demonstrated. First, as explained above, the EPA has issued
construction permits under the Class VI program. It would not have done
so, and under the regulations cannot have done so, without
demonstrations that CO2 would be securely confined. One of
these projects was for a steam generating EGU.
    Second, international experience with large scale commercial GS
projects has demonstrated through extensive monitoring programs that
large volumes of CO2 can be safely injected and securely
sequestered for long periods of time at volumes and rates consistent
with those expected under this rule. This experience has also
demonstrated the value and efficacy of monitoring programs to determine
the location of CO2 in the subsurface and detect potential
leakage through the presence of CO2 in the shallow
subsurface, near surface and air.
    The Sleipner CO2 Storage Project is located at an
offshore gas field in the North Sea where CO2 must be
removed from the natural gas in order to meet customer requirements and
reduce costs. The project began injecting CO2 into the deep
subsurface in 1996. The single offshore injection well injects
approximately 1 million metric tons per year into a thick, permeable
sandstone above the gas producing zone. Approximately 15 million metric
tons of CO2 have been injected since inception. Many US and
international organizations have conducted monitoring at Sleipner. The
location and dimensions of the CO2 plume have been measured
numerous times using 3-dimensional seismic monitoring since the 1994
pre-injection survey. The monitoring data have demonstrated that
although the plume is behaving differently than initially modeled due
to thin layers of impermeable shale that were not initially identified
in the reservoir model, the CO2 remains trapped in the
injection zone. Numerous other techniques have been successfully used
to monitor CO2 storage at Sleipner. The research and
monitoring at Sleipner demonstrates the value of a comprehensive
approach to site characterization, computational modeling and
monitoring, as is required under UIC Class VI rules. The experience at
Sleipner demonstrates that large volumes of CO2, of the same
order of magnitude expected for an EGU, can be safely injected and
stored in saline reservoirs over an extended period.
    Sn[oslash]hvit is another large offshore CO2 storage
project, located at a gas field in the Barents Sea. Like Sleipner the
natural gas must be treated to reduce high levels of CO2 to
meet processing standards and reduce costs. Gas is transported via
pipeline 95 miles to a gas processing and liquefied natural gas plant
and the CO2 is piped back offshore for injection.
Approximately 0.7 million metric tons per year CO2 are
injected into permeable sandstone below the gas reservoir. Between 2008
and 2011, the operator observed pressure increases in the injection
formation (Tubaen Formation) greater than expected and conducted time
lapse seismic surveys and studies of the injection zone and concluded
that the pressure increase was mainly caused by a limited storage
capacity in the formation.\478\ In 2011,

the injection well was modified and injection was initiated in a second
interval (St[oslash] Formation) in the field to increase the storage
capacity. Approximately 3 million metric tons of CO2 have
been injected since 2008. Monitoring demonstrates that no leakage has
occurred, again demonstrating that large volumes of CO2, of
the same order of magnitude expected for an EGU, can be safely injected
and stored in deep saline formations over an extended period.
---------------------------------------------------------------------------

    \478\ Grude, S. M. Landr[oslash]a, and J. Dvorkinb, 2014,
Pressure effects caused by CO2 injection in the
Tub[aring]en Fm., the Sn[oslash]hvit field. International Journal of
Greenhouse Gas Control 27 (2014) 178-187. Commenters argued that the
project had failed to sequester CO2, referring to the
initial cessation of injection. See, e.g. Comments of UARG p. 56
(Docket entry: EPA-HQ-OAR-2013-0495-9666). In fact, injection
resumed successfully, as described in the text above.
---------------------------------------------------------------------------

    As discussed above in Sections V.E.2.a and M, CO2 from
the Great Plains Synfuels plant in North Dakota has been injected into
the Weyburn oil field in Saskatchewan Canada since 2000. Over that time
period the project has injected more than 16 million metric tons of
CO2. It is anticipated that approximately 40 million metric
tons of CO2 will be permanently sequestered over the
lifespan of the project. Extensive monitoring by U.S. and international
partners has demonstrated that no leakage has occurred. The sources of
CO2 for EOR may vary (e.g., industrial processes, power
generation); however, this does not impact the effectiveness of EOR
operations (see Section V.M.3).
    CO2 used for EOR may come from anthropogenic or natural
sources. The source of the CO2 does not impact the
effectiveness of the EOR operation. CO2 capture, treatment
and processing steps provide a concentrated stream of CO2 in
order to meet the needs of the intended end use. CO2
pipeline specifications of the U.S. Department of Transportation
Pipeline Hazardous Materials Safety Administration found at 49 CFR part
195 (Transportation of Hazardous Liquids by Pipeline) apply regardless
of the source of the CO2 and take into account
CO2 composition, impurities, and phase behavior.
Additionally, EOR operators and transport companies have specifications
to ensure related to the composition of CO2. These
requirements and specifications ensure EOR operators receive a known
and consistent CO2 stream.
    At the In Salah CO2 storage project in Algeria,
CO2 is removed from natural gas produced at three nearby gas
fields in order to meet export quality specification. The
CO2 is transported by pipeline approximately 3 miles to the
injection site. Three horizontal wells are used to inject the
CO2 into the down-dip aquifer leg of the gas reservoir
approximately 6,200 feet deep. Between 2004 and 2011 over 3.8 million
metric tons of CO2 were stored. Injection rates in 2010 and
2011 were approximately 1 million metric tons per year. Storage
integrity has been monitored by several U.S. and international
organizations and the monitoring program has employed a wide range of
geophysical and geochemical methods, including time lapse seismic,
microseismic, wellhead sampling, tracers, down-hole logging, core
analysis, surface gas monitoring, groundwater aquifer monitoring and
satellite data. The data have been used to support periodic risk
assessments during the operational phase of the project. In 2010 new
data from seismic, satellite and geomechanical models were used to
inform the risk assessment and led to the decision to reduce
CO2 injection pressures due to risk of vertical leakage into
the lower caprock, and risk of loss of well integrity. The caprock at
the site consisted of main caprock units, providing the primary seal,
and lower caprock units, providing additional buffers. There was no
leakage from the well or through the caprock, but the risk analysis
identified an increased risk of leakage, therefore, the aforementioned
precautions were taken. Additional analysis of the reservoir, seismic
and geomechanical data led to the decision to suspend CO2
injection in June 2011. No leakage has occurred and the injected
CO2 remains safely stored in the subsurface. The decision to
proceed with safe shutdown of injection resulted from the analysis of
seismic and geomechanical data to identify and respond to storage site
risk. The In Salah project demonstrates the value of developing an
integrated and comprehensive set of baseline site data prior to the
start of injection, and the importance of regular review of monitoring
data. Commenters also noted that the data collection and analysis had
proven effective at preventing any release of sequestered
CO2 to either underground drinking water sources or to the
atmosphere.\479\
---------------------------------------------------------------------------

    \479\ ``It is important to note that although the In Salah
project is no longer injecting CO2, the CCS community
still views this early saline project as a success because the
monitoring program served its intended purpose. That is, the
monitoring methods deployed at this site informed the operator of a
potential problem, leading to a shutdown of CO2 injection
before the Caprock was breached.'' Comment of EPRI, p. 14 Docket
entry: EPA-HQ-OAR-2013-0495-8925).
---------------------------------------------------------------------------

    These projects demonstrate that sequestration of CO2
captured from industrial operations has been successfully conducted on
a large scale and over relatively long periods of time. The volumes of
captured CO2 are within the same order of magnitude as that
expected from EGUs. Even though potentially adverse conditions were
identified at some projects (In Salah and Sn[oslash]hvit), there were
no releases to air and the monitoring systems were effective in
identifying the issues in a timely manner, and these issues were
addressed effectively. In each case, the site-specific characteristics
were evaluated on a case-by-case basis to select a site where the
geologic conditions are suitable to ensure long-term, safe storage of
CO2. Each project was designed to address the site-specific
characteristics and operated to successfully inject CO2 for
safe storage.
4. Must the standard of performance for CO2 include CAA
requirements on the sequestration site?
    One commenter maintained as a matter of law that a standard
predicated on use of CCS is not a ``system of emission reduction'', and
therefore is not a ``standard of performance'' within the meaning of
section 111 (a)(1) of the Act. The commenter argued that the standard
does not require sequestration of captured CO2 but only
capture, so that no emission reductions are associated with the
standard. A gloss on this argument is that there are no enforceable
requirements for the captured CO2 (``[t]he fate of that
[captured] CO2 is something that the proposed standard does
not proscribe with enforceable requirements''). The commenter further
argues that a ``system of emission reduction'' under section 111 must
be ``designed into the new source itself'' so that off-site underground
sequestration of captured CO2 emissions ``could never
satisfy the statutory requirements governing a `standard of
performance''' (emphasis original).\480\
---------------------------------------------------------------------------

    \480\ Comments of UARG, pp. 37-38 (Docket entry: EPA-HQ-OAR-
2013-0495-9666).
---------------------------------------------------------------------------

    The EPA disagrees with both the legal and factual assertions in
this comment. As to the legal point, the commenter fails to distinguish
capture and sequestration of carbon from every other section 111
standard which is predicated on capture of a pollutant. Indeed, all
emission standards not predicated on outright pollutant destruction
involve capture of the pollutant and its subsequent disposition in the
capturing medium. Thus, metals are captured in devices like baghouses
or scrubbers, leaving a solid waste or wastewater to be managed. Gases
can be captured with activated carbon or under pressure, again
requiring further management of the captured pollutant(s). The EPA is
required to consider these potential implications in promulgating an
NSPS. See section 111(a)(1) (in promulgating a standard of performance
under section 111, the EPA must ``tak[e] into account . . . any nonair
quality health and environmental

impact''). The EPA thus considers such issues as solid waste and
wastewater generation as part of determining if a system of emission
reduction is ``best'' and ``adequately demonstrated'' under section
111. See Section V.O below (discussion of this rule's potential cross-
media impacts).
    The further comment that the standard is arbitrary because it fails
to impose any requirements on the captured CO2 is misplaced.
The commenter mischaracterizes the standard as requiring capture only.
The BSER is not just capturing a certain amount of CO2, but
sequestering it. Sequestration can occur either on-site or off-site.
Sequestration sites receiving and injecting the captured CO2
are required to obtain UIC permits and report under subpart RR of the
GHGRP. They must conduct comprehensive monitoring as part of these
obligations. Although the NSPS does not impose regulatory requirements
on the transportation pipeline or the sequestration site, such
requirements already exist under other regulatory programs of the
Department of Transportation and the EPA. In particular, the EPA is
reasonably relying on the already-adopted, and very rigorous, Class VI
well requirements in combination with the subpart RR requirements to
provide secure sequestration of captured CO2. The EPA has
also considered carefully the requirements and operating history of the
Class II requirements for EOR wells, which, in combination with the
subpart RR requirements, ensure protection of USDWs from endangerment,
provide the monitoring mechanisms to identify and address potential
leakage using SDWA and CAA authorities, and have the practical effect
of preventing releases of CO2 to the atmosphere. This is
analogous to the many section 111 standards of performance for metals
which result in a captured air pollution control residue to be disposed
of pursuant to waste management requirements of the rules implementing
the Resource Conservation and Recovery Act. It is also analogous to the
many section 111 standards of performance for metals or organics
captured in wet air pollution control systems resulting in wastewater
discharged to a navigable water where pollutant loadings are controlled
under rules implementing the Clean Water Act. Again, these are non-air
environmental impacts for which the EPA must account in establishing a
section 111(a) standard. The EPA has reasonably done so here based on
the regulatory regimes of the Class VI and Class II UIC requirements in
combination with the monitoring regime of the subpart RR reporting
rules, as well as the CO2 pipeline standards of the
Department of Transportation.
    In this regard, the EPA notes that at proposal it acknowledged the
possibility ``that there can be downstream losses of CO2
after capture, for example during transportation, injection or
storage.'' 79 FR at 1484. Given the rigorous substantive requirements
and the monitoring required by the Class VI rules, the complementary
monitoring regime of the subpart RR MRV plan and reporting rules, as
well as the regulatory requirements for Class II wells, any such losses
would be de minimis. Indeed, the same commenter maintained that the
monitoring requirements of the Class VI rule are overly stringent and
that a 50-year post-injection site care period is unnecessarily
long.\481\ As it happens, as noted above, the Class VI rules allow for
an alternative post-injection site care period based on a site-specific
demonstration. See 40 CFR 146.93(b).
---------------------------------------------------------------------------

