individual components of a new generation project with CCS have been
previously demonstrated. For example, capturing CO2 from a
coal gasification syngas stream has been occurring for more than ten
years at the Dakota Gasification facility. Experience gained at that
facility can inform design and operational choices of a new IGCC
implementing partial CCS.
    For all these reasons, the next IGCC and SCPC facilities with CCS
can be expected to be less expensive than the current FOAK projects,
but more expensive than the NOAK facilities with CCS that construct
when CCS has become a fully mature technology. The costs in Table 6
reflect those next-of-a-kind costs.
    The EPA has also examined costs of new non-fossil fueled power
generation options. These options are shown in Table 7 below.

   Table 7--Range of Levelized Cost of Electricity for Non-Fossil Fuel
  Electric Generating Technologies, Excluding Transmission Costs \230\
                                  \231\
------------------------------------------------------------------------
                                                      Levelized cost of
                    Technology                      electricity  ($2011/
                                                            MWh)
------------------------------------------------------------------------
Nuclear...........................................               103-114
Biomass...........................................                97-130
Geothermal........................................                 80-99
Combustion Turbine................................                87-116
Onshore Wind......................................                 70-97
Offshore Wind.....................................               177-289
Solar PV \232\....................................               109-220
Solar Thermal.....................................               184-412
Nuclear...........................................               103-114
Biomass...........................................                97-130
Geothermal........................................                 80-99
------------------------------------------------------------------------

    It is important to note here that both the EIA and the EPA apply a
climate uncertainty adder (CUA)--represented by a three percent
increase to the weighted average cost of capital--to certain coal-fired
capacity types. The EIA developed the CUA to address the disconnect
between power sector modeling absent GHG regulation and the widespread
use of a cost of CO2 emissions in power sector resource
planning.
---------------------------------------------------------------------------

    \230\ Data for non-fossil fuel-fired generation comes from DOE
Energy Information Administration (EIA) Annual Energy Outlook (AEO)
2013. Levelized Cost of Electricity (LCOE) estimates come from
http://www.eia.gov/forecasts/aeo/electricity_generation.cfm. To
maintain consistency with DOE/NETL estimates in Table 6, the EIA
estimates provided in this table do not include transmission
investment.
    \231\ The LCOE estimates in Table 7 are presented as a range
that reflects EIA's view on the regional variation in local labor
markets, cost and availability of fuel, and renewable resources. The
capacity factor ranges for renewable non-dispatchable technologies
are as follows: Wind--30 to 39 percent, Wind Offshore--33 to 42
percent, Solar PV--22 to 32 percent, and Solar Thermal--11 to 26
percent. Capacity factors for dispatchable non-fossil fueled
technologies are as follows: Nuclear--90 percent, Biomass--83
percent, and Geothermal--92 percent. There is no capacity credit
provided to dispatchable resources.
    \232\ Costs are expressed in terms of net AC power available to
the grid for the installed capacity.
---------------------------------------------------------------------------

    The CUA reflects the additional planning cost typically assigned by
project developers and utilities to GHG-intensive projects in a context
of climate uncertainty. The EPA believes the CUA is consistent with the
industry's planning and evaluation framework (demonstrable through IRPs
and PUC orders) and is therefore necessary to adopt in evaluating the
cost competitiveness of alternative generating technologies.
    EPA believes the CUA is relevant in considering the range of costs
that power companies are willing to pay for generation alternatives to
natural gas. To the extent that a handful of project developers are
still considering coal without CCS, EPA believes, based both on the
analysis the EIA undertook in developing the CUA approach and the EPA's
review of IRPs,\233\ they must fall into one of two classes. The first,
which is the minority, is not factoring in any form of a CUA. The
second, which is the majority, assume that coal-fired power plants
without CCS entail additional costs due to the risk of future
regulation of CO2. Factoring in risk associated with
CO2 suggests that these companies are, in fact, willing to
pay the higher cost for coal without CCS (even if they are not actually
incurring those costs today). For these reasons, EPA believes that it
is appropriate to consider the cost of coal without CCS to include the
CUA in the range of costs that utilities are willing to pay for
alternatives to natural gas.
---------------------------------------------------------------------------

    \233\ See Technical Support Document: ``Review of Electric
Utility Integrated Resource Plans'' (Docket EPA-HQ-OAR-2013-0495).
---------------------------------------------------------------------------

    The EPA is requesting comment on all aspects of the CUA, including
its magnitude and technology-specific application, to ensure that the
EPA's supporting analysis best reflects the current standards and
practices of the power sector's long-term planning process.
2. Comparison With the Costs of Other New Power Generation Options
    As Tables 6 and 7 above show, while new coal-fired generation that
includes CCS is more expensive than either new coal-fired generation
without CCS or new NGCC generation, it is competitive with new nuclear
power, which, besides natural gas combustion turbines, is the principal
other option often considered for providing new base load power. It is
also competitive with biomass-fired generation, which is another
generation technology often considered for base load power.\234\ A
review of utility IRPs shows that a number of companies are considering
new nuclear power as an option for new base load generation capacity in
lieu of new coal-fired generation with or without CCS, because,
according to the IRPs, nuclear power is a cost-effective way to
generate base load electricity that addresses risks associated with
potential future carbon liabilities. New fossil fuel-fired generation
that includes CCS serves the same basic function as new nuclear power:
providing base load power with a lower carbon footprint. New coal-fired
generation that incorporates partial CCS that is sufficient to meet the
CO2 emission limitation that we are proposing in today's
action (1,100 lb CO2/MWh) would have a similar levelized
cost of electricity (LCOE) as a new nuclear power plant (about $103/
MWh-$114/MWh). This indicates that, at the proposed emission limitation
of 1,100 lb CO2/MWh, the cost of new coal-fired generation
that includes CCS is reasonable today.
---------------------------------------------------------------------------

    \234\ Although geothermal energy is also generally considered
for base load power, it is limited in availability. The other low-
GHG emitting generation listed in Table 4--solar and wind--are not
used for base load.
---------------------------------------------------------------------------

3. Costs of ``Full Capture'' CCS
    As noted in Table 6, above, and discussed in the RIA \235\ for this
rulemaking, implementation of CCS to achieve 90 percent CO2
capture adds considerably to the LCOE from a new SCPC or IGCC unit. The
LCOE for a new SCPC and a new IGCC, both without CCS, are estimated to
be $92/MWh and $97/MWh, respectively. The corresponding costs with
implementation of ``full capture'' CCS are $147/MWh for the new SCPC
unit and $136/MWh for the new IGCC unit. These costs exceed what
project developers have been willing to pay for other low GHG-emitting
base load generating technologies (e.g., nuclear) that also provide
energy diversity. For that reason alone, we do not believe that the
costs of full implementation of CCS are reasonable at this time.
---------------------------------------------------------------------------

    \235\ Regulatory Impact Analysis for the Standards of
Performance for Greenhouse Gas Emissions for New Fossil Fuel-Fired
Electric Utility Steam Generating Units and Stationary Combustion
Turbines (available in the rulemaking docket EPA-HQ-OAR-2013-0495).
---------------------------------------------------------------------------

4. Reasonableness of Costs of Partial CCS
    As noted, the current costs of coal, natural gas, and construction
of coal-fired or natural gas-fired EGUs have led to little currently
announced or projected new coal-fired generating capacity. This very
likely reflects the large price differential between the cost of a new
NGCC (cost of electricity: $59/MWh at a natural gas price of $6.11/
MMBtu) and SCPC without CCS (cost of electricity: $92/MWh) and IGCC
without CCS (cost of electricity: $97/MWh), coupled with a leveling of
demand for electricity and the recent increase in renewable sources.
    We observe that most of the industry appears to take the view that
the price of natural gas will remain sufficiently low for at least a
long enough period into the future that new natural-gas fired
electricity generation will be less expensive than new coal-fired
generation. As a result, in most cases, customers or utilities that
contract for

new generation are doing so for natural gas-fired generation. Long-term
contracts for electricity supply are commonly for a 25-year period;
thus, most of the industry appears to consider contracting for new
natural gas-fired generation for a 25-year period to be the most
economical of their choices.
    As shown in Table 6, we estimate that a new SCPC plant costs $92/
MWh, which is $33/MWh, or about 56 percent higher than the new NGCC
cost of $59/MWh. Limiting the emission rate to 1,100 lb CO2/
MWh (which can be achieved by adding partial CCS), without sale of
captured CO2 for EOR, would add another $18/MWh to the cost
of electricity, for a total of $110/MWh. Thus, the total additional
cost to meet the proposed standard by implementing partial capture CCS
(without revenues from CO2 sales for EOR) is about half the
additional cost of coal-fired generation, compared to natural-gas fired
generation.
    We are aware of another segment of the industry, which includes
electricity suppliers who have indicated a preference for new coal-
fired generation to establish or maintain fuel diversity in their
generation portfolio because their customers have expressed a
willingness to pay a premium for that diversity. It appears these
utilities and project developers see lower risks to long-term reliance
on coal-fired generation and greater risks to long-term reliance on
natural gas-fired generation, compared to the rest of the industry.
    We consider the costs of CCS to be reasonable for this segment of
the industry as well. The additional costs of CCS for new SCPC of $18/
MWh LCOE ($110/MWh for SCPC with partial CCS compared to $92/MWh for
SCPC without CCS) are only about half as much as the additional costs
that are already needed to be incurred to develop coal-fired
electricity as compared to new NGCC generation ($92/MWh for SCPC
without CCS compared to $59 MWh for NGCC at a natural gas price of
$6.11/MMBtu). Moreover, it is possible that under these circumstances,
the demand for the electricity would be inelastic with respect to the
price because it may not depend on cost as much as on a demand for
energy diversity. These circumstances would be similar to the Portland
Cement (1975) case, discussed above, in which the D.C. Circuit upheld
NSPS controls that increased capital and operating costs by a
substantial percentage because the demand for the goods was inelastic
with respect to price, so that the industry could pass along the
costs.\236\
---------------------------------------------------------------------------

    \236\ Portland Cement Ass'n v. EPA, 513 F.2d 506, 508 (D.C. Cir.
1975).
---------------------------------------------------------------------------

    In addition, we consider the costs of partial CCS to be reasonable
because a segment of the industry is already accommodating them. As
noted, a segment of the industry consists of the several coal-fired EGU
projects that already incorporate at least partial CCS. These projects,
which are each progressing, include Kemper, TCEP, and HECA. Each is an
IGCC plant that expects to generate profits from the sale of products
that result from coal gasification, in addition to the sale of
electricity. It is true that each of these projects has received DOE
grants to encourage the development of CCS technology, but we do not
consider such government subsidies to mean that the costs of CCS would
otherwise be unreasonable. As we noted in the original proposal for
this rulemaking,\237\ many types of electricity generation receive
government subsidies. For example, nuclear power is the beneficiary of
the Price-Anderson Act, which partially indemnifies nuclear power
plants against liability claims arising from nuclear incidents,\238\
and domestic oil and gas production,\239\ coal exploration and
development,\240\ and renewable energy generation \241\ are each the
beneficiary of Federal tax incentives.
---------------------------------------------------------------------------

