capacity factor because net summer capacity reflects a lower amount
of total generation potential achievable by the unit in practice.
---------------------------------------------------------------------------

    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.
    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
existing NGCC units to 75 percent on a net summer basis would be
technically feasible.
---------------------------------------------------------------------------

    \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).
---------------------------------------------------------------------------

    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\
---------------------------------------------------------------------------

    \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.
---------------------------------------------------------------------------

    The EPA believes that producing this quantity of generation from
this set of NGCC units is feasible. To 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\
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    \669\ See section VIII for further discussion of electric
reliability planning.
---------------------------------------------------------------------------

    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 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 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.
---------------------------------------------------------------------------

    \670\ 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).
    \671\ EIA, Electric Power Monthly, February, 2014. Table 6.7.A.
---------------------------------------------------------------------------

    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 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.
---------------------------------------------------------------------------

    \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.
    \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.
---------------------------------------------------------------------------

    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 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 multi-
regional, 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 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 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 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.
---------------------------------------------------------------------------

    \675\ See Greenhouse Gas Mitigation Measures TSD for a
discussion of regional NGCC capacity factors.
    \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.
---------------------------------------------------------------------------

    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 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 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 over the 2022-2030
period, which is well within the range of historical natural gas price
variability.\677\ 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.
---------------------------------------------------------------------------

    \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/rngwhhdA.htm.
---------------------------------------------------------------------------

    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 phase-in, 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 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.
    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 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
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 back-up 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 can be replaced by using an expanded amount of
zero-emitting 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 to coordinate energy policy and promote energy self-
sufficiency and security, including solar energy legislation, the
Public Utility Regulatory Policies Act of 1978 (PURPA) and the 1980
Energy Security Act.\679\
---------------------------------------------------------------------------

    \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/history-hydropower.
    \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.
---------------------------------------------------------------------------

    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.
---------------------------------------------------------------------------

    \680\ ``Restructuring or Deregulation?'' Smithsonian Museum of
American History. Accessed March 2015. Available at: http://americanhistory.si.edu/powering/dereg/dereg1.htm.
---------------------------------------------------------------------------

    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 non-
hydropower RE.
---------------------------------------------------------------------------

    \681\ Energy Information Administration, Annual Energy Outlook
2014 with Projections to 2040, at LR-5 (2014).
---------------------------------------------------------------------------

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
---------------------------------------------------------------------------

    \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.
---------------------------------------------------------------------------

    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 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\
---------------------------------------------------------------------------

    \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 (EIA-860). Available at:
http://www.eia.gov/electricity/data/state/.
    \686\ Energy Information Administration, Monthly Energy Review,
May 2015, Table 7.2b. Available at: http://www.eia.gov/totalenergy/data/monthly/pdf/sec7_6.pdf.
---------------------------------------------------------------------------

    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\
---------------------------------------------------------------------------

    \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.
    \690\ 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.
---------------------------------------------------------------------------

    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 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.
---------------------------------------------------------------------------

    \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.
    \694\ ``Tracking the Sun VII'' LBNL, Sept 2014. Available at:
http://emp.lbl.gov/publications/tracking-sun-vii-historical-summary-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-2013-empirical-analysis-project-cost-performance-and-pricing-trends.
---------------------------------------------------------------------------

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 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.
---------------------------------------------------------------------------

    \698\ U.S. Energy Information Administration Annual Energy
Review, 2011. Accessed March 2015. Available at: http://www.eia.gov/totalenergy/data/monthly/pdf/flow/primary_energy.pdf.
---------------------------------------------------------------------------

    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\
---------------------------------------------------------------------------

    \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.
---------------------------------------------------------------------------

    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 quantities of water for steam generation and
cooling.\701\
---------------------------------------------------------------------------

    \701\ EPA, Water Resource Use. Accessed on March 2015. Available
at: http://www.epa.gov/cleanenergy/energy-and-you/affect/water-resource.html.
---------------------------------------------------------------------------

    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 well-demonstrated, 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.
---------------------------------------------------------------------------

    \702\ Refer to the GHG Mitigation Measures TSD for additional
information on RE ownership and co-location.
---------------------------------------------------------------------------

    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 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-variable-cost 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.
---------------------------------------------------------------------------

    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.