    \481\ Comments of UARG, p. 63 (Docket entry: EPA-HQ-OAR-2013-
0495-9666).
---------------------------------------------------------------------------

    The EPA addresses this comment in more detail in Chapter 2 of the
Response-to-Comment Document.
5. Other Perceived Obstacles to Geologic Sequestration
a. Class II to Class VI transition
    A number of commenters maintained that the Class VI rules could
effectively force all Class II wells to transition to Class VI wells if
they inject anthropogenic CO2, and further maintained that,
as a practical matter, this would render EOR unavailable for such
CO2. The EPA disagrees with these comments. Injection of
anthropogenic CO2 into Class II wells does not force
transition of these wells to Class VI wells--not during the well's
active operation and not when EOR operations cease. We recognize the
widespread use of EOR and the expectation that injected CO2
can remain underground. The EPA issued a memorandum to its regional
offices on April 23, 2015 reflecting these principles: \482\
---------------------------------------------------------------------------

    \482\ ``Key Principles in EPA's Underground Injection Control
Program Class VI Rule Related to Transition of Class II Enhanced Oil
Recovery or Gas Recovery Wells to Class VI'', April 23, 2015.
Available at: http://water.epa.gov/type/groundwater/uic/class6/upload/class2eorclass6memo.pdf.
---------------------------------------------------------------------------

    Geologic storage of CO2 can continue to be permitted
under the UIC Class II program.
    Use of anthropogenic CO2 in EOR operations does not
necessitate a Class VI permit.
    Class VI site closure requirements are not required for Class II
CO2 injection operations.
    EOR operations that are focused on oil or gas production will be
managed under the Class II program. If oil or gas recovery is no longer
a significant aspect of a Class II permitted EOR operation, the key
factor in determining the potential need to transition an EOR operation
from Class II to Class VI is increased risk to USDWs related to
significant storage of CO2 in the reservoir, where the
regulatory tools of the Class II program cannot successfully manage the
risk.\483\
---------------------------------------------------------------------------

    \483\ In this regard, the Class VI rules provide that, owners or
operators that are injecting carbon dioxide for the primary purpose
of long-term storage into an oil and gas reservoir must apply for
and obtain a Class VI geologic sequestration permit when there is an
increased risk to USDWs compared to Class II operations. 40 CFR
144.19.
---------------------------------------------------------------------------

b. GHGRP Subpart RR
    A number of commenters maintained that no EOR operator would accept
captured carbon from an EGU due to the reporting and other regulatory
burdens imposed by the monitoring requirements of GHGRP subpart
RR.\484\ They noted that preparing a subpart RR MRV plan could cost
upwards of $100,000 which would be cost prohibitive given other
available sources of CO2.
---------------------------------------------------------------------------

    \484\ See e.g., comments of UARG, p, 63 (Docket entry: EPA-HQ-
OAR-2013-0495-9666); Southern Co., p. 37 (Docket entry: EPA-HQ-OAR-
2013-0495-10095); American Petroleum Institute pp. 40-50 Docket
entry: EPA-HQ-OAR-2013-0495-10098).
---------------------------------------------------------------------------

    The EPA disagrees with this comment in several respects. First, the
BSER determination and regulatory impact analysis for this rule relies
on GS in deep saline formations, not on EOR. However, the EPA also
recognizes the potential for sequestering CO2 via EOR, but
disagrees that subpart RR requirements effectively preclude or
substantially inhibit the use of EOR.
    The cost of compliance with subpart RR is not significant enough to
offset the potential revenue for the EOR operator from the sale of
produced oil for CCS projects that are reliant on EOR. First, the costs
associated with subpart RR are relatively modest, especially in
comparison with revenues from an EOR field. In the economic impact
analysis for subpart RR, the EPA estimated that an EOR project with a
Class II permit would incur a first year cost of up to $147,030 to
develop an MRV plan, and an annual cost of $27,787 to maintain the
plan; the EPA estimated annual reporting and recordkeeping costs at
$13,262 per year.\485\ Monitoring costs

are estimated to range from $0.02 per metric ton (base case scenario)
to approximately $2 per metric ton of CO2 (high scenario).
Using a range of scenarios (that included high end estimates), these
subpart RR costs are approximately three to four percent of estimated
revenues for an average EOR field, indicating that the costs can
readily be absorbed. 75 FR 75073.
---------------------------------------------------------------------------

    \485\ Subpart RR costs are presented in 2008 US dollars.
---------------------------------------------------------------------------

    Furthermore, there is a demand for new CO2 by EOR
operators, even beyond current natural sources of CO2. For
example, in an April 2014 study, DOE concluded that future development
of EOR will need to rely on captured CO2.\486\ Thus, the
argument that EOR operators will obtain CO2 from other
sources without triggering subpart RR responsibilities, which assumes
adequate supplies of CO2 from other sources, lacks
foundation. In addition, the Internal Revenue Code section 45Q provides
a tax credit for CO2 sequestration which is far greater than
subpart RR costs.\487\ In sum, the cost of complying with subpart RR
requirements, including the cost of MRV, is not significant enough to
deter EOR operators from purchasing EGU captured CO2.
---------------------------------------------------------------------------

    \486\ ``Near Term Projections of CO2 Utilization for
Enhanced Oil Recovery''. DOE/NETL-2014/1648. April 2014.
    \487\ http://www.irs.gov/irb/2009-44_IRB/ar11.html. The section
45Q tax credit for calendar year 2015 is $10.92 per metric ton of
qualified CO2 that is captured and used in a qualified
EOR project and $21.85 per metric ton of qualified CO2
that is captured and used in a qualified non-EOR GS project. http://www.irs.gov/irb/2015-26_IRB/ar14.html.
---------------------------------------------------------------------------

    The EPA addresses these comments in more detail in the Response to
Comment Document.
c. Conditional exclusion for geologic sequestration of CO2 streams
under the Resource Conservation and Recovery Act (RCRA)
    Certain commenters voiced concerns that regulatory requirements for
hazardous wastes might apply to captured CO2 and these
requirements might be inconsistent with, or otherwise impede, GS of
captured CO2 from EGUs. The EPA has acted to remove any such
(highly conjectural) uncertainty. The Resource Conservation and
Recovery Act (RCRA) authorizes the EPA to regulate the management of
hazardous wastes. In particular, RCRA Subtitle C authorizes a cradle to
grave regulatory program for wastes identified as hazardous, whether
specifically listed as hazardous or whether the waste fails certain
tests of hazardous characteristics. The EPA currently has little
information to conclude that CO2 streams (defined in the
RCRA exclusion rule as including incidental associated substances
derived from the source materials and the capture process, and any
substances added to the stream to enable or improve the injection
process) might be identified as ``hazardous wastes'' subject to RCRA
Subtitle C regulation.\488\ Nevertheless, to reduce potential
uncertainty regarding the regulatory status of CO2 streams
under RCRA Subtitle C, and in order to facilitate the deployment of
geologic sequestration, the EPA recently concluded a rulemaking to
exclude certain CO2 streams from the RCRA definition of
hazardous waste.\489\ In that rulemaking, the EPA determined that if
any such CO2 streams would be hazardous wastes, further RCRA
regulation is unnecessary to protect human health and the environment
provided certain conditions are met. Specifically, the rule
conditionally excludes from Subtitle C regulations CO2
streams if they are (1) transported in compliance with U.S. Department
of Transportation or state requirements; (2) injected in compliance
with UIC Class VI requirements (summarized above); (3) no other
hazardous wastes are mixed with or co-injected with the CO2
stream; and (4) generators (e.g., emission sources) and Class VI well
owners or operators sign certification statements. See 40 CFR
261.4(h)).\490\ The D.C. Circuit recently dismissed all challenges to
this rule in Carbon Sequestration Council and Southern Company Services
v. EPA, No. 787 F. 3d 1129 (D.C. Cir. 2015).
---------------------------------------------------------------------------

    \488\ No hazardous waste listings apply to CO2
streams. Therefore, a CO2 stream could be identified
(i.e. defined) as a hazardous waste only if it exhibits one or more
of the hazardous characteristics. 79 FR 355 (Jan 3. 2014).
    \489\ 79 FR 350 (Jan. 3, 2014).
    \490\ The EPA made clear in the final conditional exclusion that
that rule does not address, and is not intended to affect the RCRA
regulatory status of CO2 streams that are injected into
wells other than Class VI. However, the EPA noted in the preamble to
the final rule that (based on the limited information provided in
public comments) should CO2 be used for its intended
purpose as it is injected into UIC Class II wells for the purpose of
EOR/EGR (enhanced oil recovery/enhanced gas recovery), it is the
EPA's expectation that such an injection process would not generally
be a waste management activity. 79 FR 355. The EPA encouraged
persons to consult with the appropriate regulatory authority to
address any fact-specific questions that they may have regarding the
status of CO2 in situations that are beyond the scope of
that rule. Id. Moreover, use of anthropogenic CO2 for EOR
is long-standing and has flourished in all of the years that EPA's
subtitle C regulations (which among other things, define what a
solid waste is for purposes of those regulations) have been in
place. The RCRA subtitle C regulatory program consequently has not
been an impediment to use of anthropogenic CO2 for EOR.
---------------------------------------------------------------------------

d. Other perceived uncertainties
    Other commenters claimed that various legal uncertainties preclude
a finding that geologic sequestration of CO2 from EGUs can
be considered to be adequately demonstrated. Many of the issues
referred to in comments relate to property rights: issues of ownership
of pore space, relationship of sequestration to ownership of mineral
rights, issues of dealing with multiple landowners, lack of state law
frameworks, or competing, inconsistent state laws.\491\ Other
commenters noted the lack of long-term liability insurance, and noted
uncertainties regarding long-term liability generally.\492\
---------------------------------------------------------------------------

    \491\ See e.g. Comments of Duke Energy, p. 28 Docket entry: EPA-
HQ-OAR-2013-0495-9426); UARG, p. 62 (Docket entry: EPA-HQ-OAR-2013-
0495-9666); AEP, p. 91 (Docket entry: EPA-HQ-OAR-2013-0495-10618).
    \492\ See e.g. Comments of UARG, pp. 26 (Docket entry: EPA-HQ-
OAR-2013-0495-9666), 62; EEI, p. 92 Docket entry: EPA-HQ-OAR-2013-
0495-9780); Duke Energy, pp. 27, 28 Docket entry: EPA-HQ-OAR-2013-
0495-9426).
---------------------------------------------------------------------------

    An IPCC special report on CCS found that with an appropriate site
selection, a monitoring program, a regulatory system, and the
appropriate use of remediation methods, the risks of GS would be
comparable to risks of current activities, such as EOR, acid gas
injection and underground natural gas storage.\493\ Furthermore, an
interagency CCS task force examined GS-related legal issues thoroughly
and concluded that early CCS projects can proceed under the existing
legal framework with respect to issues such as property rights and
liability.\494\ As noted earlier, both the Archer Daniels Midland (ADM)
and FutureGen projects addressed siting and operational aspects of GS
(including issues relating to volumes of the CO2 and the
nature of the CO2 injectate) in their permit applications.
The fact that these applicants pursued permits indicates that they
regarded any potential property rights issues as resolvable.
---------------------------------------------------------------------------

    \493\ Intergovernmental Panel on Climate Change. (2005). Special
Report on Carbon Dioxide Capture and Storage.
    \494\ http://www.epa.gov/climatechange/Downloads/ccs/CCS-Task-Force-Report-2010.pdf.
---------------------------------------------------------------------------

    Commenter American Electric Power (AEP) referred to its own
experience with the Mountaineer demonstration project. AEP noted that
although this project was not full scale, finding a suitable
repository, notwithstanding a generally favorable geologic area, proved
difficult. The company referred to years spent in site characterization
and digging multiple wells.\495\ Other commenters noted more generally
that site characterization issues can be time-consuming and difficult,
and quoted

studies suggesting that it could take 5 years to obtain a Class VI
permit.\496\
---------------------------------------------------------------------------