    \237\ 77 FR 22418/3.
    \238\ See Duke Power Co. v. Carolina Environmental Study Group,
438 U.S. 59 (1978).
    \239\ See Internal Revenue Code section 263.
    \240\ See ``General Explanations of the Administration's Fiscal
Year 2013 Revenue Proposals,'' pp. 120-24. http://www.treasury.gov/resource-center/tax-policy/Documents/General-Explanations-FY2013.pdf.
    \241\ See Internal Revenue Code section 45.
---------------------------------------------------------------------------

5. Opportunities to Further Reduce the Costs of Partial CCS
a. Enhanced Oil Recovery
    While the reasons noted above are sufficient to justify the
reasonableness of the costs of partial CCS, in most cases, we believe
that the actual costs will be less. One reason is the availability of
EOR. As noted, EOR is being actively used in various counties in the
U.S., and CO2 pipelines extend into those counties from, in
some cases, hundreds of miles away. We consider areas in close
proximity to active EOR locations, including the pipelines that extend
into those locations, to be places where EOR is available.
    We recognize that, at present, certain locations are far enough
away from either oilfields with EOR availability or pipelines to those
oil fields that any coal-fired power plants that build in those
locations would incur costs to build pipeline extensions that may
render EOR non-economical. Those locations are relatively limited when
legal or practical limits on building coal-fired power plants are taken
into account. For example, some states with locations that are not
located near EOR availability are not expected to have new coal-fired
builds without CCS in any event, for legal or practical reasons. A
number of States, at least in the short term, already have high reserve
margins and/or have large renewable targets which push new decisions
towards renewables and quick starting natural gas to provide backup to
renewables over coal-fired generation.
    In addition, it is important to note that coal-fired power plants
that build in any particular location may serve demand in a wide area.
There are many examples where coal-fired power generated in one state
is used to supply electricity in other states. For instance,
historically, nearly 40 percent of the power for the City of Los
Angeles was provided from two coal-fired power plants located in
Arizona and Utah. In another example, Idaho Power, which serves
customers in Idaho and Eastern Oregon, meets its demand in part from
coal-fired power plants located in Wyoming and Nevada.
    As a result, the geographic scope of areas in which EOR is
available to defray the costs of CCS should be considered to be large.
The costs provided in Table 6 show how the ability to sell
CO2 for utilization in EOR can significantly affect the
overall costs of the project.
    We also considered how the opportunity to sell captured
CO2 for EOR may affect the costs for new units implementing
full capture CCS. We previously indicated that the costs--$147/MWh for
the new SCPC unit and $136/MWh for the new IGCC unit--are not
reasonable and we rejected that option as BSER on that basis. We
estimated that the SCPC with full capture LCOE could be reduced to
between $93 and $115/MWh (depending on selling price of the
CO2) and the IGCC with full capture could be reduced between
$91 and $109/MWh (again, depending upon the selling price of the
CO2). These costs are similar with the reasonable costs for
partial capture similar units with no opportunity to sell captured
CO2 for EOR. This indicates that in some cases (Summit's
TCEP, for example), developers may determine that a new unit with full
capture is economically viable. However, this factor alone does not
lead us to conclude that full capture CCS should be BSER. When
considered in

conjunction with other factors, such as the cost of full CCS where EOR
is not available and the fact that more projects using partial CCS than
full CCS are underway, the EPA believes that partial CCS should be
considered BSER.
b. Government Subsidies
    In some instances, the costs of CCS can be defrayed by grants or
other benefits provided by the DOE or the states. Although, for the
reasons noted earlier, we consider the current costs of partial-capture
CCS even without subsidization to be reasonable, the availability of
these governmental subsidies supports the reasonableness of the costs.
    The 2010 Interagency Task Force Report on CCS report described the
DOE program as follows:

    The DOE is currently pursuing multiple demonstration projects
using $3.4 billion of available budgetary resources from the
American Recovery and Reinvestment Act in addition to prior year
appropriations. Up to ten integrated CCS demonstration projects
supported by DOE are intended to begin operation by 2016 in the
United States. These demonstrations will integrate current CCS
technologies with commercial-scale power and industrial plants to
prove that they can be permitted and operated safely and reliably.
New power plant applications will focus on integrating pre-
combustion CO2 capture, transport, and storage with IGCC
technology. Power plant retrofit and industrial applications will
demonstrate integrated post-combustion capture.\242\
---------------------------------------------------------------------------

    \242\ Task Force Report on CCS, p. 76

    DOE allocated some $3.4 billion for 5-10 projects, and has
committed $2.2 billion for 5 projects to date. In addition, various
other federal and state incentives are also available to many projects.
The 2010 Interagency Task Force on CCS, in surveying all of the federal
and state benefits available, concluded that the DOE grants, ``plus . .
. federal loan guarantees, tax incentives, and state-level drivers,
cover a large group of potential CCS options.'' \243\
---------------------------------------------------------------------------

    \243\ Task Force Report on CCS, p. 76
---------------------------------------------------------------------------

    In addition, regulatory programs may serve to defray the costs of
CCS, including, for example, Clean Energy Standards or guaranteed
electricity purchase price agreements.\244\
---------------------------------------------------------------------------

    \244\ See Center for Climate and Energy Solutions, ``Financial
Incentives for CCS''--available at http://www.c2es.org/.
---------------------------------------------------------------------------

    As noted above and in the April 2012 proposal, the need for
subsidies to support emerging energy systems and new control
technologies is not unusual. Each of the major types of energy used to
generate electricity has been or is currently being supported by some
type of government subsidy such as tax benefits, loan guarantees, low-
cost leases, or direct expenditures for some aspect of development and
utilization, ranging from exploration to control installation. This is
true for fossil fuel-fired; as well as nuclear-, geothermal-, wind-,
and solar-generated electricity.\245\
---------------------------------------------------------------------------

    \245\ 77 FR 22418/3.
---------------------------------------------------------------------------

c. Expected Reductions in the Costs of CCS
    The EPA reasonably projects that the costs of CCS will decrease
over time as the technology becomes more widely used. Although, for the
reasons noted earlier, we consider the current costs of CCS to be
reasonable, the projected decrease in those costs further supports
their reasonableness. The D.C. Circuit case law that authorizes
determining the ``best'' available technology on the basis of
reasonable future projections supports taking into account projected
cost reductions as a way to support the reasonableness of the costs.
    As noted above, the D.C. Circuit, in the 1973 Portland Cement Ass'n
v. Ruckelshaus case, stated that the EPA, in identifying the ``best
system of emission reduction . . . adequately demonstrated,'' may
``look[ ] toward what may fairly be projected for the regulated future,
rather than the state of the art at present. . . .'' \246\ In the 1999
Lignite Energy Council v. EPA case, the Court elaborated:
---------------------------------------------------------------------------

    \246\ Portland Cement Ass'n v. Ruckelshaus, 486 F.2d 375, 391
(D.C. Cir. 1973), quoted in Lignite Energy Council v. EPA, 198 F.3d
930, 933-34 (D.C. Cir. 1999).

    Of course, where data are unavailable, EPA may not base its
determination that a technology is adequately demonstrated or that a
standard is achievable on mere speculation or conjecture . . . but
EPA may compensate for a shortage of data through the use of other
qualitative methods, including the reasonable extrapolation of a
technology's performance in other industries.\247\
---------------------------------------------------------------------------

    \247\ Lignite Energy Council v. EPA, 198 F.3d 930, 934 (D.C.
Cir. 1999). Based on this view that EPA may extrapolate from other
industries, the Court in the Lignite Energy Council v. EPA case
upheld a control technology as being ``adequately demonstrated'' for
coal-fired industrial boilers because the technology was utilized by
utility boilers.

It is logical to read these statements in the D.C. Circuit case law to
apply as well to the cost component of the ``best system of emission
---------------------------------------------------------------------------
reduction . . . adequately demonstrated.''

    We expect the costs of CCS technologies to decrease for several
reasons. We expect that significant additional knowledge will be gained
from deployment and operation of at least two new coal-fired generation
projects that include CCS. These projects are the Southern Company's
Kemper County Energy Facility IGCC with CCS and the Boundary Dam CCS
project on a conventional coal-fired power plant in Canada. They are
currently under construction and are expected to commence operation
next year. In addition there are several other CCS projects in advanced
stages of development in the U.S. (e.g., the Texas Clean Energy
Project, the Hydrogen Energy California Project, and the Future Gen
project in Illinois) that may also provide additional information. In
addition, research is underway to reduce CO2 capture costs
and to improve performance. The DOE/NETL sponsors an extensive
research, development and demonstration program that is focused on
developing advanced technology options designed to dramatically lower
the cost of capturing CO2 from fossil-fuel energy plants
compared to today's available capture technologies. The DOE/NETL
estimates that using today's available CCS technologies would add
significantly to the cost of electricity for a new pulverized coal
plant, and the cost of electricity for a new advanced gasification-
based plant would be increased by approximately half of the increase at
a comparable PC facility. (Note that these cost increases would be less
for the partial capture standard being proposed in today's document.)
The CCS research, development and demonstration program is aggressively
pursuing efforts to reduce these costs to a less than 30 percent
increase in the cost of electricity for PC power plants and a less than
10 percent increase in the cost of electricity for new gasification-
based power plants.\248\ The large-scale CO2 capture
demonstrations that are currently planned and in some cases underway,
under the DOE's initiatives, as well as other domestic and
international projects, will generate operational knowledge and enable
continued commercialization and deployment of these technologies.
---------------------------------------------------------------------------

    \248\ DOE/NETL Carbon Dioxide Capture and Storage RD&D Roadmap,
U.S. Department of Energy National Energy Technology Laboratory,
December 2010.
---------------------------------------------------------------------------

    Gas absorption processes using chemical solvents, such as amines,
to separate CO2 from other gases have been in use since the
1930s in the natural gas industry and to produce food and chemical
grade CO2. The advancement of amine-based solvents is an
example of technology development that has improved the cost and
performance of CO2 capture. Most single component amine
systems are not practical in a flue

gas environment as the amine will rapidly degrade in the presence of
oxygen and other contaminants. The Fluor Econamine FG\SM\ process uses
a monoethanolamine (MEA) formulation specially designed to recover
CO2 and contains a corrosion inhibitor that allows the use
of less expensive, conventional materials of construction. Other
commercially available processes use sterically hindered amine
formulations (for example, the Mitsubishi Heavy Industries KS-1
solvent) which are less susceptible to degradation and corrosion
issues. The DOE/NETL and private industry are continuing to sponsor
research on advanced solvents (including new classes of amines) to
improve the CO2 capture performance and reduce costs.
    Significant reductions in the cost of CO2 capture would
be consistent with overall experience with the cost of pollution
control technology. A significant body of literature suggests that the
per-unit cost of producing or using a given technology declines as
experience with that technology increases over time,\249\ and this has
certainly been the case with air pollution control technologies.
Reductions in the cost of air pollution control technologies as a
result of learning-by-doing, reductions in financial premiums related
to risk, research and development investments, and other factors have
been observed over the decades.
---------------------------------------------------------------------------

    \249\ These studies include: John M. Dutton and Annie Thomas,
``Treating Progress Functions as a Managerial Opportunity,'' Academy
of Management review, 1984, vol. 9, No. 2, 235-247; Dennis Epple,
Linda Argote, and Rukmini Devadas, ``Organizational Learning Curves:
A Method for Investigating Intra-plant Transfer of Knowledge
Acquired Through Learning by Doing,'' Organizational Science, Vol.
2, No. 1 (February 1991); International Energy Agency, Experience
Curves for Energy Technology Policy (2000); and Paul L. Joskow and
Nancy L. Rose, ``The Effects of Technological Change, Experience,
and Environmental Regulation on the Construction Cost of Coal-
Burning Generating Units,'' RAND Journal of Economics, Vol. 16,
Issue 1, 1-27 (1985). See discussion in ``The Benefits and Costs of
the Clean Air Act from 1990 to 2020,'' U.S. EPA, Office of Air and
Radiation (April 2011).
---------------------------------------------------------------------------

    In addition, we note that the 2010 Interagency Task Force on CCS
report recognized that CCS would not become more widely available
without a regulatory framework that promoted CCS or a strong price
signal for CO2. Today's action is an important component in
developing that framework.

