heat and power facility
must install, calibrate, maintain and operate equipment to continuously
measure and record on an hourly basis useful thermal output and, if
applicable, mechanical output, which are used with net electric output
to determine net energy output.
    (5) In accordance with Sec.  60.13(g), if two or more affected EGUs
that implement the continuous emissions monitoring provisions in
paragraph (a)(2) of this section share a common exhaust gas stack and
are subject to the same emissions standard, they may monitor the hourly
CO2 mass emissions at the common stack in lieu of monitoring
each EGU separately. If an affected EGU chooses this option, the hourly
net electric output for the common stack must be the sum of the hourly
net electric output of the individual affected facility and you must
express the operating time as ``stack operating hours'' (as defined in
Sec.  72.2 of this chapter).
    (6) In accordance with Sec.  60.13(g), if the exhaust gases from an
affected EGU that implements the continuous emissions monitoring
provisions in paragraph (a)(2) of this section are emitted to the
atmosphere through multiple stacks (or if the exhaust gases are routed
to a common stack through multiple ducts and you elect to monitor in
the ducts), they must monitor the hourly CO2 mass emissions
and the ``stack operating time'' (as defined in Sec.  72.2 of this
chapter) at each stack or duct separately. In this case, an affected
EGU must determine compliance with an applicable emissions standard by
summing the CO2 mass emissions measured at the individual
stacks or ducts and dividing by the net energy output for the affected
EGU.
    (b) An affected EGU must maintain records for at least 10 years
following the date of each occurrence, measurement, maintenance,
corrective action, report, or record.
    (1) An affected EGU must maintain each record on site for at least
2 years after the date of each occurrence, measurement, maintenance,
corrective action, report, or record, according to Sec.  60.7. An
affected EGU may maintain the records off site and electronically for
the remaining year(s).
    (c) An affected EGU must include in a report required by the state
plan covering each compliance period all hourly CO2
emissions and all hourly net electric output and all hourly net energy
output measurements for a CHP facility calculated from data monitored
according to paragraph (a) of this section.

Recordkeeping and Reporting Requirements

Sec.  60.5810  What are my state recordkeeping requirements?

    (a) States must keep records of all plan components, plan
requirements, supporting documentation, and the status of meeting the
plan requirements defined in the state plan on an annual basis during
the interim plan performance period from 2020-2029. After 2029 states
must keep records of all information that is used to support any
continued effort to meet the final emissions performance goal.
    (b) States must keep records of all data submitted by each affected
entity that is used to determine compliance with each affected entity's
emissions standard.
    (c) If a state has a requirement for hourly CO2
emissions and net generation information to be used to calculate
compliance with an annual emissions standard for affected EGUs, any
information that is submitted to the EPA electronically pursuant to
requirements in Part 75 would meet the recordkeeping requirement of
this section and a state would not need to keep records of information
that would be in duplicate of paragraph (b) of this section.
    (d) A state must keep records at minimum for 20 years.

Sec.  60.5815  What are my state reporting requirements?

    (a) You must submit an annual report covering each calendar year no
later than July 1 of the following year, starting July 1 2021. The
annual report must include the following:
    (1) The level of emissions performance achieved by all affected
entities and identification of whether affected entities are on
schedule to meet the applicable level of emissions performance for
affected entities during the plan performance period and compliance
periods, as specified in the plan.
    (2) The level of emissions performance achieved by all affected
EGUs during the reporting period, and prior reporting periods,
expressed as average CO2 emissions rate or total mass
CO2 emissions, consistent with the plan approach, and
identification of whether affected EGUs are on schedule to meet the
applicable level of emissions performance for affected EGUs during the
plan performance period, as specified in the plan.
    (3) A list of affected entities and their compliance status with
the applicable emissions standards specified in the state plan.
    (4) A list of all affected EGUs and their reported CO2
emissions performance for each compliance period during the reporting
period, and prior reporting periods.
    (5) All other required information, as specified in your state plan
according to Sec.  60.5740(a)(9).
    (6) All information required by Sec.  60.5775(e).
    (b) For each two-year period in Sec.  60.5775(c)(1), you must
compare the average CO2 emission performance achieved by
affected entities in the state versus the CO2 emission
performance projected in the state plan. If actual emission performance
is greater than 10 percent in excess to projected plan performance for
a two-year comparison period, you must explain the reasons for the
deviation and specify the corrective actions that will be taken to
ensure that the required interim and final levels of emission
performance in the plan will be met. The information required in this
paragraph must be included in the annual report required by paragraph
(a) of this section.
    (c) You must include in your 2029 annual report (which is
subsequently due by July 1, 2030) the calculation of average emissions
over the 2020-2029 interim performance period used to determine
compliance with your interim emission performance level. The calculated
value must be in units consistent with your interim emission
performance level.
    (d) You must include in each report, starting with the 2032 annual
report (which is subsequently due by July 1, 2033), a 3-calendar year
rolling average used to determine compliance with the final emission
performance level. The calculated value must be in units consistent
with your final emission performance level.