    \495\ AEP Comments at pp. 93, 96 (Docket entry: EPA-HQ-OAR-2013-
0495-10618).
    \496\ See e.g. Comments of UARG, p. 55 (Docket entry: EPA-HQ-
OAR-2013-0495-9666), citing to Cichanowitz CCS Report (2012).
---------------------------------------------------------------------------

    The EPA agrees that robust site characterization and selection is
important to ensuring capacity needs are met and that the sequestered
CO2 is safely stored. Efforts to characterize geologic
formations suitable for GS have been underway at DOE through the RCSPs
since 2003 (see Section V.M). Additionally, since 2007, the USGS has
been assessing U.S. geologic storage resources for CO2. As
noted earlier, DOE, in partnership with researchers, universities, and
organizations across the country, is demonstrating that GS can be
achieved safely, permanently, and economically at large scales, and
projects supported by the department have safely and permanently stored
10 million metric tons of CO2.
    In the time since the commenter submitted comments several Class VI
permits have been issued by the EPA. These projects demonstrate that a
GS site permit applicant could potentially prepare and obtain a UIC
permit concurrent with permits required for an EGU. With respect to
AEP's experience with the Mountaineer demonstration project,
notwithstanding difficulties, the company was able to successfully dig
wells, and safely inject captured CO2. Moreover, the company
indicated it fully expected to be able to do so at full scale and
explained how.\497\ The EPA notes further that a monitoring program and
its associated infrastructure (e.g., monitoring wells) and costs will
be dependent on site-specific characteristics, such as CO2
injection rate and volume, geology, the presence of artificial
penetrations, among other factors. It is thus not appropriate to
generalize from AEP's experience, and assume that other sites will
require the same number of wells for site characterization or
injection. In this regard, we note that the ADM and FutureGen
construction permits for Class VI wells involved far fewer injection
wells than AEP references.\498\ See also discussion of this issue in
Section V.I.5 above.
---------------------------------------------------------------------------

    \497\ See AEP FEED Study at pp. 36-43. The company likewise
explained the monitoring regime it would utilize to verify
containment, and the well construction it would utilize to guarantee
secure sequestration. Id. at pp. 44-54. Available at:
www.globalccsinstitute.com/publications/aep-mountaineer-ii-project-front-end-engineering-and-design-feed-report.
    \498\ The FutureGen UIC Class VI injection well permits (four in
total) require nine monitoring wells. http://www.epa.gov/r5water/uic/futuregen/. The Archer Daniels Midland UIC Class VI injection
well permit issued in September 2014 (CCS2) requires five monitoring
wells and the Archer Daniels Midland UIC Class VI injection well
permit issued in December 2014 (CCS1) was permitted with two
monitoring wells. http://www.epa.gov/region5/water/uic/adm/.
---------------------------------------------------------------------------

O. Non-air Quality Impacts and Energy Requirements

    As part of the determination that SCPC with partial CCS is the best
system of emission reduction adequately demonstrated, the EPA has given
careful consideration to non-air quality health and environmental
impacts and energy requirements, as required by CAA section 111 (a). We
have also considered those factors for alternative potential compliance
paths to assure that the standard does not have unintended adverse
health, environmental or energy-related consequences. The EPA finds
that neither the BSER, nor the possible alternative compliance
pathways, would have adverse consequences from either a non-air quality
impact or energy requirement perspective.
    1. Transport and Sequestration of Captured CO2
    As just discussed in detail, the EPA finds that the Class VI and II
rules, as complemented by the subpart RR GHGRP reporting and monitoring
requirements, amply safeguard against potential of injected
CO2 to degrade underground sources of drinking water and
amply protect against any releases of sequestered CO2 to the
atmosphere. The EPA likewise finds that the plenary regulatory controls
on CO2 pipelines assure that CO2 can be safely
conveyed without environmental release, and that these rules, plus the
complementary tracking and reporting rules in subpart RR, assure that
captured CO2 will be properly tracked and conveyed to a
sequestration site.
2. Water Use Impacts
    Commenters claimed that the EPA ignored the negative environmental
impacts of the use of CCS for the mitigation of CO2
emissions from fossil fuel-fired steam generating EGUs. In particular,
commenters noted that the use of CCS will increase the water usage at
units that implement CCS to meet the proposed standard of performance.
At least one commenter claimed that addition of an amine-based CCS
system would double the consumptive water use of a power plant, which
would be unacceptable, especially in drought-ridden states and in the
arid west and referenced a study in the scientific literature as
support.\499\ The commenter also references a DOE/NETL report that
likewise notes significant increases in the amount of cooling and
process water required with the use of carbon capture technology.\500\
However, those studies discuss increased water use for cases where full
CCS (90 percent or greater capture) is implemented. As we discussed in
both the proposal and in this preamble, the EPA does not find that
highly efficient new generation technology implementing full CCS is the
BSER for new steam generating EGUs.
---------------------------------------------------------------------------

    \499\ See comments of UARG at p. 84 (Docket entry: EPA-HQ-OAR-
2013-0495-9666) referencing Haibo Zhai, et al., Water Use at
Pulverized Coal Power Plants with Post-combustion Carbon Capture and
Storage, 45 Environ. Sci. Technol., 2479-85 (2011).
    \500\ Id at p. 84 referencing DOE/NETL-402/080108, ``Water
Requirements for Existing and Emerging Thermoelectric Plant
Technologies'' at 13 (Aug. 2008, Apr. 2009 revision).
---------------------------------------------------------------------------

    The EPA examined water use predicted from the updated DOE/NETL
studies in order to determine the magnitude of increased water usage
for a new SCPC implementing partial CCS to meet the final standard of
1,400 lb CO2/MWh-g. The predicted water consumption for
varying levels of partial and full CCS are provided in Table 13. The
results show 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. By comparison, a unit implementing 35 percent
CCS to meet the proposed emission limitation of 1,100 lb
CO2/MWh-g would see an increase in water consumption of 16.0
percent and a new unit implementing full (90 percent) CCS would see an
increase of almost 50 percent.

  Table 13--Predicted Water Consumption With Implementation of Various
                       Levels of Partial CCS \501\
------------------------------------------------------------------------
                                             Raw water       Increase
               Technology                  consumption,     compared to
                                                gpm           SCPC, %
------------------------------------------------------------------------
SCPC....................................           4,095              --

SCPC + 16% CCS..........................           4,359             6.4
SCPC + 35% CCS..........................           4,751            16.0
SCPC + 90% CCS..........................           6,069            48.2
IGCC*...................................           3,334           -18.6
IGCC + 90% CCS*.........................           4,815            17.6
------------------------------------------------------------------------
* The IGCC results presented in the DOE/NETL report are for an IGCC with
  net output of 622 MWe and an IGCC with full CCS with net output of 543
  MWe. The water consumption for each was normalized to 550 MWe to be
  consistent with the SPCP cases.

    Similar to other air pollution controls--such as a wet flue gas
desulfurization scrubber--utilization of post-combustion amine-based
capture systems results in increased consumption of water. However, by
finalizing a standard that is less stringent than the proposed
limitation and by rejecting full CCS as the BSER, the EPA has reduced
the increased amount of water needed as compared to a similar unit
without CCS. Further, the EPA notes that there are 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 coal and from the combustion process
and recycles the captured water in the process, resulting in decreased
need for withdrawal of fresh water.
---------------------------------------------------------------------------

    \501\ Exhibits A-1 and A-2 at p. 16-17 from ``Cost and
Performance Baseline for Fossil Energy Plants Supplement:
Sensitivity to CO2 Capture Rate in Coal-Fired Power
Plants'', DOE/NETL-2015/1720 (June 22, 2015).
---------------------------------------------------------------------------

    The EPA also examined the predicted water usage for a new IGCC and
for a new IGCC implementing 90 percent CCS. The predicted water
consumption for the new IGCC unit is 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 rejected new
IGCC implementing full CCS as BSER because the predicted costs were
significantly more than alternative technologies. The EPA also does not
find that a new IGCC EGU is part of the final BSER (for reasons
discussed in Section V.P). However, the EPA does note that IGCC is a
viable alternative compliance option and, as shown here, would result
in less water consumption than a compliant SCPC EGU. The EPA also notes
that predicted water consumption at a new NGCC unit would be less than
half that for a new SCPC EGU with the same net output.\502\
---------------------------------------------------------------------------

    \502\ The EPA also finds that the standards would not result in
any significant impact on solid waste generation or management. See
Section XIII.D below.
---------------------------------------------------------------------------

3. Energy Requirements
    The EPA also examined the expected impacts on energy requirements
for a new unit meeting the final promulgated standard and finds impacts
to be minimal. Specifically, the EPA examined the increased auxiliary
load or parasitic energy requirements of a system implementing CCS. The
EPA examined the predicted auxiliary power demand from the updated DOE/
NETL studies in order to determine the increased energy requirement for
a new SCPC implementing partial CCS to meet the final standard of 1,400
lb CO2/MWh-g. The predicted gross power output, the
auxiliary power demand, and the parasitic power demand (percent of
gross output) are provided in Table 14 for varying levels of partial
and full CCS.

      Table 14--Predicted Parasitic Power Demand With Implementation of Various Levels of Partial CCS \503\
----------------------------------------------------------------------------------------------------------------
                                                                    Gross power      Auxiliary       Parasitic
                      Generation technology                         output, MWe     power, MWe      demand (%)
----------------------------------------------------------------------------------------------------------------
    SCPC........................................................             580              30             5.2
    SCPC + 16% CCS..............................................             599              38             6.3
SCPC + 35% CCS..................................................             603              53             8.8
    SCPC + 90% CCS..............................................             642              91            14.2
    IGCC........................................................             748             126            16.8
    IGCC + 90% CCS..............................................             734             191            26.0
CCS.............................................................             734             191            26.0
----------------------------------------------------------------------------------------------------------------

    The auxiliary power demand is the amount of the gross power output
that is utilized within the facility rather than used to produce
electricity for sale to the grid. The parasitic power demand (or
parasitic load) is the percentage of the gross power output that is
needed to meet the auxiliary power demand.\504\ In an SCPC EGU without
CCS, the auxiliary power is used to primarily to operate fans, motors,
pumps, etc. associated with operation of the facility and the
associated pollution control equipment. When carbon capture equipment
is incorporated, additional power is needed to operate associated
equipment, and steam is need to regenerate the capture solvents (i.e.,
the solvents are heated to release the captured CO2).
---------------------------------------------------------------------------

    \503\ Exhibits A-1 and A-2 at p. 16-17 from ``Cost and
Performance Baseline for Fossil Energy Plants Supplement:
Sensitivity to CO2 Capture Rate in Coal-Fired Power
Plants'', DOE/NETL-2015/1720 (June 2015).
    \504\ Note that this auxiliary power demand is not necessarily
met from power or steam generated from the EGU. External sources can
also be utilized for this purpose.
---------------------------------------------------------------------------

    The results in Table 14 show that a new SCPC unit without CCS can
expect a parasitic power demand of about 5.2 percent. A new SCPC unit
meeting the

final standard of performance by implementing 16 percent partial CCS
will see a parasitic power demand of about 6.3 percent, which is not a
significant increase in energy requirement. Of course, new SCPC EGUs
that implement higher levels of CCS will expect higher amounts of
parasitic power demand. As shown in Table 14, a new SCPC EGU
implementing full CCS would expect to utilize over 14 percent of its
gross power output to operate the facility and the carbon capture
system. But, the EPA does not find that a new SCPC implementing full
CCS is the BSER for new fossil-fired steam generating units. See
Section V.P.2 below.
    The EPA also notes that there is on-going research sponsored by
DOE/NETL and others to further reduce the energy requirements of the
carbon capture systems. Progress is being made. As was mentioned
previously, the heat duty (the energy required to regenerate the
capture solvent) for the amine scrubbing process used at the Searles
Valley facility in the mid-70's was about 12 MJ/mt CO2
removed as compared to a heat duty of about 2.5 MJ/mt CO2
removed for the amine processes used at Boundary Dam and for the amine
system that will be used at the WA Parish facility.\505\
---------------------------------------------------------------------------

    \505\ ``From Lubbock, TX to Thompsons, TX--Amine Scrubbing for
Commercial CO2 Capture from Power Plants'', plenary
address by Prof. Gary Rochelle at the 12th International Conference
on Greenhouse Gas Technology (GHGT-12), Austin, TX (October 2014).
---------------------------------------------------------------------------

    The EPA also examined the predicted parasitic power demand for a
new IGCC and for a new IGCC implementing 90 percent CCS. As we have
noted elsewhere, the auxiliary power demand for a new IGCC unit is more
than that for that of a new SCPC. As one can see in Table 14, a new
IGCC unit can expect to see a nearly 17 percent parasitic power demand;
and a new IGCC unit implementing full CCS would expect a parasitic
power demand of nearly 30 percent. Of course, the EPA rejected new IGCC
implementing full CCS as BSER because of the potentially unreasonable
costs. The EPA also does not find that a new IGCC EGU is part of the
final BSER (for reasons discussed elsewhere in Section V.P.1 below).
However, as we have noted, the EPA does find IGCC to be a viable
alternative compliance option. Utilities and project developers should
consider the increased auxiliary power demand for an IGCC when
considering their options for new power generation. The EPA also notes
that the predicted parasitic load for a new NGCC unit would be about 2
percent--less than half that for a new SCPC EGU with the same net
output.\506\
---------------------------------------------------------------------------

    \506\ The EPA also finds that the standards would not result in
any significant impact on solid waste generation or management. See
Section XII.D below.
---------------------------------------------------------------------------

    With respect to potential nationwide impacts on energy
requirements, as described above in Section V.H.3 and more extensively
in the RIA chapter 4, the EPA reasonably projects that no new non-
compliant fossil-fuel fired steam electric capacity will be constructed
through 2022 (the end of the 8 year review cycle for NSPS). It is
possible, as described earlier, that some new sources could be built to
preserve fuel diversity, but even so, the number of such sources would
be small and therefore would not significantly impact national energy
requirements (assuming that such sources would not already be reflected
in the baseline conditions just noted).

