significant impact on the economic viability of a new coal-fired EGU.
Table 7 shows the LCOE at an 85 percent capacity factor and $11/tonne
T&S costs compared to an LCOE using the amended T&S costs (based on the
amount of CO2 captured) and using an adjusted capacity
factor (based on the variable operating costs). The revised LCOE
numbers account for both the amended approach to calculating T&S costs
and the change in capacity factor.
---------------------------------------------------------------------------

    \73\ The EPA notes that unlike other environmental controls,
there is limited regulatory requirements or incentive to reduce GHG
emissions aside from the NSPS requirements. For example, local or
regional programs could require reductions in criteria pollutant
from all EGUs and/or owners/operators of EGUs can accrue regulatory
benefits in other regulatory programs due to criteria pollutant
reductions (e.g., offsets and emission credits). These programs
minimize the impact of the environmental controls on dispatch
because costs are spread more evenly to the entire EGU fleet.
    \74\ This could create a perverse environmental incentive to
operate existing coal more than it otherwise would. A utility-system
dispatch model would be required to estimate the potential overall
environmental impacts.

Table 7--Predicted Cost and CO2 Emission Levels for a Range of Potential
                       New Generation Technologies
------------------------------------------------------------------------
                                                           Amended LCOE
               Technology                 LCOE * ($/MWh)    ** ($/MWh)
------------------------------------------------------------------------
Subcritical PC (bit)....................            81.2            82.1
Supercritical PC (bit)..................            81.7            81.7
SCPC + ~16% CCS (bit)...................            96.2           105.4
Supercritical PC (low rank).............            85.2            85.2
Ultra-supercritical PC (low rank).......            87.6            87.0

SCPC + ~ 26% CCS (low rank).............           109.0           122.8
------------------------------------------------------------------------
* 85 percent capacity factor and $11/tonne T&S.
** Capacity factor adjusted based on variable operating costs and T&S
  costs adjusted based on amount of captured CO2.

    Assuming a constant 85 percent capacity factor and $11/tonne T&S
costs, the LCOE for a bituminous-fired SCPC with partial CCS is 18
percent higher than a SCPC without CCS. However, when the refined T&S
and capacity factors are accounted for, the relative increase in LCOE
for a bituminous-fired SCPC with partial CCS is 29 percent higher than
SCPC without CCS, a 63 percent increase in the relative LCOE impact of
partial CCS. These costs do not account for any of the potential
benefits of reduced criteria and GHG emissions due to the use of
partial CCS. The EPA solicits comment on if these should be factored
into the analysis, and if so, appropriate metrics to accounting for
these benefits (Comment C-8). Furthermore, the revised LCOE costs are
over 10 percent higher than the nuclear cost metric. Furthermore, even
with only the T&S adjustment, the revised LCOE are five percent higher
than the nuclear metric. The results of this analysis support the EPA's
proposal to revise the 2015 determination that partial CCS is BSER for
coal-fired EGUs. The EPA notes that these costs are for coal-fired EGUs
that are using geologic sequestration (GS) and do not account for any
specific economic incentives (e.g., the federal tax credits for carbon
capture, which are available only for new facilities that commence
construction before January 1, 2024, Internal Revenue Code Sec. Sec.
45Q(a)(3)-(4), (d)--which, in turn, is before the end of the 8-year
period in which the EPA is required to review and, if necessary, revise
the standard of performance that is the subject of this rulemaking, CAA
section 111(b)(1)(B)). If the owner/operator were in a location where
it could sell the byproduct CO2 (e.g., for enhanced oil
recovery or for use in the food industry) variable operating costs
could be reduced relative to an EGU without partial CCS and electric
sales would be expected to increase, offsetting some of the control
costs. For example, as discussed in the 2015 Rule, two coal-fired EGUs
elected to install carbon capture technology and sold the
CO2 to the food industry without any federal funding for the
capture technology (80 FR 64550). This type of utilization of
CO2 has the potential to both develop capture technologies
and increase economic options to reduce emissions. While sale of the
captured CO2 improves the overall economics of a new coal-
fired EGUs, the EPA recognizes that there are places where
opportunities to sell captured CO2 for utilization may not
be presently available. Therefore, consistent with approach adopted in
the 2015 Rule, the EPA is assuming no revenues from the sale of
captured CO2 (80 FR 64572).
(b) Consideration of Capital Cost Increases
    In the 2015 rulemaking, commenters from industry recommended that
the EPA should separately consider the significant capital costs of
partial CCS. In response to these comments, the EPA evaluated the
impact of 2015 GHG standards on the capital costs of new fossil-steam
generation and compared the same to the capital costs of prior EPA
regulations. The EPA determined that the incremental capital costs of
partial CCS were reasonable because they were comparable to the
percentage capital costs increase in prior regulations and because the
utility industry has demonstrated the capacity to successfully absorb
capital costs of this magnitude in the past (80 FR 64559).
Specifically, in the 2015 final rule, the EPA concluded that an
increase of 21 to 22 percent for capital coats was reasonable (80 FR
64560).
    The EPA cited several comparable rulemakings. First, the 1971 NSPS
for coal-fired EGUs increased costs by $19 million (M) for a 600 MW
plant. These costs consisted of $3.6 M for particulate matter (PM)
controls, $14.4 M for SO2 controls, and $1 M for nitrogen
oxide (NOX) controls; the capital cost of air pollution
control devices added 15.8 percent to the $120 M capital cost of a new
EGU. In that case, the baseline cost was primarily for a coal-fired EGU
with limited environmental controls. In addition, a retrospective
Congressional Budget Office (CBO) study of the 1978 EGU NSPS amendments
estimated that those amendments increased the capital costs for a new
EGU by 10 to 20 percent. There, the baseline costs and overall absolute
costs were higher than the 1971 NSPS because they included the cost of
controls required by the 1971 NSPS. Since the 1978 NSPS, additional
environmental controls have further increased the baseline costs to
construct a new coal-fired EGU. These additional costs include, but are
not limited to, NSPS amendments that established selective catalytic
reduction (SCR) as the BSER for NOX controls in place of low
NOX combustion controls and more stringent SO2
and PM standards, rulemakings that require mercury (Hg) controls, and
rulemakings that limit the use of once-through cooling. All of these
additional environmental control requirements increase the baseline
costs of constructing a new coal-fired EGU. Therefore, at the same
percentage increase in capital costs, absolute costs are much higher. A
comparable analysis would require that the additional control costs due
to previous rulemakings be accounted for in the baseline costs when
determining an appropriate percent increase in capital costs. The EPA
notes that even without accounting for the different cost basis, the
absolute increase in capital costs was higher for the 2015 Rule than
previous EGU NSPS rulemakings. It should also be noted that the
previous NSPS rulemakings generally concerned multiple pollutants and
adopted multiple requirements based on multiple control technologies,
which makes it more challenging to compare them with the current
rulemaking, which in turn concerns, as a practical matter, a single air
pollutant--CO2--and a single set of controls.
    Furthermore, the fact that the utility industry was able to absorb
20 percent increases in cost due to pollution control in the past does
not necessarily mean the industry could do so today. For example, when
previous NSPS rulemakings with significant costs for new coal-fired
EGUs were completed, electricity demand was growing and few
alternatives existed for intermediate and base load generation. At that
time, a new coal-fired EGU built by a regulated utility could
anticipate operating at a high capacity factor for several decades.

The utility sector is markedly different today. Currently, many coal-
fired EGUs operate at variable load and it would be more difficult for
an owner/operator of a new coal-fired EGU to recoup the additional
control costs. Based on these assessments, the EPA is proposing that
the increase in capital costs due to partial CCS are not reasonable.
    In addition, in the 2015 Rule, the EPA cited the Portland Cement
Ass'n ruling that upheld a 12 percent increase in capital costs as
reasonable (See 80 FR 64560, citing 486 F.2d at 387-88). As stated
previously, the EPA is proposing in this rule that the increase in
capital costs due to partial CCS are not reasonable. In any event,
Portland Cement Ass'n is not relevant because, as the EPA further noted
in the 2015 Rule, the costs of control equipment (capital and
operating) for the Portland Cement NSPS could be passed on without
substantially affecting competition with construction substitutes such
as steel, asphalt, and aluminum. Id., citing Portland Cement Ass'n v.
Ruckelshaus, 513 F.2d 506, 508 (DC Cir. 1975). However, in the 2015
Rule, the EPA did not account for the loss of sales (i.e., revenue) in
the electricity market. As described previously, at least in
deregulated markets, for coal-fired EGUs, an increase in operating
costs has an impact on dispatch order and thus product (i.e.,
electricity) sales, and therefore, the overall cost of the partial CCS
BSER determination. That is, the ability of EGUs to pass along their
capital costs to consumers depends on their ability to pass along their
operating costs to consumers. However, higher operating costs that
impact the EGU dispatch order cannot be passed on to end users as
easily (and profit margins cannot be narrowed as easily) without
affecting coal-fired generation's competitiveness with alternate forms
of electricity generation. This means that EGUs cannot pass along their
capital costs as easily as other industries.
(c) Other Measures of Reasonable Costs
    The EPA has reviewed the rationale for a dozen GHG permits for EGUs
and other industrial facilities that were permitted between 2011 and
2017. Aside from industrial sources with existing, nearly pure
CO2 process streams (e.g., a natural gas processing
facility) situated near an existing CO2 pipeline (i.e., a
few hundred feet) that could implement CO2 capture at little
or no net cost, none of the GHG permits considered CCS to be a
reasonable cost control technology. Energy efficiency was considered
the appropriate control technology for the majority permit
determinations. The fact that all of the EGU permit determinations
rejected CCS as a reasonable control technology supports the conclusion
that CCS is not an appropriate BSER.
2. Whether CCS Is Adequately Demonstrated
    In the 2015 Rule, the EPA found that partial CCS was ``adequately
demonstrated'' under CAA section 111(a)(1), a requirement that, as
noted above, incorporates the concept of technical feasibility.
However, upon further review, the EPA is proposing to revise its
analysis and determine that CCS is not adequately demonstrated in
certain key respects, as described in this section.
a. Availability of Geologic Sequestration (GS)
    In the 2015 Rule, the EPA noted that, as a practical matter, the
issue of whether all new steam-generating EGUs can implement partial
CCS depends on the geographic scope of suitable GS sites. Therefore, as
part of that rulemaking, the EPA performed a geographic analysis \75\
in which the Agency examined areas of the country with sequestration
potential in deep saline formations, oil and gas reservoirs, unmineable
coal seams, and active, enhanced oil recovery (EOR) operations;
information on existing and probable, planned or under study
CO2 pipelines; and areas within a 100-km (62-mile) area of
locations with sequestration potential. The distance of 100 km was
consistent with the assumptions underlying the NETL cost estimates for
transporting CO2 by pipeline. Based on the geographic
analysis performed, the EPA determined that GS sites were widely
available and that a steam-generating plant with partial CCS, sited
near an area suitable for GS, could serve power demand in a large area,
notwithstanding that the area itself might not contain sequestration
sites. As part of the review for this action, the EPA has re-evaluated
these determinations. In addition, the EPA has reviewed the impact of
water availability with respect to geographic availability of CCS.
---------------------------------------------------------------------------

    \75\ U.S. EPA, Technical Support Document: Geographic
Availability, July 31, 2015, available in the rulemaking docket at
https://www.regulations.gov/document?D=EPA-HQ-OAR-2013-0495-11772.
---------------------------------------------------------------------------

    Since the 2015 Rule, the EPA has updated its analysis on geographic
availability. Using updated information from NETL,\76\ the Agency has
identified the geographic extent of potential GS in deep saline
formations and oil and gas reservoirs. The updated data show relatively
minimal changes in estimated storage resources, with most of the
changes occurring in Wyoming and Midwestern states (Kentucky, Michigan,
Illinois, Indiana and North Dakota) as a result of additional
characterization and assessment studies by the DOE Regional Carbon
Sequestration Partnerships.\77\ In addition, the EPA has updated its
list of counties where active EOR operations are occurring, based on
data reported to the EPA Greenhouse Gas Reporting Program (GHGRP) (See
40 CFR part 98, subpart UU, Injection of Carbon Dioxide, 2011-2017
data).\78\ The GHGRP data show four additional counties where active
EOR operations have occurred since the EPA's analysis in 2015. Finally,
the Agency has updated its information on existing CO2
pipelines based on Department of Transportation data along with the
locations of pipelines that are probable, planned or under study. In
general, these updates do not significantly change the EPA's
understanding of which areas are amenable to GS.
---------------------------------------------------------------------------

    \76\ U.S. DOE NETL, Carbon Storage Atlas, Fifth Edition,
September 2015, available at https://www.netl.doe.gov/research/coal/carbon-storage/atlasv.
    \77\ For deep saline formations, the low-end estimate of storage
resource increased from 2,100 billion metric tons to 2,379 billion
metric tons, and the high-end estimate increased from 20,014 billion
metric tons to 21,633 billion metric tons. For oil and gas
reservoirs, the storage resource was previously estimated at 225
billion metric tons, and is now estimated at a low-end estimate of
186 billion metric tons and a high-end estimate of 232 billion
metric tons.
    \78\ U.S. EPA, Greenhouse Gas Reporting Program, available at
https://www.epa.gov/ghgreporting. Data reported as of August 19,
2018.
---------------------------------------------------------------------------