   Table 8--Sample of Owners of Affected EGUs and RE Capacity 705 706
------------------------------------------------------------------------
                                           Affected EGU      Renewable
             Ultimate parent               capacity (MW)   capacity (MW)
------------------------------------------------------------------------
NRG Energy, Inc.........................          48,787           3,149
Duke Energy Corporation.................          39,028           5,526
Southern Company........................          37,168           3,245
American Electric Power Company, Inc....          34,940           1,142
NextEra Energy, Inc.....................          29,471          11,626
Calpine Corporation.....................          23,878           1,509
Tennessee Valley Authority..............          21,717           5,427
Berkshire Hathaway Inc..................          18,899           6,650
FirstEnergy Corp........................          16,175           1,371
Exelon Corporation......................          10,283           3,361
Nebraska Public Power District..........           2,003              90
Basin Electric Power Cooperative........           1,526             275
American Municipal Power, Inc...........           1,112              53
Sacramento Municipal Utility District...             925             834
Golden Spread Electric Cooperative, Inc.             521              78
------------------------------------------------------------------------

    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
---------------------------------------------------------------------------

    \705\ SNL Energy. Data used with permission. Accessed on June 9,
2015.
    \706\ eGRID, EPA. 2012 Unit-Level Data Using the eGRID
Methodology.
    \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.
---------------------------------------------------------------------------

    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 Cooperative
had 716 megawatts and was the top ranked cooperative utility, but is
not on the top ten utilities with wind power capacity list.
---------------------------------------------------------------------------

    \709\ American Wind Energy Association. U.S. Wind Industry
Annual Market Report (2014 data). Accessed July 2015. 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.
---------------------------------------------------------------------------

    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
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\
---------------------------------------------------------------------------

    \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.
    \713\ Integrated Resource Plan Update, October 2014. Available
at: https://www.ameren.com/missouri/environment/renewables/ameren-missouri-irp.
---------------------------------------------------------------------------

    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.
---------------------------------------------------------------------------

    \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.
---------------------------------------------------------------------------

    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 well-
developed. There are no legal or technical obstacles to a fossil fuel-
fired EGU owner acting as the 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.
---------------------------------------------------------------------------

    \715\ EPA Green Power Partnership, Renewable Energy Certificates
July 2008). Available at http://www.epa.gov/greenpower/documents/gpp_basics-recs.pdf.
---------------------------------------------------------------------------

    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 with the [RE] facilities are separate from, and
may be sold separately from, the capacity and energy.'' \716\
---------------------------------------------------------------------------

    \716\ FERC Docket No. EL03-133-000, Petition for Declaratory
Order and Request for Expedited Consideration, American Ref-Fuel
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/whats-new/comm-meet/041404/E-28.pdf (accessed
11/7/2014).
---------------------------------------------------------------------------

    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\
---------------------------------------------------------------------------

    \717\ Heeter, J. Quantifying the Level of Cross-State Renewable
Energy Transactions. NREL 2015. Available at http://www.nrel.gov/docs/fy15osti/63458.pdf.
---------------------------------------------------------------------------

    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
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 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, utility-scale 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 demand-side resource,
present unique data and technical 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 cost-
effectiveness (e.g., offshore wind), contributes no generation to
building block 3 under this historically-based 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 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.
---------------------------------------------------------------------------

    \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 additional
information on the goal-setting methodology, refer to Section VI.
---------------------------------------------------------------------------

     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 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\
---------------------------------------------------------------------------

    \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.
---------------------------------------------------------------------------

     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
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.
---------------------------------------------------------------------------

    \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.

    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\
---------------------------------------------------------------------------

    \721\ For supporting data, documentation, and examples for each
step of the quantification methodology, refer to the GHG Mitigation
Measures TSD.
---------------------------------------------------------------------------

    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.
    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.

                      Table 9--Historical Capacity Changes and Associated Generation Levels
----------------------------------------------------------------------------------------------------------------
                                                                    Generation                      Generation
                                  Assumed future     Five-Year      associated                      associated
                                     capacity         average     with five year- Maximum annual   with maximum
                                      factor         capacity         average        capacity         annual
                                     (percent)      change (MW)      capacity       change (MW)      capacity
                                                                   change (MWh)                    change (MWh)
----------------------------------------------------------------------------------------------------------------
Utility-Scale Solar PV \722\....            20.7           1,927       3,494,268           3,934       7,133,601
CSP.............................            34.3             251         754,175             767       2,304,590
Onshore Wind....................            41.8           6,200      22,702,416          13,131      48,081,520
Geothermal......................            85.0             142       1,057,332             407       3,030,522
Hydropower......................            63.8             141         788,032             294       1,643,131
                                 -------------------------------------------------------------------------------
    Total Generation............             N/A             N/A      28,796,222             N/A      62,193,363
----------------------------------------------------------------------------------------------------------------

    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.
---------------------------------------------------------------------------

    \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.
---------------------------------------------------------------------------

    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 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 season.\723\
Additionally, the EPA assumes in this analysis that deployment of
variable, non-dispatchable RE resources is limited to 20 percent of 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 deployment pattern projected by the model would not incur
significant grid integration costs.\726\
---------------------------------------------------------------------------

    \723\ Refer to GHG Mitigation Measures TSD for more detail on
modeling methodology.
    \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%20Carrying%20Capacity%20of%20the%20US%20Grid%20to%20Incorporate%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.
    \726\ Refer to the GHG Mitigation Measures TSD for additional
information on constraints related to deployment of non-dispatchable
RE.
---------------------------------------------------------------------------

    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.