P. Options That Were Considered by the EPA but Were Ultimately Not
Determined To Be the BSER

    In light of the comments received, the EPA re-examined several
alternative systems of emission reduction and reaffirms in this
rulemaking our proposed determination that those alternatives do not
represent the ``best'' system of emission reduction when compared
against the other available emission reduction options. These are
described below. See also Section IV.B.1 above.
1. Highly Efficient Generation Technology (e.g., Supercritical or
Ultra-supercritical Boilers)
    In the January 2014 proposal, we considered whether `Highly
Efficient New Generation without CCS Technology' should constitute the
BSER for new steam generating units. 79 FR at 1468-69. The discussion
focused on the performance of highly efficient generation technology
(that does not include any implementation of CCS), such as a
supercritical \507\ pulverized coal (SCPC) or a supercritical CFB
boiler, or a modern, well-performing IGCC unit.
---------------------------------------------------------------------------

    \507\ Subcritical coal-fired boilers are designed and operated
with a steam cycle below the critical point of water. Supercritical
coal-fired boilers are designed and operated with a steam cycle
above the critical point of water. 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.
---------------------------------------------------------------------------

    All these options are technically feasible--there are numerous
examples of each operating in the U.S. and worldwide. However, we do
not find them to qualify as the best system for reduction of
CO2 emissions for the following reasons:
a. Lack of Significant CO2 Reductions When Compared to
Business as Usual
    At the outset, we reviewed the emission rates of efficient PC and
CFB units. According to the DOE/NETL estimates, a newly constructed
subcritical PC unit firing bituminous coal would emit approximately
1,800 lb CO2/MWh-g,\508\ a new highly efficient SCPC unit
using bituminous coal would emit nearly 1,720 lb CO2/MWh-g,
and a new IGCC unit would emit about 1,430 lb CO2/MWh-
g.509 510 Emissions from comparable sources utilizing sub-
bituminous coal or lignite will have somewhat higher CO2
emissions.\511\
---------------------------------------------------------------------------

    \508\ Exhibit ES-2 from ``Cost and Performance Baseline for
Fossil Energy Plants Volume 1: Bituminous Coal and Natural Gas to
Electricity'', Revision 2, Report DOE/NETL-2010/1397 (November
2010).
    \509\ ``Cost and Performance Baseline for Fossil Energy Plants
Supplement: Sensitivity to CO2 Capture Rate in Coal-Fired
Power Plants'', DOE/NETL-2015/1720 (June 2015); SCPC rates come from
Exhibit A-2 and IGCC rates come from Exhibit A-4.
    \510\ The comparable emissions on a net basis are: subcritical
PC--1,890 lb CO2/MWh-n; SCPC-1,705 lb CO2/MWh-
n; and IGCC--1,724 lb CO2/MWh-n. (See same references as
for gross emissions provided in the text).
    \511\ Exhibit ES-2 from ``Cost and Performance Baseline for
Fossil Energy Plants Volume 3b: Low Rank Coal to Electricity:
Combustion Cases'', Report DOE/NETL-2010/1463 (March 2011).
---------------------------------------------------------------------------

    Some commenters noted that new coal-fired plants utilizing
supercritical boiler design or IGCC would provide substantial emission
reductions compared to the emissions from the existing subcritical coal
plants that are currently in wide use in the power sector. However,
most of the recent new power sector projects using solid fossil fuel
(coal or petroleum coke) as the primary fuel--both those that have been
constructed and those that have been proposed--are supercritical
boilers and IGCC units. About 60 percent of new coal-fired utility
boiler capacity that has come on-line since 2005 was supercritical and
of the new capacity that came on-line since 2010, about 70 percent was
supercritical. No new coal-fired utility boilers began operation in
either 2013 or 2014. Coal-fired power plants that have come on-line
most recently include AEP's John W. Turk, Jr. Power Plant, which is a
600 MW ultra-supercritical \512\ PC (USCPC) facility located in the
southwest corner of Arkansas, and Duke Energy's Edwardsport plant,
which is a 618 MW

``CCS ready'' \513\ IGCC unit located in Knox County, Indiana. Both of
those facilities came on-line in 2012. It is likely that the units that
initiated operation in 2010 or later were conceived of, planned,
designed, and permitted well before 2010--likely in the early 2000s.
Thus, it seems clear that the power sector had already, at that point,
transitioned to the selection of supercritical boiler technology as
``business as usual'' for new coal-fired power plants. Since that time,
there have been other coal-fired power plants that have been proposed
and almost all of them have been either supercritical boiler designs or
IGCC units. In Table 1 of the Technical Support Document Fossil Fuel-
Fired Boiler and IGCC EGU Projects Under Development: Status and
Approach \514\ for the January 2014 proposal, the EPA listed the
development status of ``potential transitional sources'' (i.e.,
projects that had been proposed and had received Prevention of
Significant Deterioration (PSD) preconstruction permits as of April 13,
2012). Of the 16 proposed EGU projects in Table 1--most of which have
been cancelled or converted to or replaced with NGCC projects--the
majority (nine) are either supercritical PC or IGCC designs. Five of
the proposed projects were CFB designs with only one being a
subcritical PC design.
---------------------------------------------------------------------------

    \512\ Ultra-supercritical (U.S.C.) and advanced ultra-
supercritical (A-U.S.C.) are terms often used to designate a coal-
fired power plant design with steam conditions well above the
critical point.
    \513\ A ``CCS ready'' facility is one that is designed such that
the CCS equipment can be more easily added at a later time.
    \514\ Available in the rulemaking docket (entry: EPA-HQ-OAR-
2013-0495-0024).
---------------------------------------------------------------------------

    The EPA is aware of only one new coal-fired power plant that is
actively in the construction phase. That plant is Mississippi Power's
Kemper County Energy Facility in Kemper County, MS--an IGCC unit that
plans to begin operations in 2016 and will implement partial CCS to
capture approximately 65 percent of the available CO2, which
will be sold for use in EOR operations.
    Considering the direction that the power sector has been taking and
the changes that it is undergoing, identifying a new supercritical unit
as the BSER and requiring an emission limitation based on the
performance of such units thus would provide few, if any, additional
CO2 emission reductions beyond the sector's ``business as
usual''. As noted, for the most part, new sources are already designed
to achieve at least that emission limitation. This criterion does not
itself eliminate supercritical technology from consideration as BSER.
However, existing technologies must be considered in the context of the
range of technically feasible technologies and, as we discuss elsewhere
in this final preamble, partial CCS can achieve emission limitations
beyond business as usual and do so at a reasonable cost.
    The EPA also considered IGCC technology and whether it represents
the BSER for new power plants utilizing coal or other solid fossil
fuels. IGCC units, on a gross-output basis, have inherently lower
CO2 emission rates when compared to similarly-sized SCPC
units. However, the net emission rates and overall emissions to the
atmosphere (i.e., tons of CO2 per year) tend to be more
similar (though still somewhat lower) for new IGCC units when compared
to new SCPC units with the same electrical output. Therefore an
emission limitation based on the expected performance of a new IGCC
unit would result in some CO2 emission reductions from the
segment of the industry that would otherwise construct new PC units,
but not from the segment of the industry that would already construct
new IGCC units. A gross-output-based emission limitation consistent
with the expected performance of a new IGCC unit would still require
some additional control, such as partial CCS, on a new supercritical
boiler.
    As is shown in Section V.J and H, additional emission reductions
beyond those that would result from an emission standard based on a new
SCPC boiler or even a new IGCC unit as the BSER can be achieved at a
reasonable cost. Because practicable emission controls are available
that are of reasonable cost at the source level and that will have
little cost and energy impact at the national level, the EPA is
according significant weight to the factor of amount of emissions
reductions in determining the BSER. As discussed above, the D.C.
Circuit has emphasized this factor in describing the purpose of CAA
section 111 as to achieve ``as much [emission reduction] as
practicable.'' \515\
---------------------------------------------------------------------------

    \515\ Sierra Club, 657 F.2d at 327 & n. 83.
---------------------------------------------------------------------------

b. Lack of Incentive for Technological Innovation
    As discussed above, the EPA is justifying its identification of the
BSER based on its weighing of the factors explicitly identified in CAA
section 111(a)(1), including the amount of the emission reduction.
Under the D.C. Circuit case law, encouraging the development and
implementation of advanced control technology must also be considered
(and, in any case, may reasonably be considered; see Section V.H.3.d
above). Consideration of this factor confirms the EPA's decision not to
identify highly efficient generation technology (without CCS) as the
BSER. At present, CCS technologies are the most promising options to
achieve significant reductions in CO2 emissions from newly
constructed fossil fuel-fired steam generating units. CCS technology is
also now a viable retrofit option for some modified, reconstructed and
existing sources--depending upon the configuration, location and age of
those sources. As CCS technologies are deployed and used more there is
an expectation that, based on previous experience with advanced
technologies, the performance will improve and the implementation costs
will decline. The improved performance and lower costs will provide
additional incentive for further implementation in the future.
    The Intergovernmental Panel on Climate Change (IPCC) recently
released its Fifth Assessment report, \516\ which recognizes that
widespread deployment of CCS is crucial to reach the long term climate
goals. The authors of the report used models to predict the likelihood
of stabilizing the atmospheric concentration of CO2 at 450
ppm by 2050 with or without carbon capture and storage (CCS). They
found that several of the models were not able to reach this goal
without CCS, which underlines the importance of deploying and further
developing CCS on a large scale.
---------------------------------------------------------------------------

    \516\ IPCC, Working Group III, Climate Change 2014: Mitigation
of Climate Change, http://mitigation2014.org/report/publication/.
---------------------------------------------------------------------------

    American Electric Power (AEP), in an evaluation of lessons learned
from the Phase 1 of its Mountaineer CCS project, wrote: ``AEP still
believes the advancement of CCS is critical for the sustainability of
coal-fired generation.'' \517\
---------------------------------------------------------------------------

    \517\ CCS LESSONS LEARNED REPORT American Electric Power
Mountaineer CCS II Project Phase 1, Prepared for The Global CCS
Institute Project # PRO 004, January 23, 2012, page 2. See also AEP
FEED Study at pp. 4, 63 (same). Available at: http://www.globalccsinstitute.com/publications/aep-mountaineer-ii-project-front-end-engineering-and-design-feed-report.
---------------------------------------------------------------------------