G. Promotion of Technology

    It is clear that identifying partial CCS as the BSER promotes the
utilization of CCS because any new fossil fuel-fired utility boiler or
IGCC unit will need to install partial capture CCS in order to meet the
emission standard. Particularly because the technology is relatively
new, additional utilization is expected to result in improvements in
the performance technology and in cost reductions. Moreover,
identifying partial capture CCS as the BSER will encourage continued
research and development efforts, such as those sponsored by the DOE/
NETL. In contrast, not identifying partial CCS as the BSER could
potentially impede further utilization and development of CCS. It is
important to promote deployment and further development of CCS
technologies because they are the only technologies that are currently
available or are expected to be available in the foreseeable future
that can make meaningful reductions in CO2 emissions from
fossil fuel-fired utility boilers and IGCC units.
    Identifying partial CCS as the BSER also promotes further use of
EOR because, as a practical matter, we expect that new fossil fuel-
fired EGUs that install CCS will generally make the captured
CO2 available for use in EOR operations. The use of EOR
lowers costs for production of domestic oil, which promotes the
important goal of energy independence.

H. Nationwide, Longer-Term Perspective

    As noted, the D.C. Circuit in Sierra Club held:

The language of [the definition of ``standard of performance'' in]
section 111 . . . gives EPA authority when determining the best . .
. system to weigh cost, energy, and environmental impacts in the
broadest sense at the national and regional levels and over time as
opposed to simply at the plant level in the immediate present.\250\
---------------------------------------------------------------------------

    \250\ Sierra Club v. Costle, 657 F.2d at 330.

    Considering on ``the national and regional levels and over time''
the criteria that go into determining the ``best system of emission
reduction . . . adequately demonstrated'' also supports identifying
partial CCS as that best system because doing so would not have adverse
impacts on the power sector, national electricity prices, or the energy
sector.
1. Structure of the Power Sector
    Identifying partial CCS as the BSER for new fossil fuel-fired
utility boilers and IGCC units is consistent with the current and
projected future structure of the power sector. As noted, we project
that in light of the current and projected trends in coal and natural
gas costs, virtually all new electric generating capacity will employ
NGCC technology or renewable energy, and very little new capacity will
be coal-fired.
    As noted above, the recent history of solid fossil fuel-fired
projects suggest that these new coal-fired builds, if they occur, may
(i) consist of an IGCC unit, including features such as sale of
additional byproducts (e.g., plants such as the Texas Clean Energy
Project, which intends to manufacture fertilizer products for sale and
sell captured CO2 for EOR in addition to selling
electricity), use of lower cost opportunity fuels (such as petcoke
proposed to be used at the Hydrogen Energy California facility) and/or
rely on additional local regulatory drivers (such as California's AB-32
program which incentivizes lower CO2 generating
technologies), all of which would be designed to offset enough of the
additional coal-related costs to be able to compete with natural-gas
fired electricity in the marketplace; and (ii) be designed to offer
fuel diversity to a group of customers that are willing to pay a
premium in electricity prices (such as the Power4Georgians project in
Washington County, Georgia).
    Projects in the first category would by definition already include
at least partial CCS and, as a result, would be affected by this rule
to only a limited extent. Projects in the second category would be more
affected, but developers of these projects would nevertheless have
several options. They could pursue coal with CCS and possibly rely on
cost savings from EOR or on their customers' willingness to pay a
higher premium. Alternatively, they could choose a different generation
technology (most likely natural gas). Even if they chose a different
generation technology, the small number of these sources and the fact
that the basic demand for electricity would still be met would limit
the impact of this rule on the power sector.
2. Impacts on Nationwide Electricity Prices
    Identifying partial CCS as the BSER for fossil fuel-fired utility
boilers and IGCC units will not have significant impacts on nationwide
electricity prices. The reason is that the additional costs of partial
CCS will, on a nationwide basis, be small because no more than a few
new coal-fired projects are expected, and because, as noted, at least
some of these can be expected to incorporate CCS technology in any
event. It should be noted that the computerized model the EPA relies on
to assess energy sector and nationwide impacts--the Integrated Planing
Model (IPM)--does not forecast any new coal-fired EGUs through 2020.
Based on these IPM analyses, the RIA for this

rulemaking concludes that the proposed standard of 1,100 lb of
CO2/MWh for new fossil fuel-fired EGUs, which is based on
partial CCS as the best demonstrated system, does not create any costs.
3. Energy Considerations
    Identifying partial CCS as the BSER for new fossil fuel-fired
utility boilers and IGCC units is consistent with nationwide energy
considerations because it will not have adverse effects on the
structure of the power sector, will promote fuel diversity over the
long term, and will not have adverse effects on the supply of
electricity.
    Identifying partial CCS as the BSER will not have adverse impacts
on the structure of the power sector because, as noted, for reasons
related to the cost differential between natural gas-fired and coal-
fired electricity, very little, if any, new coal-fired EGUs are
projected to be built, and at least some of those that may be built
would be expected to include CCS technology in any event.
    In addition, identifying partial CCS as the BSER for coal will be
beneficial to coal-fired electric generation, and therefore fuel
diversity, over the long term. This is because identifying partial CCS
as BSER eliminates uncertainty as to future control obligations for
coal-fired capacity. Currently, any new coal-fired source that
constructs without CCS faces the risk that future state or federal
controls may require carbon capture, which would require the source to
retrofit to CCS, which, in turn, is a more expensive proposition. This
risk is heightened because power plants have expected lives of 30 to 40
years and the likelihood of future carbon limitations can be expected
to remain throughout that period. Any new coal-fired source that
constructs with partial-capture CCS will achieve some level of
CO2 emissions reductions, which lowers the risk of future
liability, and may provide competitive advantages over higher emitting
sources. Because at present, new electric generating construction is
primarily natural gas-fired, benefiting new coal-fired capacity, at
least over the long term, protects fuel diversity.
    Moreover, even if requiring CCS adds sufficient costs to prevent a
new coal-fired plant from constructing in a particular part of the
country due to lack of available EOR to defray the costs, or, in fact,
from constructing at all, a new NGCC plant can be built to serve the
electricity demand that the coal-fired plant would otherwise serve.
Thus, the present rulemaking does not prevent basic electricity demand
from being met, and thus does not have an adverse effect on the supply
of electricity. As noted above, the EPA is authorized to promulgate
standards of performance under CAA section 111 that may have the effect
of precluding construction of sources in certain geographic locations.
4. Environmental Considerations
    Identifying partial CCS as the BSER for coal-fired power plants
protects the environment by preventing large amounts of CO2
emissions from new fossil fuel-fired utility boilers and IGCC units. As
noted, CCS is the only technology available at present or within the
foreseeable future that provides meaningful reductions in the amount of
CO2 emissions in this sector.

I. Deference

    As noted above, the D.C. Circuit has held that it will grant a high
degree of deference to the EPA in determining the appropriate standard
of performance. Because determining the BSER for coal-fired power
plants requires balancing several factors, including on a nationwide
basis and over time, the EPA's determination that partial CCS is the
BSER should be granted a high degree of deference.

J. CCS and BSER in Locations Where Costs Are Too High To Implement CCS

    As noted above, under CAA section 111, an emissions standard may
meet the requirements of a ``standard of performance'' even if it
cannot be met by every new source in the source category that would
have constructed in the absence of that standard. As also noted above,
the EPA's analysis for this proposal indicates that coal-fired power
plants that would otherwise construct in the absence of the standards
in this proposal may still do so.
    However, we recognize that there may be some geographic locations
where EOR is not practicably available, so that in those locations, the
higher costs of CCS may tilt the economics against new coal-fired
construction. Even in this case, the standard would remain valid under
CAA section 111, particularly because the basic demand for electricity
could still be served by NGCC, which this rulemaking determines to be
the ``best system'' for natural gas-fired power plants.

