Joint Appendix — West Virginia, et al., Petitioners v. Environmental Protection Agency, et al.
Supreme Court briefDec 13, 2021
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Nos. 20-1530, 20-1531, 20-1778, 20-1780
IN THE
Supreme Court of the United States
WEST VIRGINIA, ET AL.,
v.
ENVIRONMENTAL PROTECTION AGENCY, ET AL.,
THE NORTH AMERICAN COAL CORPORATION,
v.
ENVIRONMENTAL PROTECTION AGENCY, ET AL.,
WESTMORELAND MINING HOLDINGS LLC,
v.
ENVIRONMENTAL PROTECTION AGENCY, ET AL.,
NORTH DAKOTA,
v.
ENVIRONMENTAL PROTECTION AGENCY, ET AL.,
On Writ Of Certiorari
To The United States Court Of Appeals
For The District Of Columbia Circuit
JOINT APPENDIX (VOLUME III OF IV)
(Pages 867–1444)
LINDSAY S. SEE
ELIZABETH B. PRELOGAR
Solicitor General
Solicitor General
Counsel of Record
Counsel of Record
U.S. DEPARTMENT OF JUSTICE OFFICE OF THE W.V. ATT’Y GEN.
950 Pennsylvania Avenue, NW State Capitol Complex
Washington, DC 20530
Building 1, Room E-26
(202) 514-2217
Charleston, WV 25305
(304) 558-2021
supremectbriefs@usdoj.gov
lindsay.s.see@wvago.gov
Counsel for Federal
Respondents
Counsel for Petitioners
West Virginia, et al.
(additional counsel listed on inside cover)
PETITIONS FOR CERTIORARI FILED: APR. 29, 2021 (20-1530),
APR. 30, 2021 (20-1531), JUNE 18, 2021 (20-1778 & 20-1780)
CERTIORARI GRANTED: OCT. 29, 2021
(continued from front cover)
BETH S. BRINKMANN
Counsel of Record
COVINGTON & BURLING LLP
850 Tenth Street, NW
Washington, DC 20001
(202) 662-5312
bbrinkmann@cov.com
Counsel for Power Company
Respondents
YAAKOV M. ROTH
Counsel of Record
JONES DAY
51 Louisiana Ave., NW
Washington, DC 20001
(202) 879-3939
yroth@jonesday.com
Counsel for Petitioner
North American Coal
Corporation
SEAN H. DONAHUE
Counsel of Record
ANDREW M. GROSSMAN
Counsel of Record
DONAHUE, GOLDBERG &
BAKER & HOSTETLER LLP
LITTLETON
1008 Pennsylvania Ave., SE
1050 Connecticut Ave., NW
Washington, DC 20003
Washington, DC 20036
(202) 277-7085
(202) 861-1697
sean@donahuegoldberg.com
agrossman@bakerlaw.com
Counsel for Non-Governmental Counsel for Petitioner
Organization & Trade
Westmoreland Mining
Association Respondents
Holdings LLC
BARBARA D. UNDERWOOD
PAUL M. SEBY
Special Assistant
Solicitor General
Attorney General
Counsel of Record
Counsel of Record
OFFICE OF THE ATT’Y GEN.
GREENBERG TRAURIG, LLP
28 Liberty Street
1144 15th Street, Suite 3300
New York, NY 10005
Denver, CO 80202
(212) 416-8016
barbara.underwood@ag.ny.gov (303) 572-6500
sebyp@gtlaw.com
Counsel for Respondents
Counsel for Petitioner State
New York, States and
of North Dakota
Municipalities
(additional counsel listed on next page)
(continued from inside cover)
ELBERT LIN
Counsel of Record
HUNTON ANDREWS KURTH LLP
951 E. Byrd Street, E. Tower
Richmond, VA 23219
(804) 788-7202
elin@huntonak.com
Counsel for Respondent
America’s Power
EMILY C. SCHILLING
Counsel of Record
HOLLAND & HART LLP
901 K Street NW, Suite 850
Washington, DC 20001
(202) 393-6500
ecschilling@hollandhart.com
Counsel for Respondent Basin
Electric Power Cooperative
MISHA TSEYTLIN
Counsel of Record
TROUTMAN PEPPER HAMILTON
SANDERS LLP
227 W. Monroe St., Suite 3900
Chicago, IL 60606
(608) 999-1240
misha.tseytlin@troutman.com
Counsel for Respondent
National Mining Association
i
TABLE OF CONTENTS
Page
VOLUME I
Docket Entries,
American Lung Association, et al. v.
EPA, et al., No. 19-1140 (D.C. Cir.) ................... 1
Opinion of the United States Court of Appeals
for the District of Columbia Circuit
(Jan. 19, 2021) .................................................. 53
Respondents’ Motion for a Partial Stay of
Issuance of the Mandate (Feb. 12, 2021) ....... 256
Order of the United States Court of Appeals
for the District of Columbia Circuit
Granting the Motion for a Partial Stay of
Issuance of the Mandate (Feb. 22, 2021) ....... 270
Formal Partial Mandate of the United States
Court of Appeals for the District of
Columbia Circuit (Mar. 5, 2021) .................... 272
VOLUME II
Carbon Pollution Emission Guidelines for
Existing Stationary Sources: Electric
Utility Generating Units,
80 Fed. Reg. 64,662 (Oct. 23, 2015) ............... 273
VOLUME III
Carbon Pollution Emission Guidelines for
Existing Stationary Sources: Electric
Utility Generating Units, 80 Fed. Reg.
64,662 (Oct. 23, 2015) (cont.) ......................... 867
ii
TABLE OF CONTENTS
(continued)
Page
VOLUME IV
Carbon Pollution Emission Guidelines for
Existing Stationary Sources: Electric
Utility Generating Units, 80 Fed. Reg.
64,662 (Oct. 23, 2015) (cont.) ....................... 1445
EPA, Regulatory Impact Analysis for the
Repeal of the Clean Power Plan, and
the Emission Guidelines for Greenhouse
Gas Emissions from Existing Electric
Utility Generating Units (June 2019)
(Excerpted).................................................... 1669
Repeal of the Clean Power Plan; Emission
Guidelines for Greenhouse Gas
Emissions From Existing Electric Utility
Generating Units; Revisions to Emission
Guidelines Implementing Regulations,
84 Fed. Reg. 32,520 (July 8, 2019) ............... 1725
867
Accordingly,
we
have
concluded
that
a
well-supported and conservative estimate of the
potential heat rate improvements (and accompanying
reductions in CO2 emission rates) that EGUs can
achieve on average through best practices and
equipment upgrades is a 4.3-percent improvement in
the
Eastern
Interconnection,
a
2.1-percent
improvement in the Western Interconnection and a
2.3-percent improvement in the Texas Interconnection.
The decision to use these values as the building block
1 potential in each region is based on the weight of
evidence that these are conservative values; for each
region, each of the three analytical approaches in our
methodology supports our determination that the heat
rate improvement value we selected is achievable.
Taken individually, each approach provides an
independently reasonable estimate of the potential for
heat rate improvement. Furthermore, as described in
the GHG Mitigation Measures TSD, these approaches
are conservative on even an individual basis because
they do not account for the full extent of heat rate
improvements
available
through
additional
equipment upgrades and best practices. Some EGUs
may have faced difficulties achieving significant heat
rate improvement in the past and EGU owners may
feel they face challenges in the future. Nevertheless,
our methodology as a whole indicates that, on average,
coal-fired EGUs can at least achieve the percentage
heat rate improvement selected for their region
through application of best practices and some of the
available equipment upgrades. A more detailed
discussion of the EPA’s analysis in determining the
heat rate improvement potential for existing coal-fired
868
EGUs may be found in the GHG Mitigation Measures
TSD supporting the final CPP.
No affected coal-fired EGU is specifically required to
improve heat rate by any amount as a result of this
rule. Rather, as described in section VI, the potential
for heat rate improvement is used to determine a CO2
emission performance rate. Those affected EGUs that
have done the most to reduce their heat rate will tend
to be closer to that CO2 emission rate. In this sense,
our approach to determining potential CO2 reductions
through heat rate improvements is similar to the way
EPA
ordinarily
approaches
standards
of
641
performance.
In this final analysis, we do not delineate what
proportion of the potential heat rate improvement can
641 To give an illustrative example, imagine a population of
sources that emit Pollutant X. Half of the sources emit Pollutant
X at 2500 lbs/hour, while the other half of the sources have
scrubbers installed that reduce their emission rates to 1500
lbs/hour. Because the sources are evenly divided between those
with and without scrubbers, the average emission rate for the
population as a whole is 2000 lbs/hour. In this hypothetical, EPA
decides to base requirements on the emission rate achievable
through use of a scrubber, meaning that all sources will have to
meet an emission rate of 1500 lbs/hour. Because the fleet as a
whole has an average emission rate of 2000 lbs/hour, it would be
accurate for EPA to say that the fleet as a whole can reduce its
emission rate by 25 percent—from 2000 lbs/hour on average (only
half the sources with scrubbers), to 1500 lbs/hour on average (all
the sources with scrubbers). This description of what is possible
for the fleet as a whole—a 25-percent reduction in emission rate—
should not be misinterpreted as a statement that every
individual source is capable of further reducing its emissions by
25 percent. The sources that have already installed scrubbers,
and which are thus already operating at 1500 lbs/hour, would not
be required to further improve their emission rate.
869
be expected from equipment upgrades versus best
practices;642 only that these heat rate improvements
are achievable in the regions through a combination of
these methods. As discussed in section V.C.3 below,
we believe that a single heat rate improvement goal
for each region incorporating both best practices and
upgrades, based on the 11 years of hourly heat rate
data for 884 coal-fired EGUs available to the EPA, is
a reasonable approach that is supported by our
analysis, and is particularly conservative given that it
does not account for the full range of heat rate
642 Examples of the many types of best practices and
equipment upgrades available to coal-fired EGUs include
adopting sliding pressure operation to reduce turbine throttling
losses; installing intelligent sootblowing system software;
upgrading the combustion control/optimization system; installing
heat rate optimization software; installing a production cost
optimization program that benchmarks plant thermal
performance using historical plant data; establishing centralized
remote monitoring centers with thermal performance software
for monitoring heat rates systemwide; repairing steam and water
leaks; automating steam system drains; performing an on-site
performance appraisal to identify potential areas for improved
performance; developing heat rate improvement procedures and
training O&M staff on their use; aligning the cycle to isolate or
capture high-energy fluid leakage from the steam cycle; repairing
utility boiler air in-leakage; performing utility boiler chemical
cleaning; installing condenser tube cleaning system; retubing
condenser; repairing/upgrading flue gas desulfurization systems;
cleaning air preheater coils; adjusting/replacing worn air heater
seals; replacing corroded air heater baskets; replacing feed pump
turbine steam seals; overhauling high pressure feedwater pumps;
installing fan and pump variable speed/frequency drives;
upgrading turbine steam seals; upgrading all turbine internals;
and installing coal drying systems. These and additional heat
rate improvement measures are discussed further in the GHG
Mitigation Measures TSD for the CPP Final Rule.
870
improvements
achievable
through
equipment upgrades and best practices.
additional
The performance rates quantified in section VI,
below, reflect the region-specific values for heat rate
improvement. Although the performance rates are
based on the least stringent overall performance rate
determined to be reasonable for any region, and are
thus based in part on the percentage heat rate
improvement identified for the region, this rule does
not itself require any specific EGU to implement
measures resulting in a specific percentage heat rate
improvement. Rather, the percentage heat rate
improvement value is merely reflected in the CO2
emission performance rates and corresponding massbased and rate-based state goals. Each state has the
flexibility to develop a plan that achieves those CO2
performance rates or emission goals by assigning the
emission standards the state considers appropriate to
its affected coal-fired EGUs. Similarly, depending on
the content of the applicable plan, affected EGUs may
achieve their emission standards through use of any of
the building block measures described in this rule or
any other measures permitted under the plan.
b.
Changes from the proposal.
In the proposed rule, we determined that building
block 1 measures could on average achieve a 6-percent
heat rate improvement from coal-fired EGUs in the
U.S. based on a 4-percent heat rate improvement from
implementation of best practices and a 2-percent heat
rate improvement from equipment upgrades. Based
on comments received and refinements made to our
methodology for determining potential heat rate
improvement from the hourly gross heat rate dataset
871
of 884 coal-fired EGUs, we have applied this
methodology on a regional basis and reduced the
overall expected percentage heat rate improvement for
coal-fired EGUs to 4.3 percent in the Eastern
Interconnection, 2.1 percent in the Western
Interconnection, and 2.3 percent in the Texas
Interconnection. 643
These
values
reflect
improvements achievable through both best practices
and equipment upgrades because, as described above,
we also no longer include a separate estimation of the
potential heat rate improvement achievable solely
through equipment upgrades.
We received comments on our proposed statistical
methodology for determining the CO2 emission
reductions opportunities achievable by coal-fired
EGUs through heat rate improvements. We have
closely reviewed those comments and, for the final rule,
have made refinements to our methodology, as
described above and explained in more detail in the
GHG Mitigation Measures TSD supporting the final
CPP.
In the final rule, the EPA extends the
implementation deadline from 2020 to 2022. This
additional time will be helpful to the states seeking to
conduct more targeted analyses of the nature and
extent of heat rate improvements that specific coalfired EGUs can make, considering specific recent
improvements or upgrades, planned retirements of
older coal-fired EGUs, and other relevant
considerations. The extended deadline will also
Had the EPA maintained a nationwide approach to
analyzing the potential reductions under building block 1, the
result would have been 4.0 percent.
643
872
provide additional time to accommodate changes to
heat rate monitoring methods at EGUs and for the
installation of new pollution controls that comply with
other rules, as discussed below in the summary of key
comments.
2. Costs of Heat Rate Improvements
By definition, any heat rate improvement made by
EGUs for the purpose of reducing CO2 emissions will
also reduce the amount of fuel that EGUs consume to
produce the same electricity output.
The cost
attributable to CO2 emission reductions, therefore, is
the net cost of achieving heat rate improvements after
any savings from reduced fuel expenses.
As
summarized below, we estimate that, on average, the
savings in fuel cost associated with the percentage
heat rate improvements we identified for each region
would be sufficient to cover much of the associated
costs.
Accordingly, the net costs of heat rate
improvements associated with reducing CO2
emissions from affected EGUs are relatively low. We
recognize that this cost analysis will represent the
costs for some EGUs better than others because of
differences in individual circumstances. We further
recognize that reduced generation from coal-fired
EGUs due to the implementation of other building
block measures would tend to reduce the fuel savings
associated with heat rate improvements, thereby
raising the effective cost of achieving the CO2 emission
reductions from the heat rate improvements.
Nevertheless, we still expect that a significant fraction
of the investment required to capture the technical
potential for CO2 emission reductions from heat rate
improvements would be offset by fuel savings, and
that the net costs of implementing heat rate
873
improvements as an approach to reducing CO2
emissions from affected EGUs are reasonable. Even if
we conservatively estimate that EGUs will largely rely
on equipment upgrades rather than cheaper best
practices to reduce heat rate, those reductions can
generally be achieved at $100 or less per kW, or
approximately $23 per ton of CO2 removed, as
described in detail in the GHG Mitigation Measures
TSD supporting the final CPP.644 Depending on the
balance between equipment upgrades and best
practices, improving heat rate would even result in a
net savings for some EGUs.
Based on the analyses of technical potential and cost
summarized above and in Chapter 2 of the GHG
Mitigation Measures TSD, we find that heat rate
improvements of 4.3, 2.1 and 2.3 percent are
reasonable and conservative estimates of what coalfired EGUs in the Eastern, Western and Texas
Interconnections, respectively, can achieve at a
reasonable cost.
3. Response to Key Comments
Many commenters said that the EPA should have
subcategorized by EGU design or operating
characteristics for purposes of evaluating potential
heat rate improvements under building block 1.
Several studies categorize EGUs broadly by
capacity, thermodynamic cycle, fuel rank or other
The $100/kW cost figure from the proposal is now
particularly conservative because it included the cost of
significant equipment upgrades that improve heat rate, whereas
building block 1 is now largely quantified based on low- or no-cost
best practices, with a smaller portion of the remainder comprised
of equipment upgrades.