    Some commenters felt that the proposed standard of performance for
new steam generating units, based on implementation of partial CCS at
an emission rate of 1,100 lb/MWh-g, would not serve to promote the
increased deployment and implementation of CCS. The commenters argued
that such a standard could instead have the unintended result of
discouraging the further development of advanced coal generating
technologies such as ultra-supercritical boilers and improved IGCC
designs.
    Commenters further argued that such a standard will stifle further

development of CCS technologies. Commenters felt that the standard
would effectively deter the construction of new coal-fired generation--
and, if there is no new coal-fired generation, then there will be no
implementation of CCS technology and, therefore, no need for continued
research and development of CCS technologies. They argued, in fact,
that the best way to promote the development of CCS was to set a
standard that did not rely on it.
    The EPA does not agree with these arguments and, in particular,
does not see how a standard that is not predicated on performance of an
advanced control technology would serve to promote development and
deployment of that advanced control technology. On the contrary, the
history of regulatory actions has shown that emission standards that
are based on performance of advanced control equipment lead to
increased use of that control equipment, and that the absence of a
requirement stifles technology development.
    There is a dramatic instance of this paradigm presented in the
present record. In 2011, AEP deferred construction of a large-scale CCS
retrofit demonstration project on one of its coal-fired power plants
because the state's utility regulators would not approve cost recovery
for CCS investments without a regulatory requirement to reduce
CO2 emissions. AEP's chairman was explicit on this point,
stating in a July 17, 2011 press release announcing the deferral:
    We are placing the project on hold until economic and policy
conditions create a viable path forward . . . We are clearly in a
classic `which comes first?' situation. The commercialization of this
technology is vital if owners of coal-fueled generation are to comply
with potential future climate regulations without prematurely retiring
efficient, cost-effective generating capacity. But as a regulated
utility, it is impossible to gain regulatory approval to recover our
share of the costs for validating and deploying the technology without
federal requirements to reduce greenhouse gas emissions already in
place. The uncertainty also makes it difficult to attract partners to
help fund the industry's share.\518\
---------------------------------------------------------------------------

    \518\ http://www.aep.com/newsroom/newsreleases/?id=1704.
---------------------------------------------------------------------------

    Some commenters also argued that the incremental cost associated
with including CCS at the proposed level would prevent new coal-fired
units from being built. Instead, they advocated for a standard based on
most efficient technology (supercritical) coupled with government
subsidies to advance and promote CCS technology. The final standard is
less stringent than that proposed, and can be met at a lower cost than
the proposed standard, and as explained above in Section V.H, the EPA
has carefully evaluated those costs and finds them to be reasonable.
Further, the record and current economic conditions (fuel costs,
renewables, demand growth, etc.) show that non-economic factors such as
a desire for fuel diversity will likely drive future development of any
new coal-fired EGUs. For this reason, the EPA does not find the
commenters' bare assertions that the incremental cost of CCS
(particularly as reasonably modulated for this final standard) would
make the difference between constructing and not constructing new coal
capacity to be persuasive. Rather, a cost-reasonable standard
reflecting use of the new technology is what will drive new technology
deployment.
    The EPA expects that it is unlikely that a new IGCC unit would
install partial CCS to meet the final standard unless the facility is
built to take advantage of EOR opportunities or to operate as a poly-
generation facility (i.e., to co-produce power along with chemicals or
other products). For new IGCC units, the final standard of performance
can be met by co-firing a small amount of natural gas. Some commenters
argued that IGCC is an advanced technology that, like CCS, should be
promoted. The EPA agrees. IGCC is a low-emitting, versatile technology
that can be used for purposes beyond just power production (as
mentioned just above). Commenters further argued that a requirement to
include partial CCS (at a level to meet the proposed standard of
performance) would serve to deter--rather than promote--more
installation of IGCC technology. We disagree with a similar argument
that commenters make with respect to partial CCS for post-combustion
facilities, but our final standard moots that argument for IGCC
facilities because the final emission limitation of 1,400 lb
CO2/MWh-g will not itself deter installation of IGCC
technology, by the terms of the commenters' own argument.
2. ``Full'' Carbon Capture and Storage (i.e., 90 Percent Capture)
    We also reconsidered whether the emission limitation for new coal-
fired EGUs should be based on the performance of full implementation of
CCS technology. For a newly constructed utility boiler, this would mean
that a post-combustion capture system would be used to treat the entire
flue gas stream to achieve an approximately 90 percent reduction in
CO2 emissions. For a newly constructed IGCC unit, a pre-
combustion capture system would be used to capture CO2 from
a fully shifted gasification syngas stream to achieve an approximately
90 percent reduction in CO2 emissions.
    In the proposal for newly constructed sources, we found that ``full
CCS'' would certainly result in significant CO2 reductions
from any new source implementing the technology. However, we also found
that the costs associated with implementation, on either a new utility
boiler system or a new IGCC unit, are predicted to substantially exceed
the costs for other dispatchable non-NGCC generating options that are
being considered by utilities and project developers (e.g., new nuclear
plants and new biomass-fired units). See 79 FR at 1477. This remains
the case, and indeed, the difference between cost of full capture and
new nuclear technology is estimated to be even greater than at
proposal. The EPA thus is not selecting full capture CCS as BSER.

Q. Summary

    The EPA finds that the best system of emission reduction adequately
demonstrated is a highly efficient supercritical pulverized coal boiler
using post-combustion partial CCS so that CO2 is captured,
compressed and safely stored over the long-term. Properly designed,
operated, and maintained, this best system can achieve a standard of
performance of 1,400 lb CO2/MWh-g, an emission limitation
that is achievable over the 12-operating-month compliance period
considering usual operating variability (including use of different
coal types, periods of startup and shutdown, and malfunction
conditions). This standard of performance is technically feasible,
given that the BSER technology is already operating reliably in full-
scale commercial application. The technology adds cost to a new
facility which the EPA has evaluated and finds to be reasonable because
the costs are in the same range as those for new nuclear generating
capacity--a competing non-NGCC, dispatchable technology that utilities
and project developers are also considering for base load application.
The EPA has also considered capital cost increases associated with use
of post-combustion partial CCS at the level needed to meet the final
standard and found them to be reasonable, and within the range of
capital cost increases for this industry in prior NSPS which have been
adjudicated as reasonable. The EPA's consideration of costs is also
informed by its judgment that new coal-

fired capacity would be constructed not as the most economic option,
but for such purposes as preserving fuel diversity in an energy
portfolio, and so would not be cost competitive with natural gas-fired
capacity, so that some additional cost premium may therefore be
reasonable. The EPA has carefully evaluated the non-air quality health
and environmental impacts of the final standard and found them to be
reasonable: CO2 pipelines and CO2 sequestration
via deep well injection are subject already to rigorous control under
established regulatory programs which assure prevention of
environmental release during transport and storage. In addition, water
use associated with use of partial CCS at the level to meet the final
standard is acceptable, and use of the technology does not impose
significant burdens on energy requirements at either the plant or
national level. The 1,400 lb CO2/MWh-g standard reflecting
performance of the BSER may be achieved without geographic constraint,
both because geologic sequestration and EOR capacity are widely
available and accessible, and also because alternative compliance
pathways are available in the unusual circumstance where a new coal-
fired plant is sited in an area without such access, that area has not
already limited construction of new coal-fired capacity in some way,
and the area cannot be serviced by coal-by-wire. Accordingly, the EPA
finds that the promulgated standard of performance for new fossil fuel-
fired steam electric generating units satisfies the requirements of CAA
section 111(a).

VI. Rationale for Final Standards for Modified Fossil Fuel-Fired
Electric Utility Steam Generating Units

    The EPA has determined that, as proposed, the BSER for steam
generating units that trigger the modification provisions is each
affected unit's own best potential performance as determined by that
unit's historical performance. The final standards of performance are
similar to those proposed in the June 2014 proposal. Differences
between the proposed standards and the final standards issued in this
action reflect responses to comments received on the proposal. Those
changes are described below.
    As noted previously, the EPA is issuing final emission standards
only for affected modified steam generating units that conduct
modifications resulting in a hourly increase in CO2
emissions (mass per hour) of more than 10 percent (``large''
modifications). The EPA is continuing to review the appropriate
standards for modified sources that conduct modifications resulting in
a hourly increase in CO2 emissions (mass per hour) of less
than or equal to 10 percent (``small'' modifications), is not issuing
final standards for those sources in this action, and is withdrawing
the proposed standards for those sources. See Section XV below.

A. Rationale for Final Applicability Criteria for Modified Steam
Generating Units

    Final applicability criteria for modified steam generating EGUs
include those discussed earlier in Section III.A.1 (General
Applicability) and Section III.A.3 (Applicability Specific to Modified
Sources).
    CAA section 111(a)(4) defines a ``modification'' as ``any physical
change in, or change in the method of operation of, a stationary
source'' that either ``increases the amount of any air pollutant
emitted by such source or . . . results in the emission of any air
pollutant not previously emitted.'' Certain types of physical or
operational changes are exempt from consideration as a modification.
Those are described in 40 CFR 60.2, 60.14(e). To be clear, our action
in this final rule, and the discussion below, does not change anything
concerning what constitutes or does not constitute a modification under
the CAA or the EPA's regulations.\519\
---------------------------------------------------------------------------

    \519\ CAA section 111(a)(4); See also 40 CFR 60.14 concerning
what constitutes a modification, how to determine the emission rate,
how to determine an emission increase, and specific actions that are
not, by themselves, considered modifications.
---------------------------------------------------------------------------

    A modified steam generating unit is a source that fits the
definition and applicability criteria of a fossil fuel-fired steam
generating unit and that commences a qualifying modification on or
after June 18, 2014 (the publication date of the proposed modification
standards). 79 FR 34960.
    For the reasons discussed below, the EPA in this final action is
finalizing requirements only for steam generating units that conduct
modifications resulting in an increase in hourly CO2
emissions (mass per hour) of more than 10 percent as compared to the
source's highest hourly emission during the previous five years. With
respect to modifications with smaller increases in CO2
emissions (specifically, steam generating units that conduct
modifications resulting in an increase in hourly CO2
emissions (mass per hour) of 10 percent or less compared to the
source's highest hourly emission during the previous 5 years), the EPA
is not finalizing any standard or other requirements, and is
withdrawing the June 2014 proposal with respect to these sources (see
Section XV below).
    The effect of the EPA's deferral on setting standards for sources
undertaking modifications resulting in smaller increases in
CO2 emissions and the withdrawal of the June 2014 proposal
with respect to such sources is that such sources will continue to be
existing sources and subject to requirements under section 111(d). This
is because an existing source does not always become a new source when
it modifies. Under the definition of ``new source'' in section
111(a)(2), an existing source only becomes a new source if it modifies
after the publication of proposed or final regulations that will be
applicable to it. Thus, if an existing source modifies at a time that
there is no promulgated final standard or pending proposed standard
that will be applicable to it as a modified ``new'' source, that source
is not a new source and continues to be an existing source. Here,
because the EPA is not finalizing standards for sources undertaking
modifications resulting in smaller increases in CO2
emissions and is withdrawing the proposal with respect to such sources,
these sources do not fall within the definition of ``new source'' in
section 111(a)(2) and continue to be an ``existing source'' as defined
in section 111(a)(6). See Section XV below.
    As we discussed in the June 2014 proposal, the EPA has historically
been notified of only a limited number of NSPS modifications \520\
involving fossil steam generating units and therefore predicted that
very few of these units would trigger the modification provisions and
be subject to the proposed standards. Given the limited information
that we have about past modifications, the agency has concluded that it
lacks sufficient information to establish standards of performance for
all types of modifications at steam generating units at this time.
Instead, the EPA has determined that it is appropriate to establish
standards of performance at this time for larger modifications, such as
major facility upgrades involving, for example, the refurbishing or
replacement of steam turbines and other equipment upgrades that result
in substantial increases in a unit's hourly CO2 emissions
rate. The agency has determined, based on its review of public comments
and other publicly available information, that it has adequate
information regarding the types of modifications that could result in
large increases in hourly CO2 emissions, as well as on the
types of

measures available to control emissions from sources that undergo such
modifications, and on the costs and effectiveness of such control
measures, upon which to establish standards of performance for
modifications with large emissions increases at this time.
---------------------------------------------------------------------------

    \520\ NSPS modifications resulting in increases in hourly
emissions of criteria pollutants.
---------------------------------------------------------------------------