                               Table 10--Building Block 3 Generation Levels (MWh).
----------------------------------------------------------------------------------------------------------------
                                                            Eastern             Western              Texas
                        Year                            interconnection     interconnection     interconnection
----------------------------------------------------------------------------------------------------------------
2022................................................         166,253,134          56,663,541          18,963,672
2023................................................         181,542,775          60,956,363          28,177,431
2024................................................         218,243,050          75,244,721          39,382,162
2025................................................         254,943,325          89,533,078          50,586,893
2026................................................         291,643,600         103,821,436          61,791,623
2027................................................         328,343,875         118,109,793          72,996,354
2028................................................         365,044,150         132,398,151          84,201,085
2029................................................         401,744,425         146,686,508          95,405,816
2030................................................         438,444,700         160,974,866         106,610,547
----------------------------------------------------------------------------------------------------------------

    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
cost-reasonableness 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, 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 utility-scale, 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-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, non-dispatchable 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 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.
---------------------------------------------------------------------------

    \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.
---------------------------------------------------------------------------

    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 generators, needs the
proper market signals to trade energy generation for ancillary service
provision.
    The transmission network can connect distant high-quality 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 used
to deliver REwithout 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.
    Increasing regional coordination between balancing areas will
increase operational flexibility. The Energy Imbalance Market (EIM)
recently implemented by the California ISO and Pacificorp is a good
example of the increased coordination that will be helpful in ensuring
that resources across the West are being utilized in an efficient way.
    Significant wind and solar supply chains have developed in the past
decade to serve the fast-growing US RE market. For wind, domestic
production capability would likely have to increase to accommodate
projected builds under the CPP in the 2022-2030 time period; however,
the global supply chain has expanded significantly to serve multiple
markets and can augment production from the domestic supply chain, if
necessary. At the start of 2014, the U.S. domestic supply chain could
produce 10,000 blades (6.2 gigawatts) and 4300 towers (8 gigawatts)
annually. It is not anticipated that expanded domestic manufacturing
will be constrained by raw materials availability or manufacturing
capability. For solar technologies, the global supply chain has a
capacity that has significantly expanded over the past few years from
1.4 gigawatts per year in 2004 to 22.5 gigawatts per year in 2011.
Current capacity exceeds these levels and is expected to grow. For PV
systems, raw materials like tellurium and indium are at highest risk of
supply shortage, but these materials are not used in the PV
technologies currently being deployed at large-scale.
8. Cost of CO2 Emission Reductions From RE Generation
    The EPA believes that RE generation at the levels represented in
building block 3 can be achieved at reasonable costs. In the EPA's
modeling of the building block 3 generation level, the projected cost
of achieving CO2 reductions through this expansion of RE
generation is $37 per ton on average from 2022 through 2030.\728\ There
are a number of reasons why the EPA believes that the cost of
CO2 emission reductions from RE generation will be lower
than this analysis suggests. First, modeling constraints that restrict
variable, non-dispatchable RE technologies to 30 percent of net energy
for load at each of the 64 U.S. IPM regions is a conservative limit
intended to eliminate significant grid integration costs at increased
levels of RE penetration. In fact, many regions have already
demonstrated levels of RE penetration that exceed the constraints, and
in practice intermittency can be managed across larger regions than the
64. Consequently, the extent to which these regions could, in practice,
achieve higher levels of RE deployment without facing substantial grid
integration costs would lead to a lower-cost RE outcome than is
estimated by this analysis. Second, there are multiple RE technologies
not quantified under building block 3 that affected EGUs may use to
demonstrate compliance (distributed generation technologies, offshore
wind, etc.). Based on preliminary analysis from DOE and NREL, cost-
effective opportunities for distributed generation alone could satisfy
one-third to over one-half of the stringency associated with building
block 3.\729\ Third, as discussed in section V and VI of the preamble,
the BSER reflects the degree of emission limitation achieved through
the application of the building blocks in the

least stringent region. By definition, in the other two regions the
BSER is less stringent than the simple combination of the three
building blocks, rendering a portion of the emission reduction
potential quantified by the building blocks unnecessary to achieving
the interim and final CO2 emission performance rates. For
example, the EPA has calculated that in excess of 160,000,000 megawatt-
hours of building block 3 potential is not required to achieve the
final CO2 emission performance rates in 2030--and would be
accessible to affected EGUs for compliance.\730\ Therefore, it is
reasonable to expect that it would cost less to achieve the component
of building block 3 potential that is reflected in the calculation of
the final CO2 emission performance rates, as compared to the
results of this analysis which assumed achievement of the entire
quantified building block 3 potential. The EPA believes that these
factors provide significant opportunities for achievement of the
building block 3 generation levels at lower costs than estimated in
this analysis.
---------------------------------------------------------------------------