644
874
characteristics. We considered subcategorizing the
EGUs by their design and fuel characteristics under
building block 1. Although grouping by categories
does not account for all of the factors that may affect
heat rate, it can provide a useful way of understanding
the operating profile of classes of coal-fired EGUs and
the fleet as a whole. However, we have declined to
subcategorize among affected coal-fired EGUs for both
technical and practical reasons. First, as discussed
above, our assessment of heat rate improvement
potential uses a unit-specific data methodology that
compares each EGU’s performance against its own
historical performance. By substantially basing our
analysis on these unit-specific assessments, we
inherently factor in the effect of numerous design
conditions. We also conducted a regression analysis
that evaluated the effect of numerous factors on heat
rate, and found that subcategorizing would generally
make little difference in our analysis. Additionally,
subdividing the EGUs into subcategories would reduce
the quantity of EGUs used to calculate each average,
which would increase the influence of random and
atypical variations in the data on the overall averages,
and would thus decrease our confidence in the results.
Furthermore, as a practical matter, states are free to
apportion reductions in a way that reflects any
subcategories of their choosing when determining the
emission standards for individual affected EGUs.
Additionally, commenters assert that because building
block 1 is calculated on an average basis, some affected
EGUs will have greater potential than others to
emissions
through
heat
rate
reduce
CO2
improvements. If an affected EGU cannot meet its
particular emission standard because it has below-
875
average potential to reduce emissions through heat
rate improvements, then in instances where the
EGU’s state plan allows emissions trading, the EGU
can acquire credits or allowances from affected EGUs
that have above-average potential. For a further
discussion of our reasonable decision not to
subcategorize among coal-fired EGUs for purposes of
determining building block 1, see the GHG Mitigation
Measures TSD supporting the final CPP.
Many commenters told the EPA that EGUs already
have undertaken significant efforts to operate
efficiently to provide reliable electric service at the
lowest reasonable cost; that they believe they cannot
significantly improve heat rate; that best practice
maintenance activities are performed on a daily basis,
including during maintenance outages that allow for
the inspection, cleaning and repair of all equipment;
that extensive capital investments have been made to
install state-of-the art equipment and replace
equipment that is beyond repair; and that their
employees continuously monitor and control operating
levels in the combustion process to maintain
maximum combustion of fuel and to avoid wasting
available heat energy.
In summary, these
commenters say they have expended considerable
effort and resources to maintain peak boiler efficiency
at all times and, therefore, the 6-percent heat rate
improvement proposed for building block 1 is
unreasonable to apply to EGUs across the board; the
EPA should develop a rule that allows treatment of
affected EGUs on a case-by-case basis.
We commend the efforts of those who strive to
operate and maintain EGUs in the best possible
manner to minimize heat loss and CO2 emissions.
876
This rule does allow for treatment of EGUs on a caseby-case basis. States may believe that individual
considerations are appropriate in some cases and,
accordingly, we have purposely allowed states to make
decisions about how to implement specific
CO2 reductions. Our determinations of 4.3-, 2.1- and
2.3-percent heat rate improvement for EGUs in the
Eastern, Western and Texas Interconnection,
respectively, are conservatively based on the lowest
value identified by any of our reasonable statistical
analyses. If states choose to set limits on individual
affected EGUs based in part on the availability of heat
rate improvements, the states are free to assess heat
rate improvements on a more targeted, case-by-case
basis that takes into account an EGU’s previous heat
rate improvement efforts, or lack thereof. The fact
that states (or EGUs complying with state
requirements) can make case-by-case decisions about
how to achieve goals does not contradict our
conservative estimates—which are based on millions
of hours of operating data reported to the EPA by
EGUs—of how much EGUs are capable of improving
their heat rate in each region overall. Opportunities
to improve heat rate abound for affected EGUs as a
whole, as evidenced by the fact that the approaches in
our statistical methodology each included a
comparison of an EGU’s historical heat rate to its 2012
heat rate. Our estimates of the potential heat rate
improvement are additionally conservative because
they are based purely on comparisons among
historical gross heat rate data, and thus do not reflect
available, cost-effective opportunities to improve heat
rate that affected EGUs never implemented during
the study period. Finally, to the extent that an
877
affected EGU was in 2012 fully implementing every
possible best practice for improving heat rate, it may
still be capable of improving heat rate through
equipment upgrades.
Other commenters said that a 6-percent heat rate
improvement overall is too high; that the heat rate
improvement from upgrades are double-counted
within the data used to determine heat rate
improvements from best practices; and that the 2percent heat rate improvement specifically for
upgrades was inappropriately based on “conceptual”
improvements from only one study.
We have reduced the 6-percent heat rate
improvement from the proposed rule to three
regionalized figures of 4.3 percent (Eastern), 2.1
percent (Western) and 2.3 percent (Texas), as
discussed above and described in detail in the GHG
Mitigation Measures TSD supporting the final CPP.
We expect that, on average, affected coal-fired EGUs
can at a minimum improve heat rate in these amounts
by implementing best practices and equipment
upgrades identified in the GHG Mitigation Measures
TSD. These overall heat rate improvement figures do
not include an estimated percentage heat rate
improvement attributable specifically to upgrades.
Although we are no longer including in our calculation
of building block 1 a separate 2-percent heat rate
improvement attributable solely to equipment
upgrades, this decision is not because we believe that
our initial 2-percent assessment of equipment
upgrades was incorrect.
To the contrary, the
information presented in the S&L study was similar
to that in other industry reports and studies—many of
which were referenced in the proposal TSD—
878
describing potential heat rate improvements at EGUs
from all types of equipment upgrades. However, we
recognized that the possibility existed that some
limited portion of that 2 percent was also reflected in
our statistical analyses of historical gross heat rate
data. In order to ensure that our methodology did not
double-count an indeterminate amount of heat rate
improvement available through equipment upgrades,
we conservatively set aside the entire additional 2
percent attributable solely to equipment upgrades.
Accordingly, we determined the amount of potential
heat rate improvement in the BSER solely from the
heat rate analyses described above, which account for
improvements through best practices and equipment
upgrades that were at some point achieved by an EGU,
but not for the full range of best practices and
equipment upgrades that are actually available.
Commenters also said that the EPA did not look at
important factors that affect heat rate such as coal
type, boiler type, cooling water temperature, age,
nameplate capacity or the use of post-combustion
pollution controls.
Our statistical methodology compared each unit to
its own historical performance and, therefore, largely
accounts for the effects that a unit’s design or fuel
characteristics would have on heat rate. As discussed
above, our methodology used hourly data from 884
units over an 11-year period (2002–2012) and
compared the variability in the heat rate of each
individual unit to that unit’s own performance. By
assessing potential heat rate improvement by first
looking at unit-specific data, our methodology
inherently factors in the possible effects of design and
fuel characteristics (e.g., coal type, boiler type,
879
nameplate capacity, age, cooling water system, air
pollution controls) on heat rate and heat rate
variability.
Although cooling water temperature likely plays an
important role in a coal-fired EGU’s heat rate, as
stated by commenters, there are no consistent qualityassured hourly cooling water temperature data
available to the EPA. However, in an effort to
determine the potential effect of cooling water
temperature on heat rate, we looked at a sample of 45
coal-fired EGUs at 19 facilities for which we had
hourly surface water temperature data (used as a
surrogate for cooling water) from monitors located
nearby and upstream of cooling water intake points.
Our analysis found that surface water temperature
did explain some of the variation in heat rate, but that
surface water temperature is strongly correlated with
ambient air temperature—a variable we did control
for in our methodology. Because of the strong
correlation between ambient air temperature and
surface water temperature, the availability of a
comprehensive dataset of nationwide hourly ambient
air temperature, and the similar explanatory power of
surface water temperature and ambient air
temperature, it is unlikely that separately addressing
cooling water temperature would significantly change
the results. Rather, we are confident that our use of
hourly ambient air temperature in our analyses
adequately addressed any significant impact of cooling
water temperature.
See the GHG Mitigation
Measures TSD supporting the final CPP for further
details about this analysis. As described further in
that TSD, the other potentially relevant variables for
880
which we did not directly control are unlikely to
significantly affect the average heat rate.
Commenters said that the heat rate improvement
attributable to upgrades will degrade over time or
require repeated and costly further upgrades.
We are aware that some heat rate improvement
measures can degrade over time. Like most power
plant components, some heat rate improvement
technologies require maintenance in order to sustain
their efficacy over time.
Therefore, to avoid
degradation, personnel at EGUs will need to diligently
apply “best practices” on a regular basis, a practice
that numerous commenters say is standard operating
procedure. The S&L study includes estimates of
associated operations and maintenance (O&M) costs
for each heat rate improvement method that is
discussed. As we explained in the proposal, the
related O&M costs of diligently applying best practices
are relatively small compared to the associated capital
costs and would, therefore, have little effect on the
economics of heat rate improvements.
Commenters stated that heat rate improvement
should be set on a basis that is narrower than
nationwide—for example, state-by-state or unit-byunit.
The EPA did not propose and is not finalizing a rule
that sets heat rate improvement goals for individual
states or for individual coal-fired EGUs. Instead, in
the approved state plans developed under this rule,
each state will set the emission standards for its
various coal-fired EGUs. In doing so, the state may
take into account its own view of the amount of heat
rate improvement needed (if any) at specific EGUs,
881
and may look to the EPA’s analysis of heat rate
improvement potential in the applicable region as a
guide, while keeping in mind the CO2 emission
performance rate. This broad-based approach is
consistent with the traditional rules evaluating the
potential for emission reductions on a source-category
basis, and is consistent with the broader goal-setting
purpose of this rule. Furthermore, the final rule
establishes a uniform national performance rate based
on the least stringent regional performance rate
calculated with the building blocks. Accordingly,
affected EGUs in regions not setting the national level
have emission reduction opportunities beyond those
reflected in the applicable performance rate.
The heat rate improvement measures comprising
building block 1 would ordinarily be evaluated on a
nationwide basis. However, in this instance there are
two good reasons to calculate building block 1 on a
regionalized basis. First, a regionalized approach is
consistent with the EPA’s approach to determining the
other building blocks. For building block 1, this means
that the heat rate improvement should reflect only as
much potential for emission reduction from building
block 1 as our analyses indicate can be achieved on
average by the affected coal-fired EGUs in that region.
This ensures that the BSER for each region is
representative of the characteristics and opportunities
available within that region, rather than a less logical
combination of opportunities in the region and
opportunities nationwide. Second, a regionalized
approach provides a more representative average of
the potential heat rate improvement that EGUs in a
given region are capable of achieving. The populations
of affected coal-fired EGUs in each region differ in
882
some respects, as discussed in the GHG Mitigation
Measures TSD, and the more nuanced regionalized
approach thus indirectly accounts for some of those
systemic differences. For these and other reasons
described in Section V.A. of the preamble with respect
to the BSER as a whole, we have reasonably based
building block 1 on a regionalized approach. Applying
this regionalized approach to building block 1 strikes
an appropriate balance between the proposed
nationwide analysis and commenters’ suggested statespecific analysis, which does not fully reflect the
interconnected nature of the system within which
affected coal-fired EGUs operate.
The practical consequence of calculating building
block 1 on a regionalized versus nationwide basis is
minimal.
This is because the CO2 emission
performance rates are based on the overall
performance rate determined to be reasonable for
EGUs in the Eastern Interconnection.
Our
methodology identifies a 4.3 percent potential
improvement in the Eastern Interconnection,
compared to a 4.0 percent figure across all three
interconnections.
We further note, along with some commenters, that
site-specific engineering studies or unit-by-unit
analyses of heat rate improvement potential for coalfired EGUs are not available to the EPA; only a small
number of site-specific case studies are available in
the public literature. We considered that for the EPA
to develop a comprehensive, unit-by-unit heat rate
improvement study of nearly 900 coal-fired EGUs
from scratch, it would likely cost the Agency $50,000
to $100,000 to study each EGU (almost $50 to $100
million total) and require three to four years to
883
complete. Such a granular analysis would not serve
the broader goal-setting purpose of this rulemaking.
We agree with commenters who have pointed out that
a heat rate improvement-estimating effort of that
magnitude and duration would be unnecessarily
lengthy and expensive. Nor would such a granular
analysis be a necessary predicate for states to develop
emission standards, or for EGUs to comply with those
emission standards. Rather, our methodology relies
on individualized, unit-by-unit hourly performance
data from 884 EGUs provides conservative and
reasonable regional estimates of heat rate
improvement potential.
Indeed, given the
conservative nature of our methodology, a unit-specific
approach that evaluates the full range of best practices
and equipment upgrades available at individual
EGUs—including upgrades not accounted for here—
would be more likely to result in higher overall heat
rate improvement figures than we are finalizing for
building block 1.
Furthermore, site-specific
information forms the foundation of the EPA’s
estimated heat rate improvement potential, and
similar data likely would be used in any site-specific
heat rate improvement engineering study. Finally,
EGU-specific
detailed
design
and
operation
information is not consistently available for all the
factors that influence heat rate. The EPA has used the
comprehensive data that are available to reasonably
and conservatively estimate potential heat rate
improvement in each region.
Commenters also said that shifting electricity
generation from coal-fired EGUs to other EGUs
because of measures implemented under other
building blocks will lower the capacity factors of coal-
884
fired EGUs, and thus increase, not decrease, their heat
rates.
We expect that most states will develop plans that
optimize the operation of existing coal-fired EGUs
while utilizing the other building blocks and other
measures to reduce emissions from carbon-intensive
generation. From our IPM projections, the average
annual capacity factor of existing coal-fired EGUs that
are expected to remain in operation in 2030 will
actually increase compared to 2012. This projection—
which is further described in the GHG Mitigation
Measures TSD—incorporates expected retirements of
inefficient units and generation shifts away from
using coal-fired EGUs as peaking units.
Commenters also noted that the EPA used net heat
rate in state goals, but used gross heat rate in its heat
rate improvement analysis—potentially ignoring the
detrimental effect that parasitic load from air
pollution control devices (APCD) and other equipment
can have on net heat rate.
The EPA’s variability analysis necessarily and
reasonably used gross output data for each of the 884
EGUs in the EPA’s database because they are the only
publicly available, unit-specific, hourly performance
data. By definition, improvement in gross heat rate
would be reflected in the net heat rate. Gross heat rate
is the total heat output from the EGU, in units of
Btu/gross kWh, and includes the power used by
auxiliary equipment required to operate the EGU
itself. By contrast, net heat rate is the remaining
Btu/kWh after subtracting the power used by the
EGU’s own auxiliary equipment from the gross heat
rate value, i.e., what the EGU is able to provide to the
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grid. Improvements in net heat rate alone (e.g.,
reducing parasitic load of on-site equipment) may be
possible on many units. Therefore, our use of gross
heat rate to estimate potential heat rate improvement
was conservative because of the additional
opportunities to achieve the uniform performance rate
through improvements in net heat rate alone.
Commenters also raised concerns that the EPA was
not taking into account net heat rate increases due to
additional add-on pollution controls that may, for
some units, be required by other rules.645
The results of our statistical analyses are based on
gross heat rates and would not change with
installation of emission controls for CSAPR, MATS, or
other rules because these controls will add parasitic
load requirements and thereby have an impact on the
net heat rates only. Furthermore, we conservatively
consider region-wide net heat rate improvement
potential to be the same as that indicated for the
region-wide gross heat rate, when in fact it is not. In
order to check our assumptions concerning gross
versus net heat rate, we used the IPM Power Sector
Modeling Platform (version 5.14) and National
Electric Energy Data System (NEEDS) (version 5.14)
to analyze the anticipated incremental heat input
required to operate additional add-on controls to
comply with various EPA rules, including CSAPR,
MATS, effluent guidelines for EGUs, and coal
combustion residuals. From this analysis, we project
that between 2012 and 2025, existing coal-fired EGUs
are expected to install approximately 18.6 GW of wet
flue gas desulphurization (FGD), 16.6 GW of dry FGD,
645 See above for an explanation of gross versus net heat rate.
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24.9 GW of selective catalytic reduction (SCR), and 3.9
GW of selective noncatalytic reduction (SNCR). The
resulting impact from new pollution controls on
existing coal-fired EGUs’ heat rate is expected to be
very small, at conservatively less than 31 Btu/kWh, or
less than 0.3 percent in 2025. 646 After 2025, this
estimate is particularly conservative because the
EPA’s cost performance models overestimate the
parasitic load from individual add-on controls for
future years. Furthermore, at some EGUs these
newer pollution control devices will replace existing
pollution control devices. Accordingly, for these EGUs,
the minimal increase in net heat rate due to power
required to operate new controls will be at least
partially offset by the decrease in net heat rate caused
by removal of the control devices currently in place.
For more information about this analysis, see the
GHG Mitigation Measures TSD supporting the final
CPP.
Commenters contended that the 11 years of data
used to evaluate potential heat rate improvement is
too broad, and that the population of domestic coalfired EGUs has changed significantly over this time
period.
The 11-year span for the hourly gross heat rate data
is appropriate because it represents a wide variety of
economic conditions, market conditions and fleet
composition, while also capturing the relatively recent
historical performance of affected coal-fired EGUs.