K. Compliance Period

1. 12-Operating-Month Period
    Under today's proposal, sources must meet the 1,100 lb
CO2/MWh limit on a 12-operating-month rolling basis. This
12-operating-month period is important due the inherent variability in
power plant GHG emissions rates. Establishing a shorter averaging
period would necessitate establishing a standard to account for the
conditions that result in the lowest efficiency and therefore the
highest GHG emissions rate.
    EGU efficiency has a significant impact on the source's GHG
emission rate. By comparison, efficiency has a smaller impact on the
emissions rate for criteria or hazardous air pollutants (HAPs). This is
because control of criteria pollutants and HAPs often involves the use
of a pollution control device that results in significant reductions,
often greater than 90 percent. In this situation, the performance of
the specific pollution control device impacts the emissions rate much
more than the EGU efficiency.
    EGU efficiency can vary from month to month throughout the year.
For example, high ambient temperature can negatively impact the
efficiency of combustion turbine engines and steam generating units. As
a result, an averaging period shorter than 12 operating-months would
require us to set a standard that could be achieved under these
conditions. This standard could potentially be high enough that it
would not be a meaningful constraint during other parts of the year. In
addition, operation at low load conditions can also negatively impact
efficiency. It is likely that for some short period of time an EGU will
operate at an unusually low load. A short averaging period that
accounts for this operation would again not produce a meaningful
constraint for typical loads.
    On the other hand, a 12-operating-month rolling average explicitly
accounts for variable operating conditions, allows for a more
protective standard and decreased compliance burden, allows EGUs to
have and use a consistent basis for calculating compliance (i.e.,
ensuring that 12 operating months of data would be used to calculate
compliance irrespective of the number of long-term outages), and
simplifies compliance for state permitting authorities. Because the 12-
operating-month rolling average can be calculated each month, this form
of the standard makes it possible to assess compliance and take any
needed corrective action on a monthly basis. The EPA proposes that it
is not necessary to have a shorter averaging period for CO2
from these sources because the effect of GHGs on climate change depends
on global atmospheric concentrations which are dependent on cumulative
total emissions over time, rather than hourly or daily emissions
fluctuations or local pollutant concentrations. Unlike for emissions of
criteria and hazardous air pollutants, we do not believe that there are

measureable implications to health or environmental impacts from short-
term higher CO2 emission rates as long as the 12-month
average emissions rate is maintained.
    We solicit comment on, in the alternative, basing compliance
requirements on an annual (calendar year) average basis.
2. 84-Operating-Month Compliance Period
    Under today's proposal, new fossil fuel-fired boilers and IGCC
units will have the option to alternatively meet an emission standard
on an 84-operating-month rolling basis.
    The EPA has previously offered sources optional, longer-term
emission standards that are stricter than the primary emissions
standard in combination with a longer averaging period. We are
proposing that this alternative emission limit should be between 1,000-
1,050 lb CO2/MWh and we are requesting comment on what the
final numerical standard should be (within that range) such that the
84-operating-month standard would be as stringent as or more stringent
than the 12-operating-month standard.
    We are also requesting comment on an appropriate 12-operating-month
standard that owners/operators electing to comply with the 84-
operating-month standard would have to comply with. This standard would
be numerically between the alternate 12-operating-month standard and an
emissions rate of a coal-fired EGU without CCS (e.g., 1,800 lb
CO2/MWh). This shorter term standard would be more easily
enforced and assure adequate emission reductions.
    This 84-operating-month period offers increased operational
flexibility and will tend to compensate for short-term emission
excursions, which may especially occur at the initial startup of the
facility and the CCS system.

L. Geologic Sequestration

1. Overview
    We expect that for the immediate future, virtually all of the
CO2 captured at EGUs will be injected underground for long-
term geologic sequestration at sites where enhanced oil recovery is
also occurring. There is an existing regulatory framework for geologic
sequestration and enhanced oil recovery activities. We intend to rely
upon this existing framework to verify that the CO2 captured
from an affected unit is injected underground for long-term
containment. More specifically, as discussed in Section III, the EPA is
proposing to build from the existing GHG Reporting Program 40 CFR part
98 to track that the captured CO2 is geologically
sequestered.
    In addition, we recognize that types of CO2 storage
technologies other than geologic sequestration are under development
(e.g. precipitated calcium carbonate, etc). EGUs may use another type
of CO2 storage technology to meet the standard, once the EPA
has approved its use, including methods for reporting, monitoring, and
verifying long-term CO2 storage. We welcome comments on an
appropriate mechanism for making this determination.
2. Existing Regulatory Framework for CCS
    As noted, the EPA expects that for the immediate future, captured
CO2 from affected units will be injected underground for
geologic sequestration at sites where EOR is occurring. Underground
injection is currently the only technology available that can
accommodate the large quantities of CO2 captured at EGUs,
and EOR provides an associated economic incentive and benefit. Three
solid-fuel fired EGU projects incorporating CCS--Kemper, TCEP, and
HECA--all include utilization of captured CO2 for EOR.
    The EPA has promulgated, or recently proposed, several rules to
protect underground sources of drinking water and track the total
amount of CO2 that is supplied to the economy and injected
underground for geologic sequestration. First, the EPA's Underground
Injection Control (UIC) Class VI rule, established under authority of
the Safe Drinking Water Act, sets requirements to ensure that geologic
sequestration wells are appropriately sited, constructed, tested,
monitored, and closed in a manner that ensures protection of
underground sources of drinking water.\251\ The UIC Class VI
regulations contain monitoring requirements to protect underground
sources of drinking water, including the development of a comprehensive
testing and monitoring plan. This includes testing of the mechanical
integrity of the injection well, ground water monitoring, and tracking
of the location of the injected CO2 and the associated area
of elevated pressure using both direct and indirect methods, as
appropriate. Projects are also required to conduct extended post-
injection monitoring and site care to track the location of the
injected CO2 and monitor subsurface pressures until it can
be demonstrated that there is no longer a risk of endangerment to
underground sources of drinking water.
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    \251\ http://water.epa.gov/type/groundwater/uic/wells_sequestration.cfm.
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    UIC Class II wells inject fluids associated with oil and natural
gas production and the storage of liquid hydrocarbons. Most of the
injected fluid is salt water, which is brought to the surface in the
process of producing (extracting) oil and gas and subsequently re-
injected. In addition, other fluids, including CO2, are
injected to enhance oil and gas production. Class II regulations
include site characterization, well construction, operating,
monitoring, testing, reporting, financial responsibility, and closure
requirements to prevent endangerment of underground sources of drinking
water. Wells that inject CO2 underground for enhanced oil or
gas recovery may be permitted as UIC Class II or Class VI wells.
However, the designation of the appropriate well class depends,
principally, on the risks posed or changes in the risks posed to
underground sources of drinking water by a specific injection
operation.
    Second, the GHG Reporting Program covers sources that generate
electricity (40 CFR part 98, subpart D), sources that supply
CO2 to the economy (40 CFR part 98, subpart PP) and sources
that inject CO2 underground for geologic sequestration (40
CFR part 98, subpart RR). Subpart D owners or operators of facilities
that contain electricity-generating units must report emissions from
electricity-generating units and all other source categories located at
the facility for which methods are defined in part 98.\252\ Owners or
operators are required to collect emission data; calculate GHG
emissions; and follow the specified procedures for quality assurance,
missing data, recordkeeping, and reporting.
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    \252\ http://www.epa.gov/ghgreporting/reporters/subpart/d.html.
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    Subpart PP provides requirements for quantifying CO2
supplied to the economy.\253\ Affected units that capture
CO2 to inject underground or supply offsite, are subject to
all of the requirements under subpart PP of the GHG Reporting Program,
which relates to suppliers of CO2. Specifically, subpart PP
requires facilities with production process unit(s) that capture a
CO2 stream for purposes of supplying CO2 for
commercial applications or that capture and maintain custody of a
CO2 stream in order to sequester or otherwise inject it
underground and which meet certain applicability requirements to report
the mass of CO2 captured. CO2 suppliers are
required to

report the annual quantity of CO2 transferred offsite and
for what end use, including geologic sequestration.
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    \253\ http://www.epa.gov/ghgreporting/reporters/subpart/pp.html.
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    Subpart RR requires facilities meeting the source category
definition (40 CFR 98.440) for any well or group of wells to report
basic information on the amount of CO2 received for
injection; develop and implement an EPA-approved monitoring, reporting,
and verification (MRV) plan; and report the amount of CO2
sequestered using a mass balance approach and annual monitoring
activities. The MRV plan must be submitted and approved by the EPA and
revised if necessary over time according to 40 CFR 98.448(d). The
subpart RR MRV plan must include five major components:
     A delineation of the maximum monitoring area (MMA) and the
active monitoring area (AMA).
     An identification and evaluation of the potential surface
leakage pathways and an assessment of the likelihood, magnitude, and
timing, of surface leakage of CO2 through these pathways in
the MMA.
     A strategy for detecting and quantifying any surface
leakage of CO2 in the event leakage occurs.
     An approach for establishing the expected baselines for
monitoring CO2 surface leakage.
     A summary of considerations made to calculate site-
specific variables for the mass balance equation.
    More information on the MRV plan is available in the Technical
Support Document for the subpart RR final rule (75 FR 75065).
    If an enhanced oil and gas recovery project holds a UIC Class VI
permit, it is required to report under subpart RR. If the project holds
a UIC Class II permit and is injecting a CO2 stream
underground, it is not subject to subpart RR, but the owner or operator
may choose to opt-in to subpart RR. Sources reporting under subpart RR,
whether they are UIC Class VI or Class II well(s), must follow the same
set of requirements.
    As stated in the preamble to the final subpart RR rule:

``while requirements under the UIC program are focused on
demonstrating that USDWs are not endangered as a result of
CO2 injection into the subsurface, requirements under the
GHG Reporting Program through 40 CFR part 98, subpart RR will enable
EPA to verify the quantity of CO2 that is geologically
sequestered and to assess the efficacy of GS as a mitigation
strategy. Subpart RR achieves this by requiring facilities
conducting GS to develop and implement a MRV plan to detect and
quantify leakage of injected CO2 to the surface in the
event leakage occurs and to report the amount of CO2
geologically sequestered using a mass balance approach, regardless
of the class of UIC permit that a facility holds.'' (75 FR 75060)

    The Internal Revenue Service relies on the existing regulatory
framework to verify geologic sequestration when determining eligibility
of taxpayers claiming the 45Q tax credit. As stated in the preamble to
the final subpart RR rule:

    ``EPA notes that the Internal Revenue Service (IRS) published
IRS Notice 2009-83 7 to provide guidance regarding eligibility for
the Internal Revenue Code section 45Q credit for CO2
sequestration, computation of the section 45Q tax credit, reporting
requirements for taxpayers claiming the section 45Q tax credit, and
rules regarding adequate security measures for secure GS. As
clarified in the IRS guidance, taxpayers claiming the section 45Q
tax credit must follow the appropriate UIC requirements. The
guidance also clarifies that taxpayers claiming section 45Q tax
credit must follow the MRV procedures that are being finalized under
40 CFR part 98, subpart RR in this final rule.'' (75 FR 75060)