    The NETL Carbon Storage Atlas (Atlas) used for the EPA's analysis
of geographic availability provides a high-level overview of
prospective resources across the United States. This assessment
represents the fraction of pore volume of porous and permeable
sedimentary rocks available for CO2 storage and accessible
to injected CO2 via drilled and completed wellbores. The
estimates in the Atlas do not take into account economic or regulatory
constraints, only physical constraints (i.e., the accessible parts of
geologic formations via wellbores). The deployment of partial CCS is
site-specific and its application will depend on local market and
geologic conditions. Therefore, the cost of deploying partial CCS will
be highly variable on a geographic basis. While storage capacity
appears large in the Atlas, site-specific technical, regulatory, and
economic considerations will ultimately impact how much of that
resource is economically available. That is, the Atlas shows an
estimate of potential storage areas, but not economically

viable storage areas (i.e., areas where projects make business and
financial sense). Additionally, the various types of geologic
formations assessed in the Atlas have been characterized to varying
degrees. That is, there is more uncertainty in the assessment of
certain types of formations as compared to others. The maturity of oil
and gas exploration and production in certain parts of the United
States makes sequestration potential in these reservoirs relatively
well understood. However, there are still limitations to the
feasibility of GS in all oil and gas reservoirs identified as areas of
potential storage in the Atlas. Additionally, despite showing large
potential, saline storage has not yet been demonstrated to be
available, both from a geographical perspective as well as
economically, at all locations. For example, the major milestone saline
project from Archer Daniels Midland is underway, but only reflects the
feasibility of saline injection and storage at one location in the
United States. This project is still in its early stages and has not
yet proven that GS in saline formations can be done throughout the
United States (at scale) in wide geographic regions with highly diverse
geologic conditions. The project is sized at one million metric tons
per year and may not demonstrate the full application of saline storage
necessary for a large power project.
    Regarding the third type of geologic formation assessed in the
Atlas, unmineable coal seams, the EPA has changed its assumptions since
the 2015 analysis. While the Atlas includes potential availability of
unmineable coal seams, the EPA has excluded this type of formation from
potential GS areas. As part of its 2015 analysis, the EPA expressed its
view unmineable coal seams offered the potential for geologic storage
and explained the technical process by which it thought that
CO2 could be injected underground to enhance methane
recovery (also known as enhanced coalbed methane recovery) while
adsorbing to the coal surface (80 FR 64576). NETL identified states
that it considered had the potential for storage in unmineable coal
seams. Some of these areas, including Iowa and Missouri, have little to
no EOR or saline sequestration potential and generate electricity at
coal-fired EGUs. Several successful small-scale demonstration projects
had been performed to evaluate the potential for GS in unmineable coal
seams, and research to optimize CO2 storage in coals was
ongoing. However, upon further review, the EPA now believes that the
processes and technologies associated with GS at unmineable coal seams
are still being developed and, in the years since the EPA expressed the
understanding and expectations underlying this aspect of its analysis
in the 2015 Rule, there have been no large-scale demonstrations of GS
associated with unmineable coal seams.\79\ In the 2015 rulemaking, the
EPA had found that the largest pilot project, the Allison Unit
CO2-ECBM pilot in New Mexico, stored 270,000 metric tons of
CO2 from 1995-2001 (an average of 45,000 tons per year).\80\
Recent DOE Regional Carbon Sequestration Partnership projects have
injected CO2 volumes ranging from 90 tons to 16,700
tons.\81\ While these projects demonstrated some degree of potential
for GS in unmineable coal seams, most were in the nature of pilot
programs undertaken to evaluate project designs and collect data to
better understand the mechanisms of injection and CO2
storage. Therefore, the project durations and injected amounts were
limited. The limited duration and amounts of the tests may have
affected the outcomes, as some tests began to show decreases in the
effectiveness of CO2 injection over time due to swelling of
the coals. This observation raises doubts regarding the feasibility of
larger-scale GS in unmineable coal seams at this time. For example, in
the Pump Canyon test, the effectiveness of CO2 storage was
believed to be limited due to the small amount of CO2
injected.\82\ The amount of CO2 injected in these tests was
significantly less than projects at deep saline formations or at oil
and gas reservoirs where CO2 was injected in the million-ton
range. The EPA now believes that additional research using larger scale
and longer duration tests in unmineable coal seams is needed to improve
the understanding and modeling of CO2 storage in coals.
Unmineable coal seams have not been shown to be a suitable GS
technology option for purposes of this action; however, such formations
could have potential applicability in the future. Therefore, unmineable
coal seams have been excluded from potential GS areas in the analysis
underlying this proposal. The elimination of unmineable coal seams
reduces the geographic availability of sequestration areas by
approximately 4 percent.\83\
---------------------------------------------------------------------------

    \79\ See, e.g., M. Godec et al., ``CO2-ECBM: A Review
of its Status and Global Potential,'' Energy Procedia 63: 5858-5869
(2014), available at https://doi.org/10.1016/j.egypro.2014.11.619;
IEAGHG, Potential Implications on Gas Production from Shales and
Coals for Geological Storage of CO2, Report Number 2013/10,
September 2013, available at http://www.ieaghg.org/docs/General_Docs/Reports/2013-10.pdf.
    \80\ Id.
    \81\ J. Litynski et al., ``Using CO2 for enhanced
coalbed methane recovery and storage, CBM Review, June 2014,
available at https://www.netl.doe.gov/File%20Library/Research/Carbon-Storage/Project-Portfolio/CBM-June-2014.pdf.
    \82\ M. Godec et al., ``CO2-ECBM: A Review of its
Status and Global Potential,'' Energy Procedia 63: 5858-5869 (2014),
available at https://doi.org/10.1016/j.egypro.2014.11.619; IEAGHG,
Potential Implications on Gas Production from Shales and Coals for
Geological Storage of CO2, Report Number 2013/10 (September 2013),
available at http://www.ieaghg.org/docs/General_Docs/Reports/2013-10.pdf.
    \83\ Based on an analysis of the information provided in U.S.
DOE NETL, Carbon Storage Atlas, Fifth Edition, September 2015,
available at https://www.netl.doe.gov/research/coal/carbon-storage/atlasv and areas within 100 km (62 miles) of these locations. The
geographic area decreased by 411,156 square km (158,748 square
miles).
---------------------------------------------------------------------------

    For these reasons, GS may not be as widely geographically available
as assumed in the 2015 analysis. Further work being conducted by DOE to
devise and develop technologies that can improve wellbore integrity,
increase reservoir storage efficiency, quantitatively assess and
mitigate risks, and confirm permanent storage of CO2 through
reliable, cost-effective, multilevel monitoring programs in storage
complexes in diverse geologic settings would help determine actual
availability of GS in all types of formations. Additionally, work on
the DOE Carbon Storage Assurance Facility Enterprise (CarbonSAFE)
initiative, an effort to develop an integrated CCS storage complex
constructed and permitted for operation in the 2025 timeframe, will
increase understanding of the feasibility of GS across the United
States and further characterize the availability of GS.
b. Water Availability
    Currently available amine-based solvent capture systems require
water for process makeup and cooling. As part of the 2015 rulemaking,
multiple commenters expressed concerns that the EPA's determination
that partial CCS was BSER was inappropriate because of increased water
consumption impacts and geographical (or other) water availability/
scarcity issues limiting or eliminating CCS implementation. The EPA
acknowledged that, similar to other air pollution controls, such as a
wet flue gas desulfurization scrubber, post-combustion amine-based
capture systems result in increased water consumption. However, the EPA
evaluated the issue and found the water use to be manageable (80 FR
64593). The Agency stated that the studies \84\

referenced by commenters that indicated significant increases in water
use from CCS cooling and process operations compared to coal-fired EGUs
without CCS were for cases where full CCS (90 percent or greater
capture) is implemented, and were therefore of limited relevance to its
determination that partial CCS was BSER.
---------------------------------------------------------------------------

    \84\ See comments of UARG at p. 84 (Docket entry: EPA-HQ-OAR-
2013-0495-9666) citing Haibo Zhai, et al., ``Water Use at Pulverized
Coal Power Plants with Post-Combustion Carbon Capture and Storage,''
Environ. Sci. Technol., 45:2479-85 (2011); U.S. DOE NETL, Water
Requirements for Existing and Emerging Thermoelectric Plant
Technologies at 13 DOE/NETL-402/080108, August 2008, April 2009
revision.
---------------------------------------------------------------------------

    In the 2015 Rule, the EPA examined water use predicted from the
updated DOE/NETL studies to determine the magnitude of increased water
usage for a new SCPC EGU implementing partial CCS to meet the final
standard of 1,400 lb CO2/MWh-gross. The EPA in 2015
determined that the results showed that a new SCPC unit that implements
16 percent partial CCS to meet the final standard would see an increase
in water consumption (the difference between the predicted water
withdraw and discharge) of about 6.4 percent compared to an SCPC with
no CCS and the same net power output. Further, the EPA expressed the
view that there would be additional opportunities to minimize the water
usage at such a facility. For example, the SaskPower Boundary Dam Unit
#3 post-combustion capture project captures water from the flue gas and
recycles the water, resulting in decreased withdrawal of fresh water.
In addition, while the Agency did not find IGCC to be the BSER, the
predicted water consumption for the new IGCC unit was nearly 20 percent
less than that predicted for the new SCPC unit without CCS (and almost
25 percent less than the SCPC unit meeting the final standard). The EPA
also predicted that water consumption at a new NGCC unit would be less
than half that for a new SCPC EGU with the same net output.
    In the 2015 Rule, the EPA's water use increase comparison, which
was summarized in Table 13 of the 2015 final rule preamble (80 FR
64592), was evaluated based on a bituminous-fired EGU with a wet
scrubber and a cooling tower. While this is one common configuration
for an EGU boiler and associated air pollution control device, this
does not account for other boiler configurations and other air
pollution control devices. Certain regions of the country with an arid
climate and/or scarce water availability often use boiler and pollution
control devices that minimize water use. While the absolute amount of
water required for CO2 capture equipment is relatively
constant on a gallon per ton of captured CO2 basis across
various boiler types, the percentage increase in water requirements is
not. A more appropriate percentage increase comparison for arid western
markets and other locations in water-scarce environments is a
subbituminous-fired PC unit with spray drying or a fluidized bed unit
and a cooling tower. To estimate the increased water consumption for
low rank coal-fired EGUs, the EPA used the NETL partial capture report
for bituminous coal-fired EGUs to determine the increased water
requirements per amount of CO2 captured. The EPA then
applied the increased water use relationship to the 2011 baseline
report that included model plants burning low rank coal.
    As shown in Table 8, the percent increase in water use for EGUs
burning low rank coals is four times as large as for bituminous-fired
EGUs. The EPA is proposing that this increase in water requirements is
so great that it could be prohibitively expensive for developers to
secure sufficient quantities of water in arid regions of the
country.85 86
---------------------------------------------------------------------------

    \85\ Part of the rationale that the water requirements are too
great is that the water requirements for partial CCS are roughly
double that of the water requirements for a spray dryer used for
SO2 control.
    \86\ In the 2015 final rule, the EPA referenced SaskPower
Boundary Dam's lignite-fired Unit #3 post-combustion capture project
that recovers water from the flue gas and recycles it, resulting in
decreased need for withdrawal of fresh water from the adjacent
reservoir. However, specific data on how much water was captured/
saved was not cited. In retrospect, the EPA now believes that it
should have considered that for new lignite-fired power plants
owners/operators would likely dry the lignite prior to combustion.
Drying lignite both decreases the capital cost of a new boiler
island and increases boiler efficiency. However, it results in less
water in the flue gas, limiting the amount that can be captured/
recycled. The same might be the case for new subbituminous coal-
fired EGUs--they would likely dry the coal prior to combustion so
less water would be available in the flue gas for recovery and
reuse.
    \87\ In the 2015 rulemaking, the raw water consumption for a
SCPC with no CCS (bit) was reported as 4,095 gallons per minute
(gpm) instead of 4,045 gpm. This resulted in a reported increase in
water use of 6.4 percent instead of 7.7 percent.

                  Table 8--Predicted Water Consumption
------------------------------------------------------------------------
                                             Raw water      Increase in
                                            consumption      water use
               Technology                   (gpm/MWnet)   compared to no
                                                \1\        CCS (%) \87\
------------------------------------------------------------------------
SCPC - no CCS (bit).....................             7.4  ..............
SCPC + ~16% CCS (bit)...................             7.9             7.7
SCPC - no CCS (low rank))...............             3.8  ..............
SCPC + ~ 26% CCS (low rank).............             4.9              28
------------------------------------------------------------------------
\1\ MWnet = megawatts-net.
\2\ SCCFB = supercritical circulating fluidized bed.