When considered on a regional basis, we expect these
controls to impact heat rate by approximately 0.3 percent in both
the Eastern and Western Interconnections, and by less than 0.1
percent in the Texas Interconnection.
646
887
We also noted in the proposal TSD that the population
of coal-fired EGUs used in the analytical approaches
to determine potential heat rate improvement is made
up of coal-fired EGUs that operated in 2012. The gross
heat rate data of any coal-fired EGUs that retired
prior to 2012 were not included in the dataset.
Commenters stated that many of the changes in
heat rate reflected in the 11-year hourly gross heat
rate dataset are attributable to changes in monitoring
methodology, and thus do not represent heat rate
improvements attributable to best practices or
equipment upgrades. In addition, commenters are
concerned that changes to the monitoring methodology
in the future could artificially alter the measured heat
rate.
Different stack gas flow monitoring methods can
yield more or less accurate measurements of heat
input and CO2 emissions. These differences depend on
the characteristics of the stack gas flow where the
monitoring and reference method measurements are
taken, and which options under the Part 75 emission
measurement rules are chosen in the application of the
various flow rate reference methods. In general, more
accurate stack gas flow monitoring methodologies
yield lower values that, when used to calculate
emissions or heat input, may lower the heat rate
values reported to the EPA.
Some EGUs adopted monitoring methodologies that
have the potential to affect the exactness of the data
we used for assessing heat rate improvements.
However, as discussed in detail in the GHG Mitigation
Measures TSD supporting the final CPP, our review of
the data shows that a relatively small amount of the
888
data are affected by these changes; we are confident
that the values adopted for building block 1 are
conservative and reasonable estimates of the potential
for heat rate improvement in each region. Some
changes in monitoring methodology would have the
result of tending to cause us to underestimate the
potential for heat rate improvement. Furthermore,
because our methodology analyzes percentage heat
rate improvement based on 2012 gross heat rate data,
our results are unaffected by EGUs that used more
accurate monitoring methodologies in 2012 or used the
same
monitoring
methodologies
consistently
throughout the 11-year study period. For these and
other reasons discussed in detail in the GHG
Mitigation Measures TSD, we remain confident in our
results despite the marginal differences attributable
to monitoring methodologies in some of the heat rate
data for a subset of EGUs.647
In terms of concerns with future methodological
changes, the overwhelming majority of the 884 EGUs
in the dataset we used to assess heat rate
improvement have already changed their stack gas
flow monitoring methodology in 2012 or earlier.
Furthermore, extension of the compliance date to 2022
for this rule, as discussed above, more than adequately
allows enough time for EGUs to determine how to
actually improve their heat rates and lower CO2
emissions while accommodating future changes to
647 Furthermore,
on a fundamental level, our methodology
accounts for a certain amount of any residual inexactness because
we have conservatively adopted the lowest value identified by any
of our reasonable approaches—all three of which are themselves
conservative because they do not account for the full extent of
heat rate improvements achievable through equipment upgrades.
889
monitoring methodologies.
For a more detailed
explanation, see the GHG Mitigation Measures TSD
supporting the final CPP.
Commenters said that there is no proof that
lowering the heat rate will reduce variability or that
reduced variability will reduce heat rate, i.e.,
correlation does not prove causation.
As an initial matter, it is important to note that for
the final rule the EPA used three types of statistical
analyses to evaluate and estimate potential heat rate
improvements of coal-fired EGUs, and only one of
these analyses involved any consideration of heat rate
variability. All three types of statistical analyses are
described in the GHG Mitigation Measures TSD
supporting the final CPP.
These commenters are correct that, in the abstract,
reducing heat rate variability only means that heat
rate will be more consistent—not necessarily lower or
higher. However, our analysis is not an abstract
evaluation of the potential to reduce variability, as
commenters suggest, but rather is an evaluation of the
potential heat rate improvement achievable through
reducing variability—i.e., reducing variability to
achieve a more consistently low heat rate. See the
more detailed discussion of the statistical procedures
used for the final rule, above. In particular, the
application of a “consistency factor” in the analyses
performed for both the proposed and final rule
demonstrates the potential results if each individual
EGU operated slightly more consistently with the
lower heat rates that the EGU had itself previously
achieved under similar conditions.
890
The consequence of a reduced heat rate is, of course,
a lower rate of CO2 emissions, which is the purpose of
the BSER for building block 1. This way of thinking
about reduced variability is consistent with the utility
power sector’s own efforts to reduce variability, which
are aimed at securing the economic benefits of a more
consistently lower overall heat rate.
Some commenters expressed concern that heat rate
improvements could trigger applicability of new
source review (NSR) provisions. The relationship of
this final rule to other regulatory provisions, including
NSR, is discussed in section X of the preamble.
D. Building Block 2—Generation Shifts Among
Affected EGUs
The second element of the foundation for the EPA’s
BSER determination for reducing CO2 emissions at
affected fossil fuel-fired EGUs entails an analysis of
the extent to which fossil steam EGUs can shift
generation to existing NGCC EGUs. In this section,
we define building block 2 as the gradual shifting of
generation from existing fossil steam to existing
NGCC within each region up to a maximum NGCC
utilization of 75 percent on a net summer basis. In
each year of the interim period, this 75 percent net
summer maximum potential is subject to a regional
limit informed by historical growth rates.
This section summarizes the EPA’s analysis
supporting that definition. We begin by discussing the
sector’s ability to reduce CO2 emissions by shifting
generation,
including
selected
background
information, data on trends toward greater NGCC
generation, and various mechanisms for executing or
facilitating generation shifts. Next, we describe the
891
amount and timing of generation shift we have
determined to be achievable through the building
block. We then discuss various elements supporting
our quantification of achievable generation shift,
including the technical feasibility of NGCC units to
increase generation; historical shifts to NGCC
generation; considerations related to reliability,
natural gas transmission infrastructure, natural gas
production,
and
electricity
transmission
infrastructure; and regulatory flexibility. A discussion
of costs follows. Finally, we respond to certain
comments not addressed in the preceding discussions.
1. Demonstration of Ability to Reduce CO2 Emissions
Through Shifting Generation
a.
Background of utility power sector.
The ability to shift generation from higher- to loweremitting sources is compatible with the way EGUs are
generally dispatched. 648 The standard approach to
dispatching
generation
is
through
Security
Constrained Economic Dispatch (SCED), a wellestablished practice in the electric power
industry. 649 As the name indicates, SCED has two
defining components:
Economic operation of
generating facilities and assurance that the electric
648 See preamble section II.C.1, History of the Power Sector,
for background to this discussion.
“Economic Dispatch: Concepts, Practices and Issues”,
FERC Staff Presentation to the Joint Board for the Study of
Economic Dispatch”, Palm Springs, California, November 13,
2005. A copy of this presentation is available in the docket for this
rule.
649
892
system remains reliable and secure. 650 Economic
dispatch generally refers to shorter-term planning and
operations from a day ahead through real time.
During this period, generating units are committed—
a process known as “unit commitment,” in which units
are committed to be ready to provide generation to the
system when they will be needed—and then
dispatched in real time to meet the electricity demand
of the system. Overall changes in the level of
generation from different facilities are also planned
over time periods longer than this 2-day dispatch
period. Over a calendar year, for example, units are
planned and scheduled seasonally or monthly to
ensure that sufficient capacity and energy will be
available to meet expected loads in an area. Over a
period of a week, units are committed to be prepared
to start up or shut down to meet forecast loads, and
dispatch is coordinated within this planning and unit
commitment framework. This process enables system
operators to respond quickly to short-term changes in
demand, and also to shift generation among different
generation types to match longer-term requirements
and goals.
EGUs using technologies with relatively low
variable costs, such as nuclear units, are for economic
reasons generally operated at their maximum output
whenever they are available. Renewable EGUs such
as wind and solar units also have low variable costs,
but the magnitude and timing of their output
generally depend on wind and sun conditions rather
“Security Constrained Economic Dispatch: Definitions,
Practices, Issues and Recommendations: A Report to Congress”,
Federal Energy Regulatory Commission, July 31, 2006.
650
893
than the operators’ discretion. In contrast, fossil fuelfired EGUs have higher variable costs and are also
relatively flexible to operate. Fossil fuel-fired EGUs
are therefore generally the units that operators use to
respond to intra-day and intra-week changes in
demand. Because of these typical characteristics of
the various EGU types, the primary opportunities for
switching generation among existing units available
to EGU owners and grid operators generally consist of
opportunities to shift generation among various fossil
fuel-fired units, in particular between coal-fired EGUs
(as well as oil- and gas-fired steam EGUs) and NGCC
units. In the short term—that is, over time intervals
shorter than the time required to build a new electric
generation unit—fossil fuel-fired units consequently
tend to compete more with one another than with
nuclear and renewable EGUs.
The amount of
generation shifting from coal-fired EGUs to NGCC
units that takes place as a result of this competition is
highly relevant to overall power sector GHG emissions,
because a typical NGCC unit produces less than half
as much CO2 per MWh of electricity generated as a
typical coal-fired EGU.
b. Trends in generation shifts from coal-fired to
natural gas-fired sources.
Since at least 2000, fossil fuel-fired generation has
been shifting from coal- and oil-fired EGUs to NGCC
units, both as a result of construction of additional
NGCC units, and also as a result of dispatch of preexisting NGCC units at higher capacity factors. As a
result, generation from NGCC EGUs in 2012 reached
over four times the level of NGCC generation in 2000,
while generation from coal and oil/gas steam EGUs
894
decreased by around one third.651 As we demonstrate
in the GHG Mitigation Measures TSD, NGCC units
are capable of operating at higher annual capacity
factors than they have historically, so there remains
considerable opportunity for increased use of existing
NGCC units to replace generation currently supplied
by higher-emitting coal and oil/gas steam units. The
electric utility industry is thus well-positioned to
address the requirements of this building block by
increasing use of existing NGCC units and
correspondingly decreasing use of steam units. The
electric industry has been shifting generation to
NGCC units in recent years and is expected to
continue to retire coal capacity and add new NGCC
capacity.
In the reference case without
implementation of CO2 emission limitations, EIA
forecasts 40 GW of coal retirements and 53 GW of
NGCC capacity additions from 2014 to 2030. 652 An
EPA review of state Integrated Resource Plans (IRPs)
shows a pattern of shifting away from coal steam
capacity to NGCC capacity and, in some cases,
conversion of coal steam capacity to natural gas steam
capacity. For example, Ameren plans to add 600 MW
of NGCC capacity and convert two coal units to
natural gas steam units, and Duke plans to add 680
MW of NGCC capacity and convert one coal unit to a
natural gas steam unit.653
651
Ventyx Electric Power Database.
Energy Information Administration, Annual Energy
Outlook 2015 reference case, ref2015.d021915a.
652
653 For
further examples, see the memo entitled “Review of
Electric Utility Integrated Resource Plans” (May 7, 2015)
available in the docket.
895
c. Mechanisms for dispatch shifts from coal-fired to
natural gas-fired generation.
There are a variety of patterns of ownership and
operational control of EGUs; these ownership and
operational structures influence how EGUs will
respond to this building block. However, all owners
and operators have the ability to comply by using this
building block. In terms of ownership, investor-owned
utilities (IOUs) serve about 75 percent of the US
population, while consumer-owned utilities serve the
remaining 25 percent. 654 In states that have
maintained traditional regulation, IOUs are generally
vertically integrated (owning generating capacity as
well as transmission and distribution infrastructure),
and the wholesale sales of these EGUs are regulated
by the state; in states that have deregulated their
retail service, ownership of the EGU is separated from
ownership of transmission, and wholesale sales of
generation are regulated by FERC. Consumer-owned
utilities comprise municipal utilities, public utility
districts of various types owned by government
agencies, nonprofit cooperative entities (co-ops), and a
number of other entities such as Native American
Tribes.
Operational control of the dispatch of power over the
electricity grid is superimposed on this pattern of
ownership. Prior to electricity restructuring, this
dispatch was typically operated by major verticallyintegrated utilities or by public power entities. Over
654 Regulatory Assistance Project, Electricity Regulation in the
US: A Guide, Page 9, March 2011. Available at
http://www.raponline.org/docs/RAP_Lazar_ElectricityRegulati
onInTheUS_Guide_2011_03.pdf.
896
the last 15 years, large portions of the power grid are
now independently operated by ISOs or RTOs. These
entities are regulated by FERC and dispatch power
from multiple owners to meet the loads on the bulk
power grid.
The combination of multiple ownership and types of
operational control adds to the complexity of
electricity dispatch, but all affected EGUs, regardless
of ownership and type of control, can use this building
block to comply with the final rule. The principal
difference among the differing entities lies in the types
of methods that are available for the affected EGU
owner to bring about the shift in generation that will
make use of this building block for compliance. There
are several alternatives to accomplish this result: The
owner of the higher-emitting affected EGU may also
own, or have affiliates that own, lower emitting
generation and thus reduce its own generation and use
its control over these other EGUs to increase their
generation; an EGU may be able to reduce its
generation and buy replacement power from the
market that is lower emitting; or the EGU may be able
to reduce its generation and procure generation from
a separately-owned lower-emitting EGU.
These
alternatives will be available in states with either rate
or mass-based state plans without any change in their
general form. Under a rate-based state plan, an EGU
owner may also be able to purchase ERCs and average
the ERCs into its emission rate for purposes of
demonstrating compliance with its standard of
performance. Under standards of performance that
incorporate emissions trading, an EGU owner may be
able to purchase rate-based emission credits or mass
based emission allowances not needed by other EGUs
897
and use those credits or allowances to help achieve its
standard of performance.
The potential to shift generation identified for this
building block is entirely consistent with the existing
economic dispatch protocols described above. State
environmental policies can shift generation in two
ways. The first is operational restrictions, such as
permit limits on the number of hours that an EGU can
operate in order to limit emissions. The second is
changes in the relative costs of generation among
different types of EGUs related to pollution reduction
measures. For example, a regulation that necessitates
the use of a control technology that requires the
application of a reagent in a certain kind of EGU will
increase the variable cost of operating that plant,
which in turn may reduce the amount of generation it
is called upon to deliver to the grid through securityconstrained economic dispatch procedures.
In an organized market, where the system operator
dispatches units partly based upon costs, an electric
power plant that experiences an increase in its
variable costs will tend to operate less than it
otherwise would have. For example, market-based
pollution control programs require units to hold
tradable allowances to authorize their emissions of a
regulated pollutant.
Such an allowance-holding
requirement puts a price on the act of emitting the
regulated pollutant, which increases the operating
costs of units that emit that pollutant, and thus such
units will be dispatched less than they otherwise
would without such an allowance-holding requirement.
The RGGI is an example of a state program that has
this effect. In the present rule, although shifts in the
mix of generation to address the costs of pollution
898
control can lead to higher electricity generating costs
overall, the EPA analysis shows these costs to be
modest and well below their associated benefits.655
Many of the NGCC units are owned by the same
companies or affiliates that also own steam units. In
these cases, changes in EGU generation can be
planned by the company or affiliate without the need
to engage in separate market transactions with
outside parties. Where the affected EGU owner is also
the dispatch entity, as in most traditional market
structures, the EGU owner will generally have
operational control over the unit. Environmental
conditions, such as compliance costs or limits on
generation, can be factored in with fuel costs for
purposes of determining when the unit is committed
to be available, how the unit can be most efficiently
cycled, and at what level the unit is dispatched.
An analysis of generation data from steam and
NGCC units in 2012 shows that 77 percent of the
steam generation occurred from an EGU that owned,
or that had an affiliate that owned, NGCC generation.
Eighty percent of the generation shift potential
identified in this building block (increasing NGCC
generation up to a 75 percent capacity factor on a net
basis to replace steam generation) could occur among
these entities that own (either directly or through
affiliates) both steam and NGCC generation.656 These
data show that most EGU generation relevant for this
655 See the Regulatory Impact Analysis.
656 SNL
2015.
Energy. Data used with permission. Accessed May
899
building block is produced by entities that own both
steam and NGCC generation.
Another alternative available to an affected EGU
owner that does not also own NGCC generation is for
the higher-emitting affected EGU to reduce its
generation and purchase replacement power from the
market. In organized markets such as RTOs, it is
available through standard practice, because the
owner impacts how its EGUs are dispatched based
upon how it bids into the RTO market. In this case,
the owner can exercise control over the levels of
generation across units by when it offers generation to
the market operator (the RTO or ISO), and the prices
it bids for this generation. As in traditional economic
dispatch by a utility, environmental conditions,
compliance costs, or limits on generation can be
incorporated by the owner into the determination of
the cost-effective generation pattern of its EGUs.