    \728\ Refer to the GHG Mitigation Measures TSD for further
analysis and IPM run results.
    \729\ See Section VIII.K. for a description of qualifying RE
technologies for compliance.
    \730\ For additional discussion on how this concept impacts
building block 3 generation levels, refer to the GHG Mitigation
Measures TSD and the CO2 Emission Performance Rate and
Goal Computation TSD for Final CPP.
---------------------------------------------------------------------------

VI. Subcategory-Specific CO2 Emission Performance Rates

A. Overview

    In this section, the EPA sets out subcategory-specific
CO2 emission performance rates to guide states in
development of their state plans. The emission performance rates
reflect the emission rates for two generating subcategories affected by
the rule (fossil steam generation and gas-fired combustion
turbines).\731\ These final emission performance rates reflect the
EPA's quantification of the BSER based on the three building blocks
described in section V above. This procedure follows a similar logic to
BSER quantification at proposal, but it keeps the emission performance
rates separate for fossil steam and NGCC subcategories instead of
immediately blending them together into a single value for all affected
EGUs. Commenters noted that the proposed rule established guidelines
that were based on the aggregation of units, and their reduction
potential, in a state rather than providing technology-specific
guidelines. While many commenters appreciated the flexibility this
state-focused structure provided, some noted two concerns with this
approach: (1) It would potentially create different incentives for the
same generating technology class depending on the state in which that
generator was located, and (2) it deviated from the EPA's previous
interpretation of the 111(d) regulatory guidelines by not providing
technology-specific standards of performance. In response to these
comments and our further consideration, the final rule establishes
subcategory-specific emission performance rates that are identical
across units within a subcategory regardless of where a unit is located
within the contiguous U.S. These subcategory-specific emission
performance rates are then translated into state-specific goals which,
as in the proposal, reflect the particular energy mix present in each
state. That translation is presented in section VII.
---------------------------------------------------------------------------

    \731\ The only natural gas fired EGUs currently considered
affected units under the 111(d) applicability criteria are NGCC
units capable of supplying more than 25 MW of electrical output to
the grid. The data and rates for these units represent all emissions
and MWh output associated with both the combustion turbines as well
as all associated heat recovery steam generating units. The
remainder of the section will use the term ``NGCC'' to collectively
refer to these natural gas fired EGUs.
---------------------------------------------------------------------------

    These performance rates reflect the average emission rate
requirement for each subcategory. Similar to the proposal, they are
presented as adjusted average emission rates that reflect other
generation components of BSER (e.g., renewable) in addition to the
fossil component. These performance rates must be achieved by 2030 and
sustained thereafter. The interim performance rates apply over a 2022-
2029 interim period and would be achieved on average through reasonable
implementation of the best system of emission reduction (based on all
three building blocks) described above. In other words, the interim
performance rates are consistent with a reasonable deployment schedule
of BSER technologies as they scale up to their full BSER potential by
2030. The performance rates are meant to reflect emission performance
required across all affected EGUs when averaged together and inclusive
of lower-emitting BSER components.
    The performance rates are expressed in the form of adjusted \732\
output-weighted-average CO2 emission rates for affected
EGUs. However, states are authorized to use a converted statewide rate-
based or mass-based goal as discussed in the next section. The EPA has
determined that the statewide rate-based and mass-based CO2
goals are expressions of the emission performance rates equivalent to
application of the emission performance rates to affected EGUs within a
state.
---------------------------------------------------------------------------

    \732\ As described below, the emission performance rates include
adjustments to incorporate the potential effects of emission
reduction measures that address power sector CO2
emissions primarily by reducing the amount of electricity produced
at a state's affected EGUs (associated with, for example, increasing
the amount of new low- or zero-carbon generation rather than by
reducing their CO2 emission rates per unit of energy
output produced).
---------------------------------------------------------------------------

    The EPA is finalizing the performance rates in a manner consistent
with the proposal, with appropriate adjustments based on comments.
Stakeholders had the opportunity to demonstrate during the comment
period that application of one or more of the building blocks would not
be expected to produce the level of emission reduction quantified by
the EPA because implementation of the building block at the levels
envisioned by the EPA was technically infeasible, or because the costs
of doing so were significantly higher than projected by the EPA. The
EPA has considered all of this input in setting final performance
rates.
    The remainder of this section addresses two sets of topics. First,
we discuss several issues related to the form of the performance rates.
Second, we describe the performance rates, computation procedure, and
adjustments made between proposal and final based on stakeholder
feedback in the comment period.
    Some of the topics addressed in this section are addressed in
greater detail in supplemental documents available in the docket for
this rulemaking, including the CO2 Emission Performance Rate
and Goal Computation TSD for CPP Final Rule and the Greenhouse Gas
Mitigation Measures TSD. Specific topics addressed in the various TSDs
are noted throughout the discussion below.