    In addition to the configurations cited in the NETL report, other
boiler configurations use even less water. For example, Black Hills
Power Corporation's 110-MW Wygen III is a pulverized coal power plant
near Gillette, Wyoming. The plant, which came online in 2010, fires
Powder River Basin coal and has an air pollution control system
comprised of selective catalytic reduction, dry flue gas
desulfurization (FGD), and a fabric filter baghouse. This type of
``dry'' plant was built with minimal water requirements due to dry
cooling and dry lime FGD for acid gas control. As described elsewhere
in the preamble, this type of boiler design is one of the
configurations likely to be considered for future coal-fired EGUs.
However, carbon capture technologies are limited to using conventional
wet cooling technologies. The EPA is unaware of any demonstration,
pilot, or large-scale projects using dry cooling technologies with
carbon capture technologies. Therefore, requiring CCS on a plant of
this design would substantially increase the plant's water-use
requirements.
    All CCS systems that are currently available require substantial
amounts of water to operate. These water requirements would limit the
geographic availability of potential future EGU construction to areas
of the country with sufficient water resources.

To establish water availability, the EPA has, for this proposal,
reviewed annual average rainfall totals as an estimation of water
availability. This approach indicates that the Western U.S. (i.e.,
areas west of a line running from central Texas to North Dakota),
excluding the Pacific Northwest, has lower amounts of water available
for EGUs. In addition, a comparison of areas of the country with lower
rainfall amounts shows considerable overlap with areas of the country
with sequestration sites. This suggests that many sequestration sites
might not have sufficient water resources to operate CO2
capture equipment. Therefore, this, in combination with the EPA's
proposed determination that its earlier understanding of the scope of
geologic sequestration site availability was an overestimation (by some
4 percent), has led the EPA to propose a revision to its 2015 findings
and a new determination that the overall geographic availability of CCS
is too limited to be considered as BSER.
    In the 2015 Rule, EPA also stated that a new IGCC unit required
nearly 20 percent less water than a new bituminous coal-fired SCPC unit
without CCS (and almost 25 percent less than the SCPC unit meeting the
final standard). The DOE/NETL reports indicate that IGCC designs are
available that use less water than comparative PC units for low rank
coals as well. However, in an April 2017 independent engineering report
on the Kemper IGCC Project,\88\ one of the concerns noted was the
underestimation of the amount of water needed for the process water
system. The report noted that the initially planned 5 million gallons
of storage was insufficient, that a new 1.7-million-gallon temporary
tank was to be installed and that additional permanent water storage
tank capacity should be considered. Based on this, the EPA is
soliciting comment on whether IGCC reduces the amount of water use by
coal-fired EGUs (Comment C-9).
---------------------------------------------------------------------------

    \88\ This project received federal assistance under the Energy
Policy Act of 2005 (EPAct05). See 2015 rule, 80 FR at 64526, n.74.
The EPA is not proposing to revise or re-open the interpretation of
EPAct05 that the EPA included in the 2015 rule. Id. at 64541-64542.
Thus, because the EPA is considering information about the Kemper
project in conjunction with other information that is not from
facilities affected by EPAct05, EPAct05 does not preclude the EPA
from considering such Kemper information.
---------------------------------------------------------------------------

c. Review of Technical Feasibility of Carbon Capture Equipment
    In the 2015 Rule, the EPA determined that CO2 capture
technology was technically feasible based on EGUs that had previously
and were currently using post-combustion carbon capture technology
(especially Boundary Dam), commercial vendors that offered carbon
capture technology and other performance guarantees, a review of the
literature, and industry and technology developers' pronouncements of
the feasibility and availability of CCS technologies. Since the 2015
rulemaking, the Petra Nova CCS project, located at NRG's W.A. Parish
power generating station near Houston, Texas, has begun operations, and
is reported to be the world's largest post-combustion carbon capture
system.\89\
---------------------------------------------------------------------------

    \89\ As with the Kemper project discussed above, this project
received federal assistance under EPAct05. See 2015 rule, 80 FR at
64526, n.74. As with the Kemper project, because EPA is considering
information about the Petra Nova project in conjunction with other
information that is not from facilities affected by EPAct05, EPAct05
does not preclude EPA from considering the Petra Nova information.
---------------------------------------------------------------------------

    While the carbon capture technology at the Boundary Dam project is
currently operating, that project experienced multiple issues with the
performance of the capture technology during its first year of
operation (2014-15). During that time, the capture equipment was
operating with lower reliability than designed, and, as a result,
SaskPower renegotiated its CO2 supply contract with Cenovus
to avoid paying penalties for not supplying the agreed amount of
CO2 for the company's EOR projects. These problems included
the amine chemistry and the CO2 compression system. While
the Petra Nova project is currently operating, it has not demonstrated
the integration of the thermal load of the capture technology into the
EGU steam generating unit (i.e., boiler) steam cycle. Rather, the
parasitic electrical and steam load are supplied by a new 75 MW co-
located natural gas-fired CHP facility. The EPA solicits comment on
whether Boundary Dam's first-year operational problems cast doubt on
the technical feasibility of fully integrated CCS (Comment C-10). For
example, would an EGU with a fully integrated steam cycle that draws
steam from the steam turbine to regenerate the amine be able to operate
during periods when the carbon capture system is not operating?
    The EPA notes that while both these projects are currently
operating, both received significant government support to mitigate the
financial risks associated with the CCS technology. Because no
independent commercial CCS projects are in operation, the EPA solicits
comment on whether the fact that Boundary Dam and Petra Nova were
dependent on government support casts doubt on the technical
feasibility of CCS, e.g., whether it raises concerns as to the extent
to which developers are willing to accept the risks associated with the
operation and long-term reliability of CCS technology (Comment C-11).
    While the EPA did not find that a new IGCC EGU is part of the final
BSER, the Agency did note that IGCC without CCS is a viable alternative
compliance option. However, both the Edwardsport and Kemper IGCC
facilities had significant cost overruns. In fact, the Kemper IGCC's
technology challenges, escalating costs, and project management issues
resulted in the company suspending startup and operations activities
involving the lignite gasification portion of the energy facility,
leaving only the natural gas combined cycle plant in operation.\90\ The
EPA solicits comment on the extent to which the issues with these IGCC
EGUs cast doubt on the economic viability of IGCC as an option for new
generation (Comment C-12).
---------------------------------------------------------------------------

    \90\ URS Corp., IM Monthly Report--Mississippi Public Service
Commission: Kemper IGCC Project, April 2017, available at http://www.psc.state.ms.us/executive/pdfs/2017/Kemper/Monthly%20Report%20April%202017%20Executive%20Summary.pdf.
---------------------------------------------------------------------------

B. Identification of the Revised BSER

    The EPA evaluated six different control technology configurations
as potentially representing the BSER for new and reconstructed coal-
fired EGUs: (1) The use of partial CCS, (2) conversion to (or co-firing
with) natural gas, (3) the use of CHP, (4) the use of a hybrid power
plant, (5) the use of IGCC technology, and (6) efficient generation.
This section discusses each of these alternatives, including the
technical systems that the EPA considered for the BSER, evaluations of
each system, and the reasons for determining that the most efficient
generating technology meets the criteria to qualify as the BSER. The
discussion includes the rationale for selecting the proposed standards
of performance based on those BSER.
    As noted above, the EPA determines the best demonstrated system
based on the following key considerations, among others:
     The system of emission reduction must be technically
feasible.
     The costs of the system must be reasonable. The EPA may
consider the costs on the source level, the industrywide level, and, at
least in the case of the power sector, on the national level in terms
of the overall costs of electricity and the impact on the national
economy over time.

     The EPA must also consider energy impacts, and, as with
costs, may consider them on the level of the source, the region, and on
the nationwide structure of the power sector over time.
     According to the D.C. Circuit caselaw, the EPA must
consider the amount of emissions reductions that the system would
generate, and that CAA section 111 is designed to promote the
development and implementation of technology. Moreover, the EPA has
discretion to weigh these various considerations, may determine that
some merit greater weight than others, and may vary the weighting
depending on the source category.
1. Partial CCS
    As described previously, under the revised analysis set forth in
this proposal, the EPA proposes that the cost of partial CCS is not
reasonable. In addition, when the availability of water and geologic
sequestration sites are considered together, the EPA finds that partial
CCS is not widely geographically available. In addition, the EPA is
soliciting comment on whether there is sufficient information about the
long-term reliability of carbon capture technology and sequestration
capture technology to assess the technical feasibility of CCS (Comment
C-13). Therefore, the EPA proposes to rescind our finding that partial
CCS satisfies the BSER criteria and proposes to find that it does not.
2. Conversion to or Co-Firing With Natural Gas
    While co-firing with natural gas in a utility steam generating unit
a technically feasible option to reduce CO2 emission rates,
it is an inefficient way to generate electricity compared to use of an
NGCC. For cases where the natural gas could be co-fired without any
capital investment (e.g., sufficient natural gas is available at the
site) or impact on the performance or operation of the affected EGU,
the costs of CO2 reduction would be between approximately
$40 to $70 per ton of CO2 avoided (that is, $40/ton for
bituminous coal and $70/ton for subbituminous coal), depending on the
coal rank burned in the boiler. This calculation only accounts for the
relative costs and CO2 emission rates of the fuel and does
not account for potential adverse or positive impacts on the operation
of the boiler. While natural gas prices have fallen significantly over
the past decade, long term price projections forecast that natural gas
will still be significantly more expensive than coal on a $/MMBtu
basis. The higher fuel costs from co-firing would increase both the
LCOE and variable operating costs of the unit. As described earlier,
due to economic dispatch, the unit would be expected to have lower
electricity sales, and therefore generate less revenue and less
marginal and overall profit. Further, if an owner/operator is required
to burn natural gas for compliance purposes, it would likely have to
enter into firm service contracts as opposed to interruptible service
contracts for natural gas, which would increase its costs for natural
gas. Potential positive aspects include a reduction in pre-post
combustion control criteria pollutant and HAP emission rates. Due to
these lower pre-post combustion emission rates, post-combustion control
requirements are reduced and savings could be realized due to both
lower capital and O&M post combustion control costs and/or the cost of
emission allowances under certain pollution control programs. Most
pollutants, and especially NOX, would be reduced in
proportion to the amount of natural gas burned.
    Natural gas reburning (NGR) is a combustion technology in which a
portion of the main fuel heat input is diverted to locations above the
burners, creating a secondary combustion zone called the reburn zone.
In NGR, natural gas is injected to produce a slightly fuel rich reburn
zone. Overfire air (OFA) is added above the reburn zone to complete
burnout. NGR requires 15 to 20 percent of furnace heat input from
natural gas and OFA and has been demonstrated to reduce NOX
emissions by 39 to 67 percent on several existing coal-fired boilers in
applications ranging in size from 33 to 600 MW in the U.S. and up to
800 MW internationally. With NGR at 15 and 20 percent of the heat input
to a coal-fired boiler, the CO2 emission rate would be
reduced by 6 to 10 percent.
    Fuel lean gas reburning (FLGR\TM\), also known as controlled gas
injection, is a process in which natural gas is injected above the main
combustion zone at a lower temperature zone than in NGR. FLGR\TM\ is
different from NGR because the gas is injected in a manner that
optimizes the furnace's stoichiometry on a localized basis. By doing
this, the process avoids creating a fuel-rich zone and maintains
overall fuel-lean conditions. The FLGR\TM\ technology achieves
NOX control using less than 10 percent natural gas heat
input without the requirement for OFA. FLGR\TM\ has a capital cost of
approximately $8/kW \91\ and been demonstrated to reduce NOX
emissions by 33 to 45 percent. At a 10 percent heat input reburn rate,
the CO2 emission rate of a coal-fired EGU would be reduced
by 4 to 5 percent. Based strictly on the difference in fuel prices, co-
firing 10 percent natural gas would only increase the LCOE of a coal-
fired EGU by approximately 2 or 3 percent. However, variable operating
costs would increase between approximately 7 to 9 percent, impacting
dispatch and energy revenue for the EGU.
---------------------------------------------------------------------------

    \91\ Breen, Fuel Lean Gas Reburn (FLGR) Solutions, available at
http://breenes.com/wp-content/uploads/2017/07/FLGR_ljv4singles.pdf.
---------------------------------------------------------------------------

    In addition, while many recently constructed coal-fired power
plants routinely use natural gas or other fuels such as low sulfur fuel
oil for start-up operations and, if needed, to maintain the EGU in
``warm stand-by,'' some areas of the U.S. have natural gas pipeline
infrastructure limitations. These areas either currently lack access to
natural gas transportation infrastructure or face capacity constraints
in their existing natural gas pipelines (i.e., they are not able to
greatly increase purchase volumes with the existing
infrastructure).\92\ For new coal-fired EGUs wishing to locate in these
areas, it could be either infeasible or extremely costly to co-fire
natural gas. The EPA solicits comment on the cost to add natural gas
capability to areas of the county without sufficient infrastructure to
support a new natural gas-fired EGU (Comment C-14).
---------------------------------------------------------------------------