In regions with organized electricity markets
(including, but not limited to, RTOs or ISOs), the
various types of EGU owners of higher-emitting
sources can reduce their generation, and any resulting
deficit in generation on the system can be supplied
from other EGUs in the region; for example, a coalfired unit can reduce generation that is then replaced
through the operation of the market by generation
from an NGCC unit, subject to dispatch by a regional
operator to ensure the reliable delivery of the
generation to loads within the region. To comply with
this rule, higher-emitting steam units will need
greater emission reductions relative to lower-emitting
NGCC units which will, in turn, tend to raise steam
unit costs compared to NGCC units. As a result, the
bids that a steam unit provides a market operator will
900
rise relative to NGCC units. This process of reducing
generation from a higher-emitting unit will lead to
substitution of lower-emitting generation.
EGU owners that do not participate in an organized
electricity market may nevertheless purchase power
from the wholesale power market. Purchases in the
wholesale power market can be spot purchases, which
are typically general purchases of system power
supplied by the EGUs across a region, or contract
purchases, which may have more provider-specific
characteristics (such as specifying the type of unit that
is providing the power). Purchases between EGUs
through the wholesale power market will have similar
emission-lowering properties as operation of the
organized market discussed above, because dispatch
in balancing areas outside RTOs and ISOs also follows
a similar economic dispatch protocol that is informed
by each unit’s production costs and environmental
limitations.
Under this alternative, the steam generators may,
in effect, realize emission reductions from building
block 2 simply by reducing their generation. Steam
generators do not need to purchase replacement
electricity as a prerequisite for realizing emission
reductions from reducing their own generation
because other generators already have an incentive to
provide as much electricity as load-serving entities are
willing to buy in order to satisfy electricity demand.657
657 Some owners or operators of steam generators may have
electricity supply obligations to which they may be applying
power from those steam generators. However, such parties may
fulfil those supply obligations using the wholesale power market
in the exact same way described here that enables any other
generator with economically attractive electricity to offer such
901
As noted above, higher-emitting generation sources
will have to incorporate correspondingly higher costs
of pollution reduction into their supply bids compared
to lower-emitting generation sources, and as a result,
load-serving entities will seek to buy a greater share
of electricity from the lower-emitting sources because
their supply bids will be more economically attractive.
Once the steam generators reduce their generation
(and associated emissions), the other entities in the
electricity system arrange for the replacement
electricity. The outcome of this power market process
will reduce both the mass and the rate of emissions
across sources.
An owner of a source can also reduce the generation
of an EGU by substituting generation from a loweremitting NGCC directly. For an EGU owner without
existing NGCC generation, this substitution can take
the form of a bilateral contract purchase. In RTOs and
ISOs, this alternative often takes the form of a
contract for differences, where the replacement source
could be an NGCC and the contract specifies a delivery
location and the price of the power. In bilateral
markets, the contract vehicle could be a Power
Purchase Agreement from a replacement source. It is
also possible that the owner of a steam unit could
directly invest in an existing EGU by purchasing the
asset or taking a partial ownership position, thus
acquiring the generation from the unit through that
means. The acquired generation and its associated
supply. In other words, the ability of a steam generator to reduce
its generation is not contingent on an associated purchase to
replace that power, notwithstanding the possibility that the
owner or operator of that steam unit may choose to make such a
purchase to meet an electricity supply obligation.
902
emissions could be used for compliance by the higheremitting EGU, in accordance with the plan under
which it is operating. The amount of generation that
could be shifted using the approaches described in this
paragraph will depend on the type and terms of the
commercial arrangements, as well as the potential
need for regulated entities to obtain approvals for
contracts or for changes in asset positions. The wide
range of approaches permitted by this rule provides
flexibility, both within a year and across multiple
years, for EGUs to fashion these arrangements to fit
their circumstances.
Where permitted under its state plan, an EGU
would also be able to meet its reduction obligations
using ERCs or allowances. The particular nature of
this alternative will depend on how a state elects to
develop its plan. If a state chooses a mass-based
approach, the EGU would simply need to hold
allowances to cover its emissions. To realize an
emission reduction from building block 2 under this
approach, a steam generator would only need either to
reduce its emissions by reducing its generation, which
would lead to that generator needing fewer allowances
to cover its emissions under the program, or to
purchase surplus allowances not needed by another
EGU that had reduced its emissions. In a rate-based
state, the state may choose to provide for compliance
through the acquisition of tradable ERCs. To realize
an emission reduction from building block 2 under this
approach, a steam generator would be able to adjust
its effective emission rate by purchasing ERCs that
are produced by other sources whose emission rates
are lower than the applicable rate standard. In this
fashion, a steam generator does not need to purchase
903
lower-emitting replacement power per se in order to
demonstrate an emission reduction from this building
block; instead, the steam generator may purchase any
ERCs that were produced from lower-emitting sources
(see section VIII for more detail on how state plans can
use an ERC approach to facilitate a rate-based
compliance demonstration of this type of emission
reduction).658
The
approaches
shown
here
collectively
demonstrate that all steam generators—regardless of
size, location, form of ownership, or type of market in
which they operate—can implement building block 2
through some or all of the mechanisms described.
2. Amount and Timing of Generation Shift
The EPA has determined that for purposes of
quantifying the CO2 emission reductions achievable
through building block 2, a reasonable amount of
generation shift is the amount of generation shift that
would result from existing NGCC units, on average,
increasing their annual utilization rates to 75 percent
of net summer capacity. However, the building block
does not reflect achievement of this average capacity
factor at the start of the interim period, but instead
reflects a glide path of increases in NGCC utilization
over the interim period. Below, we discuss the glide
658 Stakeholders have recognized that ERCs and allowances
are an effective tool for EGUs to implement the building blocks
and achieve their standards of performance required under this
rule. See “Clean Power Plan Implementation: Single-State
Compliance Approaches with Interstate Elements,” Georgetown
Climate Center (May 2015), http://www.georgetownclimate.org/
sites/www.georgetownclimate.org/files/GCC_ComplianceAppro
acheswithInterstateElements_May2015.pdf.
904
path, and in the following section we discuss the basis
for finding the 75 percent utilization rate, achieved
over the period of time consistent with the glide path,
to be reasonable.
The EPA received significant public comments
expressing concern regarding the proposal’s
incorporation of the full building block 2 shift in
generation by the first year of the interim period.
These commenters perceived this approach as
requiring states to achieve such a significant portion
of the required CO2 emission reductions early in the
interim period that states would lack flexibility in
when and how they may achieve the required emission
reductions. Other commenters expressed concern that
the full extent of building block 2 would be difficult for
some states to achieve by the first year of the interim
period as a result of technical, engineering, and
infrastructure limitations or other considerations;
that such timing may crowd out other cost-effective
options for emission reductions; and that such timing
might have negative implications for reliability.
In the proposal, the EPA determined that emission
reductions are feasible and achievable at fossil fuelfired steam EGUs by shifting from more carbonintensive EGUs to less carbon-intensive EGUs, as part
of the BSER. More specifically, the EPA proposed that
generation shifts from fossil fuel-fired steam units
(which are primarily coal-fired) to NGCC units, up to
a utilization of 70 percent on a nameplate capacity
basis, could be achieved by 2020. In contrast, the EPA
proposed that reductions in CO2 emissions from fossil
fuel-fired units associated with other measures, such
as increased utilization of RE generating capacity and
increased demand-side EE, would be achievable on a
905
phased-in basis between 2020 and 2029, reflecting the
time needed for deployment. 659 In light of the
concerns noted above, in the October 2014 NODA, the
EPA solicited comment on potential rationales for
phasing in the potential to shift generation under
building block 2.660
As already noted, in the final rule the EPA has
revised the interim period to start in 2022, which itself
is a meaningful response regarding the concerns
expressed by commenters about the timing of building
block 2’s generation shift potential. In addition, the
EPA has evaluated the feasibility over time of building
block 2 within the framework of BSER, and is
finalizing a change to building block 2 that gradually
phases in the shift from existing fossil steam to
existing NGCC over the interim period. This phase-in
allows for additional time to complete potential
infrastructure improvements (e.g., natural gas
pipeline expansion or transmission improvements)
that might be needed to support more use of existing
natural gas-fired generation, and provides states with
the increased ability to coordinate actions taken under
building block 2 with actions taken under building
block 3 (deployment of new renewable capacity).
The phase-in schedule applies a limit to the
maximum building block 2 potential in each year of
the interim period based on two parameters. The first
parameter defines an amount of generation shift to
existing NGCC capacity that is feasible by 2022, and
the second parameter defines how quickly that
659 79 FR 34866.
660 79 FR 64543.
906
amount could grow until the full amount of NGCC
generation could be achieved as part of the BSER.
Both of these parameters are determined by
examining the extent to which gas-fired generation
has increased over historical time periods. The first
parameter is based on the single largest annual
increase in power sector gas-fired generation since
1990, which occurred between 2011 and 2012 and is
equal to 22 percent.661 We believe that this amount is
a conservative estimate of the ability of the sector to
increase utilization of NGCC capacity by 2022, given
that this increase has already occurred in a single year.
The second parameter is based on the average annual
growth in gas-fired generation in the power sector
between 1990 and 2012, which is approximately 5
percent per year.
In the performance rate calculation methodology,
these two parameters constrain the annual rate at
which building block 2 shifts generation from fossil
steam units to NGCC units. The interim performance
rate is an average of annual rates calculated over the
2022–2029 period. The two parameters above limit
the extent to which NGCC generation is able to
increase and replace fossil steam generation in each
year of the interim period. In the first year, NGCC
generation is limited to a maximum of a 22 percent
increase from 2012 levels in each region. In each
subsequent year, regional NGCC generation is limited
to a maximum of a 5 percent increase from the
661 US EIA Monthly Energy Review, Table 7.2b Electricity Net
Generation: Electric Power Sector (2015), available at
http://www.eia.gov/totalenergy/data/browser/xls.cfm?tbl=T07
.02B&freq=m.
907
previous year.
This phase-in continues in the
performance rate-setting methodology until the full
building block 2 level of shifting from fossil steam
generation to NGCC generation is reached. Under
this approach, building block 2 is completely phased
into the source category calculation of all regions by
the end of the interim period.
908
TABLE 7—BSER MAXIMUM NGCC GENERATION BY REGION AND YEAR (TWH)
NGCC generation (TWh)
Region
Maximum
2012
potential
(adjusted)
at 75%
2022
BSER maximum
2023
2024
2025
2026
2027
2028
2029
2030
Limit ....................
...............
.............
22%
5%
5%
5%
5%
5%
5%
5%
5%
Eastern
Interconnection ...
988
735
896
941
988
988
988
988
988
988
988
Western
Interconnection ...
306
198
242
254
267
280
294
306
306
306
306
Texas
Interconnection ...
204
137
167
176
185
194
203
204
204
204
204
909
This phase-in, in addition to the flexible nature of
the goals, ensures that the overall framework of this
final rule includes sufficient flexibility, particularly
with respect to timing of and strategies for reducing
emissions from the affected units, so that states can
develop cost-effective strategies and allow for
infrastructure improvements to occur should they
prove necessary in some locations.
3. Basis for Magnitude of Generation Shift
a. Technical feasibility of NGCC units to generate
at 75% of their capacity.
In order to estimate the potential magnitude of the
opportunity to reduce power sector CO2 emissions
through shifting generation among existing EGUs, the
EPA first examined information on the design
capabilities and availability of NGCC units.
Availability is defined as the number of hours that
generators are available to generate electricity, and it
is typically expressed as a percentage of the total
number of hours in a year. Since the value of NGCC
capacity is related to how much electricity the owner
of that capacity can generate and sell, units are
typically designed with very high availability ratings.
Baseload units have annual average availabilities of
approximately 91%–92%, and peaking units are
generally available 96% to 98% of peak hours.662 The
EPA also examined information on the historical
availability of NGCC units in practice.
This
examination showed that, although most NGCC units
Negotiating Availability Guarantees for Gas Turbine
Plants, available at: http://www.power-eng.com/articles/
print/volume-105/issue-3/features/negotiating-availabilityguarantees-for-gas-turbine-plants.html.
662
910
have historically been operated in intermediate-duty
roles for economic reasons, they are technically
capable of operating in baseload roles at much higher
annual utilization rates. Average annual availability
(that is, the percentage of annual hours when an EGU
is not in a forced or maintenance outage) for NGCC
units in the U.S. generally exceeds 85 percent, and can
exceed 90 percent for some groups.663
We also researched historical data to determine the
utilization rates that NGCC units have already
demonstrated their capability to sustain. Over the
last several years, the utilization patterns of fossil
fuel-fired units have shifted relative to historical
dispatch patterns, with NGCC units increasing
generation and many coal-fired EGUs reducing
generation. In fact, in April 2012, for the first time
ever the total quantity of electricity generated
nationwide from natural gas was approximately equal
to the total quantity of electricity generated
nationwide from coal.664 These changes in generation
patterns have been driven largely by changes over
time in the relative prices of natural gas and coal.
Although the relative fuel prices vary by location, as
do the recent generation patterns, this trend holds
across broad regions of the U.S. In the aggregate, the
historical data provide ample evidence indicating that,
663 See, e.g., North American Electric Reliability Corp., 2008–
2012 Generating Unit Statistical Brochure—All Units Reporting,
http://www.nerc.com/pa/RAPA/gads/Pages/Reports.aspx;
Higher Availability of Gas Turbine Combined Cycle, Power
Engineering (Feb. 1, 2011), http://www.power-eng.com/
articles/print/volume-115/issue-2/features/higher-availabilityof-gas-turbine-combined-cycle.html.
664 http://www.eia.gov/todayinenergy/detail.cfm?id=6990.
911
on average, existing NGCC units can achieve and
sustain utilization rates higher than their historical
average utilization rates.
Utilization of EGUs is often considered using the
metric of a capacity factor, which is the percentage of
total production potential that an electric generating
unit achieves in a given time period. A capacity factor
of 75 percent thus represents a unit producing threequarters of the electricity it could have produced in
that time had it utilized its entire capacity. The EPA
received multiple comments regarding the proposed
use of nameplate capacity in calculating the potential
utilization level of existing NGCCs under building
block 2. These comments stated that net summer
capacity is a more meaningful and reliable metric than
nameplate capacity, because net capacity best reflects
the electric output available to serve load. The EPA
agrees with these comments. The quantification of
building block 2 as well as performance rate and state
goal calculations in the final rule are all based on net
summer generating capacity. An annual utilization
rate of 75 percent on a net summer basis is similar to
the proposed rule’s consideration of 70 percent
utilization on a nameplate basis.665
The experience of relatively heavily-used NGCC
units provides an additional indication of the degree of
increase in average NGCC unit utilization that is
technically feasible.
For a given amount of net generation, a net summer
capacity factor appears higher compared to a corresponding
nameplate capacity factor because net summer capacity reflects
a lower amount of total generation potential achievable by the
unit in practice.
665
912
The EPA reexamined the historical NGCC plant
utilization rate data reported to the EIA, and found
that in 2012 roughly 15 percent of existing NGCC
plants operated at annual utilization rates of 75
percent or higher on a net summer basis.666 In effect,
these plants were providing baseload power. In
addition to the 15 percent of NGCC plants that
operated approximately at a 75 percent utilization
rate on an annual basis, some NGCC plants operated
at even higher utilization rates for shorter, but still
sustained, periods of time in response to high cyclical
demand.
For example, on a seasonal basis, a
significant number of NGCC plants have achieved
utilization rates greater than 90 percent on a net
summer basis; during the summer of 2012 (June
through August), about 30 percent of NGCC plants
operated at utilization rates of 75 percent or more
across the entire season. During the spring and fall
periods when electricity demand levels are typically
lower, these plants were sometimes idled or operated
at much lower capacity factors. Nonetheless, the data
clearly demonstrate that a substantial number of
existing NGCC plants have proven the ability to
sustain 75 percent utilization rates for extended
periods of time. We view this as strong evidence that
increasing the annual average utilization rates of
666 Net summer capacity is defined as: “The maximum output,
commonly expressed in megawatts (MW), that generating
equipment can supply to system load, as demonstrated by a
multi-hour test, at the time of summer peak demand (period of
June 1 through September 30.) This output reflects a reduction
in capacity due to electricity use for station service or auxiliaries.”
(EIA, http://www.eia.gov/tools/glossary).
913
existing NGCC units to 75 percent on a net summer
basis would be technically feasible.