    In establishing standards of performance at this time for
modifications with large emissions increases, but not for those with
small increases, the EPA is exercising its policy discretion to
promulgate regulatory requirements in a sequential fashion for classes
of modifications within a source category, accounting for the
information available to the agency, while also focusing initially on
those modifications with the greatest potential environmental impact.
This approach is consistent with the case law that authorizes agencies
to establish a regulatory framework in an incremental fashion, that is,
a step at a time.\521\
---------------------------------------------------------------------------

    \521\ As the U.S. Supreme Court recently stated in Massachusetts
v. EPA, 549 U.S. 497, 524 (2007): `` `Agencies, like legislatures,
do not generally resolve massive problems in one fell regulatory
swoop;' '' and instead they may permissibly implement such
regulatory programs over time, `` `refining their preferred approach
as circumstances change and as they develop a more nuanced
understanding of how best to proceed.' '' See Grand Canyon Air Tour
Coalition v. F.A.A., 154 F.3d 455 (D.C. Cir. 1998), City of Las
Vegas v. Lujan, 891 F.2d 927, 935 (D.C. Cir. 1989), National
Association of Broadcasters v. FCC, 740 F.2d 1190, 1209-14 (D.C.
Cir. 1984). See also, Hazardous Waste Treatment Council v. U.S.
E.P.A., 861 F.2d 277, 287 (D.C. Cir. 1988) (``[A]n agency's failure
to regulate more comprehensively is not ordinarily a basis for
concluding that the regulations already promulgated are invalid.
`The agency might properly take one step at a time.' United States
Brewers Assoc. v. EPA, 600 F.2d 974,982 (D.C. Cir. 1979). Unless the
agency's first step takes it down a path that forecloses more
comprehensive regulation, the first step is not assailable merely
because the agency failed to take a second. The steps may be too
plodding, but that raises an entirely different issue . . . .'').
---------------------------------------------------------------------------

    To be clear, the EPA is not reaching a final decision as to whether
it will regulate modifications with smaller increases, or even that
such modifications should be subject to different requirements than we
are finalizing in this rule for the modifications with larger
increases. We have made no decisions and this matter is not concluded.
We plan to continue to gather information, consider the options for
modifications with smaller increases, and, in the future, develop a
proposal for these modifications or otherwise take appropriate steps.
    As a means of determining the proper threshold between the larger
and smaller increases in CO2 emissions, the EPA examined
changes in CO2 emissions that may result from large,
capital-intensive projects, such as major facility upgrades involving
the refurbishing or replacement of steam turbines and other equipment
upgrades that would significantly increase a unit's capacity to burn
more fossil fuel, thereby resulting in large emissions increases. Major
upgrades such as these could increase a steam generating unit's hourly
CO2 emissions by well over 10 percent.\522\
---------------------------------------------------------------------------

    \522\ See e.g., Power Engineering, Steam Turbine Upgrades Boost
Plant Reliability, Efficiency, available at www.power-eng.com/articles/print/volume-116/issue-11/features/steam-turbine-upgrades-boost-plant-reliability-efficiency.html.
---------------------------------------------------------------------------

    An example of such major upgrade would be work performed at
AmerenUE's Labadie Plant, a facility with four 600-MW (nominal) coal-
fired units located 35 miles west of St. Louis. In the early 2000s,
plant staff conducted process improvements that raised maximum unit
capacity by nearly 10 percent (from 580 MW to 630 MW).\523\ Those
changes included boiler improvements necessitated by its switch from
bituminous to subbituminous coal,\524\ installation of low-
NOX burners, an overfire air system, and advanced computer
controls. One of the performance gains came from upgrading all four
steam turbines, which AmerenUE chose to replace as modules allowing
engineers more freedom to maximize performance unconstrained by the
units' existing outer casing.
---------------------------------------------------------------------------

    \523\ ``Steam turbine upgrading: Low-hanging fruit'', Power (04/
15/2006), www.powermag.com/steam-turbine-upgrading-low-hanging-fruit.
    \524\ Note that a change in coal-type or change in the use of
other raw material does not necessarily constitute an ``operational
change''. See 40 CFR 60.14(e)(4).
---------------------------------------------------------------------------

    Another example is the refurbishment of the 2,100 MW Eskom Arnot
coal-fired power plant in South Africa with a resulting increase in its
power output by 300 MW to 2,400 MW--an increase in capacity of 14
percent.\525\ For each of the plant's six steam generating units, the
company conducted a complete retrofit of the high pressure and
intermediate pressure steam turbines, a capacity upgrade of the low
pressure steam turbine, and the replacement and upgrade of associated
turbine side pumps and auxiliaries. In addition, major upgrades to the
boiler plant were conducted, including supply of new pressure part
components, new burners, and modification to other equipment such as
the coal mills and classifiers, fans, and heaters. Other examples are
provided in a technical memo available in the rulemaking docket.\526\
---------------------------------------------------------------------------

    \525\ www.alstom.com/press-centre/2006/10/alstom-signs-power-plant-upgrade-and-retrofit-contract-with-eskom-in-south-africa/.
    \526\ See ``U.S. DOE Information Relevant to Technical Basis for
``Large Modification'' Threshold'' available in the rulemaking
docket EPA-HQ-OAR-2013-0495.
---------------------------------------------------------------------------

    The EPA does not intend to imply that these specific projects would
have resulted in an increase in hourly CO2 emissions of
greater than 10 percent. Capacity increases are often the result of
efficient improvements or are accompanied by other facility
improvements that can offset emissions increases due to increased fuel
input capacity. However, these examples are intended to show the types
of large, more capital intensive projects that can potentially result
in increases in hourly emissions of CO2 of at least 10
percent.
    The EPA believes that it is reasonable to set the threshold between
``large'' modifications and ``small'' modifications at 10 percent, a
level commensurate with the magnitude of the emissions increases that
could result from the types of projects described above, and we are
issuing a final standard of performance for those sources that conduct
modifications resulting in hourly CO2 emission increases
that exceed that threshold. We are not issuing standards of performance
for those sources that conduct modifications resulting in an hourly
increase of CO2 emissions of less than or equal to 10
percent.
    Therefore, the EPA is withdrawing the proposed standards for those
sources that conduct modifications resulting in a hourly increase in
CO2 emissions (mass per hour) of less than or equal to ten
percent and is not issuing final standards for those sources at this
time. See Section XV below. Utilities, states and others should be
aware that the differentiation between modifications with larger and
smaller increases in CO2 emissions only applies to sources
covered under 40 CFR part 60, subpart TTTT, i.e., it is only applicable
to CO2 emissions from fossil fuel-fired steam generating
units. There is no similar provision for criteria pollutants or for
other source categories. Utilities, states and others should also be
aware that the distinction between large and small modifications only
applies to NSPS modifications. Sources undertaking modifications may
still be subject to requirements of New Source Review under CAA Title I
part C or D (which have different standards for modifications than the
NSPS and require a case-by-case analysis) or other CAA requirements.
    The EPA notes that some commenters expressed concern that a number
of existing fossil steam generating units, in order to fulfill
requirements of an approved CAA section 111(d) plan, may pursue actions
that involve physical or operational changes that result in some
increase in their CO2 emissions on an hourly basis, and thus
constitute

modifications. Some commenters suggested that the EPA should exempt
projects undertaken specifically for the purpose of complying with CAA
section 111(d).
    The EPA does not have sufficient information at this time to
predict the full array of actions that existing steam generating units
may undertake in response to applicable requirements under an approved
CAA section 111(d) plan, or which, if any, of these actions may result
in increases in CO2 hourly emissions. Nevertheless, the EPA
expects that, to the extent actions undertaken by existing steam
generating units in response to 111(d) requirements trigger
modifications, the magnitude of the increases in hourly CO2
emissions associated with such modifications would generally be smaller
and would therefore generally not subject such modifications to the
standards of performance that the EPA is finalizing in this rule for
modified steam generating units with larger increases in hourly
CO2 emissions.

B. Identification of the Best System of Emission Reduction

    The EPA has determined that, as was proposed, the BSER for steam
generating units that trigger the modification provisions is the
affected EGU's own best potential performance as determined by that
source's historical performance.
    The EPA proposed that the BSER for modified steam generating EGUs
is each unit's own best potential performance based on a combination of
best operating practices and equipment upgrades. Specifically, the EPA
co-proposed two alternative standards for modified utility steam
generating units. In the first co-proposed alternative, modified steam
generating EGUs would be subject to a single emission standard
determined by the affected EGU's best demonstrated historical
performance (in the years from 2002 to the time of the modification)
with an additional 2 percent emission reduction. The EPA proposed that
the standard could be met through a combination of best operating
practices and equipment upgrades. To account for facilities that have
already implemented best practices and equipment upgrades, the proposal
also specified that modified facilities would not have to meet an
emission standard more stringent than the corresponding standard for
reconstructed EGUs.
    The EPA also co-proposed that the specific standard for modified
sources would be dependent on the timing of the modification. We
proposed that sources that modify prior to becoming subject to a CAA
section 111(d) plan would be required to meet the same standard
described in the first co-proposal--that is, the modified source would
be required to meet a unit-specific emission limit determined by the
affected EGU's best demonstrated historical performance (in the years
from 2002 to the time of the modification) with an additional 2 percent
emission reduction (based on equipment upgrades). We also proposed that
sources that modify after becoming subject to a CAA section 111(d) plan
would be required to meet a unit-specific emission limit that would be
determined by the CAA section 111(d) implementing authority and would
be based on the source's expected performance after implementation of
identified unit-specific energy efficiency improvement opportunities.
    The final standards in this action do not depend upon when the
modification commences (as long as it commences after June 8, 2014).
The EPA received comments on the June 2014 proposal that called into
question the need to differentiate the standard based on when the
modification was undertaken. Further, commenters noted that the
proposed requirements for sources modifying after becoming subject to a
CAA section 111(d) plan, which were based on energy efficiency
improvement opportunities were vague and that standard setting under
CAA section 111(b) is a federal duty and would require notice-and-
comment rulemaking. The EPA considered those comments and has
determined that we agree that there is no need for subcategories based
on the timing of the modification.

C. BSER Criteria

1. Technical Feasibility
    The EPA based technical feasibility of the unit-specific efficiency
improvement on analyses done to support heat rate improvement for the
proposed CAA section 111(d) emission guidelines (Clean Power Plan).
That work was summarized in Chapter 2 of the TSD, ``GHG Abatement
Measures''.\527\ In response to comments on the proposed Clean Power
Plan, the approach was adjusted, as described in the final CAA section
111(d) emission guidelines. As with proposed actions, the EPA is basing
technical feasibility for final standards for modified source
efficiency improvements on the analyses for heat rate improvements for
the CAA 111(d) final rule.
---------------------------------------------------------------------------

    \527\ Technical Support Documents ``GHG Abatement Measures''
(proposal) and ``GHG Mitigation Measures'' (final) available in the
rulemaking docket EPA-HQ-OAR-2013-0495.
---------------------------------------------------------------------------

2. Cost
    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. As summarized below, we estimate that, on average, the
savings in fuel cost associated with a 4 percent heat rate improvement
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.
    We recognize that our cost analysis just described will represent
the costs for some EGUs better than others because of differences in
EGUs' individual circumstances. We 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, we still expect that the majority 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. The EPA further
notes that the types of large, more capital intensive projects that may
trigger the ``larger modifications'' threshold (i.e., result in an
hourly increase in CO2 emissions of more than 10 percent)
often are undertaken in order to increase the capacity of the source
but also to improve the heat rate or efficiency of the unit.
3. Emission Reductions
    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.
4. Promotion of Technology and Other Systems of Emission Reduction
    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 weigh this
factor, along with the various other factors. With the selection of
emissions controls, modified sources face inherent constraints that
newly constructed greenfield and even 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.

VII. Rationale for Final Standards for Reconstructed Fossil Fuel-Fired
Electric Utility Steam Generating Units

A. Rationale for Final Applicability Criteria for Reconstructed Sources

    The applicability rationale for reconstructed utility steam
generating units is the same as for newly constructed utility steam
generating units. We are finalizing the same general criteria and not
amending the reconstruction provisions included in the general
provisions.