    Third, the EPA proposed a rule that would conditionally exclude
CO2 streams from the definition of hazardous waste under
RCRA, where these streams are being injected for purposes of geologic
sequestration, into a UIC Class VI well and meet other conditions.\254\
The rationale for the rule was that any CO2 stream that
would otherwise be defined as hazardous waste, need not be managed as
hazardous waste, provided it is managed under other regulatory programs
that address the potential risks to human health and the environment
that these materials may pose.
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    \254\ 76 FR 48073 (Aug. 8, 2011).
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3. Proposal
a. Geologic Sequestration
    To provide certainty and verify that CO2 captured at an
affected unit is geologically sequestered, today's action relies upon
the existing regulatory framework the EPA already has in place under
the GHG Reporting Program 40 CFR part 98. As discussed in the previous
section, there are key subparts (i.e., subpart D, PP and RR) under 40
CFR part 98 that provide a transparent reporting and verification
mechanism for EPA and the public. The EPA requires electric generating
units to report CO2 emissions under subpart D. Facilities
that capture CO2 are required to report quantities of
CO2 captured and injected on site or transferred off-site
under subpart PP. Facilities that inject CO2 underground for
geologic sequestration report under subpart RR.
    First, the EPA is proposing that any affected unit that employs CCS
technology which captures enough CO2 to meet the 1,100 lb/
MWh standard must report, under 40 CFR part 98, subpart RR, if the
captured CO2 is injected onsite. If the captured
CO2 is sent offsite, then the facility injecting the
CO2 underground must report under 40 CFR part 98, subpart
RR. As noted above, owners and operators of projects that inject
CO2 underground and that are permitted under a UIC Class VI
permit are required to comply with subpart RR. The practical impact of
our proposal would be that owners and operators of projects injecting
CO2 underground that are permitted under UIC Class II and
that receive CO2 captured from EGUs to meet the proposed
performance standard will also be required to submit and receive
approval of a subpart RR MRV plan and report under subpart RR. This
proposal does not change any of the requirements to obtain or comply
with a UIC permit for facilities that are subject to EPA's UIC program
under the Safe Drinking Water Act.
    In order to use the GHG Reporting Program to ensure that the
affected unit is sending its captured CO2 to a site
reporting under subpart RR, the EPA proposes minor modifications to
subpart PP, CO2 supply. We propose that a facility capturing
CO2 from an affected unit, and therefore subject to 40 CFR
part 98, subpart PP, must provide additional information in its subpart
PP annual report including (1) the electronic GHG Reporting Tool
identification (e-GGRT ID) of the facility with the electric generating
unit from which CO2 was captured, and (2) the e-GGRT ID(s)
for, and mass of CO2 transferred to, each geologic
sequestration site reporting under subpart RR. This proposed amendment
to the GHG Reporting Program provides a transparent and consistent
method to track CO2 capture and sequestration without
significantly increasing burden on the affected sources. If the
affected unit does not report under 40 CFR part 98, subpart PP and
comply with these proposed requirements, it will be considered in
noncompliance with today's proposal.
    The EPA notes that compliance with the standard of 1,100 lb
CO2/MWh is determined exclusively by the tons of
CO2 captured by the emitting EGU. The tons of CO2
sequestered by the geologic sequestration site are not part of that
calculation. However, to verify that the CO2 captured at the
emitting EGU is sent to a geologic sequestration site, we are building
on existing regulatory requirements under the GHG Reporting program.

    The EPA acknowledges that there can be downstream losses of
CO2 after capture, for example during transportation,
injection or storage. Though a well selected and operated site is
expected to contain CO2 for the long-term, there is the
potential for unanticipated leakage. The EPA expects these losses to be
modest with incentives due to the market use of CO2 as a
purchased product. There remains an issue of whether the standard
itself should be adjusted to reflect these downstream losses. The EPA
is not proposing to do so. Moreover, the EPA wishes to encourage rather
than discourage EOR using captured CO2 since the practice
makes CCS itself more economic and thus promotes use of the technology
on which the proposed standard is based. See Sierra Club v. Costle, 657
F. 2d at 347 (one purpose of section 111 standards is to promote
expanded use and development of technology).
    We also emphasize that today's proposal does not involve regulation
of any downstream recipients of captured CO2. That is, the
regulatory standard applies exclusively to the emitting EGU, not to any
downstream user or recipient of the captured CO2 (whether
the captured CO2 is sold for EOR or otherwise sequestered
underground). The requirement that the emitting EGU assure that
captured CO2 is managed at an entity subject to the GHG
reporting rules is thus exclusively an element of enforcement of the
EGU standard. Similarly, the existing regulatory requirements
applicable to geologic sequestration are not part of the proposed NSPS.
The standard is a numeric value, applicable exclusively to the emitting
EGU.
    The approach proposed today relies on the existing GHG Reporting
framework to ensure that CO2 captured at an affected unit is
transferred to a facility reporting geologic sequestration, and it does
not impose any additional requirements for an affected unit to
demonstrate how the captured CO2 is transferred to a
facility that is compliant with 40 CFR part 98, subpart RR. We seek
comment on whether there should be such requirements and suggestions
for what those might include.
b. Alternatives to Geologic Sequestration
    In the development of this proposal, the EPA has identified some
potential alternatives to geologic sequestration, including but not
limited to CO2 stored in precipitated calcium carbonate and
certain types of cement. The EPA solicits comment on whether these and
other alternatives to geologic sequestration permanently store
CO2 (so that the stack standard is assured of achieving its
object--to capture CO2 and prevent its atmospheric release)
and if they are technically available for EGUs to meet the performance
standard. Consideration of how these alternatives could meet the
performance standard involves understanding the ultimate fate of the
captured CO2 and the degree to which the method permanently
isolates the CO2 from the atmosphere, as well as existing
methodologies to verify this permanent storage. The EPA proposes that
alternatives to geologic sequestration could not be used until the EPA
finalizes a mechanism to demonstrate that a non-CCS technology would
result in permanent storage of CO2. The EPA believes that
the number of cases where an EGU would seek to comply with the
performance standard through an alternative to CCS will be very few.
However, the EPA wishes to encourage development of alternatives to
geologic sequestration that could help offset the cost of
CO2 capture.
c. Drafting PSD Permits for Affected Sources Using Geologic
Sequestration
    In most cases, sources that are subject to this NSPS will also be a
major source or major modification under PSD and required to obtain a
PSD permit prior to commencing construction. A permit is the legal tool
used to establish all the source limitations deemed necessary by the
reviewing agency during review of the permit application, and is the
primary basis for enforcement of PSD requirements. A well written
permit reflects the outcome of the permit review process and clearly
defines what is expected of the source. The permit must be a ``stand-
alone'' document that: (1) Identifies the emissions units to be
regulated; (2) establishes emissions standards or other operational
limits to be met; (3) specifies methods for determining compliance and/
or excess emissions, including reporting and recordkeeping
requirements; and (4) outlines the procedures necessary to maintain
continuous compliance with the emission limits.
    One of the criteria that must be met to obtain a PSD permit is that
the owner or operator of the facility must demonstrate that emissions
from construction or operation of the facility will not cause or
contribute to air pollution in excess of ``any other applicable
emissions standard or standard of performance under this chapter.'' 42
U.S.C. 7475(a)(3)(C); see also 42 U.S.C. 7410(j). Accordingly, PSD
permits for EGU sources that are subject to this NSPS will need to
reflect that, at a minimum, the source will meet the requirements of
this NSPS. Compliance with the NSPS emissions standard is determined
exclusively by evaluating emissions of CO2 at the EGU.\255\
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    \255\ We note that the PSD program regulates CO2 as
part of the ``Greenhouse Gas'' pollutant, which includes the
aggregate group of the following gases: CO2,
CH4, N20, SF6, HFCs, and PFCs.
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    As noted in the ``Implications for PSD and Title V programs''
section of this preamble, some states have authority to issue PSD
permits. In other cases, the EPA issues the permit. States with EPA-
approved permitting programs have some discretion in making permit
decisions and including the necessary conditions in the permit to
ensure the enforceability of the requirements. Additionally, some
states may have additional state-specific requirements (e.g., a
renewable portfolio standard adopted by a state) that may affect the
stringency of the emission limits for the permits issued in their
states. Thus, permits for similar source types may vary from state to
state depending on the permitting program of the state, and the case-
specific PSD evaluation of the source under review. However, the
permits for similar sources should generally contain the same basic
information.
    Thus, while EPA recognizes that permit conditions may vary from
state to state, the EPA believes it is important to clarify the key
components that should be included in a PSD permit for sources subject
to the NSPS, as proposed here, and that intend to comply with the
standard using geologic storage. We believe the following general
condition areas of a PSD permit would adequately show that the source
will not cause or contribute to air pollution in excess of this NSPS:
     A BACT emissions limit that applies to the EGU (or EGUs)
at the stationary source (``EGU facility'') that does not exceed the
NSPS emission limit standard using the 12-operating-month rolling
average or the NSPS alternative compliance method.
     Procedures for how the EGU will demonstrate compliance
with the permitted emissions limit, which, at a minimum, meet the
monitoring and recordkeeping requirements defined in Sec.  60.5355.
     A requirement that CO2 produced by the EGU (or
EGUs) is reported under Subpart PP by the permittee.
     A requirement that all CO2 that is geologically
sequestered at the site of the EGU facility is reported under subpart
RR by the permittee.
     A requirement that the captured CO2 that the
permittee sends offsite of the EGU facility is transferred to an

entity that is subject to the requirements of Subpart RR.
    We specifically request comment on this basic framework for PSD
permits that are issued for affected EGU sources that use geologic
sequestration.