The EPA believes that an annual average
utilization rate of 75 percent on a net summer basis is
a conservative assessment of what existing NGCC
plants are capable of sustaining for extended periods
of time. In 2012, roughly 10 percent of existing NGCC
plants operated at annual utilization rates of 80
percent or higher on a net summer basis. While the
EPA believes this level is also technically feasible on
average for the existing NGCC fleet, the EPA is
quantifying building block 2 assuming an NGCC
utilization level of 75% on a net summer basis in order
to offer sources additional compliance flexibility, given
that the extent to which they realize a utilization level
beyond 75 percent will reduce their need to rely on
other emission reduction measures or building blocks.
b. Historical generation shifts to NGCC generation.
In 2012, total electric generation from existing
NGCC units was 966 TWh.667 After the application of
the building block 2 potential (increasing NGCC
utilization up to a 75 percent capacity factor on a net
summer basis, including generation from NGCC units
that were under construction), the total generation
from these existing sources is assumed to be 1,498
TWh.668
The EPA believes that producing this quantity of
generation from this set of NGCC units is feasible. To
667 Appendix
1, CO2 Emission Performance Rate and Goal
Computation Technical Support Document for CPP Final Rule.
668 Appendix
1, CO2 Emission Performance Rate and Goal
Computation Technical Support Document for CPP Final Rule.
914
put this level of generation into context, NGCC
generation increased by approximately 439 TWh (an
83 percent increase) between 2005 and 2012. The EPA
calculates that assumed NGCC generation in 2022
through the quantification of building block 2
potential is approximately 44 percent higher than
2014 levels. This reflects a smaller growth rate in
potential NGCC generation between 2015 and 2022
than has been observed in practice from 2005 to 2012,
a time period of the same duration.
c.
Reliability.
We also expect that an increase in NGCC generation
of this amount would not impair power system
reliability.
Sources can achieve increases in
utilization of existing NGCCs that displace generation
from steam sources without impacting reliability
because this shift in average annual utilization across
existing EGUs does not inhibit the power sector’s
ability to maintain adequate dispatchable resources to
continue to meet reserve margins and maintain
reliability. Furthermore, sources are not required to
achieve the exact or even the full extent of the building
block 2 generation shift itself, which means that
sources will have ample flexibility to maintain
reliability-relevant operations while achieving
emission reductions through a variety of measures.669
d.
Natural gas infrastructure.
The EPA also examined the technical capability of
the natural gas supply and delivery system to provide
increased quantities of natural gas and the capability
669 See section VIII for further discussion of electric reliability
planning.
915
of the electricity transmission system to accommodate
shifting generation patterns. For several reasons, we
conclude that these systems would be capable of
supporting the degree of increased NGCC utilization
potential in building block 2. First, the natural gas
pipeline system is already supporting national
average NGCC utilization rates of 60 percent or higher
during peak hours, which are the hours when
constraints on pipelines or electricity transmission
networks are most likely to arise. NGCC unit
utilization rates during the range of peak daytime
hours from 10 a.m. to 9 p.m. are typically 15 to 20
percentage points above their average utilization rates
(which have recently been in the range of 40 to 50
percent). 670
Fleet-wide combined-cycle average
monthly utilization rates have reached 65 percent, 671
showing that the pipeline system can currently
support these rates for an extended period. If the
current pipeline and transmission systems allow these
utilization rates to be achieved in peak hours and for
extended periods, it is reasonable to expect that
similar utilization rates should also be possible in
other hours when constraints are typically less severe,
and be reliably sustained for other months of the year.
Furthermore, the NGCC utilization increase assumed
in building block 2 could occur without a significant
impact on peak demand for natural gas, including
winter demand (when the power sector’s demand for
EIA, Average utilization of the nation’s natural gas
combined-cycle power plant fleet is rising, Today in Energy, July
9,2011, http://www.eia.gov/todayinenergy/detail.cfm?id=1730#;
EIA, Today in Energy, Jan. 15, 2014, http://www.eia.gov/
todayinenergy/detail.cfm?id=14611 (for recent data).
670
671 EIA, Electric Power Monthly, February, 2014. Table 6.7.A.
916
natural gas competes with other sectors’ demands for
natural gas), since increasing annual utilization of
NGCCs could focus on non-peak periods when NGCC
capacity factors are currently low.
The second consideration supporting a conclusion
regarding the adequacy of the gas supply
infrastructure is that pipeline and transmission
planners have repeatedly demonstrated the ability to
methodically relieve bottlenecks and expand
capacity. 672 Natural gas pipeline capacity has
regularly been added in response to increased gas
demand and supply, such as the addition of large
amounts of new NGCC capacity from 2001 to 2003, or
the delivery to market of unconventional gas supplies
since 2008. These pipeline capacity increases have
added significant deliverability to the natural gas
pipeline network to meet the potential demands from
increased use of existing NGCC units. Over a longer
time period, much more significant pipeline expansion
is possible. In previous studies, when the pipeline
system was expected to face very large demands for
natural gas use by electric utilities, the pipeline
industry projected that increases of up to 30 percent in
total deliverability out of the pipeline system would be
672 See, e.g., EIA, Natural Gas Pipeline Additions in 2011,
Today
in Energy, available at
http://www.eia.gov/
todayinenergy/detail.cfm?id=5050; INGAA Foundation, Pipeline
and Storage Infrastructure Requirements for a 30 Tcf Market
(2004 update), available at http://www.ingaa.org/Foundation/
Foundation-Reports/Studies/FoundationReports/45.aspx;
INGAA Foundation, North American Midstream Infrastructure
Through 2035—A Secure Energy Future Report (2011), available
at http://www.ingaa.org/File.aspx?id=14911.
917
possible.673 There have been notable pipeline capacity
expansions over the past five years, and substantial
additional pipeline expansions are currently under
construction. 674 Further, the phasing in of building
block 2’s potential in the determination of the BSER;
the flexible nature of multi-year compliance with the
ultimate emission reduction requirements of the rule;
and the seven years between finalization of this rule
and the first year of compliance provide time for
infrastructure improvements to occur should they
prove necessary in some locations. Combining these
factors of currently observed average monthly NGCC
utilization rates of up to 65 percent, the flexibility of
the emission guidelines, the rates of historical growth,
and the availability of time to address any existing
pipeline infrastructure limitations, it is reasonable to
conclude that the natural gas pipeline system can
reliably deliver sufficient natural gas supplies to allow
NGCC utilization to increase up to an average annual
capacity factor of 75 percent on a net summer basis.
e.
Natural gas production.
We recognize that an increase in NGCC utilization
rates at existing units corresponds with an associated
increase in natural gas production, consistent with the
673 Pipeline and Storage Infrastructure Requirements for a 30
Tcf Market, INGAA Foundation, 1999 (Updated July, 2004); U.S.
gas groups confident of 30-tcf market, Oil and Gas Journal, 1999.
674 For example, between 2010 and April 2014, 118 pipeline
projects with 44,107 MMcf/day of capacity (4,699 miles of pipe)
were placed in service, and between April 2014 and 2016 an
additional 47 pipeline projects with 20,505 MMcf/day of capacity
(1,567 miles of pipe) are scheduled for completion. Energy
Information Administration, http://www.eia.gov/naturalgas/
data.cfm.
918
current trends in the natural gas industry. The EPA
expects the growth in NGCC generation assumed for
building block 2 to be feasible and consistent with the
production potential of domestic natural gas supplies.
Increases in the natural gas resource base have led to
fundamental changes in the outlook for natural gas.
There is general agreement that recoverable natural
gas resources will be substantially higher for the
foreseeable future than previously anticipated,
exerting downward pressure on natural gas prices.
According to EIA, proven natural gas reserves have
doubled between 2000 and 2012. Domestic dry gas
production has increased by 25 percent over that same
timeframe (from 19.2 TCF in 2000 to 24.0 TCF in
2012). EIA’s Annual Energy Outlook Reference Case
for 2015 projects that production will further increase
to 29.5 TCF by 2022 and 33 TCF by 2030, as a result
of increased supplies and favorable market conditions.
In the AEO 2015 high oil and gas resource case,
production is projected to increase to 42.7 TCF in 2030.
For comparison, building block 2 assumes NGCC
generation growth of 235 TWh from 2012 to reach the
level assumed for 2022, and that NGCC generation
growth would result in increased gas consumption of
less than 2 TCF for the electricity sector, which is less
than EIA’s projected increase in natural gas
production of 5.5 TCF from 2012 to 2022.
The EPA has also assessed the ability of the
electricity and natural gas industries to achieve the
potential quantified for building block 2 using the
Integrated Planning Model (IPM). IPM is a multiregional, dynamic, deterministic linear programming
model of the U.S. electric power sector that the EPA
has used for over two decades to evaluate the economic
919
and emission impacts of prospective environmental
policies. To inform its projections of least-cost capacity
expansion and electricity dispatch, IPM incorporates
representations of constraints related to fuel supply,
bulk power transmission capacity, and unit
availability.
The model includes a detailed
representation of the natural gas pipeline network and
the capability to project economic expansion of that
network based on pipeline load factors. At the EGU
level, IPM includes detailed representations of key
operational limitations such as turn-down constraints,
which are designed to account for the cycling
capabilities of EGUs to ensure that the model properly
reflects the distinct operating characteristics of
peaking, cycling, and base load units.
As described in more detail below, the EPA used
IPM to assess the costs of increasing generation from
existing NGCC capacity. IPM was able to meet
average NGCC utilization rates of 75 percent on a net
summer basis, while observing the market, technical,
and regulatory constraints represented in the model.
This modeling also demonstrates the ability of
domestic natural gas supplies to increase their
production levels, and deliver that supply through the
pipeline network, to support the level of NGCC
generation quantified in building block 2. Such a
result is consistent with the EPA’s determination that
increasing the average utilization rate of existing
NGCC units to 75 percent would be technically
feasible.
f.
Transmission planning and construction.
Achieving the generation shift quantified in
building block 2 would not impose significant
920
additional burden on the transmission planning
process and does not necessitate major construction
projects. Two considerations are important for this
conclusion:
First, building block 2 applies only to increases in
generation at existing NGCC facilities and does not
contemplate any connection of new capacity to the
bulk power grid. Second, regional grids are already
supporting operation of the NGCC units for sustained
periods of time at the capacity factors quantified in
building block 2. 675 Although some upgrades to the
grid (including potential, but modest, expansions of
transmission capacity) may be necessary to support
the extension of the time that these capacity factors
are sustained over the course of the annual time period
on which building block 2 is based, such upgrades are
part of the normal planning process around the
increased use of existing facilities. In fact, the electric
transmission system is currently undergoing
substantial expansion. 676 Consequently, EPA does
not believe that achieving the generation shift
potential in building block 2 would necessitate any
See Greenhouse Gas Mitigation Measures TSD for a
discussion of regional NGCC capacity factors.
675
676 According to the Edison Electric Institute, member
companies are planning over 170 projects through 2024, with
costs totaling approximately $60.6 billion (this is only a portion
of the total transmission investment anticipated). Approximately
75 percent of the reported projects (over 13,000 line miles) are
high voltage (345 kV and higher). Construction of transmission
lines of 345KV and above are generally major projects that are
particularly effective at carrying power of large distances.
http://www.eei.org/issuesandpolicy/transmission/Documents/
Trans_Project_lowres_bookmarked.pdf.
921
significant additional requirements for transmission
planning and construction beyond those already being
addressed at routine intervals by the power sector.
Furthermore, the phasing in of building block 2’s
potential in the determination of the BSER; the
flexible nature of multi-year compliance with the
ultimate emission reduction requirements of the rule;
and the seven years between finalization of this rule
and the first year of compliance all provide time for
infrastructure improvements to occur should they
prove necessary in some locations.
g.
Regulatory flexibility.
The final consideration supporting our view that
natural gas and electricity system infrastructure
would be capable of supporting increased NGCC unit
utilization rates at a maximum of 75% on a net
summer basis is the substantial unit-level compliance
flexibility of the emission guidelines. The final rule
does not require any particular NGCC unit to achieve
any particular utilization rate in any specific hour or
year. Thus, even if isolated natural gas or electricity
system constraints were to limit NGCC unit
utilization rates in certain locations in certain hours,
this would not prevent an increase in NGCC
generation overall across a state or broader region and
across all hours on the order assumed in the
generation shift potential quantified for building block
2.
4. Cost
Having established the technical feasibility and
quantification of the potential to replace incremental
generation at higher-emitting EGUs with generation
at NGCC facilities as a CO2 emissions reduction
922
strategy, we next turn to the question of cost. The cost
of the power sector CO2 emission reductions that can
be achieved through shifting generation among
existing fossil fuel-fired EGUs depends on the relative
variable costs of electricity production at EGUs with
different degrees of carbon intensity. These variable
costs are driven by the EGUs’ respective fuel costs and
by the efficiencies with which they can convert fuel to
electricity (i.e., their heat rates). Historically, natural
gas has had a higher cost per unit of energy content
(e.g., MMBtu) than coal in most locations, but for
NGCC units this disadvantage in fuel cost per MMBtu
relative to coal-fired EGUs is typically offset in
significant part, and sometimes completely, by a
technological heat rate advantage.
To consider the cost implications of building block 2,
the EPA expanded upon the proposal’s extensive
analysis of the magnitude and cost of CO2 emission
reductions through generation shifting within defined
areas (consistent with the application of building
blocks for performance rate- and state goal-setting),
without consideration of the availability of other
emission reduction methods ultimately available to
units for compliance.
To evaluate how EGU owners and grid operators
could respond to a state plan’s possible requirements,
signals, or incentives to shift generation from more
carbon-intensive to less carbon-intensive EGUs, the
EPA analyzed a series of scenarios in which the fleet
of NGCC units within each of the regions considered
for quantifying BSER (i.e., the three interconnections)
was directed to achieve a specified average annual
utilization rate across that region on a net basis while
maintaining a fixed level of aggregate generation in
923
that region across all existing fossil fuel-fired sources.
The EPA conducted such scenarios to address average
utilization rates of 70 percent, 75 percent and 80
percent on a net basis, allowing for shifting of fossil
generation between existing units within the regions
described above. This scenario identifies a generation
pattern that would meet electricity demand at the
lowest total cost, subject to all other specified
operating and bulk power transfer constraints for the
scenario, including the specified average NGCC unit
utilization rate.
The costs of the various scenarios were evaluated by
comparing the total costs and emissions from each
scenario to the costs and emissions from a base case
scenario. For the scenario reflecting a 75 percent
NGCC utilization rate on a net basis with regional
fossil generation shifting, comparison to the base case
indicates that the average cost of the CO2 reductions
achieved over the 2022–2030 period was $24 per short
ton of CO2. We view these estimated costs as
reasonable and therefore as supporting the use of a 75
percent net utilization rate target for purposes of
quantifying the emission reductions achievable at a
reasonable cost through the application of building
block 2 in the BSER.
We also conclude from these analyses that potential
impacts to fuel prices and electricity prices from
achieving the extent of fossil generation shifting
quantified for this building block are reasonably
within the bounds of power sector experience. For
example, in the 75 percent NGCC unit utilization rate
scenario where generation shifting is limited to
regional boundaries, the delivered natural gas price
was projected to increase by an average of 7 percent
924
over the 2022–2030 period, which is well within the
range
of
historical
natural
gas
price
677
variability.
Projected wholesale electricity price
increases over the same period were less than 4
percent, which similarly is well within the range of
historical electric price variability. These projected
impacts on prices were captured in the emission
reduction costs of these scenarios already described
above, which are reasonable and support use of a 75
percent NGCC utilization rate target for purposes of
quantifying the emission reductions achievable
through application of the BSER.
However, we also note that the costs (and their
incorporated price impacts) just described are higher
than we would expect to actually occur in real-world
compliance with the final rule’s compliance
requirements for the following reasons. First, this
analysis does not capture the building block 2 phasein, which assumes an average utilization rate over the
interim period of less than 75 percent in all three
interconnections. Second, the analysis overstates the
extent to which building block 2 is ultimately reflected
in the source category performance rates. While the
performance rate computation procedure assumes a
maximum NGCC utilization rate of 75 percent on a net
summer basis, the Eastern Interconnection’s
realization of this level of NGCC utilization yields
higher source category performance rates for steam
than what would have been calculated for units in the
677 According to EIA data, year-to-year changes in natural gas
prices at Henry Hub averaged 29.9 percent over the period from
2000 to 2013. http://www.eia.gov/dnav/ng/hist/rngwhh
dA.htm.