    \92\ Maps of natural gas pipelines and underground storage
facilities are available from EIA, https://www.eia.gov/naturalgas/archive/analysis_publications/ngpipeline/index.html. Information on
pending projects are available from EIA and the Federal Energy
Regulatory Commission (FERC), https://www.eia.gov/naturalgas/pipelines/EIA-NaturalGasPipelineProjects.xlsx and https://www.ferc.gov/industries/gas/indus-act/pipelines/pending-projects.asp
---------------------------------------------------------------------------

    While co-firing natural gas might be a viable option for specific
coal-fired EGUs, the EPA is not proposing natural gas co-firing as part
of the BSER for multiple reason. First, as discussed previously, a
significant benefit of a new coal-fired power plant is the fuel
diversity value that it brings. Requiring the EGU to burn natural gas
defeats the purpose of constructing the EGU in the first place.
Further, not all areas of the country have cost-effective access to
natural gas. Co-firing natural gas is an inefficient use of the
nation's natural gas resources, which is relevant under the ``energy
requirements'' criterion for BSER. Combined cycle EGUs are more
efficient at using natural gas to generate electricity and it would not
be environmentally beneficial for utilities to combust natural gas in
less steam generating units to satisfy a facility specific emissions
standard. Finally, at this time, the EPA does not have

sufficient information to analyze the overall impact of co-firing
natural gas, particularly impacts on dispatch.
3. Combined Heat and Power (CHP)
    CHP, also known as cogeneration, is the simultaneous production of
electricity and/or mechanical energy and useful thermal output from a
single fuel. CHP requires less fuel to produce a given energy output,
and because less fuel is burned to produce each unit of energy output,
CHP reduces air pollution and GHG emissions. CHP has lower emission
rates and can be more economic than separate electric and thermal
generation. However, a critical requirement for a CHP facility is that
it primarily generates thermal output and generates electricity as a
byproduct and must therefore be physically close to a thermal host that
can consistently accept the useful thermal output. For coal-fired EGUs,
it can be particularly difficult to locate a thermal host with
sufficiently large thermal demands such that the useful thermal output
would impact the emissions rate. The refining, chemical manufacturing,
pulp and paper, food processing, and district energy industries tend to
have large thermal demands. However, the thermal demand at these
facilities is generally only sufficient to support a smaller coal-fired
power plant, approximately a maximum of 100 MW. This would limit the
geographically available locations where new coal-fired generation
could be constructed in addition to limiting size. Furthermore, even if
a sufficiently large thermal host were in close proximity, the owner/
operator of the EGU would be required to rely on the continued
operation of the thermal host for the life of the EGU. If the thermal
host were to shut down, the EGU would be unable to comply with the
emissions standard. This reality would likely result in difficulty in
securing funding for the construction of the EGU and could also lead
the thermal host to demand discount pricing for the delivered useful
thermal output. For these reasons, the EPA proposes it is not
practicable to find that CHP is BSER.
4. Hybrid Power Plant
    Hybrid power plants combine two or more forms of energy input into
a single facility with an integrated mix of complementary generation
methods. While there are multiple types of hybrid power plants, the
most relevant type for this proposal is the integration of solar energy
(e.g., concentrating solar thermal) with a fossil fuel-fired EGU. Both
coal-fired and NGCC EGUs have operated using the integration of
concentrating solar thermal energy for use in boiler feed water
heating, preheating makeup water, and/or producing steam for use in the
steam turbine or to power the boiler feed pumps.
    One of the benefits of integrating solar thermal with a fossil
fuel-fired EGU is the lower capital and O&M costs of the solar thermal
technology. This is due to the ability to use equipment (e.g., HRSG,
steam turbine, condenser, etc.) already included at the fossil fuel-
fired EGU. Another advantage is the improved electrical generation
efficiency of the non-emitting generation. For example, solar thermal
often produces steam at relatively low temperatures and pressures, and
the conversion of the thermal energy in the steam to electricity is
relatively low. In a hybrid power plant, the lower quality steam is
heated to higher temperatures and pressures in the boiler (or HSRG)
prior to expansion in the steam turbine, where it produces electricity.
Upgrading the relatively low-grade steam produced by the solar thermal
facility in the boiler improves the relative conversion efficiencies of
the solar thermal to electricity process. The primary incremental costs
of the non-emitting generation in a hybrid power plant is the costs of
the mirrors, additional piping, and a steam turbine that is 10 to 20
percent larger than that in a comparable fossil only EGU to accommodate
the additional steam load during sunny hours. A drawback of integrating
solar thermal is that the larger steam turbine will operate at part
loads and reduced efficiency when no steam is provided from the solar
thermal panels during periods when the sun is not shining (i.e., the
night and cloudy weather). This limits the amount of solar thermal that
can be integrated into the steam cycle at a fossil fuel-fired EGU.
    In the 2018 Annual Energy Outlook \93\ (AEO 2018), the levelized
cost of concentrated solar power (CSP) without transmission costs or
tax credits is $161/MWh. Integrating solar thermal into a fossil fuel
EGU reduces the capital cost and O&M expenses of the CSP portion by 25
and 67 percent compared to a stand-alone CSP EGU respectively.\94\ This
results in an effective LCOE for the integrated CSP of $104/MWh.
Assuming the integrated CSP is sized to provide 10 percent of the
maximum steam turbine output and the relative capacity factors of the
coal-fired boiler and the CSP (those capacity factors are 85 and 25
percent, respectively) the overall annual generation due to the
concentrating solar thermal would be 3 percent of the hybrid EGU
output. This would result in a three percent reduction in the overall
CO2 emissions and a one percent increase in the LCOE,
without accounting for any reduction in the steam turbine efficiency.
However, these costs do not account for potential reductions in the
steam turbine efficiency due to being oversized relative to a non-
hybrid EGU. Without this information, the EPA does not have sufficient
information to evaluate costs and overall impact, and therefore cannot
propose this technology as the BSER.
---------------------------------------------------------------------------

    \93\ EIA, Annual Energy Outlook 2018, February 6, 2018,
available at https://www.eia.gov/outlooks/aeo/.
    \94\ B. Alqahtani and D. Pati[ntilde]o-Echeverri, Duke
University, Nicholas School of the Environment, ``Integrated Solar
Combined Cycle Power Plants: Paving the Way for Thermal Solar,''
Applied Energy 169:927-936 (2016).
---------------------------------------------------------------------------

    In addition, solar thermal facilities require locations with
abundant sunshine and significant land area in order to collect the
thermal energy. Existing concentrated solar power projects in the U.S.
are primarily located in California, Arizona, and Nevada with smaller
projects in Florida, Hawaii, Utah, and Colorado. Not all areas of the
U.S. have both sufficient space and the abundant sunshine to
successfully operate a hybrid power plant. The EPA proposes that due to
the limited geographic availability of concentrated solar thermal
projects, the Agency cannot propose this technology as BSER.
---------------------------------------------------------------------------

    \95\ The Gerstein power plant, unit K, in Germany integrates a
natural gas-fired combustion turbine that discharges the exhaust
directly into the coal-fired boiler. This essentially creates a
combined cycle EGU with a coal-fired heat recovery steam generator.
---------------------------------------------------------------------------

    An alternate, but similar, approach for coal-fired EGUs to
integrate lower-emitting generation would be to use natural gas-fired
combustion turbines, fuel cells, or other combustion technology. These
alternatives can reheat or preheat boiler feed water (minimizing the
steam that is otherwise extracted from the steam turbine), preheat
makeup water and combustion air, produce steam for use in the steam
turbine or to power the boiler feed pumps, or use the exhaust directly
in the boiler to generate steam. In theory, this could lower generation
costs as well the GHG emissions rate for a coal-fired EGU. The EPA is
aware of only one coal-fired EGU currently integrating lower-emitting
combustion technology,\95\ does not have sufficient information to
evaluate costs, and therefore cannot propose this technology as the
BSER.

5. IGCC
    The EPA also considered whether IGCC technology represents the BSER
for new power plants using coal or other solid fossil fuels. While
gasification is available and used in other industrial sectors (e.g.,
petroleum refining) there are relatively few IGCC EGUs. According to
the NETL baseline fossil reports, IGCC units are projected to have a
lower gross-output based emission rates compared to SCPC. However, the
design net emission rates and absolute amount of emissions to the
atmosphere tend to be materially similar so there are limited, if any,
net GHG benefits. Furthermore, the emissions data for the IGCC
facilities in the EPA database does not include the output from the
steam turbine. As a result, it is not possible to verify the gross
emissions rate or estimate the net emissions rate. Therefore, the EPA
does not currently have sufficient information based on actual
operating data to evaluate whether IGCC meets the BSER requirements. In
addition, the NETL baseline fossil fuel reports indicate that IGCC LCOE
costs are 20 percent higher, and the incremental generating costs are 4
percent higher, than a comparable SCPC. However, the two most recent
IGCC EGUs constructed in the U.S. (Edwardsport and Kemper) both
experienced significant cost overruns. In fact, the technical
complexity and costs of the Kemper project were so great that the
gasification project was abandoned and the facility is currently
operating as a natural gas-fired combined cycle facility. Based on
consideration of these factors, the EPA is not proposing IGCC as the
BSER.
6. Energy Efficient Power Generation
    This section describes the technology that the EPA proposes for the
BSER: the most efficient generation technology available, which is the
use supercritical \96\ steam conditions (i.e., a SCPC or supercritical
circulating fluidized bed (CFB) boiler) for large EGUs, and the use of
the best available subcritical steam conditions for small EGUs in
combination with the best operating practices and dry cooling. The use
of higher steam temperatures and pressures (e.g., supercritical steam
conditions) increases the efficiency of converting the thermal energy
in the steam to electrical energy. Best operating practices, include,
but are not limited to, installing and maintaining equipment (e.g.,
economizers, feedwater heaters, etc.) in such a way to maximize overall
efficiency and to operate the steam generating unit to maximize overall
efficiency (e.g., minimize excess air, optimize soot blowing, etc.).
The cooling (i.e., condensing) system also has a significant impact on
efficiency. Once through cooling systems use an open system where
cooling water is extracted directly from a water body and returned to
the same water body at a high temperature. This type of cooling result
in the most efficient operation. However, once through system have
greater environmental impacts and new EGUs use either cooling towers or
dry cooling systems. Cooling towers are closed systems where the water
extracted for cooling is evaporated in the cooling tower. Cooling
towers reduce water impacts compared to once through systems, but still
require substantial amounts of water to operate. Dry cooling systems
use air heat exchangers to provide cooling and minimize water impacts.
However, these systems are also the least efficient.
---------------------------------------------------------------------------

    \96\ Subcritical coal-fired boilers are designed and operated
with a steam cycle below the critical point of water (22 MPa (3,205
psi)). EGUs using supercritical steam conditions operate at
pressures greater than 22 MPa and temperatures greater than 550
[deg]C (1,022 [deg]F). Increasing the steam pressure and temperature
increases the amount of energy within the steam, so that more energy
can be extracted by the steam turbine, which in turn leads to
increased efficiency and lower emissions.
---------------------------------------------------------------------------

a. Reasonable Costs
    Advanced generation technologies enhance operational efficiency
compared to lower efficiency designs. Such technologies are technically
feasible and present little incremental capital cost compared to other
types of technologies that may be considered for new and reconstructed
sources. In addition, due to the lower variable operating costs, more
efficient designs would be expected to dispatch more often and sell
more electricity, thereby offsetting increases in capital costs. It
should be noted that this cost evaluation is not an attempt to
determine the affordability of advanced generation in a business or
economic sense (i.e., the reasonableness of the imposed cost is not
determined by whether there is an economic payback within a predefined
time period). Table 9 lists the capital costs, variable operating
costs, design emission rates, and LCOE for various boiler designs.