VIII. Rationale for Emission Standards for Natural Gas-Fired Stationary
Combustion Turbines

A. Best System of Emission Reduction

    The EPA evaluated several different control technology
configurations as potentially representing the ``best system of
emissions reductions . . . adequately demonstrated'' (BSER) for new
natural gas-fired stationary combustion turbines: (i) The use of full
or partial capture CCS; and two types of efficient generation without
any CCS, including (ii) high efficiency simple cycle aeroderivative
turbines; and (iii) natural gas combined cycle (NGCC) technology. We do
not consider full or partial capture CCS to be BSER because of
insufficient information to determine technical feasibility and because
of adverse impact on electricity prices and the structure of the
electric power sector. In addition, we do not consider simple cycle
turbines to be BSER because they have a higher emission rate and a
higher cost than NGCC technology. We do find NGCC technology to be the
BSER because it is technically feasible and relatively inexpensive, its
emission profile is acceptably low, and it would not adversely affect
the structure of the electric power sector.
    We note at the outset that currently, virtually all new sources in
this category are using NGCC technology. That technology is considered
to be the state of the art for this source category. Because, in this
rulemaking, we are considering, and selecting, NGCC as the BSER for
this category, as a matter of terminology, to avoid confusion, we
generally refer to the affected sources as natural gas-fired combustion
turbines, and not as NGCC sources.
1. Full and Partial CCS
    To determine the BSER for natural-gas-fired stationary source
combustion turbines, we evaluated full and partial CCS against the
criteria. We propose to reject CCS technology as the BSER because we
cannot conclude that it meets several of the key criteria.
    First, it is not clear that full or partial capture CCS is
technically feasible for this source category. There are significant
differences between natural gas-fired combustion turbines and solid
fossil fuel-fired EGUs that lead us to this conclusion. First, while
some of these turbines are used to serve base load power demand, many
cycle their operation much more frequently than coal-fired power
plants. It is unclear how part-load operation and frequent startup and
shutdown events would impact the efficiency and reliability of CCS. We
are not aware that any of the pilot-scale CCS projects have operated in
a cycling mode. Similarly, none of the larger CCS projects being
constructed, or under development, are designed to operate in a cycling
mode. Furthermore, the CO2 concentration in the flue gas of
a natural gas combustion turbine is much lower (usually approximately 4
volume percent) than the CO2 concentration in the flue gas
stream of a typical coal-fired plant (which is approximately 16 volume
percent for a SCPC or CFB unit) or the syngas of an IGCC unit (in which
CO2 can be as high as 60 volume percent). Therefore, the
overall amount of CO2 that can be captured in a CCS project
is likely lower. Finally, unlike subpart Da affected facilities, where
there are full-scale plants with CCS that are currently under
construction or in advanced stages of development, the EPA is aware of
only one demonstration project, which is an approximately 40 MW slip
stream installation on a 320 MW NGCC unit.
    Additional factors that make CCS more challenging for a natural gas
combustion turbine compared to coal-fired EGUs include the time it
would take to complete the CCS project and the water use requirements.
Requiring CCS at a natural gas combustion turbine facility would
potentially delay the project more than at a coal-fired EGU. Natural
gas combustion turbine facilities can be constructed in about half the
time required to construct a coal-fired EGU. Therefore, the time
necessary to construct the carbon capture equipment and any associated
pipelines to transport the CO2 would have a relatively
larger impact on a natural gas combustion turbine than a coal-fired
EGU. Natural gas combustion turbines have relatively low cooling
requirements for the steam condensing cooling cycle compared to coal-
fired EGUs and often use dry cooling technology. The imposition of CCS
would have a larger impact on water requirements for a natural gas
combustion turbine facility compared to a coal-fired EGU.
    Moreover, identifying partial or full CCS as the BSER for new
stationary combustion turbines would have significant adverse effects
on national electricity prices, electricity supply, and the structure
of the power sector. Because virtually all new fossil fuel-fired power
is projected to use NGCC technology, requiring CCS would have more of
an impact on the price of electricity than the few projected coal
plants with CCS and the number of projects would make it difficult to
implement in the short term. In addition, requiring CCS could lead some
operators and developers to forego retiring older coal-fired plants and
replacing them with new NGCC projects, and instead keep the older
plants on line longer, which could have adverse emission impacts.
Identifying CCS and BSER for combustion turbines would likely result in
higher nationwide electricity prices and could adversely affect the
supply of electricity, since virtually all new fossil fuel-fired power
is projected to use NGCC technology.
    We recognize that identifying full or partial CCS as the BSER for
this source category would result in significant emissions reductions,
but at present, we already consider natural gas to be a low-GHG-
emitting fuel and NGCC to be a low-emitting technology. Although
identifying CCS as the BSER would promote the development and
implementation of emission control technology, for the reasons
described, the EPA does not believe that CCS represents BSER for
natural gas combustion turbines at this time.
2. Energy Efficient Generation Technology
    To determine the BSER, the EPA also evaluated the use of energy
efficient generation technology, including high efficiency simple cycle
aeroderivative turbines.
    The use of high efficiency simple cycle aeroderivative turbines
does not provide emission reductions from the current state-of-the-art
technology, is more expensive than the current state-of-the-art
technology, and does not develop emission control technology. For these
reasons, we do not consider it BSER. According to the AEO 2013
emissions rate information, advanced simple cycle combustion turbines
have a base load rating CO2 emissions rate of 1,150 lb
CO2/MWh, which is higher than the base load rating emission
rates of 830 and 760 lb CO2/MWh for the conventional and
advanced NGCC model facilities, respectively.
    In the April 2012 proposal, we identified NGCC as the BSER for this
source category, and proposed a standard of 1,000 lb/MWh. We stated:

    [A] NGCC facility is the best system of emission reduction for
new base load and intermediate load EGUs. To establish an
appropriate, natural gas-based standard, we reviewed the emissions
rate of natural gas-fired (non-CHP) combined cycle facilities

used in the power sector that commenced operation between 2006 and
2010 and that report complete generation data to EPA. Based on this
analysis, nearly 95% of these facilities meet the proposed standards
on an annual basis. These units represent a wide range of geographic
locations (with different elevations and ambient temperatures),
operational characteristics, and sizes.\256\
---------------------------------------------------------------------------

    \256\ 77 FR 22414/1.

    The same information supports our current proposal. As described
above, NGCC has a lower cost of electricity than simple cycle turbines
at intermediate and high capacity factors. In addition, NGCC has an
emissions rate that is approximately 25 percent lower than the most
efficient simple cycle facilities. Therefore, the use of a heat
recovery steam generator in combination with a steam turbine to
generate additional electricity is a cost effective control for
intermediate and high capacity factor stationary combustion turbines.
Therefore, BSER for intermediate and high capacity factor stationary
combustion turbines is the use of modern high efficiency NGCC
technology.

B. Determination of the Standards of Performance

    Multiple commenters on the April 2012 proposal stated the proposed
standard of 1,000 lb CO2/MWh for combined cycle facilities
in the April 2012 proposal was too stringent and should be increased to
a minimum of 1,100 lb CO2/MWh. Commenters explained that the
increased use of renewable energy for electricity generation will
require combined cycle facilities to startup, shutdown, cycle, and
operate at part-load more frequently than they currently do, and that
this more cyclical operation necessarily entails a higher emission
rate. The commenters stated that the recent historical emissions data
that the EPA relied on for the original proposal does not account for
these likely operational changes. Additional reasons given justifying a
higher standard include the deterioration of efficiencies over time,
the need for flexibility to use distillate oil as a backup fuel, the
operation of combined cycle facilities in simple cycle mode, the fact
that combined cycle facilities located at high elevations and/or in
locations with high ambient temperatures are less efficient, and the
fact that smaller combined cycle facilities are inherently less
efficient than larger facilities. On the other hand, other commenters
stated that the final standard should be lower than proposed on grounds
that the best performing facilities are operating below the original
proposed standard. Multiple commenters also stated that the EPA should
evaluate additional CEMS data to determine the appropriate standard.
    In light of these comments, we have reviewed the CO2
emissions data from 2007 to 2011 for natural gas-fired (non-CHP)
combined cycle units that commenced operation on or after January 1,
2000, and that reported complete electric generation data, including
output from the steam turbine, to the EPA. A more detailed description
of this emissions data analysis is included in a technical support
document in the docket for this rulemaking. These 307 NGCC units are
diverse in location, age, capacity, and operating profile. Based on
these data, we propose to subcategorize the turbines into the same two
size-related subcategories currently in subpart KKKK for standards of
performance for the combustion turbine criteria pollutants. These
subcategories are based on whether the design heat input rate to the
turbine engine is either less than or equal to 850 MMBtu/h or greater
than 850 MMBtu/h. We further propose to establish different standards
of performance for these two subcategories.
    This subcategorization has a basis in differences in several types
of equipment used in the differently sized units, which affect the
efficiency of the units. Large-size combustion turbines use industrial
frame type combustion turbines and may use multiple pressure or steam
reheat turbines in the heat recovery steam generator (HRSG) portion of
a combined cycle facility. Multiple pressure HRSGs employ two or three
steam drums that produce steam at multiple pressures. The availability
of multiple pressure steam allows the use of a more efficient multiple
pressure steam turbine, compared to a single pressure steam turbine. A
steam reheat turbine is used to improve the overall efficiency of the
generation of electricity. In a steam reheat turbine, steam is
withdrawn after the high pressure section of the turbine and returned
to the boiler for additional heating. The superheated steam is then
returned to the intermediate section of the turbine, where it is
further expanded to create electricity. Although HRSGs with steam
reheat turbines are more expensive and complex than HRSGs without them,
steam reheat turbines offer significant reductions in CO2
emission rates. In contrast, small-size combustion turbines frequently
use aeroderivative turbine engines instead of industrial frame design
turbines. While there is not a strict definition for an aeroderivative
turbine, at least parts of aeroderivative turbines are derived from
aircraft engines. Aeroderivative and frame turbines use different
combustor designs, lubrication oil systems, and bearing designs. While
aeroderivative turbines are typically more expensive than industrial
frame turbines, they are generally more compact, lighter, are able to
start up and shut down more quickly, and handle rapid load changes more
easily than industrial frame turbines. Due to their higher simple cycle
efficiencies, they have traditionally been used more for peak and
intermittent purposes rather than base power generation. However,
combined cycle facilities based on aeroderivative combustion turbines
are available. Due to the higher efficiency of the simple cycle portion
of an aeroderivative turbine based combined cycle facility, the HRSG
portion would contribute relatively less to the overall efficiency than
a HRSG in a frame turbine based combined cycle facility. Therefore,
adding a multiple steam pressure and/or a reheat steam turbine to the
HRSG would be relatively more expensive to an aeroderivative turbine
based combined cycle facility compared to a frame based combined cycle
facility. Consequently, multiple pressure steam and reheat steam
turbine HRSG are not widely available for aeroderivative turbine based
combined cycle facilities. In addition, since aeroderivative turbine
engines have faster start times and change load more quickly than frame
turbines, aeroderivative turbine based combined cycle facilities are
more likely to run at part load conditions and to potentially bypass
the HRSG and run in simple cycle mode for short periods of time than
industrial frame turbine based combined cycle facilities.
    Because of these differences in equipment and inherent efficiencies
of scale, the smaller capacity NGCC units (850 MMBtu/h and smaller)
available on the market today are less efficient than the larger units
(larger than 850 MMBtu/h). According to the data in the EPA's Clean Air
Markets Division database, which contains information on 307 NGCC
facilities, there is a 7 percent difference in average CO2
emission rate between the small- and large-size units. This relative
difference is consistent with what would be predicted when comparing
the efficiency values reported in Gas Turbine World of small and large
combined cycle designs.\257\ Fourteen of the study NGCC facilities
evaluated using the Clean Air Markets data have heat input rates of
less than or equal to 850 MMBtu/h, and the

remaining 293 are above 850 MMBtu/MWh. Two of the small combined cycle
facilities had a maximum 12-operating-month rolling average emissions
rate equal to or greater than 1,000 lb CO2/MWh and one had a
maximum 12-operating-month rolling average emissions rate equal to or
greater than 1,100 lb CO2/MWh. Twenty three of the large
turbines had at least one occurrence of a 12-operating-month rolling
average emissions rate greater than or equal to 1,000 lb
CO2/MWh and forty four had at least one occurrence of a 12-
operating-month rolling average emissions rate greater than or equal to
950 lb CO2/MWh. Therefore, because over 90 percent of small
and large existing NGCC facilities are currently operating below the
emission rates of 1,100 lb CO2/MWh and 1,000 lb
CO2/MWh, respectively, these rates are considered BSER for
new NGCC facilities in those respective subcategories. These values
represent the emission rates that a modern high efficiency NGCC
facility located in the U.S. would be able to maintain over its life.
---------------------------------------------------------------------------

    \257\ Gas Turbine World--2012 GTW Handbook.
---------------------------------------------------------------------------

    To further evaluate the impact of the proposed rule we reviewed the
GHG BACT permits for eight recently permitted NGCC facilities. Of these
facilities, seven are larger than 850 MMBtu/h, and one is smaller. The
seven larger facilities all have emission rates below 1,000 lb/MWh, and
as low as 880 lb/MWh. The single smaller facility, which is 400 MMBtu/
h, has a permitted emissions rate of 1,100 lb CO2/MWh. The
GHG BACT permit limits are higher than the base load rating emissions
rates because they take into account actual operating conditions.
    We are requesting comment on a range of 950 to 1,100 lb
CO2/MWh (430 to 500 kg CO2/MWh) for the large
turbine subcategory and 1,000 to 1,200 lb CO2/MWh (450 to
540 kg CO2/MWh) for the small turbine subcategory.