925
Western Interconnection and Texas Interconnection if
they realized that maximum NGCC utilization rate in
conjunction with the other building blocks. In other
words, there is substantial building block 2 potential
in the Western Interconnection and Texas
Interconnection that is not actually captured in the
source category performance rates that are ultimately
assigned to steam through this rate- and goal-setting
approach (where the performance rates are ultimately
determined by the BSER region with the highest rate
outcome in the calculation). Therefore, the building
block 2 analysis overstates the cost of this component
of BSER to the extent that it assumes achievement of
this generation shift potential that is not reflected in
the source category performance rates ultimately
determined. Third, as a practical matter, sources will
be able to achieve additional emission reductions
through other measures that may prove to be less
costly than generation shifting and could substitute
for the reductions and costs considered here. These
building block 2 analyses were focused on evaluating
the potential impacts of fossil generation shifting in
isolation, and as a result, they do not consider states’
and sources’ flexibility to choose among alternative
CO2 reduction strategies that could offer lower-cost
reductions, instead of relying on fossil generation
shifting to the extent analyzed here.
Based on the analyses summarized above, the EPA
concludes that an average annual utilization rate for
each region’s NGCC units of up to 75 percent is a
technically feasible, cost-effective, and adequately
demonstrated building block for BSER.
926
For further information on the analysis discussed in
this section, see Chapter 3 of the GHG Mitigation
Measures TSD for the CPP Final Rule.
5. Major Comments and Responses
The EPA received numerous comments regarding
building block 2. Many of these comments provided
helpful information and insights and have resulted in
improvements to the rule. This section summarizes
some of these comments, and the remainder of the
comments are responded to in the Response to
Comment document, available in the docket.
The EPA received comment regarding the potential
for an increase in upstream methane emissions from
increased utilization of natural gas. Our analysis
found that the net upstream methane emissions from
natural gas systems and coal mines and CO2 emissions
from flaring of methane will likely decrease under the
Clean Power Plan. Furthermore, the changes in
upstream methane emissions are small relative to the
changes in direct emissions from power plants. The
technical details supporting this analysis can be found
in the Regulatory Impact Analysis.
Commenters also expressed concern that neither a
utility nor any state agency controls dispatch in most
states. The EPA believes these comments fail to
adequately appreciate that the utilities do control the
dispatch of units that they own and/or operate, either
by being the actual dispatch agent in many cases
where there is no RTO or ISO that schedules the
dispatch, or by the choice of units and bids they offer
into an organized electricity market operated by an
RTO or ISO. These entities currently control the
dispatch of their units while respecting all existing
927
requirements from environmental rules. This final
rule does not change these current circumstances and
makes clear that it is the EGU that is responsible for
meeting the requirements in the state plan; the state
is responsible for the development of that plan, but the
state does not need to control the dispatch.
Other comments object to the use of a single
capacity factor for all existing NGCCs to quantify
building block 2 potential on the grounds that not all
units may be able to achieve this utilization level, and
that some units may be designed for cycling and so
may need upgrades to sustain such utilization. The
EPA disagrees with these comments. The 75 percent
capacity factor establishes a regional potential for
generation from existing NGCC capacity, and it does
not establish any individual unit requirements.
Some comments argue that generation limits in
permits for some existing NGCC units will limit the
amount by which these units can increase their
generation and thereby limit the feasibility of building
block 2. The EPA disagrees with these comments.
Although permit limits can constrain the ability of
individual units to operate above certain levels,
building block 2 was developed conservatively, with
units operating on average at a level below the
maximum levels at which some units have
demonstrated the capability to operate. No individual
unit is required to achieve the average generation
levels used to quantify building block 2. Further,
permit limits at individual units can be considered
when state plans are developed. There are many
flexibilities in the final rule, including the opportunity
to establish standards of performance that incorporate
928
emissions trading or develop plans that will respect
any existing permit limits at individual units.
The EPA also received comments asserting that
increasing generation from new renewables would
require increased use of natural gas capacity for backup and ramping, and therefore it is not possible for
NGCC units to run at BSER utilization rates and also
be available to support the additional variable
renewable generation resulting from building block 3.
The EPA disagrees with this comment. The 75% net
summer utilization rates defined by building block 2 is
a conservative assessment and applied on an annual
average basis. It is therefore possible for these
existing units to both operate at higher annual
utilization rates, and also to operate at higher rates
during limited periods and still maintain a 75% net
summer average annual utilization rate.
While
variable renewable generation does require additional
load following and ramping resources and unit cycling,
these requirements are generally a small part of the
overall ramping costs of the system (see NREL,
Relevant Studies for NERC’s Analysis of EPA’s Clean
Power Plan 111(d) Compliance). Additionally, while
existing NGCC units are an efficient source of ramping
to support variable renewables, other units running in
an intermediate mode can also provide load following
and ramping.
E. Building Block 3—New Zero-Emitting Renewable
Generating Capacity
The third element of the foundation for the EPA’s
BSER determination for reducing CO2 emissions at
affected fossil fuel-fired EGUs entails an analysis of
the extent to which generation at the affected EGUs
929
can be replaced by using an expanded amount of zeroemitting renewable electricity (RE) generating
capacity to produce replacement generation.
In this section we address first the history of and
then trends in RE development, as well as the
importance of expanding the use of RE. Next we
discuss the ability of affected EGUs to access
generation from new RE generating capacity, followed
by a discussion of renewable energy certificate (REC)
markets. We then describe the quantification of the
amount of generation from new RE generating
capacity achievable through building block 3,
including key comments, changes made from the
proposal, the method by which RE target generation
levels are quantified, and the magnitude and timing of
increases in RE generation associated with this
building block. Next, we discuss the feasibility of
implementing the identified incremental amounts of
RE generation.
Finally, we address the costs
associated with those increases in RE generation.
1. History of RE Development
RE generating technologies are a well-established
part of the utility power sector. These technologies
generate electricity from renewable resources, such as
wind, sun and water. While RE has been used to
generate electricity for over a century, the push to
commercialize RE more broadly began in the
1970s. 678 Following a series of energy crises, new
federal organizations and initiatives were established
678 Nearly all U.S. hydroelectric capacity was built before the
mid-1970s. U.S. DOE. History of Hydropower. Accessed March
2015. Available at: http://energy.gov/eere/water/historyhydropower.
930
to coordinate energy policy and promote energy selfsufficiency and security, including solar energy
legislation, the Public Utility Regulatory Policies Act
of 1978 (PURPA) and the 1980 Energy Security Act.679
PURPA was a key step in stimulating RE
development. By requiring utilities to purchase
generation from qualifying facilities (i.e., certain CHP
and RE generators) at avoided costs, PURPA opened
electricity markets to more RE generation and gave
rise to non-utility generators that were willing to try
new RE technologies. 680 In addition, since 1992,
federal tax policy has provided important financial
support via tax credits for the production of RE and
investments in RE.
States have also taken a significant lead in
requiring the development of RE resources. In
particular, a number of states have adopted renewable
portfolio standards (RPS), which are regulatory
mandates to increase production of RE. As of 2013, 29
states and the District of Columbia had enforceable
RPS or similar laws. 681 These RPS requirements
continue to drive robust near-term growth of nonhydropower RE.
679 U.S. DOE Office of Management, Timeline of Events: 1971–
1980. Accessed March 2015. Available at: http://energy.gov/
management/office-management/operational-management/
history/doe-history-timeline/timeline-events-1.
680 “Restructuring or Deregulation?” Smithsonian Museum of
American History. Accessed March 2015. Available at:
http://americanhistory.si.edu/powering/dereg/dereg1.htm.
Energy Information Administration, Annual Energy
Outlook 2014 with Projections to 2040, at LR-5 (2014).
681
931
2. Trends in RE Development
Today, RE is tightly integrated with the utility
power sector in multiple ways: States have set RE
targets for electrical load serving entities; utilities
themselves are diversifying their portfolios by
contracting with RE generators; and new RE
generators are being developed to provide more
electrical power grid support services beyond just
energy (e.g., modern electronics allow wind turbines to
provide voltage and reactive power control at all
times).682 683
Use of RE continues to grow rapidly in the U.S. In
2013, electricity generated from RE technologies,
including conventional hydropower, represented 12
percent of total U.S. electricity, up from 8 percent in
2005.684 In 2013, U.S. non-hydro RE capacity for the
total electric power industry exceeded 80,000
megawatts, reflecting a fivefold increase in just
15 years.685 In particular, there has been substantial
682 IPCC,
Renewable Energy Sources and Climate Change
Mitigation, 2012. Accessed March 2015. Available at:
http://www.ipcc.ch/pdf/special-reports/srren/SRREN_Full_
Report.pdf.
683 American Wind Energy Association. AWEA Comments on
EPA’s Proposed Carbon Pollution Emission Guidelines for
Existing Stationary Sources and Supplemental Proposed Rule. p.
107.
684 Energy Information Administration, Monthly Energy
Review,
May
2015,
Table
7.2b.
Available
at:
http://www.eia.gov/totalenergy/data/monthly/pdf/sec7_6.pdf.
685 Non-hydro RE capacity for the total electric power industry
was more than 16,000 megawatts in 1998. Energy Information
Administration, 1990–2013 Existing Nameplate and Net
Summer Capacity by Energy Source Producer Type and State
932
growth in the wind and solar photovoltaic (PV)
markets in the past decade. Since 2009, U.S. wind
generation has tripled and solar generation has grown
twentyfold.686
The global market for RE is projected to grow to
$460 billion per year by 2030.687 RE growth is further
spurred by the significant amount of existing natural
resources that can support RE production in the
U.S. 688 In the Energy Information Administration’s
Annual Energy Outlook 2015, RE generation grows
substantially from 2013 to 2040 in the reference case
and all alternative cases.689 In the reference case, RE
generation increases by more than 70 percent from
2013 to 2040 and accounts for over one-third of new
generation capacity.690
(EIA-860).
Available
data/state/.
at:
http://www.eia.gov/electricity/
Energy Information Administration, Monthly Energy
Review,
May
2015,
Table
7.2b.
Available
at:
http://www.eia.gov/totalenergy/data/monthly/pdf/sec7_6.pdf.
686
687 “Global
Renewable Energy Market Outlook.” Bloomberg
New Energy Finance, November 16, 2011. Available at
http://bnef.com/WhitePapers/download/53.
688 Lopez et al., NREL, “U.S. Renewable Energy Technical
Potentials: A GIS-Based Analysis,” (July 2012). Available at
http://www.nrel.gov/docs/fy12osti/51946.pdf.
689 Energy Information Administration, Annual Energy
Outlook 2015 with Projections to 2040 (2015), p. 25. Available at
http://www.eia.gov/forecasts/aeo/pdf/0382(2015).pdf.
Energy Information Administration, Annual Energy
Outlook 2015 with Projections to 2040 (2015), p. ES-6–7.
Available
at
http://www.eia.gov/forecasts/aeo/pdf/0382
(2015).pdf.
690
933
The recent and projected growth of RE is in part a
reflection of its increasing economic competitiveness.
Numerous studies have tracked capital cost reductions
and performance improvements for RE, particularly
for solar and wind. For instance, Lazard’s analysis of
wind and utility-scale solar PV levelized costs of
energy (LCOE), on an unsubsidized basis, over the last
five years found the average percentage decrease of
high and low of LCOE ranges were 58 percent and 78
percent, respectively. 691 Analyses of wind’s
competitiveness found falling wind turbine LCOE
while the wind industry developed projects at lower
wind speed sites using new turbine designs (e.g.,
increased turbine hub heights and rotor diameters).
Performance improvements have come from novel
deployments of new turbines designed for lower
quality wind sites that are deployed at higher quality
wind sites, which have resulted in capacity factor
increases for these locations. 692 693 For utility-scale
solar, cost and performance have also improved
significantly. Analysis has shown that the installed
price of solar photovoltaics (PV) systems, prior to any
incentives, has declined substantially since 1998.
Capacity-weighted average prices of solar PV in
utility-scale deployments were 40 percent lower in
691 Lazard, Levelized Cost of Energy Analysis-Version 8.0,
September 2014, p. 9, Available at: http://www.lazard.com/
media/1777/levelized_cost_of_energy_-_version_80.pdf.
692 “2013 Wind Technologies Market Report,” LBNL, August
2014. Available at http://emp.lbl.gov/sites/all/files/2013_
Wind_Technologies_Market_Report_Final3.pdf.
693 “2013
Cost of Wind Energy Review,” NREL, Feb 2015.
Available at: http://www.nrel.gov/docs/fy15osti/63267.pdf.
934
2013 than five years earlier. 694 695 Initially, price
declines were partially driven by oversupply and
manufacturers’ thin margins, but, in 2014, prices have
remained low due to reductions in manufacturing
costs. 696 The capacity factors of new utility-scale
installations have increased as systems are optimized
to maximize energy production. For example, a
growing number of utility-scale PV systems are
increasing the direct current capacity of the solar
array relative to the alternating current rating of the
array’s inverter to increase energy production and
improve project economics. 697
The cost and
performance improvements for wind and solar are
driven by increased scale of production, improved
technologies,
and
advancements
in
system
deployments.
3. Importance of Increasing Use of RE
Currently, the utility power sector accounts for 40
percent of total annual energy consumption in the
U.S.698 Introducing more zero-emitting RE generation
694 “Tracking
the Sun VII” LBNL, Sept 2014. Available at:
http://emp.lbl.gov/publications/tracking-sun-vii-historicalsummary-installed-price-photovoltaics-united-states-1998-20.
695 “Photovoltaic System Pricing Trends,” NREL, 22 Sept 2014.
Available at: http://www.nrel.gov/docs/fy14osti/62558.pdf.
696 “Revolution Now—The Future Arrives for Four Clean
Energy Technologies—2014 Update,” DOE, Oct 2014. Available
at: http://energy.gov/sites/prod/files/2014/10/f18/revolution_
now_updated_charts_and_text_october_2014_1.pdf.
697 “Utility-Scale Solar 2013,” LBNL, Sept 2014. Available at:
http://emp.lbl.gov/publications/utility-scale-solar-2013empirical-analysis-project-cost-performance-and-pricing-trends.
698 U.S.
Review,
Energy Information Administration Annual Energy
2011. Accessed March 2015. Available at:
935
over the long term could significantly reduce CO2
emissions, as production of RE predominantly
replaces fossil fuel-fired generation and thereby avoids
the emissions from that replaced generation.
A number of studies and recent policy developments
have acknowledged RE as an important means of
achieving CO2 reductions.
California cited the
reduction of CO2 emissions from electrical generations
as one of the reasons for increasing its RE target from
20 percent to 33 percent by 2020 (and potentially 50
percent by 2030). 699 A recent IPCC report also
concluded that RE has large potential to mitigate CO2
emissions.700
Increased use of RE provides numerous benefits in
addition to lower CO2 emissions.
RE typically
consumes less water than fossil fuel-fired EGUs.
Wind power and solar PV systems do not require the
use of any water to generate electricity; water is only
needed for cleaning to ensure efficient operation. In
contrast, utility boilers, in particular, require large
http://www.eia.gov/totalenergy/data/monthly/pdf/flow/prim
ary_energy.pdf.
699 California S.B. 2 (1X), 2011. Accessed March 2015.
Available at: http://www.leginfo.ca.gov/pub/11-12/bill/sen/
sb_0001-0050/sbx1_2_bill_20110412_chaptered.pdf.
700 IPCC,
Renewable Energy Sources and Climate Change
Mitigation, 2012. Accessed March 2015. Available at:
http://www.ipcc.ch/pdf/special-reports/srren/SRREN_Full_
Report.pdf.
936
quantities of water for steam generation and
cooling.701
Increasing RE use will also continue to lower other
air pollutants (e.g., fine particles, ground-level ozone,
etc.). In addition, the RIA notes that increasing RE
will diversify energy supply, hedge against fossil fuel
price increases and create economic development and
jobs in manufacturing, installation, and other sectors
of the economy.
4. Access to RE by Owners of Affected EGUs
The ability of affected EGUs to co-locate or obtain
incremental RE to reduce CO2 emissions is welldemonstrated, whether it is through direct ownership,
bilateral contracts, or procurement of the
environmental attributes associated with RE
generation. 702 Consequently, the EPA believes that
an increase in RE is a proven way to reduce CO2
emissions at affected EGUs of all types at a reasonable
cost.
Owners and operators of affected EGUs across the
U.S. already have substantial opportunities to procure
RE regardless of their organizational structure and/or
business model. In many parts of the country, EGUs
are owned and operated by vertically integrated
utilities.
These utilities can be investor-owned
utilities that operate under traditional electricity
regulation, municipal utilities (munis), or electric
EPA, Water Resource Use. Accessed on March 2015.
Available at: http://www.epa.gov/cleanenergy/energy-andyou/affect/water-resource.html.
701
702 Refer to the GHG Mitigation Measures TSD for additional
information on RE ownership and co-location.
937
cooperatives (co-ops). These utilities have significant
control over the types of generating capacity they
develop or acquire, and over the electricity mix used to
meet demand within their service territories.