                        Table 9--Cost and Emission Rates of Coal-Fired EGUs (2016 $) \97\
----------------------------------------------------------------------------------------------------------------
                                                                                Design
                                                  Total as spent     Variable     emissions rate
                 Technology \98\                  capital ($/kW)     operating     (lb CO2/ MWh-   LCOE ($/MWh)
                                                                   costs ($/MWh)       net)
----------------------------------------------------------------------------------------------------------------
Subcritical PC (bit)............................           2,850            32.3           1,780            81.2
Supercritical PC (bit)..........................           2,940            31.3           1,710            81.7
IGCC (bit)......................................           3,590            32.0           1,730            97.9
Supercritical PC (low rank).....................           3,340            28.0           1,890            85.2
Ultra-supercritical PC (low rank)...............           3,520            27.4           1,840            87.6
----------------------------------------------------------------------------------------------------------------

b. Non-Air Quality Health and Environmental Impacts and Energy
Requirements
---------------------------------------------------------------------------

    \97\ The primary sources of information are the NETL baseline
fossil reports. The EPA converted the dollar year to 2016 values and
estimated low rank subcritical and bituminous ultra-supercritical
based on the ratios in the relevant baseline fossil reports.
Consistent with the NETL partial CCS approach, costs are ``next-of-
a-kind'' rather than first of a kind (80 FR at 64,570/3). First of a
kind costs are higher than ``next-of-a-kind'' costs but are expected
to decrease (as is normally the case) with the completion of
additional projects and DOE/NETL research.
    \98\ The NETL design values are 16.5 MPa (2,400 pounds per
square inch gauge (psig)) () and 566 [deg]C (1,050 [deg]F) for
subcritical EGUs, 24 MPa (3,500 psig) and 593 [deg]C (1,100 [deg]F)
for supercritical EGUs, and 28 MPa (4,000 psig) and 650 [deg]C
(1,200 [deg]F) for ultra-supercritical EGUs.
---------------------------------------------------------------------------

    Highly efficient generation reduces all environmental and energy
impacts compared to less efficient generation. Even when operating at
the same input-based emissions rate, the more efficient a unit is, the
less fuel is required to produce the same level of output, so overall
emissions are reduced for all pollutants. Supercritical steam
conditions, compared to subcritical, reduce all pollutants between
approximately 3 to 5 percent. More

efficient EGUs also have lower auxiliary (i.e., parasitic) loads so
that impacts on energy requirements are also reduced.
c. Extent of Reductions in CO2 Emissions
    In the 2015 Rule, the EPA found that highly efficient generation
did not represent BSER in part because it would not result in
meaningful emission reductions and did not promote the development of
control technology. That conclusion was based on the assumption that
any new coal-fired EGU built in the U.S. would use highly efficient
generation even in the absence of 40 CFR part 60, subpart TTTT.
    Close to 90 percent of the large coal-fired EGUs that have
commenced operation since 2010 in the U.S. use either supercritical
steam conditions or IGCC technology. The remainder of the capacity uses
subcritical steam conditions. However, according to data submitted to
the EPA's Clean Air Markets Division (CAMD), the average 2017 reported
emissions rate of all large coal-fired boilers that commenced operation
since 2010 was 1,938 lb CO2/MWh-gross. This is two percent
higher than the proposed standard. The sole small coal-fired EGU
reporting emissions that commenced operation since 2010 in the U.S.
uses subcritical steam conditions and had a reported annual emissions
rate of 2,200 lb CO2/MWh-gross, nine percent higher than the
proposed standard. Therefore, if a new coal-fired EGU were to be
constructed, the EPA estimates that the proposed BSER standards would
result in reductions in emissions of approximately two percent for
large EGUs and nine percent for small EGUs when compared to the
expected emissions for new EGUs absent an NSPS establishing standards
for GHG emissions. Fuel costs makeup a significant portion of the
variable operating costs of a coal-fired EGUs and owners/operators of
EGUs currently have a financial incentive to maximize efficiency and
minimize CO2 emissions. While achievable, the proposed
emission rates would require owners/operators of a new coal-fired EGU
to both construct a highly efficient EGU and operate and maintain it to
minimize CO2 emissions.
d. Technical Feasibility
    The use of supercritical steam conditions has been demonstrated by
multiple facilities since the 1970s. Between 2013 and 2017, 327
gigawatts (GW) of coal-fired EGUs entered operation globally in 15
countries. The new capacity is split roughly equally between
subcritical, supercritical, and ultra-supercritical steam conditions.
Subcritical units tend to be smaller (i.e., less than 300 MW) and
supercritical units tend to be approximately 500 MW. Ultra-
supercritical EGUs tend to be larger (e.g., 800 MW) and have been built
in China, Germany, South Korea, Netherlands, Malaysia, and Japan.
Materials capable of withstanding ultra-supercritical steam conditions
of 30 MPa (4,350 psi) and 620 [deg]C (1,120 [deg]F) have been
demonstrated internationally at coal-fired boilers.\99\ In addition,
vendors are offering designs capable of withstanding advanced ultra-
supercritical steam conditions of 33 MPa and 670 [deg]C.\100\
Furthermore, using supercritical steam also allows the use of a second
reheat cycle, which further increases efficiency.
---------------------------------------------------------------------------

    \99\ Isogo unit 2 (located in Japan) has a reheat temperature of
620 [deg]C and Avedore 2 (located in Denmark) operates at 30 MPa.
    \100\ https://www.ge.com/power/steam/steamh.
---------------------------------------------------------------------------

    As stated in the 2015 Rule, the smallest supercritical coal-fired
EGU is approximately 200 MW, and steam turbines that operate on
supercritical steam are currently not commercially available for
smaller coal-fired EGUs. Consequently, developers of a small EGU that
wished to use supercritical steam conditions would have to have a steam
turbine designed specifically for that project, substantially
increasing the cost of the project. Therefore, for smaller new and
reconstructed EGUs the maximum economically viable steam pressure and
temperature for which steam turbines are currently available are 21 MPa
(3,000 psi) and 570 [deg]C (1,060 [deg]F). Above this pressure, the
steam would be supercritical. Also, using subcritical steam conditions
limits the steam cycle to use of a single steam reheat cycle.
Therefore, it is not technically feasible for smaller EGUs to use a
second reheat cycle to improve efficiency.
e. Promotion of the Development and Implementation of Technology
    As noted above, the case law makes clear that the EPA is to
consider the effect of its selection of BSER on technological
innovation or development, but that the EPA also has the authority to
weigh this against the other factors. Selecting highly efficient
generation technology as the BSER offers an opportunity to encourage
the development and implementation of improved control technology. This
technology is readily transferrable to other countries, existing EGUs,
and other industries.
    According to EIA, demand in India and Southeast Asia is projected
to drive an increase in coal use over the next two decades. Coal is
often the fuel of choice because it is abundant, inexpensive, secure,
and easy to store. Clean coal technologies are critical to ensuring
that these economies develop in a more environmentally sustainable way.
According to the World Electric Power database, sixty percent of the
new coal-fired capacity in India and Southeast Asia between 2013 and
2017 uses subcritical steam conditions. Although supercritical
technology is already developed, establishing it as the basis for
control requirements in the U.S. for new and reconstructed sources
would help establish it in other nations, resulting in a reduction in
global CO2 emissions. The EPA considers that the proposed
BSER will promote the development and implementation of viable control
technologies.
f. Nationwide, Longer-Term Perspective of Impacts on the Energy Sector
    Designating the most efficient generation technology as the BSER
for new and reconstructed coal-fired utility boilers and IGCC units
will not have significant impacts on nationwide electricity prices.
This is because (1) the additional costs of the use of efficient
generation will, on a nationwide basis, be small because few, if any,
new coal-fired projects are expected, and because at least some of
these can be expected to incorporate efficient generation technology in
any event; and (2) the technology does not add significant costs. For
similar reasons, designation of the most efficient generation
technology as the BSER for reconstructed new coal-fired utility boilers
and IGCC units will not have adverse effects on the structure of the
power sector, will promote fuel diversity, and will not have adverse
effects on the supply of electricity.
    Based on the reasonable cost, technical feasibility, and emission
reductions the EPA proposes that efficient generation in combination
with the best operating practices is the BSER for new coal-fired EGUs.

C. Reconstructed EGUs

    In the 2015 Rule, the EPA explained the background of, and
requirements for, reconstructed EGUs, evaluated various control
technology configurations to determine the BSER for reconstructed coal-
fired boiler and IGCC EGUs, and selected efficiency improvements
achieved through the use of the most efficient generation technology.
The EPA explained that this technology was technically feasible, had
sufficient emission reductions, had reasonable costs, and had some
opportunity for technological

innovation. The EPA is taking the same approach in this rulemaking and
is not proposing to change the BSER technology. However, since the BSER
is the same, the Agency is proposing to use the emissions analysis as
for new EGUs for reconstructed EGUs as well. For each of the
subcategories, that is, the BSER and emissions standard for
reconstructed EGUs is the same as for new EGUs.

D. Coal Refuse Subcategory

    Coal refuse (also called waste coal) is a combustible material
containing a significant amount of coal mixed with rock, shale, slate,
clay and other material that is reclaimed from refuse piles remaining
at the sites of past or abandoned coal mining operations. In the April
2012 proposal, the EPA solicited comment on subcategorizing EGUs that
burn over 75 percent coal refuse on an annual basis (the EGU NSPS for
criteria pollutants contain such a subcategory). Multiple commenters
supported a subcategory, citing numerous environmental benefits of
remediating coal refuse piles. The EPA declined to adopt a subcategory
and explained that the costs faced by coal refuse facilities to install
partial CCS were similar for coal-fired EGUs burning any of the primary
coals (i.e., bituminous, subbituminous, and lignite). Further, the
final applicable requirements and standards in the rule did not
entirely preclude the development of new coal refuse-fired units
without CCS, for example, through the exclusion for industrial CHP
units. Many existing coal refuse-fired units are relatively small and
designed as CHP units. Due to the expense of transporting coal refuse
long distances, the EPA projected that any new coal refuse-fired EGU
would likely be relatively small. Moreover, sites with sufficient
thermal demand exist such that the unit could be designed as an
industrial CHP facility and the requirements of 40 CFR part 60, subpart
TTTT would not apply.
    Under the 2015 partial CCS BSER determination, due to lower
efficiencies and higher uncontrolled emission rates, coal refuse-fired
EGUs would have had to install a slightly higher percentage of partial
CCS, increasing costs roughly in proportion to the percentage increase
in partial CCS. These increase in costs were determined to be
sufficiently similar and a subcategory for coal refuse-fired EGUs was
not necessary. However, as described previously the proposed BSER (and
the corresponding emissions rate) for coal-fired EGUS (including coal
refuse-fired EGUs) is efficient generation and not the use of partial
CCS. Therefore, the cost rationale for not providing a subcategory for
coal refuse-fired EGUs is not necessarily applicable. For multiple
reasons, coal refuse-fired EGUs have higher uncontrolled emission
rates. Coal refuse generally has lower energy density (British thermal
units per pound (Btu/lb) of fuel) due to its high ash content along
with a higher emissions rate on a pound of CO2 per million
British thermal unit (lb CO2/MMBtu) basis. Unlike with
``wet'' coals such as lignite, there are limited options for upgrading
the energy density of coal refuse. This lower energy density leads to
inherently lower efficiency steam generating units. Furthermore,
certain coal refuse piles have high sulfur contents. While remediating
these piles through combustion provides significant multimedia
environmental benefits, combusting these fuels presents challenging
problems. To control sulfur emissions, significant quantities of
limestone are added to the fluidized bed boilers. This not only
decreases efficiency (due to the additional fuel required to calcine
the limestone) but leads to chemically created CO2 (released
when the limestone is calcined to lime) that is released through the
stack. These factors make it difficult for coal refuse-fired EGUs to
achieve the same output-based GHG emission rates of EGUs burning
primary coals. While coal refuse-fired EGUs do not report sufficient
emissions data to the EPA's CAMD to determine their emission rates,
based on normalization of emissions data, a coal refuse-fired EGU would
emit approximately 20 percent more than a comparable bituminous-fired
EGU. Therefore, if there is not a subcategory for coal refuse-fired
EGUs, a developer of a new coal refuse-fired EGU would be required to
install controls beyond the BSER technology basis.
    In the 2015 Rule, the EPA concluded that, due to their relatively
small size, new coal refuse-fired EGUs would likely be designed as CHP
units and would therefore not be subject to 40 CFR part 60, subpart
TTTT. However, the EPA has conducted a more recent analysis of the
makeup of existing coal refuse-fired EGUs, which calls this conclusion
into question. There are 18 existing coal refuse-fired EGUs that range
from 400 to 2,500 MMBtu/h heat input. Only half of these units are CHP
units, and the other half are strictly electricity production
facilities. As stated previously, coal refuse-fired EGUs tend to be
located close to existing coal refuse piles, and there is no assurance
that a suitable thermal host will locate in those areas. Without a
thermal host, the coal refuse-fired unit would not qualify as a CHP
unit, and, instead, would become subject to 40 CFR part 60, subpart
TTTT. Consequently, the EPA is proposing to revise our conclusion that
all new coal refuse-fired EGUs have the ability to avoid applicability
with 40 CFR part 60, subpart TTTT.
    Considering these factors, the EPA proposed that the BSER for coal
refuse-fired EGUs is the use of the best available subcritical steam
conditions in combination with the best operating practices. One
benefit of creating a subcategory for coal refuse-fired EGUs is to not
discourage the development of these projects and to recognize the
multimedia environmental benefits of remediating coal refuse
piles.\101\ The non-air quality environmental benefits include the
remediation of acid seepage and leachate production, low soil
fertility, and reclaiming land for productive use. An additional
consideration is that existing coal refuse piles are slowly combusting
in place and the CO2 will eventually be released to the
atmosphere so net GHG emissions are lower than those measured at the
stack.
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    \101\ The criteria pollutant coal-fired EGU NSPS subcategorizes
coal refuse-fired EGUs in part due to the environmental benefits of
remediating coal refuse piles.
---------------------------------------------------------------------------