IX. Implications for PSD and Title V Programs

A. Overview

    The proposal in this rulemaking would, for the first time, regulate
GHGs under CAA section 111. Commenters have raised questions regarding
whether this rule will have implications for regulations and permits
written under the CAA PSD preconstruction permit program and the CAA
Title V operating permit program.
    Today's proposal should not require any additional SIP revisions to
make clear that the Tailoring Rule thresholds--described below--
continue to apply to the PSD program. Likewise, today's rulemaking does
not have implications for the Tailoring Rule thresholds established
with respect to sources subject to title V requirements. Furthermore,
this proposal does not have any direct applicability on the
determination of Best Available Control Technology (BACT) for existing
EGUs that require PSD permits to authorize a major modification of the
EGU. Finally, this proposal does have some implications for Title V
fees, but EPA is proposing action to address those implications as
discussed below.

B. Applicability of Tailoring Rule Thresholds Under the PSD Program

    States with approved PSD programs in their state implementation
plans (SIPs) implement PSD, and most of these States have recently
revised their SIPs to incorporate the higher thresholds for PSD
applicability to GHGs that the EPA promulgated under what we call the
Tailoring Rule.\258\ Commenters have queried whether under the EPA's
PSD regulations, promulgation of a section 111 standard of performance
for GHGs would require these states to revise their SIPs again to
incorporate the Tailoring Rule thresholds again. The EPA included an
interpretation in the Tailoring Rule preamble, which makes clear that
the Tailoring Rule thresholds continue to apply if and when the EPA
promulgates requirements under CAA section 111. Even so, in today's
proposal, the EPA is including a provision in the CAA section 111
regulations that confirms this interpretation.
---------------------------------------------------------------------------

    \258\ ``Prevention of Significant Deterioration and Title V
Greenhouse Gas Tailoring Rule; Final Rule,'' 75 FR 31514 (June 3,
2010). In the Tailoring Rule, EPA established a process for phasing
in PSD and Title V applicability to sources based on the amount of
their GHG emissions, instead of immediately applying PSD and title V
at the 100 or 250 ton per year or thresholds included under the PSD
and title V applicability provisions.
---------------------------------------------------------------------------

    However, if a state with an approved PSD SIP program that applies
to GHGs believes that were the EPA to finalize the rulemaking proposed
today, the state would be required to revise its SIP to make clear that
the Tailoring Rule thresholds continue to apply, then (i) the EPA
encourages the state to do so as soon as possible, and (ii) if the
State cannot do so promptly, the EPA will assess whether to proceed
with a separate rulemaking action to narrow its approval of that
state's SIP so as to assure that for federal purposes, the Tailoring
Rule thresholds will continue to apply as of the effective date of the
final rule that the EPA is proposing today.
    In the alternative, if the Tailoring Rule thresholds would not
continue to apply when the EPA promulgates requirements under CAA
section 111, then the EPA would assess whether to proceed with a
separate rulemaking action to narrow its approval of all of the State's
approved SIP PSD programs to assure that for federal purposes, the
Tailoring Rule thresholds will continue to apply as of the effective
date of the final rule that EPA is proposing today.
    Under the PSD program in part C of title I of the CAA, in areas
that are classified as attainment or unclassifiable for NAAQS
pollutants, a new or modified source that emits any air pollutant
subject to regulation at or above specified thresholds is required to
obtain a preconstruction permit. This permit assures that the source
meets specified requirements, including application of BACT. States
that are authorized by the EPA to administer the PSD program may issue
PSD permits. If a state is not authorized, then the EPA issues the PSD
permits.
    Regulation of GHG emissions in the Light Duty Vehicle Rule (75 FR
25324) triggered applicability of stationary sources to regulations for
GHGs under the PSD and title V provisions of the CAA. Hence, on June 3,
2010 (75 FR 31514), the EPA issued the ``Tailoring Rule,'' which
establishes thresholds for GHG emissions in order to define and limit
when new and modified industrial facilities must have permits under the
PSD and title V programs. The rule addresses emissions of six GHGs:
CO2, CH4, N2O, HFCs, PFCs and
SF6. On January 2, 2011, large industrial sources, including
power plants, became subject to permitting requirements for their GHG
emissions if they were already required to obtain PSD or title V
permits due to emissions of other (non-GHG) air pollutants.
    Commenters have queried whether, because of the way that the EPA's
PSD regulations are written, promulgating the rule we propose today may
raise questions as to whether the EPA must revise its PSD regulations--
and, by the same token, whether states must revise their SIPs--to
assure that the Tailoring Rule thresholds will continue to apply to
sources subject to PSD. That is, under the EPA's regulations, PSD
applies to a ``major stationary source'' that undertakes construction
and to a ``major modification.'' 40 CFR 51.166(a)(7)(i) and (iii). A
``major modification'' is defined as ``any physical change in or change
in the method of operation of a major stationary source that would
result in a significant emissions increase . . . and a significant net
emissions increase. . . .'' Thus, for present purposes, the key
component of these

applicability provisions is that PSD applies to a ``major stationary
source.''
    The EPA's regulations define the term ``major stationary source''
as a ``stationary source of air pollutants which emits, or has the
potential to emit, 100 [or, depending on the source category, 250] tons
per year or more of any regulated NSR pollutant.'' 40 CFR
51.166(b)(1)(i)(a). The EPA's regulations go on to define ``regulated
NSR pollutant'' 40 CFR 51.166(b)(49) to include any pollutant that is
subject to any standard promulgated under section 111 of the Act. Thus,
the PSD regulations contain a separate PSD trigger for pollutants
regulated under the NSPS, 40 CFR 51.166(b)(49)(ii) (the ``NSPS trigger
provision''), so that as soon as the EPA promulgates the first NSPS for
a particular air pollutant, as we are doing in this rulemaking with
respect to the GHG air pollutant, then PSD is triggered for that air
pollutant.
    The Tailoring Rule, on the face of its regulatory provisions,
incorporated the revised thresholds it promulgated into only the fourth
prong (``[a]ny pollutant that otherwise is subject to regulation under
the Act''), and not the NSPS trigger provision in the second prong
(``[a]ny pollutant that is subject to any standard promulgated under
section 111 of the Act''). For this reason, a question may arise as to
whether the Tailoring Rule thresholds apply to the PSD requirement as
triggered by the NSPS that the EPA is promulgating in this rulemaking.
    However, although the Tailoring Rule thresholds on their face apply
to only the term, ``subject to regulation'' in the definition of
``regulated NSR pollutant,'' the EPA stated in the Tailoring Rule
preamble that the thresholds should be interpreted to apply to other
terms in the definition of ``major stationary source'' and in the
statutory provision, ``major emitting facility.'' Specifically, the EPA
stated:
3. Other Mechanisms

    As just described, we selected the ``subject to regulation''
mechanism because it most readily accommodated the needs of States
to expeditiously revise--through interpretation or otherwise--their
state rules. Even so, it is important to recognize that this
mechanism has the same substantive effect as the mechanism we
considered in the proposed rule, which was revising numerical
thresholds in the definitions of major stationary source and major
modification. Most importantly, although we are codifying the
``subject to regulation'' mechanism, that approach is driven by the
needs of the states, and our action in this rulemaking should be
interpreted to rely on any of several legal mechanisms to accomplish
this result. Thus, our action in this rule should be understood as
revising the meaning of several terms in these definitions,
including: (1) The numerical thresholds, as we proposed; (2) the
term, ``any source,'' which some commenters identified as the most
relevant term for purposes of our proposal; (3) the term, ``any air
pollutant; or (4) the term, ``subject to regulation.'' The specific
choice of which of these constitutes the nominal mechanism does not
have a substantive legal effect because each mechanism involves one
or another of the components of the terms ``major stationary
source''--which embodies the statutory term, ``major emitting
facility''--and ``major modification,'' which embodies the statutory
term, ``modification,'' and it is those statutory and regulatory
terms that we are defining to exclude the indicated GHG-emitting
sources.\[Footnote]\
    [Footnote: We also think that this approach better clarifies our
long standing practice of interpreting open-ended SIP regulations to
automatically adjust for changes in the regulatory status of an air
pollutant, because it appropriately assures that the Tailoring Rule
applies to both the definition of ``major stationary source'' and
``regulated NSR pollutant.'' ]

75 FR 31582.
    Thus, according to the preamble of the final Tailoring Rule, the
definition of ``major stationary source'' itself already incorporates
the Tailoring Rule thresholds, and not just through one component (the
``subject to regulation'' prong of the term ``regulated NSR
pollutant'') of that definition. For this reason, it is the EPA's
position that the Tailoring Rule thresholds continue to apply even when
the EPA promulgates the first NSPS for GHGs (which, as noted above,
triggers the PSD requirement under the NSPS trigger provision in the
definition of ``regulated NSR pollutant'').\259\
---------------------------------------------------------------------------

    \259\ This position reads the regulations to be consistent with
the CAA PSD provisions themselves. Under those provisions, PSD
applies to any ``major emitting facility,'' which is defined to mean
stationary sources that emit or have the potential to emit ``any air
pollutant'' at either 100 or 250 tons per year, depending on the
source category. CAA section 165(a), 169(1). EPA has long
interpreted these provisions to apply PSD to a stationary source
that emits the threshold amounts of any air pollutant subject to
regulation. See Tailoring Rule, 75 FR 31579. Under these provisions,
at present, PSD is already applicable to GHGs because GHGs are
already subject to regulation, and regulating GHGs under CAA section
111 does not create any additional type of PSD trigger.
---------------------------------------------------------------------------

    As a result, the EPA believes that states that incorporated the
Tailoring Rule thresholds into their SIPs may take the position that
they also incorporated the EPA's interpretation in the preamble that
the thresholds apply to the definition ``major stationary source.''
    Even so, to clarify and confirm that the Tailoring Rule thresholds
apply to the section 111 prong of the definition of regulated NSR
pollutant, in this proposed rulemaking, the EPA is proposing to add new
provisions to the NSPS regulations, although not the PSD regulations,
to make explicit that the NSPS trigger provision in the PSD regulations
incorporates the Tailoring Rule thresholds.\260\ Under these new
provisions, to the extent that promulgation of section 111 requirements
for GHGs triggers PSD requirements for GHGs, it does so only for GHGs
emitted at or above the Tailoring Rule thresholds.
---------------------------------------------------------------------------

    \260\ The Tailoring Rule thresholds themselves are not at issue
in this rulemaking.
---------------------------------------------------------------------------