Definitions

Sec.  60.5820  What definitions apply to this subpart?

    As used in this subpart, all terms not defined herein will have the
meaning given them in the Clean Air Act and in subparts A (General
Provisions) and B of this part.

    Affected electric generating unit or Affected EGU means a steam
generating unit, an IGCC facility, or a stationary combustion turbine
that meets the applicability conditions in section Sec.  60.5795.
    Affected Entity shall mean any of the following: An affected EGU,
or another entity with obligations under this subpart for the purpose
of meeting the emissions performance goal requirements in these
emission guidelines.
    Base load rating means the maximum amount of heat input (fuel) that
a steam generating unit can combust on a steady state basis, as
determined by the physical design and characteristics of the steam
generating unit at ISO conditions. For a stationary combustion turbine,
base load rating means 100 percent of the design heat input capacity of
the simple cycle portion of the stationary combustion turbine at ISO
conditions (heat input from duct burners is not included).
    CO2 emissions performance goal means the rate-based CO2
emissions performance goal specified for a state in Table 1 of this
subpart, or a translated mass-based form of that goal.
    Coal means all solid fuels classified as anthracite, bituminous,
subbituminous, or lignite by the American Society of Testing and
Materials in ASTM D388 (incorporated by reference, see Sec.  60.17),
coal refuse, and petroleum coke. Synthetic fuels derived from coal for
the purpose of creating useful heat, including but not limited to
solvent-refined coal, gasified coal (not meeting the definition of
natural gas), coal-oil mixtures, and coal-water mixtures are included
in this definition for the purposes of this subpart.
    Combined cycle facility means an electric generating unit that uses
a stationary combustion turbine from which the heat from the turbine
exhaust gases is recovered by a heat recovery steam generating unit to
generate additional electricity.
    Combined heat and power facility or CHP facility, (also known as
``cogeneration'') means an electric generating unit that that use a
steam-generating unit or stationary combustion turbine to
simultaneously produce both electric (or mechanical) and useful thermal
output from the same primary energy source.
    Compliance period means the period of time, set forth by a state in
its state plan, during which each affected entity must demonstrate
compliance with an applicable emissions standard, and shall be no
greater than a three year period for a mass-based plan, and shall be no
greater than a one year period for a rate-based plan.
    Emission performance level in a state plan means the level of
emissions performance for affected entities specified in a state plan,
according to Sec.  60.5740.
    Emission standard means in addition to the definition in Sec.
60.21, any requirement applicable to any affected entity other than an
affected source that has the effect of reducing utilization of one or
more affected sources, thereby avoiding emissions from such sources,
including, for example, renewable energy and demand-side energy
efficiency measures requirements.
    Excess emissions means a specified averaging period over which the
CO2 emissions rate is higher than an applicable emissions
standard or an averaging period during which an affected EGU is not in
compliance with any other emission limitation specified in an emission
standard.
    Existing state program, requirement, or measure means, in the
context of a state plan, a regulation, requirement, program, or measure
administered by a state, utility, or other entity that is currently
established. This may include a regulation or other legal requirement
that includes past, current, and future obligations, or current