Even when EGU owners participating in organized
markets do not directly determine dispatch among
energy sources, such EGU owners make decisions
about what types of capacity they choose to develop
and thus what generation mix they can ultimately
supply into that market’s dispatch choices. Because
zero-emitting RE technologies have relatively low
variable costs, an EGU owner’s decision to install (or
to finance the installation of) RE capacity will yield
lower-cost electricity generation that, when available,
a system dispatcher will prefer over higher-variablecost generation from fossil fuel-fired capacity.
Therefore, all owners of affected EGUs have a direct
path for replacing higher-emitting generation with RE
regardless of their organizational type and regardless
of whether they operate in a cost-of-service framework
or in a competitive, organized market.
Many affected EGUs have already directly invested
in RE. Of the 404 entities that owned part of at least
one affected EGU under this rule, 178 also owned RE
(biomass, geothermal, solar, water or wind). These
178 owners owned 82 percent of affected EGU capacity.
As a whole, these entities’ share of RE capacity was
equal to 25 percent of the total of their affected EGU
capacity.703
703 SNL Energy. Data used with permission. Accessed on June
9, 2015.
938
Some of the largest owners of affected EGUs also
owned RE (see Table 8). For example, NRG Energy,
Inc. owns more than 3,000 megawatts of RE capacity,
over 20 percent of which (nearly 800 megawatts) is
solar, and almost 80 percent of which (over 2,500
megawatts) is wind. Duke Energy Corporation owns
175 megawatts of solar and over 1,500 megawatts of
wind. NextEra Energy, Inc.’s share of RE capacity
approaches 40 percent of their total affected EGU
capacity.704 Table 8 lists a sampling of affected EGUs
that have large amounts of fossil fuel-fired capacity
and RE capacity:
704 Ibid.
939
TABLE 8—SAMPLE OF OWNERS OF AFFECTED EGUS AND RE CAPACITY 705 706
Ultimate parent
NRG Energy, Inc. ..........................................................................
Duke Energy Corporation .............................................................
Southern Company ........................................................................
American Electric Power Company, Inc. ......................................
NextEra Energy, Inc......................................................................
Calpine Corporation ......................................................................
Tennessee Valley Authority ..........................................................
Berkshire Hathaway Inc. ..............................................................
FirstEnergy Corp. ..........................................................................
Exelon Corporation ........................................................................
Nebraska Public Power District....................................................
Basin Electric Power Cooperative.................................................
American Municipal Power, Inc. ...................................................
Sacramento Municipal Utility District .........................................
Golden Spread Electric Cooperative, Inc. .....................................
Affected EGU
capacity (MW)
48,787
39,028
37,168
34,940
29,471
23,878
21,717
18,899
16,175
10,283
2,003
1,526
1,112
925
521
705 SNL Energy. Data used with permission. Accessed on June 9, 2015.
706 eGRID, EPA. 2012 Unit-Level Data Using the eGRID Methodology.
Renewable
capacity (MW)
3,149
5,526
3,245
1,142
11,626
1,509
5,427
6,650
1,371
3,361
90
275
53
834
78
940
Large vertically integrated utilities generally have
multiple options for investing in RE, including
building their own RE capacity or procuring RE under
a long-term power purchase agreement. Municipal
utilities and rural cooperatives that own generating
asset portfolios, particularly generation and
transmission cooperatives and larger municipal
utilities, have also used RE to reduce carbon emissions.
Large generation and transmission cooperatives also
purchase significant quantities of RE for their
members. Federal power authorities own or contract
for significant amounts of RE.707 708
The list of ten electric utilities with the largest
amounts of wind power capacity on the system (owned
or under contract) includes a variety of affected EGU
organizational structures, including vertically
integrated investor-owned utilities, municipal utilities,
and federal power authorities. Xcel Energy and
Berkshire Hathaway Energy rank first and second
with 5,736 megawatts and 4,992 megawatts of wind
capacity, respectively. Tennessee Valley Authority, a
federal power authority, had 1,572 megawatts and
CPS Energy, a public utility, had 1,059 megawatts of
wind power capacity. 709 Basin Electric Power
707 American Wind Energy Association. AWEA Comments on
EPA’s Proposed Carbon Pollution Emission Guidelines for
Existing Stationary Sources and Supplemental Proposed Rule. pp.
88–91.
708 Solar Energy Industries Association. Comments to the EPA
and States on the Proposed Clean Power Plan Regulating
Existing Power Plants Under Section 111(d) of the Clean Air Act.
pp. 98–147.
709 American
Wind Energy Association. U.S. Wind Industry
Annual Market Report (2014 data). Accessed July 2015.
941
Cooperative had 716 megawatts and was the top
ranked cooperative utility, but is not on the top ten
utilities with wind power capacity list.
Many affected EGUs are already planning on
deploying significant amounts of RE according to their
integrated resource plans (IRPs). Electric utilities use
IRPs to plan operations and investments over long
time horizons. These plans typically cover 10 to 20
years and are mandated by public utility commissions
(PUCs). A recent study of IRPs, included in the docket
for this rulemaking, shows this trend.710 For instance,
Dominion plans for over 800 megawatts of wind and
solar in their 2015 to 2029 planning period.711 Duke
Energy Carolinas’ IRP has no plans for new coal, but
describes plans for roughly 1,250 megawatts of
additional RE by 2021, and approximately 2,150
megawatts by 2029. A significant portion (1,670
megawatts) of the planned RE is solar.712 Ameren is
Available at http://www.awea.org/AnnualMarketReport.aspx?
ItemNumber=7422&RDtoken=64560&userID=. The ten largest
electric utilities with wind power capacity on the system (owner
or under contract) includes: Xcel Energy; Berkshire Hathaway
Energy; Southern California Edison; American Electric Power;
Pacific Gas & Electric; Tennessee Valley Authority; San Diego
Gas & Electric; CPS Energy; Los Angeles Department of Water
& Power; and Alliant Energy.
710 See memo entitled “Review of Electric Utility Integrated
Resource Plans” (May 7, 2015).
711 Dominion North Carolina Power’s and Dominion Virginia
Power’s Report of Its Integrated Resource Plan, August 2014.
Available at: https://www.dom.com/library/domcom/pdfs/
corporate/integrated-resource-planning/nc-irp-2014.pdf.
712 Duke
Energy Carolinas’ 2014 Integrated Resource Plan,
September 2014. Available at: http://starw1.ncuc.net/NCUC/
ViewFile.aspx?Id=c3c5cbb5-51f2-423a-9dfc-a43ec559d307.
942
planning to retire one-third of the coal generating
capacity, as well as installing an additional
400 megawatts of wind, 445 megawatts of solar, and
28 megawatts of hydroelectric generating capacity.713
Independent power producers (IPPs) also can and do
own both RE and fossil generation. For example, NRG
is a diversified IPP that operates substantial coal,
natural gas, wind, solar, and nuclear capacity. NRG
demonstrates the ability of IPPs to reduce utilization
of fossil fuel-fired EGUs and replace that generation
with RE. NRG announced a goal to cut CO2 emissions
from its fleet by 50 percent by 2030 (from a 2014
baseline).714 NRG has already reduced CO2 emissions
from its fleet by 40 percent since 2005.
This
achievement demonstrates that when an IPP commits
to shifting its generation portfolio, it can do so at
reasonable cost and without reliability impacts. The
NRG example shows that reduced utilization of fossil
fuel-fired EGUs that is replaced by RE also owned by
the EGU owner is adequately demonstrated.
EGU owners can also replace fossil fuel-fired
generation with RE through bilateral contracts and
REC purchases, as described below. Both the bilateral
market for RE contracts and REC markets are welldeveloped. There are no legal or technical obstacles to
a fossil fuel-fired EGU owner acting as the
713 Integrated
Resource Plan Update, October 2014.
Available at: https://www.ameren.com/missouri/environment/
renewables/ameren-missouri-irp.
714 NRG, “NRG Energy Sets Long-Term Sustainability Goals
at Groundbreaking of ‘Ultra-Green’ New Headquarters” (Nov. 20,
2014). Available at http://investors.nrg.com/phoenix.zhtml?
c=121544&p=irolnewsArticle&ID=1991552.
943
counterparty of a bilateral contract for purchase of
energy from a RE facility. Any type of EGU owner
(utility or otherwise) can purchase and retire RECs.
The fact that RECs are purchased by a diverse set of
market participants—including residential consumers,
commercial businesses, and industrial facilities—
demonstrates that such a purchase for all EGU owners
is adequately demonstrated.
5. REC Markets
Affected EGU owners do not need to directly invest
in, or own, renewable generating capacity in order to
replace fossil fuel-fired generation with RE as an
emission reduction measure. RECs are used to
demonstrate compliance with state RE targets, such
as state RPS, and also to substantiate claims
stemming from RE use.
RECs are tradable
instruments that are associated with the generation of
one megawatt-hour of RE and represent certain
information or characteristics of the generation, called
attributes. 715 RECs may be traded and transferred
regardless of the actual energy flow.
The legal basis for RECs is established by state
statutes and administrative rules. Nearly all states
with a mandatory RPS have established RECs as a
means of compliance. The Federal Energy Regulatory
Commission (FERC) has observed that states created
RECs to facilitate programs designed to promote
increased use of RE, and that “attributes associated
EPA Green Power Partnership, Renewable Energy
Certificates July 2008). Available at http://www.epa.gov/
greenpower/documents/gpp_basics-recs.pdf.
715
944
with the [RE] facilities are separate from, and may be
sold separately from, the capacity and energy.”716
In complying with states’ RPS requirements,
utilities have contracted for RECs from in-state and
out-of-state resources in accordance with RPS
requirements. Utilities may have sourced RECs from
out-of-state to reduce the cost of compliance, to source
RECs from specific generation types, or for other
reasons.717
The development of REC markets to facilitate RPS
compliance provides evidence that markets can
develop to facilitate compliance with rate-based state
plans. These markets will afford affected EGU owners
an alternative to directly invest in, or own, renewable
generating capacity in order to replace fossil fuel-fired
generation with RE as an emission reduction measure.
6. Quantification of RE Generation Potential for
BSER and Major Comments
The methodology for quantifying RE generation
levels under building block 3 is a modified version of
the alternative RE approach from proposal, with
adjustments that reflect the data and information the
716 FERC Docket No. EL03-133-000, Petition for Declaratory
Order and Request for Expedited Consideration, American RefFuel Company, Covanta Energy Group, Montenay Power
Corporation, and Wheelabrator Technologies, Inc. June 16, 2003,
Order Granting Petition for Declaratory Ruling, October 1, 2003.
American Ref-Fuel Co. et al., 105 FERC ¶ 61,004 (2003); and
Order Denying Rehearing. April 15, 2004. 107 FERC ¶ 61,016
(2004). Available online at: http://www.ferc.gov/whatsnew/comm-meet/041404/E-28.pdf (accessed 11/7/2014).
717 Heeter, J. Quantifying the Level of Cross-State Renewable
Energy
Transactions.
NREL
2015.
Available
http://www.nrel.gov/docs/fy15osti/63458.pdf.
at
945
EPA collected through stakeholder comments and the
EPA’s additional analysis and information collection.
In evaluating the proposed and alternative RE
approaches commenters observed that RPS, as the
basis for quantifying RE generation levels under the
proposed approach, are policy instruments that states
may choose to implement for a variety of reasons not
related to CO2 emission reductions. Additionally,
differences across RPS policies in eligible resources,
crediting mechanisms, deliverability requirements,
alternative compliance payments, and other policy
elements made the regional averaging of state-level
RPS requirements challenging. Finally, commenters
provided data demonstrating that RE resource
potential can vary significantly within the regions
identified under the proposed approach, producing
state-level RE generation levels that may not be
aligned with the opportunity to deploy incremental RE
resources at reasonable cost. In contrast, commenters
argued that a methodology similar to the alternative
RE approach, which is based on economic potential,
represents a more technically sound basis for
quantifying building block 3 target generation levels
that accounts for regional differences in RE resources
and power market conditions, such as projected fuel
prices, load growth and wholesale power prices. The
EPA agrees with these comments.
Within the framework of the alternative RE
approach, the EPA received significant comments on a
number of issues, including the use of historical
deployment rates, the interstate nature of RE and the
power system, merits of total versus incremental RE
generation as the metric by which building block 3
generation levels are quantified, types of RE
946
technologies that contribute to those generation levels,
cost and performance estimates associated with those
RE technologies, magnitude of the reduced cost
applied to new RE capacity as an incentive to deploy,
and application of a nationally uniform benchmark
development rate to modeled projections of economic
deployment.
Based on commenter data and
information, as well as further analysis and
information collection, the primary adjustments the
EPA made to the alternative RE approach are:
• The basis for quantifying building block 3
generation has been modified to incorporate historical
deployment patterns for RE technologies as well as the
economic potential identified through modeling
projections. The introduction of historical capacity
additions to the final methodology further grounds
building block 3 generation in demonstrated levels of
RE deployment that have been successfully
incorporated into the power system. This adjustment
also serves to harmonize the approach across all three
building blocks in which historical data is the primary
basis for identifying emission reduction opportunities
under the BSER.
• The RE technologies used to quantify building
block 3 generation levels are onshore wind, utilityscale solar PV, concentrating solar power (CSP),
geothermal and hydropower.
Each of these
technologies is a utility-scale, zero-emitting resource
that was included under the alternative RE approach
at proposal.
Additionally, the EPA received
significant comments on the opportunities and
challenges
associated
with
distributed
RE
technologies. Distributed technologies, as a demandside resource, present unique data and technical
947
challenges (such as the role of evaluation,
measurement and verification (EM&V) procedures in
verifying their production, the diverse economic
incentives of different parties involved in their
deployment, and the variety of grid integration
policies and conditions across potential deployment
sites) that complicate identifying a technically feasible
and cost-effective level of generation. Consequently,
the EPA is, at this time, choosing not to include
distributed technologies as part of the BSER (although,
as explained in section VIII.K of this preamble,
distributed RE technologies that meets eligibility
criteria may be used for compliance). Finally, any RE
technology that has not been deployed in the U.S.,
including demonstrated RE technologies for which
there is clear evidence of technical feasibility and costeffectiveness (e.g., offshore wind), contributes no
generation to building block 3 under this historicallybased methodology.
These RE technologies are
consequently reserved for compliance, which offers
affected EGUs additional flexibility and will reduce
their need to rely on other emission reduction
measures or building blocks.
•
Building block 3 generation levels are expressed
in terms of incremental, rather than total, RE
generation. As a metric, incremental generation is
better aligned with quantifying an amount of
expanded RE to replace generation at affected
EGUs. 718 Specifically, the generation levels under
718 Consistent with the October 2014 NODA, the final goal-
setting methodology assumes replacement of affected EGU
generation by incremental building block 3 generation in
calculating source-specific CO2 emission performance rates. For
948
building block 3 include generation from capacity that
commenced operation subsequent to 2012 (the data
year on which the BSER is evaluated). Commenters
remarked that it is unnecessary to include generation
from RE capacity that was already in operation by
2012 in building block 3 because the impact of that
generation on fossil fuel-fired EGUs is already
reflected in the observed 2012 emissions and
generation data of those EGUs.
• Due to the interstate nature of RE and the
power system, and consistent with the rationale
provided in the October 2014 Notice of Data
Availability (NODA), building block 3 generation
levels are quantified for each of the three BSER
regions—the Eastern Interconnection, Western
Interconnection, and Texas Interconnection—rather
than at the state-level. This regionalized approach, as
described in the NODA, takes into account the
opportunity to develop regional RE resources and thus
better aligns building block 3 generation levels with
the rule’s approach to allowing the use of qualifying
out-of-state renewable generation for compliance.
• Commenters observed that the cost and
performance estimates the EPA relied on at proposal
from the Energy Information Administration’s Annual
Energy Outlook 2013 do not reflect the decline in cost
and increase in performance that have been
demonstrated by current projects, particularly in
regards to wind and solar technologies. Commenters
provided data from a variety of sources to support
these claims, including Lawrence Berkeley National
additional information on the goal-setting methodology, refer to
Section VI.