B. Emission Performance Rate Requirements

    The EPA has developed a single performance rate requirement for
existing fossil steam units in the contiguous U.S., and a single rate
for existing gas turbines in the contiguous U.S., reflecting
application of the BSER, based on all three building blocks described
earlier, to pertinent data. The rates are intended to represent
CO2 emission rates achievable by 2030 after a 2022-2029
interim period on an output-weighted-average basis by all affected
EGUs, with certain computation adjustments described below to reflect
the potential to achieve mass emission reductions by avoiding fossil
fuel-fired generation.
1. Final Emission Performance Rate Requirements
    The emission performance rates are set forth in Table 11 below,
followed by

a description of the computation methodology.

                  Table 11--Emission Performance Rates
  [Adjusted output-weighted-average pounds of CO2 per net MWh from all
                    affected fossil fuel-fired EGUs]
------------------------------------------------------------------------
                                                     Interim     Final
                    Subcategory                        rate       rate
------------------------------------------------------------------------
Fossil Fuel-Fired Electric Steam Generating Units.      1,534      1,305
Stationary Combustion Turbines....................        832        771
------------------------------------------------------------------------

    The emission performance rates are expressed as adjusted output-
weighted-average emission rates for each subcategory. As discussed
later in this section, the emission rate computation includes an
adjustment designed to reflect mass emission reductions associated with
lower-emitting BSER components. The adjustment is made by estimating
the annual net generation associated with an achievable amount of
qualifying incremental lower-carbon and zero-carbon generation and
substituting those MWhs for the baseline electricity generation and
CO2 emissions from the higher-emitting affected EGUs. Under
the final rule approach, regionally identified building block 3
potential generation replaces fossil steam and NGCC generation on a
pro-rata basis corresponding to the baseline mix of fossil generation
in each region.
2. Interim Emission Performance Rates
    Some commenters suggested that the interim period starting in 2020
provided too little time for implementation of measures required to
demonstrate compliance during the interim period. As discussed in
section V.A.3.g of this preamble, the EPA has determined that an
interim period beginning in 2022 provides sufficient time for states to
undertake necessary planning exercises and for the implementation of
measures towards achieving the performance rates. The EPA determined
the interim rates in a manner similar to proposal, with an adaptation
to address the revised timing of the interim compliance period
(beginning in 2022 rather than in 2020 as proposed). They reflect the
averaging of estimated emission performance rates for each year in the
interim period (i.e., 2022-2029).
    The interim performance rates are less stringent than the final
2030 emission performance rates because the amount of emission
reduction potential identified for the BSER increases over time, as
explained in section V.

C. Form of the Emission Performance Rates

1. Rate-Based Guidelines
    The interim and final emission performance rates for fossil steam
and NGCC units are presented in the form of adjusted output-weighted-
average CO2 emission rates that the affected fossil fuel-
fired units could achieve, through application of the measures
comprising the BSER (or alternative control methods). Several aspects
of this form of emission rate are worth noting at the outset: The use
of emission rates expressed in terms of net rather than gross energy
output; the use of output-weighted-average emission rates for all
affected EGUs; the use of adjustments to accommodate incremental NGCC
generation and RE measures that reduce CO2 emissions by
reducing the quantity of fossil fuel-fired generation and associated
emissions; and the adjustability of the goals based on the severability
of the underlying building blocks.
    a. Rationale for rate-based guidelines.
    First, the EPA sets an emission rate requirement for each
subcategory by identifying the technology-specific reductions available
under the building blocks. We then give each state the choice to apply
the emission performance rates directly to the affected EGUs within the
state or provides the opportunity to use the statewide rate-based goal
or the equivalent mass-based form translated from the emission
performance rates for state plan purposes. The emission performance
rates reflect the BSER, and the statewide rate-based goal and statewide
mass-based goal are alternative metrics for realizing the emission
performance rates at the aggregate affected fleet level for a state.
    Stakeholders have expressed support for having the flexibility to
choose from among the multiple options for crafting an implementation
plan to realize the BSER. The EPA is providing emission performance
rate-based guidelines that apply uniformly to technology subcategories
nationwide, and the EPA is providing corresponding state emission rate
goals and state mass goals to further enhance compliance flexibility
for each state. This approach allows each state to adopt a plan that it
considers optimal and is consistent with the state flexibility
principle that is central to the EPA's development of this program.
    b. Net vs. gross MWh.
    The second aspect noted above concerns the expression of the goals
in terms of net energy output \733\--that is, energy output
encompassing net MWh of generation measured at the point of delivery to
the transmission grid rather than gross MWh of generation measured at
the EGU's generator. The difference between net and gross generation is
the electricity used at a plant to operate auxiliary equipment such as
fans, pumps, motors, and pollution control devices. Because
improvements in the efficiency of these devices represent opportunities
to reduce carbon intensity at existing affected EGUs that would not be
captured in measurements of emissions per gross MWh, goals are
expressed in terms of net generation. As noted by commenters, EGUs have
familiarity and in some places already have in place equipment
necessary to collect and report hourly net generation.\734\
---------------------------------------------------------------------------