programs and measures that are in place and are anticipated to be
continued or expanded in the future, in accordance with established
plans. An existing state program, requirement, or measure may have
past, current, and future impacts on EGU CO2 emissions.
    Fossil fuel means natural gas, petroleum, coal, and any form of
solid, liquid, or gaseous fuel derived from such material for the
purpose of creating useful heat.
    Gaseous fuel means any fuel that is present as a gas at ISO
conditions and includes, but is not limited to, natural gas, refinery
fuel gas, process gas, coke-oven gas, synthetic gas, and gasified coal.
    Heat recovery steam generating unit (HRSG) means a unit in which
hot exhaust gases from the combustion turbine engine are routed in
order to extract heat from the gases and generate useful output. Heat
recovery steam generating units can be used with or without duct
burners.
    Integrated gasification combined cycle facility or IGCC facility
means a combined cycle facility that is designed to burn fuels
containing 50 percent (by heat input) or more solid-derived fuel not
meeting the definition of natural gas plus any integrated equipment
that provides electricity or useful thermal output to either the
affected facility or auxiliary equipment. The Administrator may waive
the 50 percent solid-derived fuel requirement during periods of the
gasification system construction, startup and commissioning, shutdown,
or repair. No solid fuel is directly burned in the unit during
operation.
    ISO conditions means 288 Kelvin (15[deg] C), 60 percent relative
humidity and 101.3 kilopascals pressure.
    Liquid fuel means any fuel that is present as a liquid at ISO
conditions and includes, but is not limited to, distillate oil and
residual oil.
    Mechanical output means the useful mechanical energy that is not
used to operate the affected facility, generate electricity and/or
thermal output, or to enhance the performance of the affected facility.
Mechanical energy measured in horsepower hour should be converted into
MWh by multiplying it by 745.7 then dividing by 1,000,000.
    Natural gas means a fluid mixture of hydrocarbons (e.g., methane,
ethane, or propane), composed of at least 70 percent methane by volume
or that has a gross calorific value between 35 and 41 megajoules (MJ)
per dry standard cubic meter (950 and 1,100 Btu per dry standard cubic
foot), that maintains a gaseous state under ISO conditions. In
addition, natural gas contains 20.0 grains or less of total sulfur per
100 standard cubic feet. Finally, natural gas does not include the
following gaseous fuels: Landfill gas, digester gas, refinery gas, sour
gas, blast furnace gas, coal-derived gas, producer gas, coke oven gas,
or any gaseous fuel produced in a process which might result in highly
variable sulfur content or heating value.
    Net-electric output means the amount of gross generation the
generator(s) produce (including, but not limited to, output from steam
turbine(s), combustion turbine(s), and gas expander(s)), as measured at
the generator terminals, less the electricity used to operate the plant
(i.e., auxiliary loads); such uses include fuel handling equipment,
pumps, fans, pollution control equipment, other electricity needs, and
transformer losses as measured at the transmission side of the step up
transformer (e.g., the point of sale).
    Net energy output means:
    (1) The net electric or mechanical output from the affected
facility, plus 75 percent of the useful thermal output measured
relative to SATP conditions that is not used to generate additional
electric or mechanical output or to enhance the performance of the unit
(e.g., steam delivered to an industrial process for a heating
application).
    (2) For combined heat and power facilities where at least 20.0
percent of