B. Identification of the Best System of Emission Reduction

    In the proposal, the EPA evaluated seven different control
technology configurations to determine the BSER for reconstructed
fossil fuel-fired boiler and IGCC EGUs: (1) The use of partial CCS, (2)
conversion to (or co-firing with) natural gas, (3) the use of CHP, (4)
hybrid power plants, (5) reductions in generation associated with
dispatch changes, renewable generation, and demand side energy
efficiency, (6) efficiency improvements achieved through the use of the
most efficient generation technology, and (7) efficiency improvements
achieved through a combination of best operating practices and
equipment upgrades.
    Although the EPA concluded that the first 4 technologies met most
of the evaluation criteria, namely they are adequately demonstrated,
have reasonable costs and provide GHG emissions reductions, they were
inappropriate for BSER due to site specific constraints for existing
EGUs on a nationwide basis. We rejected best operating practices and
equipment upgrades because we concluded the GHG reductions are not
sufficient to qualify as BSER. The majority of commenters agree with
the EPA's decision that these technologies are not BSER. In contrast,
as described in more detail later in this section a few commenters did
support partial CCS as BSER.
    The fifth option, reductions in generation associated with dispatch
changes, renewable generation, and demand side energy efficiency, is
comparable to application of measures identified in building blocks
two, three and four in the emissions guidelines that we proposed under
CAA section 111(d). We solicited comment on any additional
considerations that the EPA should take into account in the
applicability of building blocks two, three and four in the BSER
determination. Most commenters stated that building blocks two, three
and four should not be considered for reconstructed sources.
    The proposed BSER was based on the performance of the most
efficient generation technology available, which we concluded was the
use of the best available subcritical steam conditions for small units
and the use of supercritical steam conditions for large units. We
concluded this technology to be technically feasible, to have
sufficient emission reductions, to have reasonable costs, and some
opportunity for technological innovation. The proposed emission
standard for these sources was 1,900 lb CO2/MWh-n for units
with a heat input rating of greater than 2,000 MMBtu/h and 2,100 lb
CO2/MWh-n for units with a heat input rating of 2,000 MMBtu/
h or less. The difference in the proposed standards for larger and
smaller units was based on greater availability of higher pressure/
temperature steam turbines (e.g. supercritical steam turbines) for
larger units. As explained in Section III of this preamble, we are
finalizing the standard on a gross output basis for utility steam
generating units. The equivalent gross-output-based standards are 1,800
lb CO2/MWh and 2,000 lb CO2/MWh respectively.
    We solicited comment on multiple aspects of the proposed standards.
First, we solicited comment on a range of 1,600 to 2,000 lb
CO2/MWh-g for large units and 1,800 to 2,200 lb
CO2/MWh-g for small units. We also solicited comment on
whether the standards for utility boilers and IGCC units should be
subcategorized by primary fuel type. In addition, we solicited comment
on if there are sufficient alternate compliance technologies (e.g., co-
firing natural gas) that the small unit subcategory is unnecessary and
should be eliminated. Those small sources would be required to meet the
same emission standard as large utility boilers and IGCC units.
    Many commenters supported the upper limits of the suggested ranges,
saying the standard will be consistently met. Some commenters raised
concerns about the achievability of these limits for the many boiler
and fuel types. A few commenters suggested that there should be
separate subcategories for coal-fired utility boilers and IGCC units,
since IGCC units have demonstrated limits closer to 1,500 lb
CO2/MWh-n and the units' designs are so fundamentally
different. Some commenters said that CFB (due to lower maximum steam
temperatures), IGCC, and traditional boilers each need their own
subcategory. Some commenters suggested that due to high moisture
content and high relative CO2 emissions of lignite, lignite-
fired units should have its own subcategory. Other commenters opposed
the proposed standards for reconstructed units because they thought the
BSER determination for reconstructed subpart Da units was inconsistent
with the BSER determination for newly constructed units. These
commenters stated that the EPA did not provide sufficient justification
for eliminating partial carbon capture and sequestration (CCS). These
commenters also stated that the reason the EPA gave for dismissing CCS
in the proposal was a lack of ``sufficient information about costs.''
These commenters hold that the cost rationale does not apply for
reconstructed coal-fired power plants. The fact that reconstructed
units may face greater costs to comply with a CAA section 111(b)
standard than new sources does not relieve them of their compliance
obligation.
    Based on a review of the comments, we have concluded that both the
proposed BSER and emission standards are appropriate, and we are
finalizing the standards as proposed. Nothing in the comments changed
our view that the BSER for reconstructed steam generating units should
be based on the performance of a well operated and maintained EGU using
the most efficient generation technology available, which we have
concluded is a supercritical pulverized coal (SCPC) or supercritical
circulating fluidized bed (CFB) boiler for large units, and subcritical
for small units. As described at proposal, we have concluded that these
standards are achievable by all the primary coal types. The final
standards for reconstructed utility boilers and IGCC units is 1,800 lb
CO2/MWh-g for sources with a heat input rating of greater
than 2,000 MMBtu/h and 2,000 lb CO2/MWh-g for sources with a
heat input rating of 2,000 MMBtu/h or less.

    While the final emission standards are based on the identified
BSER, a reconstructed EGU would not necessarily have to rebuild the
boiler to use steam temperatures and pressures that are higher than the
original design. As commenters noted, a reconstructed unit is not
required to meet the standards if doing so is deemed to be
``technologically and economically'' infeasible. 40 CFR 60.15(b). This
provision inherently requires case-by-case reconstruction
determinations in the light of considerations of economic and
technological feasibility. However, this case-by-case determination
would consider the identified BSER (the use of the best available steam
conditions), as well as--at a minimum--the first four technologies the
EPA considered, but rejected, as BSER for a nationwide rule. One or
more of these technologies could be technically feasible and reasonable
cost, depending on site specific considerations and, if so, would
likely result in sufficient GHG reductions to comply with the
applicable reconstructed standards. Finally, in some cases, equipment
upgrades and best operating practices would result in sufficient
reductions to achieve the reconstructed standards.

VIII. Summary of Final Standards for Newly Constructed and
Reconstructed Stationary Combustion Turbines

    This section summarizes the final applicability requirements, BSER
determinations, and emission standards for newly constructed and
reconstructed stationary combustion turbines. In addition, it also
summarizes significant differences between the proposed and final
provisions.

A. Applicability Requirements

    We are finalizing BSER determinations and emission standards for
newly constructed and reconstructed stationary combustion turbines that
(1) have a base load rating for fossil fuels greater than 260 GJ/h (250
MMBtu/h) and (2) serve a generator capable of selling more than 25 MW-
net of electricity to the grid. We also are finalizing applicability
requirements that will exempt from the final standards (1) all
stationary combustion turbines that are dedicated non-fossil fuel-fired
units (i.e., combustion turbines capable of combusting 50 percent or
more non-fossil fuel) and subject to a federally enforceable permit
condition restricting annual fossil fuel use to 10 percent or less of a
unit's annual heat input capacity; (2) the large majority of industrial
CHP units (i.e., CHP combustion turbines that are subject to a
federally enforceable permit condition limiting annual net-electric
sales to the product of the unit's net design efficiency multiplied by
the unit's potential output, or 219,000 MWh, whichever is greater); (3)
combustion turbines that are physically incapable of burning natural
gas (i.e., not connected to a natural gas pipeline); and (4) municipal
waste combustors and commercial or industrial solid waste incinerators
(units subject to subparts Eb or CCCC of this part).
    For combustion turbines subject to an emission standard, we are
finalizing three subcategories: base load natural gas-fired units, non-
base load natural gas-fired units, and multi-fuel-fired units. We use
the term base load natural gas-fired units to refer to stationary
combustion turbines that (1) burn over 90 percent natural gas and (2)
sell electricity in excess of their design efficiency (not to exceed 50
percent) multiplied by their potential electric output. To be in this
subcategory, a stationary combustion turbine must exceed the ``natural
gas-use criterion'' on a 12-operating-month rolling average and the
``percentage electric sales'' criterion on both a 12-operating-month
and 3-year rolling average basis. We use the term non-base load natural
gas-fired units to refer to stationary combustion turbines that (1)
burn over 90 percent natural gas and (2) have net-electric sales equal
to or below their design efficiency (not to exceed 50 percent)
multiplied by their potential electric output. These criteria are
calculated on the same rolling average bases as for the base load
subcategory. Finally, we use the term multi-fuel-fired units to refer
to stationary combustion turbines that burn 10 percent or more non-
natural gas on a 12-operating-month rolling average basis. We are not
finalizing the proposed emission standards for modified sources and are
withdrawing those standards. We explain our rationale for these final
decisions in Sections IX and XV of this preamble.

B. Best System of Emission Reduction

    We are finalizing BSER determinations for the three subcategories
of stationary combustion turbines referred to above: base load natural
gas-fired units, non-base load natural gas-fired units, and multi-fuel-
fired units. For newly constructed and reconstructed base load natural
gas-fired stationary combustion turbines, the BSER is the use of
efficient NGCC technology. For newly constructed and reconstructed non-
base load natural gas-fired stationary combustion turbines, the BSER is
the use of clean fuels (i.e., natural gas with an allowance for a small
amount of distillate oil). For multi-fuel-fired stationary combustion
turbines, the BSER is also the use of clean fuels (e.g., natural gas,
ethylene, propane, naphtha, jet fuel kerosene, fuel oils No. 1 and 2,
biodiesel, and landfill gas).

C. Final Emission Standards

    For all newly constructed and reconstructed base load natural gas-
fired combustion turbines, we are finalizing an emission standard of
1,000 lb CO2/MWh-g, calculated on a 12-operating-month
rolling average basis. We are also finalizing an optional emission
standard of 1,030 lb CO2/MWh-n, calculated on a 12-
operating-month rolling average basis, for stationary combustion
turbines in this subcategory. For newly constructed and reconstructed
non-base load natural gas-fired combustion turbines, we are finalizing
a standard of 120 lb CO2/MMBtu, calculated on a 12-
operating-month rolling average basis. For newly constructed and
reconstructed multi-fuel-fired combustion turbines, we are finalizing a
standard of 120 to 160 lb CO2/MMBtu, calculated on a 12-
operating-month rolling average basis. The emission standard for multi-
fuel-fired combustion turbines co-firing natural gas with other fuels
shall be determined at the end of each operating month based on the
percentage of co-fired natural gas. Table 15 summarizes the
subcategories, BSER determinations, and emission standards for
combustion turbines.

           Table 15--Combustion Turbine Subcategories and BSER
------------------------------------------------------------------------
           Subcategory                   BSER          Emission standard
------------------------------------------------------------------------
Base load natural gas-fired       Efficient NGCC....  1,000 lb CO2/MWh-g
 combusiton turbines.                                  or 1,030 lb CO2/
                                                       MWh-n
Non-base load natural gas-fired   Clean fuels.......  120 lb CO2/MMBtu
 combustion turbines.
Multi-fuel-fired combustion       Clean fuels.......  120 to 160 lb CO2/
 turbines.                                             MMBtu \528\
------------------------------------------------------------------------

D. Significant Differences Between Proposed and Final Combustion
Turbine Provisions

    As shown in Tables 16 and 17 below, the proposed rule included
several general applicability criteria and two subcategorization
criteria for combustion turbines. In addition to the proposed
applicability and subcategorization framework, we solicited comment on
a ``broad applicability approach'' that included most combustion
turbines irrespective of the actual amount of electricity sold to the
grid or the actual amount of natural gas burned (i.e., non-base load
units and multi-fuel-fired units, respectively). The broad
applicability approach changed the proposed ``percentage electric
sales'' and ``natural gas-use'' criteria to distinguish among
subcategory-specific emissions standards. Specifically, in the broad
applicability approach, we solicited comment on subjecting non-base
load units and multi-fuel-fired units to ``no emissions standard,''
while still including them in the general applicability. We also
solicited comment on establishing a separate numerical standard for
non-base load units. The final rule retains all of the proposed
applicability criteria in some form, but most closely tracks the broad
applicability approach by finalizing the percentage electric sales and
natural gas-use criteria as thresholds that distinguish among three
subcategories of combustion turbines with separate emissions standards.
---------------------------------------------------------------------------

    \528\ The emission standard for combustion turbines co-firing
natural gas with other fuels shall be determined based on the amount
of co-fired natural gas at the end of each operating month.
---------------------------------------------------------------------------

    The final rule also includes exceptions to the broad applicability
approach that we solicited comment on, with some changes that are
responsive to public comments. Categorical exceptions to the broad
applicability criteria are the exclusions for CHP units, non-fossil
fuel units, and combustion turbines not able to combust natural gas.
First, the proposed applicability criteria did not include CHP units
that were constructed for the purpose of or that actually sell one-
third or less of their potential electric output or 219,000 MWh,
whichever is greater, to the grid. The final rule eliminates the
``constructed for the purpose of'' and actual sales aspects of the
proposal and replaces them with an exemption for CHP units that take
federally enforceable permit conditions restricting net-electric sales
to a percentage of potential electric sales based on the unit's design
efficiency or 219,000 MWh, whichever is greater. Second, the proposed
applicability criteria did not include non-fossil fuel units that burn
10 percent or less fossil fuel on a 3-year rolling average. The final
rule similarly replaces the actual fuel-use aspect of the proposal with
an exemption for non-fossil fuel units that take federally enforceable
permit conditions limiting fossil-fuel use to 10 percent or less of
annual heat input capacity. Finally, the proposed applicability
criteria did not include combustion turbines that burn 90 percent or
less natural gas on a 3-year rolling average basis. In contrast, the
final rule includes most fossil fuel-fired combustion turbines
regardless of the amount of natural gas burned, with an exception for
combustion turbines that are not connected to natural gas pipelines.
Finally, in response to public comments, we are not finalizing the
subcategories for large and small combustion turbines that were
contained in the proposal. Instead, all base load natural gas-fired
combustion turbines must meet an emission standard of 1,000 lb
CO2/MWh-g.