E. Determination of the Level of the Standard

    Once the EPA has determined that a particular system or technology
represents BSER, the CAA authorizes the Administrator to establish NSPS
emission standards for new units that reflect the application of that
BSER. In this case, the EPA proposes to determine that BSER is
supercritical steam technology for large EGUs, and subcritical steam
technology for small EGUs and coal refuse-fired EGUs. However, the Act
prohibits the Administrator from expressly requiring sources to use any
particular technology, such as supercritical steam conditions (See CAA
section 111(b)(5), (h)). These provisions also ensure that NSPS
standards do not preclude development of future technologies that may
be even more efficient than the current supercritical systems. For new
and reconstructed coal-fired boiler and IGCC EGUs, the EPA proposes to
find that the best available steam conditions--which qualify as the
BSER--support a standard of 1,900 lb CO2/MWh-gross for large
EGUs (i.e., those with a nameplate heat input greater than 2,000 MMBtu/
h), 2,000 lb CO2/MWh-gross for small EGUs (i.e., those with
a nameplate heat input less

than or equal 2,000 MMBtu/h), and 2,200 lb CO2/MWh-gross for
coal refuse-fired EGUs. Compliance with these standards would be
determined on a 12-operating month rolling average basis. These levels
of the standard are based on the emissions performance that can be
achieved by a large pulverized or CFB coal-fired EGU using
supercritical steam conditions and small and coal refuse-fired EGUs
using subcritical steam conditions.
    To determine what emission rates are currently achieved by existing
coal-fired EGUs, the EPA reviewed annual generation and CO2
emissions data from 2008 through 2017 for all coal-fired EGUs that
submitted continuous emissions monitoring system (CEMS) data to the
EPA's emissions collection and monitoring plan system (ECMPS). The data
was sorted by the lowest maximum annual emissions rate for each unit to
identify long term emission rates on a lb CO2/MWh-gross
basis that have been demonstrated by the existing coal fleet. Since an
NSPS is a never-to-exceed standard, the EPA is proposing that long-term
data are more appropriate than shorter term data to use in determining
an achievable standard. These long-term averages account for
degradation and variable operating conditions, and the EGUs should be
able to maintain their current emission rates, as long as the units are
properly maintained. While annual emission rates indicate a particular
standard is achievable for certain EGUs in the short term, they are not
necessarily representative of emission rates that can be maintained
over an extended period using the most efficient available steam cycle
(i.e., the BSER), the range of fuel types that are burned, or all
cooling systems.
    Specifically, EGUs with the lowest annual emission rates use wet
cooling systems and do not use dry cooling systems. Both recirculating
cooling towers and once-through cooling systems require substantial
amounts of water. In fact, the power sector is one of the largest
freshwater consumers in the U.S.\102\ Water usage by the power sector
strongly depends on the generation technology. For example, combined
cycle units use much less cooling water, because significantly less
heat energy remains that is required to be removed by cooling at the
outlet of the steam turbine of a combined cycle unit compared to a
coal-fired EGU of the same capacity.
---------------------------------------------------------------------------

    \102\ Water use in coal to Power Applications, available at
https://www.netl.doe.gov/research/Coal/energy-systems/gasification/gasifipedia/water-usage.
---------------------------------------------------------------------------

    Dry cooling systems, however, may be necessary for a particular EGU
due to limited water availability or desirable to eliminate the adverse
environmental impacts caused by cooling tower intake structures. A
drawback of dry cooling systems is that the EGU is unable to reach as
low of a condensing temperature as with either a recirculating cooling
tower or a once-through open system and is therefore less efficient.
The EPA is aware of four existing coal-fired EGUs using a dry cooling
system. Three are located in Wyoming, and one is located in Virginia.
While the projects in Wyoming use this type of system in part or in
whole due to the arid climate, the project in Virginia demonstrates
that water use concerns are likely applicable to areas with larger
amounts of rainfall as well. To further determine the likelihood that a
developer of a new coal-fired EGU would want to use a dry cooling
system, the EPA reviewed the cooling system of combined cycle units.
More than 15 percent of operating natural gas-fired combined cycled
capacity in the U.S. uses dry cooling technology.\103\ Based on
analysis of form EIA-860 data, these dry cooling systems are located
throughout the U.S., further indicating that water use concerns are
more widespread than just arid locations with limited rainfall.
Therefore, the EPA is proposing that the NSPS for coal-fired EGUs
should account for the use of dry cooling by setting higher emission
rates that account for the lower efficiency of EGUs using dry cooling.
The EPA is soliciting comment on whether it is appropriate to
subcategorize based on geography and, if so, how that subcategorization
should be done (Comment C-15). One potential approach would be to add a
provision allowing the Administrator to approve alternate emissions
standards for coal-fired EGUs located in areas without access to
sufficient water to operate a cooling tower. Paragraph 60.4330(b) of
the combustion turbine criteria pollutant NSPS (40 CFR part 60, subpart
KKKK) includes a similar provision. That provision allows the
Administrator to approve alternate SO2 standards for a
combustion turbine without access to natural gas and located in an area
where removal of sulfur compounds would cause more environmental harm
than good.
---------------------------------------------------------------------------

    \103\ ``Some U.S. electricity generating plants use dry
cooling,'' Today in Energy, EIA, 29 August 2018, https://www.eia.gov/todayinenergy/detail.php?id=36773.
---------------------------------------------------------------------------

    In order to determine the 12-operating month average emissions rate
that is achievable by application of the BSER, the EPA analyzed data
reported by owners/operators of EGUs to the CAMD database to identify
the best performing (i.e., the best operated and maintained) EGUs. The
EPA normalized the emissions rate data to account for factors that the
Agency has information on and that engineering equations can be used to
account for design efficiency differences between EGUs based on the
factors. The design factors include the steam cycle (i.e., steam
temperature and pressure and the number of reheat cycles), coal type
(which impacts both boiler efficiency and emissions on a lb
CO2/MMBtu basis), cooling type (i.e., dry, recirculating
cooling tower, and open), and average ambient temperature. The EPA
identified the single best EGU based on this normalized emissions rate.
The EPA selected this single best unit to account for site specific
factors about which the Agency does not have specific information.
These factors include, but are not limited to, (1) design factors
influencing efficiency (e.g., number of feedwater heaters, economizer
efficiency, combustion and soot blowing optimization, and an exposed
structure or main building enclosure) and (2) O&M practices (e.g.,
percent excess air, operator training, and prioritizing efficiency
related repairs). The owner/operator of a new EGU would be able to
incorporate the best EGU design parameters and O&M practices. The EPA
then adjusted the emissions data for the best performing EGU by
applying engineering equations for the EGU design factors (steam cycle,
etc.) that impact the theoretical efficiency and the CO2
emissions rate. For example, if a particular unit had no steam reheat
cycle, the EPA estimated the theoretical increase in efficiency for a
similar unit with a single reheat cycle.
    Factors for which owners/operators have more limited influence
include the condenser technology and ambient temperature. For example,
designers can specify ultra-supercritical steam conditions compatible
with state-of-the art metallurgy, multiple stages of feedwater heating,
and double steam reheat cycles to optimize efficiency gains
attributable to increasing the average temperature at which heat is
supplied to the cycle. However, designers have fewer options for
lowering the temperature at which heat is rejected from an affected EGU
because this low-temperature constraint is largely determined by the
available cooling reservoir and local ambient

conditions. Consistent with the 2015 Rule, to account for the impact of
ambient conditions, the EPA conservatively normalized the emission rate
data to 20 [deg]C, with one exception. Since coal refuse-fired EGUs are
located in more temperate regions, the EPA assumed 10 [deg]C for coal
refuse-fired EGUs. In the 2015 rulemaking, the EPA assumed that a new
large EGU would use some type of a wet cooling tower, but specifically
accounted for air cooled condensers (i.e., dry cooling) only for the
small EGU subcategory. However, as described previously, the EPA is
proposing to account for dry cooling for both large and small EGUs.
    The EPA calculated 12-month CO2 emission rates by
dividing the sum of the CO2 emissions by the sum of the
gross electrical energy output over the same period. The best
performing large EGU is Weston 4, which is a supercritical
subbituminous-fired EGU located in Wisconsin, with an emissions rate of
1,780 lb CO2/MWh-gross, measured over 12-operating months
with 99-percent confidence. Based on the normalization of the Weston 4
data using various steam cycles and fuels, as well as dry cooling, the
proposed emissions rate of 1,900 lb CO2/MWh-gross is
achievable for EGUs burning subbituminous, petroleum coke, and lignite
using ultra-supercritical steam conditions and dry cooling. An EGU
burning bituminous coal and dry cooling would be able to comply using
supercritical steam conditions. Based on data submitted to ECMPS, 25
existing EGUs have maintained annual emission rates of 1,900 lb
CO2/MWh-gross over the past 10 years. While this includes a
broad range of EGU types, it does not include any lignite-fired EGUs or
coal-fired EGUs using dry cooling. The lowest emitting lignite-fired
EGU is emitting at approximately 2,000 lb CO2/MWh-gross, and
the lowest emitting coal-fired EGU using dry cooling is emitting at
approximately 2,100 lb CO2/MWh-gross. However, no lignite-
fired or coal-fired EGU using dry cooling is using ultra-supercritical
steam conditions. The EPA has concluded that additional efficiency
technologies could be incorporated into new units to allow a new EGU
burning lignite with dry cooling to comply with the proposed standard.
    The best performing small EGU is Wygen III, which is a subcritical
subbituminous-fired EGU located in Wyoming, with a 12-operating month,
99-percent confidence emissions rate of 2,170 lb CO2/MWh-
gross. Wygen III has relatively low steam temperatures and pressures
\104\ and does not have a reheat cycle. Based on the normalization of
the Wygen III data to the most efficient subcritical conditions and dry
cooling,\105\ the proposed 2,000 lb CO2/MWh-gross emissions
rate is achievable for any solid fuel other than coal refuse using the
best available subcritical steam conditions and dry cooling. Based on
data submitted to ECMPS, five small bituminous-fired EGUs have
maintained a maximum annual emissions rate of 2,000 lb CO2/
MWh-gross over the reviewed 10-year period. These EGUs commenced
operation between 1957 and 1960 and range in size from 1,400 MMBtu/h to
2,000 MMBtu/h. Four of these EGUs use once-through open cooling
systems, and one uses a recirculating cooling tower for steam
condensing. These long-term averages account for degradation and
variable operating conditions and the EGUs should be able to maintain
their current emission rates as long as the units are properly
maintained. Normalization of the Wygen III data for a coal refuse-fired
EGU indicates that a standard of 2,200 lb CO2/MWh-gross is
achievable for a coal refuse-fired EGU.
---------------------------------------------------------------------------

    \104\ 11 MPa steam pressure and 541[deg] C main steam
temperature with no reheat cycle.
    \105\ The best available subcritical steam conditions are 21 MPa
steam pressure and 570[deg] C main and reheat steam temperature.
---------------------------------------------------------------------------

    While the EPA is proposing these standards of performance, the
Agency is also taking comment on a range of potential emission
standards. Specifically, the EPA solicits comment on the following
emission standard ranges:
     For new and reconstructed fossil fuel-fired steam
generating units and IGCC units with a heat input rating that is
greater than 2,000 MMBtu/h, a range of 1,700--1,900 lb CO2/
MWh-gross (Comment C-16);
     For new and reconstructed fossil fuel-fired steam
generating units and IGCC units with a heat input rating of 2,000
MMBtu/h or less, a range of 1,800--2,000 lb CO2/MWh-gross
(Comment C-17);
     For new and reconstructed coal refuse-fired steam
generating units and IGCC units, a range of 2,000-2,200 lb
CO2/MWh-gross (Comment C-18);
    While some domestic coal-fired EGUs have maintained annual emission
rates of 1,700 lb CO2/MWh-gross, no existing coal-fired
units have demonstrated multi-year performance at 1,700 lb
CO2/MWh-gross. Based on normalized Weston 4 data, this
emissions rate could be met by a bituminous-fired EGU using
supercritical steam conditions, a subbituminous-fired EGU using ultra-
supercritical steam conditions, and petroleum coke and lignite-fired
EGUs using the best available ultra-supercritical steam conditions and
a cooling tower.\106\ Three existing coal-fired EGUs have maintained a
maximum annual emissions rate of 1,800 lb CO2/MWh-gross over
the reviewed 10-year period. These units include two supercritical
bituminous-fired EGUs and one supercritical subbituminous-fired EGU.
The EGUs commenced operation between 2008 and 2012 and range in size
from 5,200 MMBtu/h to 7,900 MMBtu/h. All use recirculating cooling
towers for condensing. Based on normalized Weston 4 data, an emission
rate of 1,800 lb CO2/MWh-gross is achievable for bituminous-
fired EGUs using the best available subcritical steam condition; and
subbituminous and dried lignite-fired EGUs using supercritical steam
conditions when paired with a cooling tower.\107\ An EGU burning
undried lignite or petroleum coke could comply using ultra-
supercritical steam conditions and a cooling tower.\108\ However, a key
assumption for achieving an 1,800 lb CO2/MWh-gross emissions
rate is the use of a cooling tower. With dry cooling, an 1,800 lb
CO2/MWh-gross emissions rate is only achievable for a
bituminous-fired EGU using ultra-supercritical steam conditions. Based
on normalized Weston 4 data, a 1,900 lb CO2/MWh-gross
emissions rate is achievable for bituminous-fired EGUs using the best
available subcritical steam condition; and subbituminous, dried
lignite, and petroleum coke-fired EGUs using supercritical steam
conditions when paired with dry cooling. An EGU burning undried lignite
could comply using ultra-supercritical steam conditions and dry
cooling. The EPA proposes that a standard above 1,900 lb
CO2/MWh-gross for large units would not promote the use of
the best available steam conditions.
---------------------------------------------------------------------------