    \733\ As discussed below in Section VIII on state plans, we are
similarly determining that states choosing a rate-based form of
emission performance level for their plans should establish a
requirement for affected EGUs to report hourly net energy output.
    \734\ Specifically, commenters noted that while net generation
is not reported to the EPA under 40 CFR part 75, affected EGUs are
generally required to report gross and net generation on a monthly
basis to EIA through form 923 submittal.
---------------------------------------------------------------------------

    c. Output-weighted performance rates for all affected EGUs.
    This final rule provides an expression of the BSER as subcategory-
specific emission performance rates rather than the state goals
provided at proposal. Whereas the proposal also estimated the BSER
impact on fossil steam and NGCC emissions and generation, it went one
step further by averaging these two technology rates into a single rate
for each state. Under this final rule, the EPA is identifying the
fossil steam rate and the NGCC rate separately instead of only
presenting them in a blended fashion at the state level.\735\ These two
emission performance rates are the expression of the BSER for the final
rule for affected EGUs located within the contiguous U.S.
---------------------------------------------------------------------------

    \735\ However, as discussed in the next section, in order to
provide maximum flexibility to states, the EPA averages these two
emission rates together for each state using their adjusted 2012
baseline generation share to arrive at a single statewide emission
performance goal. The state has the option to comply with this
statewide goal through a compliance pathway of its choice. This
compliance pathway may or may not involve requiring its affected
units to meet the emission performance rates.
---------------------------------------------------------------------------

    The modification from a blended emission rate in the proposed rule
to a subcategory-specific emission performance rate for affected EGU
categories in the final rule was made in response to comments that
technology

subcategory-specific emission rates were more analogous to prior 111(d)
efforts and more consistent with the statute. The EPA received
significant comments suggesting a technology subcategory-specific rate
is consistent with past section 111(d) regulations. However, many
commenters also supported the flexibility provided to states through a
state goal metric provided at proposal. Therefore, the EPA does provide
alternative statewide rate-based and mass-based goals in the next
section.
    The EPA's main consideration has been to ensure that the expression
of the BSER reflects opportunities to manage CO2 emissions
by shifting generation among different types of affected EGUs. Both the
performance rates in this final rule and the state goals at proposal
rely on the adjusted emission rate metric to reflect that potential
shifting. Specifically, because CO2 emission rates differ
widely across the fleet of affected EGUs, and because transmission
interconnections typically provide system operators with choices as to
which EGU should be called upon to produce the next MWh of generation
needed to meet demand, opportunities exist to manage utilization of
high carbon-intensity EGUs based on the availability of less carbon-
intensive generating capacity. For states and generators, this means
that CO2 emission reductions can be achieved by shifting
generation from EGUs with higher CO2 emission rates, such as
coal-fired EGUs, to EGUs with lower CO2 emission rates, such
as NGCC units. Our analysis indicates that shifting generation among
EGUs offers opportunities to achieve large amounts of CO2
emission reductions at reasonable costs. The realization of these
opportunities can be reflected in an emission rate established in the
form of an output-weighted-average emission rate where the weighting
reflects the varying levels of replacement generation technologies.
    d. Severability of building blocks.
    Section V above discusses the severability of the three building
blocks upon which the CO2 emission performance rates are
based. Because the building blocks can be implemented independently of
one another and the emission performance rates reflect the sum of the
emission reductions from all of the building blocks, if any of the
building blocks is found to be an invalid basis for the ``best system
of emission reduction . . . adequately demonstrated,'' the rates would
be adjusted to reflect the emissions reductions from the remaining
building blocks. The sole exception, as described above, is the
application of building block 1 in isolation, which would not be
implemented independently. The performance rates and statewide goals
that would result from any combination of the building blocks could be
computed using the formulas and data included in the CO2
Emission Performance Rate and Goal Computation TSD for CPP Final Rule
and its appendices using the methodology described below and elaborated
on in that TSD.