949
Laboratory (LBNL), the Department of Energy (DOE)
and Lazard. Each of these sources supported the
contention that RE technologies, particularly wind
and solar, have realized gains in cost and efficiency at
a scale that has altered the competitive dynamic
between RE and conventional resources. As a result,
it has become increasingly necessary for any long-term
outlook of the utility power sector to continually assess
the development of RE technology cost and
performance trends. In performing this task, the EPA
revised its data for onshore wind and solar
technologies to reflect the mid-case estimates from the
National Renewable Energy Laboratory’s (NREL’s)
2015 Annual Technology Baseline. The EPA selected
the NREL 2015 Annual Technology Baseline (ATB)
estimates based on the quality of its data as well as
NREL’s demonstrated success in both reflecting and
anticipating RE cost and performance trends. In
addition to wind and solar technologies, the EPA
evaluated hydropower deployment potential based on
the latest cost and performance data from NREL’s
Renewable Energy Economic Potential study.719
• The benchmark development rate that
constrained cost-effective RE deployment under the
alternative RE approach in the proposal has been
removed from the final methodology.720 Commenters
detailed several issues with applying the benchmark
719 For additional information on the updated RE cost and
performance assumptions used to quantify building block 3
generation, refer to the GHG Mitigation Measures TSD.
720 The technical potential limiter was a nationally uniform,
technology-specific limit on cost-effective RE deployment based
on the amount of 2012 generation in a state as a share of that
state’s total technical potential.
950
development rate, including that it does not factor in
the total size of the RE resource in a given state and is
inconsistent with a regional approach to quantifying
target generation levels. EPA agrees with these
comments and the benchmark development rate has
been eliminated.
In addition to the comments described above, the
EPA received significant comments on a wide variety
of topics related to building block 3. Many of these
comments provided helpful information and insights,
and have resulted in improvements to the final rule.
These comments, as well as the EPA responses, are
available in the Response to Comment document.
The final methodology for quantifying incremental
RE target generation levels contains seven steps.
Each step is described below.721
First, the EPA collected data for each RE technology
(onshore wind, utility-scale solar PV, CSP, geothermal
and hydropower) to determine the annual change in
capacity over the most recent five-year period. From
these data, the EPA calculated the five-year annual
average change in capacity and the five-year
maximum annual change in capacity for each
technology.
Second, the EPA determined an appropriate
capacity factor to apply to each RE technology that
would be representative of expected future
performance from 2022 through 2030. For this
purpose the EPA relied on NREL’s ATB.
721 For supporting data, documentation, and examples for each
step of the quantification methodology, refer to the GHG
Mitigation Measures TSD.
951
Third, the EPA calculated two generation levels for
each RE technology. The first generation level is the
product of each technology’s five-year average capacity
change and the assumed future capacity factor. The
second generation level is the product of each
technology’s five-year maximum annual capacity
deployment and the assumed future capacity factor.
Table 9 below shows the data and assumptions used
for these calculations.
952
TABLE 9—HISTORICAL CAPACITY CHANGES AND ASSOCIATED GENERATION LEVELS
Utility-Scale Solar PV722 .......
CSP..........................................
Onshore Wind .........................
Geothermal ..............................
Hydropower .............................
Total Generation ...............
Assumed
future
capacity
factor
(percent)
Five-Year
average
capacity
change
(MW)
20.7
34.3
41.8
85.0
63.8
N/A
1,927
251
6,200
142
141
N/A
Generation
associated
with five
yearaverage
capacity
change
(MWh)
3,494,268
754,175
22,702,416
1,057,332
788,032
28,796,222
Maximum
annual
capacity
change
(MW)
3,934
767
13,131
407
294
N/A
Generation
associated
with
maximum
annual
capacity
change
(MWh)
7,133,601
2,304,590
48,081,520
3,030,522
1,643,131
62,193,363
722 Capacity values for utility-scale solar PV are expressed in terms of MWDC. The assumed future capacity
factor for this utility-scale solar PV includes a DC-to-AC conversion, enabling the generation totals to be
combined across all RE technologies.
953
Fourth, the EPA quantified the RE generation from
capacity commencing operation after 2012 that can be
expected in 2021 (the year before this rule’s first
compliance period) without the imposition of this rule.
Because building block 3 is focused on the ability of
fossil fuel-fired EGUs to reduce their emissions by
deploying incremental RE, it is reasonable to take into
account the considerable amount of RE deployment
that is already taking place and is projected to
continue doing so before considering the additional
deployment that would be motivated by this rule’s
mandate to reduce emissions from affected EGUs. The
EPA considered its base case power sector modeling
projections using IPM to quantify this component of
future-year RE generation, which the EPA assumes to
be 213,084,125 megawatt-hours in 2021.
Fifth, the EPA applied the generation associated
with the five-year average capacity change to the first
two years of the interim period. Combining the
projected 2021 RE generation from capacity starting
operation after 2012 with the generation increment
associated with the five-year average change in
capacity produces 241,880,347 megawatt-hours in
2022 and 270,676,570 megawatt-hours in 2023. The
EPA believes it is appropriate to apply the generation
associated with the five-year average capacity change
for the first two years of the interim period to ensure
adequate opportunity to plan for and implement any
necessary RE integration strategies and investments
in advance of the higher RE deployment levels
assumed for later years.
Sixth, for all years subsequent to 2023 the EPA
applied the generation associated with the maximum
annual capacity change from the historical data
954
analysis. In 2024, this produces a building block 3
generation level of 332,869,933 megawatt-hours
(aggregated across all three BSER regions); by 2030,
that generation level is 706,030,112 megawatt-hours.
Seventh, to further evaluate the technical feasibility
and cost-effectiveness of the building block 3
generation levels (aggregated across all three BSER
regions), as well as to produce interconnection-specific
levels of building block 3 generation from the national
totals described in steps 5 and 6, the EPA conducted
analysis using IPM of a scenario directing the power
sector to achieve those RE generation levels. IPM
modeling projections assess opportunities for RE
deployment in an integrated framework across power,
fuel, and emission markets. The modeling framework
incorporates a host of constraints on the deployment
of RE resources, including resource constraints such
as resource quality, land use exclusions, terrain
variability, distance to existing transmission, and
population density; system constraints such as
interregional transmission limits, partial reserve
margin credit for intermittent RE installations,
minimum turndown constraints for fossil fuel-fired
EGUs, and short-term capital cost adders to reflect the
potential added cost due to competition for scarce labor
and materials; and technology constraints such as
construction lead times and hourly generation profiles
for
non-dispatchable
resources
by
723
Additionally, the EPA assumes in this
season.
analysis that deployment of variable, nondispatchable RE resources is limited to 20 percent of
723 Refer to GHG Mitigation Measures TSD for more detail on
modeling methodology.
955
net energy for load by technology type and 30 percent
of net energy for load in total at each of IPM’s 64
U.S. sub-regions.724 The 30 percent constraint applied
to variable, non-dispatchable RE resources reflects
levels commonly modeled in grid integration studies at
the level of the interconnection. These studies have
demonstrated that impacts to the grid in reaching
levels as high as 30 percent of net energy for load are
relatively minor.725 For example, the Western Wind
and Solar Study Phase 2 found cycling costs ranged
from $0.14 to $0.67 per megawatt-hour of added wind
and solar generation. These integration cost levels are
not impactful in determining cost-effectiveness. As
such, applying the 30 percent constraints at the IPM
sub-region level is very conservative and provides a
high degree of assurance that the RE capacity
724 Regions that have already exceeded these limits are held at
historical percent of net energy for load.
725 2013
Wind Technologies Market Report. LBNL. August
2014. Available at http://emp.lbl.gov/sites/all/files/2013_
Wind_Technologies_Market_Report_Final3.pdf.
Grid Integration and the Carrying Capacity of the U.S. Grid to
Incorporate Variable Renewable Energy. NREL. Cochran et al.,
April 2015. http://energy.gov/sites/prod/files/2015/04/f22/
QER%20Analysis%20%20Grid%20Integration%20and%20the%2
0Carrying%20Capacity%20of%20the%20US%20Grid%20to%20I
ncorporate%20Variable%20Renewable%20Energy_1.pdf.
The Western Wind and Solar Integration Study Phase 2.
NREL. Lew et al., 2013. Available at http://www.nrel.gov/docs/
fy13osti/55588.pdf. Refer to GHG Mitigation Measures TSD for
further analysis.
956
deployment pattern projected by the model would not
incur significant grid integration costs.726
In addition to facilitating the EPA’s assessment of
the feasibility and cost of reaching the aggregate
building block 3 generation levels across all three
BSER regions, the IPM projections also provide the
EPA with a basis for apportioning those generation
levels to each interconnection. The EPA considered
the projected regional location of the evaluated RE
deployment in this analysis, which shows the majority
of such deployment occurring in the Eastern
Interconnection. The GHG Mitigation Measures TSD
describes in greater detail the process by which the
EPA calculated the apportionment of building block 3
generation levels to each of the BSER regions, taking
these modeling projections into account. Table 10
describes the annual building block 3 generation levels
for each interconnection from 2022 through 2030.
726 Refer to the GHG Mitigation Measures TSD for additional
information on constraints related to deployment of nondispatchable RE.
957
TABLE 10—BUILDING BLOCK 3 GENERATION LEVELS (MWH).
Year
2022 ........................................................
2023 ........................................................
2024 ........................................................
2025 ........................................................
2026 ........................................................
2027 ........................................................
2028 ........................................................
2029 ........................................................
2030 ........................................................
Eastern
interconnection
166,253,134
181,542,775
218,243,050
254,943,325
291,643,600
328,343,875
365,044,150
401,744,425
438,444,700
Western
interconnection
56,663,541
60,956,363
75,244,721
89,533,078
103,821,436
118,109,793
132,398,151
146,686,508
160,974,866
Texas
interconnection
18,963,672
28,177,431
39,382,162
50,586,893
61,791,623
72,996,354
84,201,085
95,405,816
106,610,547
958
Through the quantification methodology detailed
above, the EPA has identified amounts of incremental
RE generation that are reasonable, rather than the
maximum amounts that could be achieved while
preserving the cost-effectiveness of the building block.
For example, assuming gradual improvement in RE
technology capacity factors consistent with historical
trends, expanding the portfolio of RE technologies that
contribute to the building block 3 generation level, and
applying the five-year maximum capacity change
values to all years of the interim period are
adjustments that would produce higher building block
3 generation levels and maintain the primacy of
historical data in quantifying RE generation potential.
External analysis and studies of RE penetration levels
strongly support the technical feasibility and costreasonableness of RE deployment well in excess of the
levels established by building block 3, as detailed in
section V.E.7. By identifying reasonable rather than
maximum achievable amounts, we are increasing the
assurance that the identified amounts are achievable
by the source category and providing greater flexibility
to individual affected EGUs to choose among
alternative measures for achieving compliance with
the standards of performance established for them in
their states’ section 111(d) plans.
7. Feasibility of RE Deployment
The 2030 level of RE deployment and the rate of
progress during the interim period in getting to that
level are well supported by comments received, DOE
and NREL analysis, and external studies evaluating
the costs of and potential for RE penetration. The EPA
has assessed the feasibility of RE in terms of
deployment potential, system integration, reliability,
959
backup capacity, transmission investments, and RE
supply chains.
Historical RE deployment rates are a strong
indication of the feasibility of the 2030 level of
deployment and interim period pathway. The use of
RE continues to grow rapidly in the U.S. In 2013,
electricity generated from RE, including conventional
hydropower, represented 12 percent of total U.S.
electricity, up from 8 percent in 2005. In particular,
there has been substantial growth in the wind and
solar markets in the past decade. Since 2009, wind
energy has tripled and solar has grown tenfold.
The expected future capacity installations in 2022–
2030 needed to reach the 2030 level of incremental RE
generation are consistent with historical deployment
patterns. Forecasts by Cambridge Energy Research
Associates (CERA) of 17 gigawatts in 2015 and
historical deployment of 16 gigawatts in 2012 are
significant. The average deployment of wind over the
past five years was 6,200 megawatts per year; 2014
deployment of solar PV, both distributed and utilityscale, was 6,201 megawatts. This contribution from
solar PV is consistent with the rapid reduction in costs
that is currently being observed and is expected to
continue.
Grid operators are reliably integrating large
amounts of RE, including variable, non-dispatchable
RE today. For example, Iowa and South Dakota
produced more than 25 percent of their electricity from
wind in 2013, with a total of nine states above 12
percent and 17 states at more than 5 percent.
California served nearly 19 percent of total load in
2013 with RE resources, not including behind-the-
960
meter distributed solar resources, and approximately
25 percent of total load with RE in 2014. On an
instantaneous basis, California is regularly serving
above 25 percent of load with RE resources, recently
began seeing over 5,000 megawatt-hours of solar
energy, and is on track for 33 percent of load with no
serious reliability or grid integration issues. Germany
exceeded 28 percent non-hydro RE as a percentage of
total energy in first half of 2014. Other recent
examples include: ERCOT met 40 percent of demand
on March 31, 2014 with wind power; SPP met 33
percent of demand on April 6, 2013 with wind power;
and, Xcel Energy Colorado met 60 percent of demand
on May 2, 2013 with wind power. Operational and
technical upgrades to the power system may be
required to accommodate high levels of variable, nondispatchable RE like wind and solar over longer time
periods; however, the penetration levels cited above
have been achieved without negative impacts to
reliability due in large part to low-cost measures such
as expanded operational flexibility and effective
coordination with other regional markets.
RE can contribute to reliable system operation. The
abundance and diversity of RE resources in the U.S.
can support multiple combinations of RE in much
higher penetrations. When California, the Midwest,
PJM, New York, and New England experienced record
winter demand and prices during the polar vortex,
wind generation played a key role in maintaining
system reliability.
Wind and solar PV are increasingly productive and
capable of being accurately forecast, which improves
grid reliability. Increasing capacity factors mean less
variability and more generation. While the wind
961
industry develops more projects at lower wind speed
sites, wind turbine design changes are driving
capacity factors higher among projects located in a
given wind resource regime. 727 Average capacity
factors have risen from the low 30 percent range to
high 30 percent range and continue to improve. One
key recent advancement is the increasing use of
turbines designed for low to medium wind speed sites
(with higher hub-heights and larger rotors, relative to
nameplate capacity) at higher wind-speed sites with
low turbulence.
New variable RE generators can provide more
electrical power grid support services beyond just
energy. Modern wind turbine power electronics allow
turbines to provide voltage and reactive power control
at all times. Wind plants meet a higher standard and
far exceed the ability of conventional power plants to
“ride-through” power system disturbances, which is
essential for maintaining reliability when large
conventional power plants break down. Xcel Energy
sometimes uses its wind plants’ exceedingly fast
response to meet system need for frequency response
and dispatchable resources. Utility-scale PV can
incorporate control systems that enable solar PV to
contribute to grid reliability and stability, such as
voltage regulation, active power controls, ramp-rate
controls, fault ride through, and frequency control.
Solar generation is capable of providing many
ancillary services that the grid needs but, like other
727 LBNL,
Wind Technologies Market Report 2013, August
2014, p. 43, Available at: http://emp.lbl.gov/sites/all/files/
2013_Wind_Technologies_Market_Report_Final3.pdf.
962
generators, needs the proper market signals to trade
energy generation for ancillary service provision.
The transmission network can connect distant highquality RE to load centers and improve reliability by
increasing system flexibility.
Investments in
transmission and distribution upgrades also enable
improvements
in
system-wide
environmental
performance at lower cost.
The potential range of new transmission
construction is within historical investment
magnitudes. Under nearly all scenarios analyzed for
the DOE’s Quadrennial Energy Review, circuit-miles
of transmission added through 2030 are roughly equal
to those needed under the base case, and while those
base case transmission needs are significant, they do
not appear to exceed historical annual build rates.
DOE’s Wind Vision findings project 11.5 gigawatts of
wind per year from 2021–2030. This deployment level
would require 890 circuit miles per year of new
transmission; 870 miles per year have been added on
average between 1991 and 2013. 11.5 gigawatts per
year is consistent with building block 3 deployment
levels for wind capacity over the compliance period.
DOE’s SunShot scenario, which increases utility-scale
PV to 180 gigawatts by 2030, required spending of $60
billion on transmission through 2050. On an average
annual basis, this expenditure is within the historical
range of annual transmission investments made by
IOUs in recent decades.
Incremental grid infrastructure needs can be
minimized by repurposing existing transmission
resources. Transmission formerly used to deliver
fossil-fired power to distant loads can—and is—being
963
used to deliver RE without new infrastructure. First
Solar’s Moapa project uses transmission built to
deliver coal-fired power from Navajo to Los Angeles.
NV Energy’s retirement of Reid-Gardner will free up
additional transmission capacity. The Milford wind
projects in Utah already utilize transmission that was
built to deliver coal power to Los Angeles.
Storage can be helpful but is not essential for the
feasibility of RE deployment because there are many
sources of flexibility on the grid. DOE’s Wind Vision
and many other studies have found an array of
integration options (e.g., large balancing areas,
geographically dispersed RE, weather forecasting
used in system operations, sub-hourly energy markets,
access to neighboring markets) for RE beyond storage.
Storage is a system resource, as its value for
renewables is a small share of its total value.
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