    \106\ Best available ultra-supercritical steam conditions are
650 [deg]C (1,400 [deg]F) and 36 MPa (5,000 psi).
    \107\ 24 MPa steam pressure and 593 [deg]C main and reheat steam
temperature (supercritical steam conditions).
    \108\ 30 MPa steam pressure and 600 [deg]C main and 620 [deg]C
reheat steam temperature (ultra-supercritical steam conditions).
---------------------------------------------------------------------------

    For small EGUs, based on the normalization of the Wygen III
emissions data, an emissions rate of 1,800 lb CO2/MWh-gross
is achievable for bituminous-fired EGUs using the best available
subcritical steam conditions with either a cooling tower or dry
cooling. In order to achieve this emissions rate, however, EGUs burning
other solid fuels would be required to

use additional compliance options such as co-firing natural gas, a
hybrid power plant, integration of non-emitting generation
technologies, or combined heat and power. Based on the normalization of
the Wygen III emissions data, an emissions rate of 1,900 lb
CO2/MWh-gross could be met by any coal-fired EGU using the
best available subcritical steam conditions and a cooling tower.
However, only bituminous and subbituminous-fired EGUs could comply with
this emissions rate using dry cooling. Without additional controls
(e.g., co-firing natural gas) EGUs burning dried lignite, petroleum
coke, and undried lignite are only able to comply with an emissions
rate of 2,000 lb CO2/MWh-gross using dry cooling. The EPA proposes that
a standard above 2,000 lb CO2/MWh-gross for small units
would not appropriately promote the use of the best available
efficiency technologies.
    For all reconstructed EGUs, large and small, the EPA is soliciting
comment on an emission standard consistent with the proposed standard
for new small EGUs (i.e., all reconstructed EGUs would have a standard
of 2,000 lb CO2/MWh-gross) (Comment C-19). While multiple
organizations are evaluating repowering existing subcritical EGUs with
supercritical topping cycles,\109\ the EPA is only aware of a single
EGU where this was actively considered--the Ferrybridge unit in the
United Kingdom. The addition of a supercritical topping cycle is
projected to reduce the heat rate for a large EGU by between 4 to 8
percent. While this would entail a substantial reduction in emissions,
based on existing emissions data some large EGUs would still not be
able to comply with an emissions rate of 1,900 lb CO2/MWh-
gross even with an 8 percent reduction in the emissions rate. For these
units, additional efficiency improvements would also have to be
conducted as part of the reconstruction project. The EPA is soliciting
comment on whether a single standard regardless of size for
reconstructed EGUs is appropriate and whether the existing
reconstruction exemption in the general provisions (i.e., a
reconstructed EGU will be exempt from the requirement to meet the
standard if the Administrator determines the standard is not
technically or economically achievable (40 CFR 60.15(b)(2))) is
sufficient to account for circumstances where a large reconstructed EGU
would not be able to achieve the proposed emissions standard (Comment
C-20).
---------------------------------------------------------------------------

    \109\ A supercritical topping cycle adds a new supercritical
steam turbine that exhausts at the temperature, pressure, and flow
of the existing steam turbine, allowing for reuse of existing
infrastructure.
---------------------------------------------------------------------------

F. Format of the Output-Based Standard

    For all newly constructed units, the proposed standards are
expressed on a gross output emission rate basis consistent with current
monitoring and reporting requirements under 40 CFR part 75.\110\ For a
non-CHP EGU, gross output is the electricity generation measured at the
generator terminals. In addition, the EPA is proposing equivalent net-
output-based standards as a compliance alternative. Net output is the
gross electrical output less the unit's total parasitic (i.e.,
auxiliary) power requirements. A parasitic load for an EGU is a load or
device powered by electricity, steam, hot water, or directly by the
gross output of the EGU that does not contribute electrical,
mechanical, or useful thermal output. In general, parasitic energy
demands include less than 7.5 percent of non-IGCC and non-CCS coal-
fired station power output and approximately 15 percent of non-CCS
IGCC-based coal-fired station power output. Net output is used to
recognize the environmental benefits of: (1) EGU designs and control
equipment that use less auxiliary power; (2) fuels that require less
emissions control equipment; and (3) higher efficiency motors, pumps,
and fans. Thus, allowing compliance through net output would enable
owners/operators of these types of units to pursue projects that reduce
auxiliary loads for compliance purposes.
---------------------------------------------------------------------------

    \110\ 79 FR 1447-48.
---------------------------------------------------------------------------

    Owners/operators of utility boilers have multiple technology
pathways available to comply with the actual emission standard, and the
choice of both control technologies and fuel impact the overall
auxiliary load. In the 2015 Rule, for utility boilers and IGCC units,
the EPA finalized only gross-output-based standards. The rationale for
not including an alternate net-output-based standard was that the
Agency did not have sufficient information to establish an appropriate
net-output-based standard that would not impact the identified BSER for
these types of units. Therefore, the Agency could not identify an
appropriate assumed auxiliary load to establish an equivalent net-
output-based standard.
    Since the proposed BSER determination has changed, the EPA is
proposing CO2 standards for steam generating units in a
format similar to the 40 CFR part 60, subpart TTTT standards for
combustion turbines and current EGU NSPS format for criteria
pollutants. Thus, the proposed standards establish a gross-output-based
standard. This allows owners/operators of new EGU to comply with the
CO2 emissions standard under Part 60 using the same data
currently collected under Part 75.\111\ However, in the 2015 Rule, many
permitting authorities commented that the environmental benefits of
using net-output-based standards can outweigh any additional
complexities for particular units.\112\ The EPA expects permitting
authorities to continue to move toward net-output-based standards and
have concluded that it is appropriate to support the expanded use of
net-output-based standards. Therefore, the EPA is proposing to allow
owners/operators of sources to elect between gross-output-based and
net-output-based standards.
---------------------------------------------------------------------------

    \111\ Additionally, having an NSPS standard that is measured
using the same monitoring equipment as required under the operating
permit minimizes compliance burden. If a combustion turbine were
subject to both a gross and net emission limit, more expensive
higher accuracy monitoring could be required for both measurements.
    \112\ In the 2015 rulemaking, the EPA solicited comment on a
range of options for the form of the final standards. Many
commenters supported gross-output-based standards, maintaining that
a net-output standard penalizes the operation of air pollution
control equipment and EGUs located in hot and/or dry areas of the
country. Commenters further disagreed that a net-output standard
provides any significant incentive to minimize auxiliary loads.
Other commenters, however, maintained that the final rule should
strictly require compliance on a net output-basis. They believed
that this is the only way for the standards to minimize the carbon
footprint of the electricity delivered to consumers. In general,
both sets of commenters believed it appropriate to include net-
output-based standards as an option in the final rule.
---------------------------------------------------------------------------

    The EPA is proposing to use the current 40 CFR part 60, subpart
TTTT procedures for requesting the use of the alternate net-output-
based standard (40 CFR 60.5520(c)). Specifically, the owner/operator
would be required to petition the Administrator in writing to comply
with the alternate applicable net-output-based standard. If the
Administrator grants the petition, this election would be binding and
would be the unit's sole means of demonstrating compliance. Owners/
operators complying with the net-output-based standard must similarly
petition the Administrator to switch back to complying with the gross-
output-based standard. This flexibility is particularly important for
IGCC co-production (i.e., to produce useful by-products and chemicals
along with electricity) facilities. The implementing authority (e.g.,
delegated state permitting authority) will best be able to identify the
appropriate format for facilities of this type.
    The EPA is not proposing to revise or reopening the 2015 Rule's (1)
approach

for determining the emissions rate for CHP units with useful thermal
output that meet the applicability criteria or (2) expression of the
standards in the form of limits on only emissions of CO2,
and not the other constituent gases of the air pollutant GHGs.\113\
---------------------------------------------------------------------------

    \113\ As noted above, in the 2009 Endangerment Finding, EPA
defined the relevant ``air pollution'' as the atmospheric mix of six
long-lived and directly-emitted greenhouse gases: carbon dioxide
(CO2), methane (CH4), nitrous oxide
(N2O), hydrofluorocarbons (HFCs), perfluorocarbons
(PFCs), and sulfur hexafluoride (SF6). 74 FR 66497.
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VI. Rationale for Proposed Emission Standards for Modified Fossil Fuel-
Fired Steam Generating Units

    In CAA section 111(a)(4), a ``modification'' is defined as ``any
physical change in, or change in the method of operation of, a
stationary source which increases the amount of any air pollutant
emitted by such source or which results in the emission of any air
pollutant'' not previously emitted. The EPA, through regulations, has
determined that certain types of changes are exempt from consideration
as a modification.\114\ As discussed in the 2015 rulemaking, the EPA
has historically been notified of only a limited number of NSPS
modifications \115\ involving fossil steam generating units and
therefore predicted that few of these units would trigger the
modification provisions and be subject to the final standards. Given
the limited information that the Agency has about past modifications,
the EPA concluded that it lacked sufficient information to establish
standards of performance for all types of modifications at steam
generating units. Instead, the EPA determined that it was appropriate
to establish standards of performance for larger modifications, such as
major facility upgrades involving, for example, the refurbishing or
replacement of steam turbines and other equipment upgrades that could
result in substantial increases in a unit's hourly CO2
emissions rate. The Agency determined that it had adequate information
regarding (1) the types of modifications that could result in large
increases in hourly CO2 emissions, (2) the types of measures
available to control emissions from sources that undergo such
modifications, and (3) the costs and effectiveness of such control
measures, upon which to establish standards of performance for
modifications with large emissions increases. The EPA concluded that
the BSER for steam generating units that conduct modifications
resulting in an hourly increase in CO2 emissions (mass per
hour) of more than 10 percent (``large'' modifications) was each
affected unit's own best potential performance as determined by that
unit's historical performance. The EPA deferred establishing standards
for modified sources that conduct modifications resulting in an hourly
increase in CO2 emissions (mass per hour) of less than or
equal to 10 percent (``small'' modifications). Therefore, sources that
conduct small modifications did not fall within the definition of ``new
source'' in section 111(a)(2) and continued to be an ``existing
source'' as defined in section 111(a)(6).
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    \114\ 40 CFR 60.2, 60.14(e).
    \115\ NSPS modifications resulting in increases in hourly
emissions of criteria pollutants.
---------------------------------------------------------------------------

    In this proposal, the EPA is soliciting comment on a BSER and
standard of performance for fossil fuel-fired steam generating EGUs
that conduct small modifications. The BSER and associated standard of
performance for which the EPA solicits comment are similar to the BSER
and standard for fossil fuel-fired steam generating EGUs that conduct
large modifications. To explain this solicitation of comment, it is
convenient to refer to the 2015 Rule's discussion of the BSER and
standard for large modifications (80 FR 64597-64600). However, the EPA
is not proposing to revise or reopening the BSER or final standard for
fossil fuel-fired steam generating EGUs that conduct large
modifications (except that, as noted above, the EPA is proposing to
revise the maximum stringency of the standard). The EPA is also not
proposing standards of performance for fossil fuel-fired stationary
combustion turbines that conduct modifications.