the total gross energy output consists of electric or direct mechanical
output and 20.0 percent of the total gross energy output consists of
useful thermal output on a rolling 3 year basis, the net electric or
mechanical output from the affected facility divided by 0.95, plus 75
percent of the useful thermal output measured relative to SATP
conditions that is not used to generate additional electric or
mechanical output or to enhance the performance of the unit (e.g.,
steam delivered to an industrial process for a heating application).
    Petroleum means crude oil or a fuel derived from crude oil,
including, but not limited to, distillate and residual oil.
    Solid fuel means any fuel that has a definite shape and volume, has
no tendency to flow or disperse under moderate stress, and is not
liquid or gaseous at ISO conditions. This includes, but is not limited
to, coal, biomass, and pulverized solid fuels.
    Standard ambient temperature and pressure (SATP) conditions means
298.15 Kelvin (25[deg] C, 77 [deg]F)) and 100.0 kilopascals (14.504
psi, 0.987 atm) pressure. The enthalpy of water at SATP conditions is
50 Btu/lb.
    Stationary combustion turbine means all equipment, including but
not limited to the turbine engine, the fuel, air, lubrication and
exhaust gas systems, control systems (except emissions control
equipment), heat recovery system, fuel compressor, heater, and/or pump,
post-combustion emissions control technology, and any ancillary
components and sub-components comprising any simple cycle stationary
combustion turbine, any combined cycle combustion turbine, and any
combined heat and power combustion turbine based system plus any
integrated equipment that provides electricity or useful thermal output
to the combustion turbine engine, heat recovery system or auxiliary
equipment. Stationary means that the combustion turbine is not self-
propelled or intended to be propelled while performing its function. It
may, however, be mounted on a vehicle for portability. If a stationary
combustion turbine burns any solid fuel directly it is considered a
steam generating unit.
    Steam generating unit means any furnace, boiler, or other device
used for combusting fuel and producing steam (nuclear steam generators
are not included) plus any integrated equipment that provides
electricity or useful thermal output to the affected facility or
auxiliary equipment.
    Useful thermal output means the thermal energy made available for
use in any industrial or commercial process, or used in any heating or
cooling application, i.e., total thermal energy made available for
processes and applications other than electric generation, mechanical
output at the affected facility, or to directly enhance the performance
of the affected facility (e.g., economizer output is not useful thermal
output, but thermal energy used to reduce fuel moisture is considered
useful thermal output). Useful thermal output for affected facilities
with no condensate return (or other thermal energy input to the
affected facility) or where measuring the energy in the condensate (or
other thermal energy input to the affected facility) would not
meaningfully impact the emission rate calculation is measured against
the energy in the thermal output at SATP conditions. Affected
facilities with meaningful energy in the condensate return (or other
thermal energy input to the affected facility) must measure the energy
in the condensate and subtract that energy relative to SATP conditions
from the measured thermal output.

    Table 1 to Subpart UUUU of Part 60--State Rate-Based CO2 Emission
                            Performance Goals
                       [Pounds of CO2 per net MWh]
------------------------------------------------------------------------
                State                   Interim goal       Final goal
------------------------------------------------------------------------
Alabama.............................             1,147             1,059
Alaska..............................             1,097             1,003
Arizona.............................               735               702
Arkansas............................               968               910
California..........................               556               537
Colorado............................             1,159             1,108
Connecticut.........................               597               540
Delaware............................               913               841
Florida.............................               794               740
Georgia.............................               891               834
Hawaii..............................             1,378             1,306
Idaho...............................               244               228
Illinois............................             1,366             1,271
Indiana.............................             1,607             1,531
Iowa................................             1,341             1,301
Kansas..............................             1,578             1,499
Kentucky............................             1,844             1,763
Louisiana...........................               948               883
Maine...............................               393               378
Maryland............................             1,347             1,187
Massachusetts.......................               655               576
Michigan............................             1,227             1,161
Minnesota...........................               911               873
Mississippi.........................               732               692
Missouri............................             1,621             1,544
Montana.............................             1,882             1,771
Nebraska............................             1,596             1,479
Nevada..............................               697               647
New Hampshire.......................               546               486
New Jersey..........................               647               531
New Mexico..........................             1,107             1,048
New York............................               635               549
North Carolina......................             1,077               992
North Dakota........................             1,817             1,783

Ohio................................             1,452             1,338
Oklahoma............................               931               895
Oregon..............................               407               372
Pennsylvania........................             1,179             1,052
Rhode Island........................               822               782
South Carolina......................               840               772
South Dakota........................               800               741
Tennessee...........................             1,254             1,163
Texas...............................               853               791
Utah................................             1,378             1,322
Virginia............................               884               810
Washington..........................               264               215
West Virginia.......................             1,748             1,620
Wisconsin...........................             1,281             1,203
Wyoming.............................             1,808             1,714
------------------------------------------------------------------------

[FR Doc. 2014-13726 Filed 6-17-14; 8:45 am]
BILLING CODE 6560-50-P