D. Emission Performance Rate-Setting Equation and Computation Procedure

    The methodology used to compute the performance rates is summarized
on a step-by-step basis below in section 3. The methodology is
described in more detail in the CO2 Emission Performance
Rate and Goal Computation TSD for CPP Final Rule, which includes a
numerical example illustrating the full procedure. The quantification
of the building blocks used in the computation procedure is discussed
in Section V above and in the Greenhouse Gas Mitigation Measures TSD.
1. Inventory of Likely Affected EGUs
    In order to calculate the subcategory-specific emission performance
rates reflecting the BSER, the EPA first needed to develop a baseline
inventory of likely affected EGUs in order to estimate the impact of
the BSER. The EPA developed an inventory of likely affected units that
were operating in 2012 or that began construction prior to January 8,
2014 and that appeared to meet the final rule's applicability
criteria.\736\ This inventory does not constitute a final applicability
determination, but best reflects the EPA's estimate of units subject to
the 111(d) applicability criteria as laid out in Section IV. The EPA
identified a list of likely affected units at proposal comprised of
approximately 3,000 EGUs. The agency took comment on this list and has
made a number of updates to the inventory in response to those comments
and in regards to applicability criteria changes resulting from
comments. However, the inventory does not reflect a final applicability
determination, and where a unit's status was unclear, the EPA generally
treated the unit's status in a manner consistent with the proposal and
publically available reported data.\737\
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    \736\ The EPA's responsibility is to determine the BSER for all
affected EGUs. Some of these under construction units may not enter
operation until 2015 or later, but they are likely affected units
and therefore appropriate to reflect in the baseline and
corresponding subcategory-specific emission performance rates and
state goals.
    \737\ The EPA notes that in some cases, it may not yet be
possible to determine the status of an EGU as affected or unaffected
without additional data. There are potentially some units excluded
or included in the baseline that will ultimately have a different
status following an applicability determination. However, these
cases are limited, and the effect of any collective changes to the
affected fleet inventory will not yield a bias in the BSER
computation at the regional level.
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    Since the final rule's applicability includes under construction
units, the EPA also identified units that had not yet commenced
operation by the 2012 baseline period, but that commenced construction
before January 8, 2014. The EPA received significant comment on the
proposal's sole use of the National Electric Energy Data System (NEEDS)
to identify these under construction units. Commenters suggested that
the EPA also utilize EIA and 2012 proposed unit-level files to help
better identify under construction units. In some cases, NEEDS did not
reflect units that had commenced construction. Therefore, the EPA
updated its approach to identifying units that had commenced
construction prior to January 8, 2014, but that had not commenced
operation in 2012. In the final rule, the EPA uses EIA data, comments,
as well as NEEDS data to identify these under construction
units.738 739 740
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    \738\ The NEEDS database was also updated to reflect the latest
data and commenter input on under construction units.
    \739\ For purposes of determining emission performance rates,
the EPA classifies any unit that had begun construction prior to
Jan. 8, 2014, but had not commenced operation by Dec. 31, 2011 as
``under construction''. Many of these ``under construction'' units
have commenced operation at some point during 2012 or prior to
signature of this final rule.
    \740\ ``Commence'' and ``construction'' are defined in 40 CFR
60.2.
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    These units that were operating by 2012 along with those that had
not commenced operation by 2012 but had commenced construction by
January 8, 2014, reflect the EPA baseline inventory of likely affected
EGUs. The CO2 Emission Performance Rate and Goal Computation
TSD for CPP Final Rule explains the prime mover, capacity, and fuel
criteria used to identify the likely affected EGUs.\741\
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    \741\ The baseline inventory relies on historical data and does
not incorporate anticipated future retirements. Most commenters
supported this treatment as they viewed those scheduled retirements
(and corresponding emission reductions) as an alternative compliance
flexibility.
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    The EPA received significant comment that units that came online
during the baseline year (e.g., 2012) should be treated as under
construction rather than operating units in 2012 for purposes of
estimating baseline values, because their 2012 operation may be

misrepresentative of anticipated future-year operation due to partial
year operation in 2012. The EPA has made an adjustment to flag these
units as having commenced operation during 2012 and treat them as under
construction units, consistent with commenters' suggestion; for BSER
computational purposes, generation and emissions for these units are
estimated based on a representative first full year of operation for
that technology class.
2. Data Year
    In the proposed rule, the EPA considered using a historical-year
data set or a projected-year data set as a starting point for applying
the technology assumptions identified under BSER. The EPA proposed
using 2012 data as it was the most recent data year for which complete
data were available when the EPA undertook analysis for the proposed
rule and it reflected actual performance at the state level. The EPA
took comment on alternative data sets. In particular, the EPA issued a
NODA on October 30, 2014 (79 FR 64543) in which we provided 2010 and
2011 historic data for consideration.
    The EPA received a significant number of comments supporting the
use of historical data as the basis from which to quantify performance
rates reflecting BSER. Some commenters supported the 2012 data year as
the best reflection of the power fleet, and some suggested that the EPA
use a different year or a historical average to control for data
anomalies in 2012. Moreover, some commenters pointed out that using
2010, 2011, 2012 data, or an average of the three would not address
their concerns about recent year anomalies in hydro generation due to
high snow pack. Some commenters also suggested the EPA use a baseline
including years prior to 2012, not to increase representativeness of
the power sector, but as a means of recognizing early action.
    In this final rule, the EPA is taking an approach to the baseline
year where we still largely rely on reported 2012 data as the best and
most recent available data representing the power sector from which to
apply the BSER, but also including targeted baseline adjustments to
address commenter concerns with 2012 data.\742\ Below, we explain why--
at the nationwide level--2012 data are preferable, more objective, and
more accurate than a prior year, or an average of years, for informing
the baseline. Then, we explain the adjustments that we are making to
the 2012 data along with our rationale for such adjustments, in
response to comments we received.
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    \742\ The EPA recognizes that more recent emissions and
generation data have become available since 2012, but 2012 data
constituted the most recent year for which full data was available
at the time the EPA began its analysis for proposal.
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    Some commenters supported the EPA's use of 2012 data to inform
performance rates, and the EPA agrees that 2012 data with targeted
adjustments, relative to other historical years, best reflects the
power sector and best informs the performance rates that pertain to the
BSER. The EPA believes that starting with 2012 data is more accurate
and better informs the BSER than an earlier historical year or
historical multi-year average for the following reasons:

    (1) Of the historical data fully available at the time the
proposal analysis began, 2012 was the most recent and best reflects
the power fleet. Approximately 43 GW of new capacity came online in
2010 and 2011. In other words, there was 43 GW of capacity online as
of 2012 that had not been in service at some point during the 2010-
2011 period. Likewise, approximately 17 GW of capacity that were
operable in 2010 and/or 2011 were retired prior to 2012.\743\ Using
state-level, prior year data, either on its own, or as part of a
multi-year baseline, is not as representative of the current power
fleet as the 2012 data, which better reflects significant changes in
power sector infrastructure.
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    \743\ EIA Form 860, 2012.
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    (2) A three-year baseline would not address some of the
substantive concerns raised by commenters. Many commenters pointed
out that using a three-year baseline would not address their
critical concern about variation in the hydrological cycle due to
snow pack (particularly in the Northwest), because the snow pack was
significantly above average in both 2011 and 2012. The EPA agrees
with commenters that we can better address their baseline data
concerns regarding an average hydro year by identifying those states
with a significant share of hydro generation and variation in that
hydro generation, and making targeted adjustments to those states'
affected fossil generation levels in order to reflect a more typical
snow-pack year. This procedure is described in more detail below and
in theTSDs.
    (3) In addition to being, in the EPA's view, a less
representative baseline of the existing power fleet, a multi-year
baseline would also likely entail complexity when determining how to
average together yearly fleet data while appropriately accounting
for fleet changes occurring during those years. The 2012 baseline
starting point maximizes the EPA's reliance on latest reported
operating data and minimizes the need for fleet capacity
adjustments. For instance, because of year-to-year fleet turnover,
the averaging of multiple baseline years would require additional
assumptions in regards to which generation to consider from a fleet
that is changing in a given state or region (or even where units are
switching fuel sources such as a coal-to-gas conversion).
    (4) Due to the region-based approach to quantify building blocks
and the BSER as subcategory-specific emission performance rates,
variations in unit-level data do not significantly impact the
calculation of emission performance rates. For instance, if one
fossil unit is operating less in a given year due to an outage,
another fossil unit in the same region is generally operating more.
Therefore, at the regional level, fossil generation and emissions do
not vary to the same degree that unit-level data varies. Moreover,
the variation at the regional level that does exist in 2012 relative
to previous years is not necessarily unrepresentative variation, but
illustrates trends in the power sector infrastructure that are
desirable to capture for purposes of determining a representative
year from which further improvements in CO2 emissions
performance can be made. Because the EPA is moving from a state
approach at proposal to a regional approach for calculating the
expression of the BSER in this final rule, unit-level operational
variation from year to year becomes even less relevant to the
calculation of regional emission performance rates.
    (5) Some commenters suggested the EPA use an earlier baseline
year as a means of recognizing early action. They noted that an
earlier baseline would reflect a higher-emitting fleet and therefore
when the same level of building block MWhs are applied, they would
result in a higher (i.e., less stringent) state goal. The EPA
disagrees with this view for several reasons. First, the objective
of selecting a baseline to inform BSER is to have one that best
reflects the power sector and consequently the best system of
emission reductions of which the power fleet is capable. Using an
earlier baseline that ``inflates'' the starting point would
undermine this objective, not serve it. Second, the EPA disagrees
with the premise of this comment--that the baseline would change and
building block potentials would stay the same. For instance,
building block 2 functions based on incremental generation potential
(incremental generation = potential generation-baseline generation).
This incremental value would increase if an earlier baseline period
was used that had less existing NGCC generation.
    (6) Some commenters pointed out that the EPA relied on multi-
year historical data in allowance allocation in previous rulemakings
(e.g., CAIR and/or CSAPR allocations). However, that comparison is
not relevant to the quantification of emission reduction potential
under 111(d). In those previous instances, the EPA was considering
typical unit-level behavior for allowance allocation purposes--not
for determining the emission reduction requirements of the program.
Those allowance allocation determinations were independent of and
subsequent to the determination of emission reduction requirements
in those rulemakings.
    (7) The EPA received significant comment that 2012 was not a
representative year for natural gas prices, and thus the EPA should
use another year. The EPA disagrees with this comment, and does not
view it as grounds for a change to the baseline period. While the
EPA does recognize that Henry

Hub natural gas prices were lower in 2012 relative to previous
years, this does not invalidate the suitability of the data year