A. Identification of the BSER

    The 2015 Rule provided that a steam generating EGU that undertook a
large modification was required to meet a unit-specific CO2
emission limit determined by that unit's best demonstrated historical
performance (i.e., the best annual performance during the years from
2002 to the time of the modification).\116\ The EPA determined that
this standard based on each unit's own best historical performance
could be met through a combination of best operating practices and
equipment upgrades and that these steps could be implemented cost
effectively at the time when a source was undertaking a large
modification. To account for facilities that had already implemented
best practices and equipment upgrades, the final rule also specified
that modified facilities did not have to meet an emission standard more
stringent than the corresponding standard for reconstructed steam
generating units.
---------------------------------------------------------------------------

    \116\ For the 2002 reporting year, EPA introduced new automated
checks in the software that integrated automated quality assurance
(QA) checks on the hourly data. Thus, EPA believes that the data
from 2002 and forward are of higher quality.
---------------------------------------------------------------------------

    In this action, the EPA is soliciting comment on a similar, but not
identical, BSER and standard of performance for fossil fuel-fired steam
generating EGUs that undertake small modifications (Comment C-21). The
EPA believes that there are potentially different circumstances
surrounding a small versus large modification. It seems highly unlikely
that an owner or operator could inadvertently make a physical change
in, or change in the method of operation of, a fossil fuel-fired steam-
generating EGU that would result in an increase of hourly
CO2 emissions of more than 10 percent. As stated in the
final 2015 Rule, such an increase in CO2 emissions would
likely come as a result of a significant capital investment in, or a
significant change in the method of operation of, the affected EGU.
    However, it is conceivable that an owner or operator could make a
small physical change in, or change in the method of operation of, a
fossil fuel-fired steam-generating EGU that results in an increase of
hourly CO2 emissions of less than 10 percent. If there is an
applicable standard of performance for such ``small'' modifications,
then the EGU could trigger the modification provisions and become a
unit subject to federally-enforced CAA section 111(b) emission
standards and, if the source had previously become subject to a CAA
section 111(d) state program, it would no longer be subject to that
program. The EPA solicits comment on the types of changes in operation
or physical changes to a unit that could result in small increases in
hourly CO2 emissions (Comment C-22).
    In this action, the Agency is seeking comment on the need for a
standard for a small modification and, if needed, on the BSER and
appropriate standard of performance (Comment C-23). As with the 2015
Rule's BSER for fossil fuel-fired EGUs conducting large modifications,
the EPA solicits comment on identifying the BSER for such units
conducting small modifications as also heat rate or efficiency
improvements.
1. Reasonable Costs
    Any efficiency improvement made by EGUs for the purpose of reducing
CO2 emissions will also reduce the amount of fuel that EGUs
consume to produce the same electricity output. The cost attributable
to CO2 emission reductions, therefore, is the net cost of
achieving

heat rate improvements after any savings from reduced fuel expenses.
The EPA estimates that, on average, the savings in fuel cost associated
with heat rate improvements would be sufficient to cover much of the
associated costs, and thus that the net costs of heat rate improvements
associated with reducing CO2 emissions from affected EGUs
are relatively low.
    The EPA recognizes that our cost analysis just described will
characterize the costs for some EGUs more accurately than others
because of differences in EGUs' individual circumstances. The EPA
further recognize that reduced generation from coal-fired EGUs will
tend to reduce the fuel savings associated with heat rate improvements,
thereby raising the effective cost of achieving the CO2
emission reductions from the heat rate improvements. Nevertheless, the
EPA still expect that most of the investment required to capture the
technical potential for CO2 emission reductions from heat
rate improvements would be offset by fuel savings, and that the net
costs of implementing heat rate improvements as an approach to reducing
CO2 emissions from modified fossil fuel-fired EGUs are
reasonable.
2. Reductions in CO2 Emissions
    This approach would achieve reasonable reductions in CO2
emissions from the affected modified units as those units will be
required to meet an emission standard that is consistent with more
efficient operation. In light of the limited opportunities for emission
reductions from retrofits, these reductions are adequate.
3. Technical Feasibility
    A standard that is based on a site-specific, previously achieved
emissions rate is technically feasible because there are a large number
of available technologies and equipment upgrades, as well as best
operating and maintenance practices, that EGU owners or operators may
use to improve an EGU's efficiency.
4. Promotion of the Development and Implementation of Technology
    As noted previously, the case law makes clear that the EPA is to
consider the effect of its selection of the BSER on technological
innovation or development, but that the EPA also has the authority to
balance this factor against the various other factors (See Sierra Club,
657 F.2d at 346-47). With regard to the selection of emissions
controls, modified sources face inherent constraints that newly
constructed greenfield and reconstructed sources do not. As a result,
modified sources present different, and in some ways more limited,
opportunities for technological innovation or development. In this
case, the standards promote technological development by promoting
further development and market penetration of equipment upgrades and
process changes that improve plant efficiency.

B. Determination of the Level of the Standard

    An existing source that undergoes a modification should be able to
at least match its best emission rate since 2002 because with the
modification, it is expanding its capacity and therefore appears to be
interested in upgrading and appears to believe that it will continue to
operate for the long term. The EPA believes that any source that meets
those conditions should be able to make whatever additional investment
is necessary to assure that it meets its most efficient emission rate
since 2002. Improving its efficiency in that manner should be
consistent with its long-term operational goals. On the other hand, an
existing source that is not undertaking that type of upgrade is
differently situated. For example, it may not expect to operate over
the long-term and it may have limited funds available for upgrades.
Thus, it should be subject to the 111(d) rule's requirements, which
assume that it can apply the EPA-identified heat rate improvement
measures, but allow the state to determine whether all of those
measures are appropriate, and further allow the state to grant a
variance.
    In the 2015 Rule, the final standard of performance for a steam
generating unit implementing a large modification was a unit-specific
emission limit based on that unit's own best one-year historical
performance. The EPA determined that such a standard was achievable for
a unit implementing a large (likely capital intensive and pre-planned)
modification because the necessary upgrades could be implemented at the
same time as the large modification. However, a unit that undertakes a
small change may trigger the modification requirement, even without a
large capital expenditure or coinciding with a pre-planned outage. The
EPA solicits comment on the appropriate standard of performance for
such EGUs (Comment C-24). In particular, the EPA solicits comment on
whether the 2015 unit-specific emission limit is also appropriate for
an EGU that conducts a small modification (Comment C-25).
    To assess the potential heat rate improvement for existing coal-
fired EGUs, the EPA looked at 11 years of historical gross heat rate
data from 2007 to 2017 for 574 coal-fired EGUs that reported both heat
input and gross electricity output to the Agency in 2017. The Agency
used the 2007 to 2017 data to calculate several ``benchmark'' heat
rates for each unit. This included calculating the 1-year average heat
rate, the 2-year rolling average heat rate, and the 3-year rolling
average heat rate. Within each of these groups, the EPA then selected
the best (lowest) heat rate and fourth best heat rate. In all, the
Agency calculated heat rate improvement potential using six different
``benchmarks'' (1-year best, 1-year fourth best, 2-year best, 2-year
fourth best, 3-year best, and 3-year fourth best.). Within each
category, each unit's ``benchmark'' heat rate has been used to
calculate a gross electricity output weighted average across the unit
population. The difference between the gross electricity output
weighted average for a ``benchmark'' category and the 2017 gross
electricity output weighted average (baseline) indicates the heat rate
improvement potential. The heat rate improvement potential has been
calculated nationally and at each regional interconnection: East, West,
and Texas. Table 10 below shows the results expressed as a percent
difference between the 2017 baseline heat rate and each ``benchmark.''
Nationally the range in heat rate improvement varies between 2 and 6.6
percent depending on which ``benchmark'' is used.

                                          Table 10--Potential Heat Rate Improvement Using Different Benchmarks
                                                      [Nationally and by regional interconnection]
--------------------------------------------------------------------------------------------------------------------------------------------------------
                                                                                Fourth best                     Fourth best
                                                           Best one-year    Fourth best    Best two-year     two-year       Best three-     three-year
              Interconnect                2017 Heat rate      average        one-year         rolling         rolling      year average       rolling
                                           (Btu/kWh \1\)     (percent)        average         average         average        (percent)        average
                                                                             (percent)       (percent)       (percent)                       (percent)
--------------------------------------------------------------------------------------------------------------------------------------------------------
National................................           9,849             6.6             2.9             5.4             2.4             4.6             2.0

East....................................           9,780             6.6             2.8             5.4             2.3             4.6             1.9
West....................................          10,045             6.1             2.4             4.8             2.1             3.9             1.8
Texas...................................          10,097             7.0             3.6             6.0             3.1             5.3             2.8
--------------------------------------------------------------------------------------------------------------------------------------------------------
\1\ Btu/kWh = British thermal units per kilowatt-hour.

    The EPA solicits comment on which, if any, of these formulations
should be used to determine the unit-specific standard of performance
for a fossil fuel-fired steam generating unit that implements small
modifications (Comment C-26). For example, should the EPA finalize a
standard of performance that requires a steam generating unit that
implements a small modification to meet an emission limit consistent
with its best 1-year average emission or an emission limit consistent
with its fourth best 2-year rolling average or some other emission
limit? The EPA solicits comment on this approach and on any other
methods to determine an appropriate unit-specific standard that takes
into consideration the inherent differences in small modifications
versus large modifications (Comment C-27).

VII. Interactions With Other EPA Programs and Rules

    Nothing in this rulemaking changes the EPA's regulations or
processes for determining whether a source is subject to permitting
under the Prevention of Significant Deterioration (PSD) program or
title V for its GHG emissions, nor does it require any additional
revisions to State Implementation Plans for PSD applicability purposes
or State title V Programs.
    With respect to PSD, the CAA specifies that the best available
control technology (BACT) cannot be less stringent than any applicable
standard of performance under section 111. Id. Thus, in determining GHG
BACT for a new EGU, if the EGU meets the applicability criteria of 40
CFR part 60, subpart TTTT, permitting authorities currently must
consider the emission levels established under 40 CFR part 60, subpart
TTTT as a controlling floor in the BACT review. If the EPA finalizes
these proposed changes to 40 CFR part 60, subpart TTTT, permitting
authorities will need to consider the amended 40 CFR part 60, subpart
TTTT when determining the minimum level of GHG control that represents
BACT for an affected EGU.
    With respect to the title V operating permits program, this rule
does not affect whether sources are subject to the requirement to
obtain a title V operating permit. The 2015 rule included revisions to
the fee requirements of the 40 CFR part 70 and part 71 operating permit
rules under title V of the CAA to avoid inadvertent consequences for
fees that would be triggered by the promulgation of the first CAA
section 111 standard to regulate GHGs. In order to avoid excess fees
from GHG emissions, the EPA revised the definition of regulated
pollutant (for presumptive fee calculation) in 40 CFR 70.2 and
regulated pollutant (for fee calculation) in 40 CFR 71.2 to exempt GHG
emissions. This regulatory amendment had the effect of excluding GHG
emissions from being subject to the statutory ($/ton) fee rate set for
the presumptive minimum calculation requirement of part 70 and the fee
calculation requirements of part 71. See 80 FR at 64632-64638; Updated
Guidance on EPA Review of Fee Schedules for Operating Permit Programs
Under Title V, Peter Tsirigotis, Director of the Office of Air Quality
Planning and Standards, U.S. EPA, at 14-16 (Mar. 27, 2018). The EPA is
not proposing to revise or reopening these provisions of the 2015 Rule,
and nothing in this proposed rulemaking would require any additional
changes to the title V regulations.

VIII. Summary of Cost, Environmental, and Economic Impacts

    As discussed in the economic impact analysis accompanying this
action, substantial new construction of coal-fired steam units is not
anticipated under existing prevailing and anticipated future
conditions. Therefore, the economic impact analysis concludes that this
final rule will result in no or negligible costs overall on owners and
operators of newly constructed EGUs during the 8-year NSPS review cycle
(See CAA section 111(b)(1)(B)). This analysis reflects the best data
available to the EPA at the time the modeling was conducted. As with
any modeling of future projections, many of the inputs are uncertain.
In this context, notable uncertainties, in the future, include the cost
of fuels, the cost to operate existing power plants, the cost to
construct and operate new power plants, infrastructure, demand, and
policies affecting the electric power sector. The modeling conducted
for this economic impact analysis is based on estimates of these
variables, which were derived from the data currently available to the
EPA. However, future realizations could deviate from these expectations
as a result of changes in wholesale electricity markets, federal policy
intervention, including mechanisms to incorporate value for onsite fuel
storage, or substantial shifts in energy prices. The results presented
in this economic impact analysis are not a prediction of what will
happen, but rather a projection describing how this proposed regulatory
action may affect electricity sector outcomes in the absence of
unexpected shocks. The results of this economic impact analysis should
be viewed in that context.
    With regard to modified and reconstructed fossil fuel-fired steam
generating units, this action proposes amended standards for
reconstructed sources and the maximally stringent standard for modified
sources. Historically, few EGUs have notified the EPA that they have
modified under the modification provision of section 111(b), and
similarly only one EGU, over the history of the NSPS program,\117\ has
notified the EPA that it has reconstructed. Moreover, approximately
half of existing coal refuse-fired facilities are potentially exempt
from this standard as CHP units. Based on this information, the EPA
anticipates that few, if any, EGUs will take actions during the period
of analysis that would be considered NSPS modifications or
reconstruction and, as a result, be

subject to the standards of performance proposed in this action.
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    \117\ That is, from 1975, when EPA promulgated the regulations
establishing the requirements for reconstructions, 40 FR 58420 (Dec.
16, 1975) (promulgating 40 CFR 60.15).
---------------------------------------------------------------------------

A. What are the air impacts?

    The EPA does not anticipate that this proposed rule will result in
significant CO2 emission changes by 2026. As explained
immediately above, the EPA does not anticipate the construction of new
coal-fired steam generating units and expects few, if any, coal-fired
EGUs to trigger the proposed NSPS modification or reconstruction