  Table 16--Proposed Applicability Criteria versus Final Applicability
                                Criteria
------------------------------------------------------------------------
                                       Proposed              Final
     Applicability Criteria          Applicability       Applicability
------------------------------------------------------------------------
Base load rating criterion......  Base load rating >  Base load rating >
                                   73 MW (250 MMBtu/   260 GJ/h \529\
                                   h).                 (250 MMBtu/h)
Total electric sales criterion..  Constructed for     Ability to sell >
                                   purpose of and      25 MW-n to the
                                   actually selling    grid
                                   > 219,000 MWh-n
                                   to the grid.
Percentage electric sales         Constructed for     Changed to
 criterion.                        purpose of and      subcategorization
                                   having actual net-  criterion per
                                   sales to the grid   broad
                                   > one-third of      applicability
                                   potential           approach
                                   electric output.
Natural gas-use criterion.......  Actually burns >     Changed
                                   90 percent          to
                                   natural gas.        subcategorization
                                                       criterion per
                                                       broad
                                                       applicability
                                                       approach
                                                       Exemption
                                                       for combustion
                                                       turbines that are
                                                       not connected to
                                                       a natural gas
                                                       supply
Fossil fuel-use criterion.......  Actually burns >    Exemption based on
                                   10 percent fossil   permit condition
                                   fuel.               limiting amount
                                                       of fossil fuel
                                                       burned to <= 10
                                                       percent of annual
                                                       heat input
                                                       capacity
Combined Heat and Power (CHP)     NA................  Exemption based on
 exemption.                                            permit condition
                                                       limiting net-
                                                       electric sales to
                                                       <= design
                                                       efficiency
                                                       multiplied by
                                                       potential
                                                       electric output,
                                                       or 219,000 MWh-n,
                                                       whichever is
                                                       greater
Non-EGU exemption...............  Exemption for       Same as proposal
                                   municipal solid
                                   waste combustors
                                   and commercial or
                                   industrial solid
                                   waste
                                   incinerators.
------------------------------------------------------------------------

       Table 17--Proposed Subcategories versus Final Subcategories
------------------------------------------------------------------------
           Subcategory             Proposed Criteria    Final Criteria
------------------------------------------------------------------------
Small combustion turbine          Base load rating    NA
 subcategory.                      <= 850 MMBtu/h.
Large combustion turbine          Base load rating >  NA
 subcategory.                      850 MMBtu/h.
Base load natural gas-fired base  NA................   Actually
 load combustion turbine                               burns > 90
 subcategory.                                          percent natural
                                                       gas
                                                       Net-
                                                       electric sales >
                                                       design efficiency
                                                       (not to exceed 50
                                                       percent)
                                                       multiplied by
                                                       potential
                                                       electric output
Non-base load natural gas-fired   NA................   Actually
 combustion turbine subcategory.                       burns > 90
                                                       percent natural
                                                       gas
                                                       Net-
                                                       electric sales <=
                                                       design efficiency
                                                       (not to exceed 50
                                                       percent)
                                                       multiplied by
                                                       potential
                                                       electric output
Multi-fuel-fired combustion       NA................  Actually burns <=
 turbine subcategory.                                  90 percent
                                                       natural gas
------------------------------------------------------------------------

IX. Rationale for Final Standards for Newly Constructed and
Reconstructed Stationary Combustion Turbines

    This section discusses the EPA's rationale for the final
applicability criteria, BSER determinations, and standards of
performance for newly constructed and reconstructed stationary
combustion turbines. In this section, we present a summary of what we
proposed, a selection of the significant comments we received, and our
rationale for the final determinations, including how the comments
influenced our decision-making.
---------------------------------------------------------------------------

    \529\ 73 MW is equivalent to 260 GJ/h. We changed units to avoid
potential confusion of MW referring to electric output rather than
heat input.
---------------------------------------------------------------------------

A. Applicability

    This section describes the proposed applicability criteria,
applicability issues we specifically solicited comment on, the relevant
significant comments, and the final applicability criteria. We also
provide our rationale for finalizing applicability criteria based
strictly on design and permit restrictions rather than actual operating
characteristics. Finally, we explain why the proposed percentage
electric sales and natural gas-use applicability criteria are being
finalized instead as criteria to distinguish between separate
subcategories of stationary combustion turbines.
1. Proposed Applicability Criteria
    In the January 2014 proposal, we proposed several applicability
criteria for stationary combustion turbines. Specifically, to be
subject to the proposed emission standards, we proposed that a unit
must (1) be capable of combusting more than 73 MW (250 MMBtu/h) heat
input of fossil fuel; (2) be constructed for the purpose of supplying
and actually supply more than one-third of its potential electric
output capacity to a utility power distribution system for sale (that
is, to the grid) on a 3-year rolling average; (3) be constructed for
the purpose of supplying and actually supply more than 219,000 MWh net-
electric output to the grid on a 3-year rolling average; (4) combust
over 10 percent fossil fuel on a 3-year rolling average; and (5)
combust over 90 percent natural gas on a 3-year rolling average. We
proposed exempting municipal solid waste combustors and commercial and
industrial solid waste incinerators.
    Under these proposed applicability criteria, two types of
stationary combustion turbines that are currently subject to criteria
pollutant standards under subpart KKKK would not have been subject to
CO2 standards. The first type was stationary combustion
turbines that are constructed for the purpose of selling and that
actually sell one-third or less of their potential output or 219,000
MWh or less to the grid on a 3-year rolling average basis (i.e., non-
base load units). The second type was combustion turbines that actually
combust 90 percent or less natural gas on a 3-year rolling average
basis (i.e., multi-fuel-fired units).
    We proposed the electric sales criteria in part because they
already exist in other regulatory contexts (e.g., the coal-fired EGU
criteria pollutant NSPS) and would promote consistency between
regulations. Our understanding at proposal was that the percentage
electric sales criterion would distinguish between non-base load units
(e.g., low capital cost, flexible, but relatively inefficient simple
cycle units) and base load units (i.e., higher capital cost, less
flexible, but relatively efficient combined cycle units).
    While the proposed applicability criteria did not explicitly exempt
simple cycle combustion turbines from the emission standards, we
concluded that, as a practical matter, the vast majority of simple
cycle turbines would be excluded because they historically have
operated as peaking units and, on average, have sold less than five
percent of their potential electric output on an annual basis, well
below the proposed one-third electric sales threshold.
a. Solicitation of comment on applicability, generally
    We solicited comment on a range of issues related to applicability.
In conjunction with the proposed one-third (i.e., 33.3 percent)
electric sales threshold, we solicited comment on a threshold between
20 to 40 percent of potential electric output. We also solicited
comment on a variable percentage electric sales criterion, which would
allow more efficient, lower emitting turbines to run for longer periods
of operation before becoming subject to the standards of performance.
Under this ``sliding scale'' approach, the percentage electric sales
criterion would be based on the net design efficiency of the combustion
turbine being installed. In this way, more efficient combustion
turbines would be able to sell a greater portion of their potential
electric output compared with less efficient combustion turbines before
becoming subject to an emission standard. This approach had the benefit
of incentivizing the development and installation of more efficient
simple cycle combustion turbines to serve peak load.
    We also solicited comment on whether the percentage electric sales
criterion for stationary combustion turbines should be defined on a
single calendar year basis. In addition, we solicited comment on
eliminating the 219,000 MWh aspect of the total electric sales
criterion to eliminate any incentive for generators to install
multiple, small, less-efficient stationary combustion turbines that
would be exempt due to their lower output. We further solicited comment
on whether to provide an explicit exemption for all simple cycle
combustion turbines regardless of the amount of electricity sold. We
additionally solicited comment on how to implement the proposed
electric sales, fossil fuel-use, and natural

gas-use criteria given that they were to be evaluated as 3-year rolling
averages during the first three years of operation, and we requested
comment on appropriate monitoring, recordkeeping, and reporting
requirements. We specifically solicited comment on whether these
proposed requirements raised implementation issues because they were
based on source operation after construction has occurred.
    We also solicited comment on excluding electricity sold during
system emergencies from the calculation of percentage electric sales.
The rationale for this exclusion was that simple cycle combustion
turbines intended only for peaking applications might be required to
operate above the proposed percentage electric sales threshold if a
major power plant or transmission line became unexpectedly unavailable
for an extended period of time. The EPA proposed that this flexibility
would be appropriate if the unit were called upon to run after all
other available generating assets were already running at full load.
b. Solicitation of comment on broad applicability approach
    In both the January 2014 proposal for newly constructed EGUs and
the June 2014 proposal for modified and reconstructed EGUs, the EPA
solicited comment on finalizing a broad applicability approach instead
of the proposed approach. Under the proposed approach, a stationary
combustion turbine could be an affected EGU one year, but not the next,
depending on the unit's actual electric sales and the composition of
fuel burned. The broad applicability approach is consistent with
historical NSPS applicability approaches that are based on design
criteria and include different emission standards for subcategories
that are distinguished by operating characteristics. Specifically, we
solicited comment on whether we should completely remove the electric
sales and natural gas-use criteria from the general applicability
framework. Instead, the percentage electric sales and natural gas-use
thresholds would serve as subcategorization criteria for distinguishing
among classes of EGUs and subcategory-specific emissions standards.
Under this broad applicability approach, the ``constructed for the
purpose of'' component of the percentage electric sales criterion would
be completely eliminated so that applicability for combustion turbines
would be determined only by a unit's base load rating (i.e., greater
than 260 GJ/h (250 MMBtu/h)) and its capability to sell power to a
utility distribution system (i.e., serving a generator capable of
selling more than 25 MW). In contrast to the proposed applicability
criteria, under the broad applicability approach, non-base load (e.g.,
simple cycle) and multi-fuel-fired (e.g., oil-fired) combustion
turbines would remain subject to the rule regardless of their electric
sales or fuel use. We solicited comment on all aspects of this ``broad
applicability approach,'' including the extent to which it would
achieve our policy objective of assuring that owners and operators
install NGCC combustion turbines if they plan to sell more than the
specified electric sales threshold to the grid.
2. Comments on Applicability
    This section summarizes the comments we received specific to each
of the proposed applicability criteria. We also received more general
comments on the scope of the proposed framework as compared to the
scope of the broad applicability approach. Comments on applicability
for dedicated non-fossil and CHP units are discussed in Section III.
a. Base load rating criterion
    Many commenters supported a base load rating of 260 GJ/h (250
MMBtu/h) because it is generally consistent with the threshold used in
states participating in the Regional Greenhouse Gas Initiative (RGGI)
and under Title IV programs. Other commenters opposed the proposed
applicability thresholds and stated that all new, modified, and
reconstructed units that sell electricity to the grid, including small
EGUs and simple cycle combustion turbines, should be affected EGUs
because they would otherwise have a competitive advantage in energy
markets as they would not be required to internalize the costs of
compliance.
b. Total electric sales criterion