    The EPA requests that all States with approved SIP PSD programs
that apply to GHGs indicate during the comment period on this rule
whether, (i) in light of EPA's interpretation that the Tailoring Rule
thresholds continue to apply even when the EPA promulgates the first
NSPS for GHGs, and (ii) assuming that EPA finalizes the added
provisions to the section 111 regulations proposed today, they can
interpret their SIPs already to apply the Tailoring Rule thresholds to
the NSPS prong or whether they must revise their SIPs. For any State
that says it must revise its SIP (or that does not respond), the EPA
will assess whether to propose a rule shortly after the close of the
comment period, to narrow its approval of that state's SIP so as to
assure that for federal purposes, the Tailoring Rule thresholds will
continue to apply as of the effective date of the final rule that the
EPA is proposing today. Such a rule would be comparable to what we call
the SIP PSD Narrowing Rule that EPA promulgated in December, 2010.\261\
The EPA may finalize such a narrowing rule at the same time that it
finalizes this NSPS rule.
---------------------------------------------------------------------------

    \261\ ``Limitation of Approval of Prevention of Significant
Deterioration Provisions Concerning Greenhouse Gas Emitting-Sources
in State Implementation Plans; Final Rule,'' 75 FR 82536 (December
30, 2010).
---------------------------------------------------------------------------

C. Implications for BACT Determinations Under PSD

    New major stationary sources and major modifications at existing
major stationary sources are required by the CAA to, among other
things, obtain a permit under the PSD program before commencing
construction. A source is subject to PSD by way of its proposed
construction and the effect of the construction and operation of the
new equipment on emissions. The emission thresholds that define PSD
applicability can be found in 40 CFR parts 51 and 52 and are discussed
briefly in the above section.
    As mentioned above, sources that are subject to PSD must obtain a

preconstruction permit that contains emission limitations based on
application of Best Available Control Technology for each regulated NSR
pollutant. The BACT requirement is set forth in section 165(a)(4) of
the CAA, and in EPA regulations under 40 CFR parts 51 and 52. These
provisions require that BACT determinations be made on a case-by-case
basis after consideration of the record in each case. CAA section
169(3) defines BACT as an emissions limitation (including a visible
emission standard) based on the maximum degree of reduction for each
pollutant subject to regulation under the Clean Air Act which would be
emitted from any proposed major stationary source or major modification
which the Administrator, on a case-by-case basis, taking into account
energy, environmental, and economic impacts and other costs, determines
is achievable for such facility through application of production
processes and available methods, systems, and techniques, including
fuel cleaning, clean fuels, or treatment or innovative fuel combustion
techniques for control of each such pollutant.
    Furthermore, this definition in the CAA specifies that ``[i]n no
event shall application of [BACT] result in emissions of any pollutants
which will exceed the emissions allowed by any applicable standard
established pursuant to section 111 or 112 of the Act.'' This has
historically been interpreted to mean that BACT cannot be less
stringent than any applicable standard of performance under the NSPS.
See e.g. EPA, PSD and Title V Permitting Guidance for Greenhouse Gases,
p. 20-21 (March 2011). Thus, upon completion of an NSPS, EPA reads the
CAA to mean that the NSPS establishes a ``BACT Floor'' for PSD permits
issued to affected facilities covered by an NSPS. It is important to
note that a proposed NSPS does not establish the BACT Floor for
affected facilities seeking a PSD permit. This is explained on page 25
of EPA's PSD and Title V Permitting Guidance for Greenhouse Gases
(March 2011):

In cases where a NSPS is proposed, the NSPS will not be controlling
for BACT purposes since it is not a final action and the proposed
standard may change, but the record of the proposed standard
(including any significant public comments on EPA's evaluation)
should be weighed when considering available control strategies and
achievable emission levels for BACT determinations made that are
completed before a final standard is set by EPA. However, even
though a proposed NSPS is not a controlling floor for BACT, the NSPS
is an independent requirement that will apply to an NSPS source that
commences construction after an NSPS is proposed and carries with it
a strong presumption as to what level of control is achievable. This
is not intended to limit available options to only those considered
in the development of the NSPS. (p.25)

    However, once an NSPS is finalized, then the standard applies to
any new source or modification that meets the applicability of the NSPS
and has not commenced construction as of the date of the proposed NSPS.
    It is also important to keep in mind that BACT is a case-by-case
review that considers a number of factors, and the fact that a minimum
control requirement is established by EPA through an NSPS does not mean
that a more stringent control cannot be chosen by the permitting
agency. The EPA's PSD and Title V Permitting Guidance for Greenhouse
Gases (March 2011) discusses considerations (e.g., technical
feasibility, economic impacts and other costs, and environmental and
energy impacts) when evaluating BACT for CO2, as well as
other greenhouse gases.
    Under this proposed NSPS, an affected facility is a new EGU. In
this rule we are not proposing standards for modified or reconstructed
sources. However, since both a new and existing power plant can add new
EGUs to increase generating capacity, this NSPS will apply to both a
new, greenfield EGU facility or an existing facility that adds EGU
capacity by adding a new EGU that is an affected facility under this
NSPS. While this latter scenario can be considered the modification of
existing sources under PSD, this proposed NSPS will not apply to
modified or reconstructed sources as those terms are defined under part
60. Thus, this NSPS would not establish a BACT floor for sources that
are modifying an existing EGU, for example, by adding new steam tubes
in an existing boiler or replacing blades in their existing combustion
turbine with a more efficient design.
    Furthermore, our analysis for this proposed NSPS considers only the
extent to which particular pollution control techniques are BSER for
new units, and does not evaluate whether such techniques also qualify
as BSER for modified or reconstructed sources under Part 60 or are
otherwise achievable methods for reducing GHG emission from such
sources considering economic, environmental, and energy impacts.
Therefore, we do not believe that the content of this rule has any
direct applicability on the determination of BACT for any part 60
modified or reconstructed sources obtaining a PSD permit.

D. Implications for Title V Program

    Under the title V program, a source that emits any air pollutant
subject to regulation at or above specified thresholds (along with
certain other sources) is required to obtain an operating permit. This
permit includes all of the CAA requirements applicable to the source.
These permits are generally issued through EPA-approved State title V
programs.
    As the EPA explained in the Tailoring Rule preamble, title V
applies to a ``major source,'' CAA section 502(a), which is defined to
include, among other things, certain sources, including any ``major
stationary source,'' CAA section 501(2)(B), which, in turn, is defined
to include a stationary source of ``any air pollutant'' at or above 100
tpy. CAA section 302(j). The EPA's regulations under title V define the
term ``major source,'' and in the Tailoring Rule, the EPA revised that
definition to make clear that the term is limited to stationary sources
that emit any air pollutant ``subject to regulation.'' The EPA
incorporated the Tailoring Rule threshold within the definition of
``subject to regulation.'' The EPA described its action as follows in
the preamble to the Tailoring Rule:

    Thus, EPA is adding the phrase ``subject to regulation'' to the
definition of ``major source'' under 40 CFR 70.2 and 71.2. The EPA
is also adding to these regulations a definition of ``subject to
regulation.'' Under the part 70 and part 71 regulatory changes
adopted, the term ``subject to regulation,'' for purposes of the
definition of ``major source,'' has two components. The first
component codifies the general approach EPA recently articulated in
the ``Reconsideration of Interpretation of Regulations That
Determine Pollutants Covered by Clean Air Act Permitting.'' 75 FR
17704. Under this first component, a pollutant ``subject to
regulation'' is defined to mean a pollutant subject to either a
provision in the CAA or regulation adopted by EPA under the CAA that
requires actual control of emissions of that pollutant and that has
taken effect under the CAA. See id. at 17022-23; Wegman Memorandum
at 4-5. To address tailoring for GHGs, EPA includes a second
component of the definition of ``subject to regulation,'' specifying
that GHGs are not subject to regulation for purposes of defining a
major source, unless as of July 1, 2011, the emissions of GHGs are
from a source emitting or having the potential to emit 100,000 tpy
of GHGs on a CO2e basis.

75 FR 31583.
    Unlike the PSD regulations described above, the title V definition
of ``major source'', as revised by the Tailoring Rule, does not on its
face distinguish among types of regulatory triggers for title V.
Because title V has already been triggered for GHG-emitting sources,
the

promulgation of CAA section 111 requirements has no further impact on
title V applicability requirements for major sources of GHGs.
Accordingly, today's rulemaking has no title V implications with
respect to the Tailoring Rule threshold. Of course, unless exempted by
the Administrator through regulation under CAA section 502(a), sources
subject to a NSPS are required to apply for, and operate pursuant to, a
title V permit that assures compliance with all applicable CAA
requirements for the source, including any GHG-related applicable
requirements. We have concluded that this rule will not affect non-
major sources and there is no need to consider whether to exempt non-
major sources.
    Note that we propose to move the definition of ``Greenhouse gases''
currently within the definitions of ``Subject to regulation'' in 40 CFR
70.2 and 71.2 to a definition within 70.2 and 71.2 to promote clarity
in the regulations.

E. Implications for Title V Fee Requirements for GHGs

    The issuance of the final EGU GHG NSPS will trigger certain
requirements related to title V fees for GHG emissions under 40 CFR
parts 70 and 71. States (and approved local and tribal permitting
authorities) will be required to include GHG emissions in determining
whether they collect adequate fees, if the state relies on the
``presumptive minimum'' approach to demonstrating fee adequacy. In
addition, sources subject to federal permitting under part 71 will be
required to include GHG emissions in calculating their annual permit
fee.\262\ The EPA is proposing changes to the title V rules to limit
the impact of the requirements that would otherwise occur under the
existing rules, provide flexibility to the states to ensure sufficient
funding for their programs, and to ensure that the requirements are
consistent with the Clean Air Act.
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    \262\ Also, we understand several states may have fee
requirements that are structured with similar definitions that would
result in GHGs being added to the list of air pollutants that are
subject to title V fees.
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    These requirements would be triggered because the regulation of
GHGs under section 111 for the first time through the issuance of the
EGU GHG NSPS would make GHGs a ``regulated air pollutant,'' as defined
under 40 CFR parts 70 and 71, a ``regulated pollutant (for presumptive
fee calculation)'' as defined under part 70 and a ``regulated pollutant
(for fee calculation)'' as defined under part 71.
    Under the current part 70, regulation of GHGs under section 111
through the issuance of any NSPS would result in GHGs being added to
the list of air pollutants used in ``presumptive minimum'' fee
calculations. Also, in EPA's part 71 permit program, and possibly in
certain state part 70 programs, issuance of a NSPS standard would
result in GHGs being added to the list of air pollutants that are
subject to fee payment by sources. This effect of adding GHGs to
certain title V fee requirements was not discussed in the original
proposal for the EGU GHG NSPS; however, several public comments were
raised on this issue, and a number of related issues, during the public
comment period on the original proposal for the EGU GHG NSPS.
    In this re-proposal of the EGU GHG NSPS, we discuss this issue for
GHGs related to title V fees and propose rule amendments that will
enable permitting authorities to collect fees as needed to support
their programs, and to avoid excessive and unnecessary fees. We also
respond to and clarify some related issues raised by commenters on the
original proposal.
    In summary, we are proposing to exempt GHGs from the presumptive
fee calculation, yet account for the costs of GHG permitting program
costs through a cost adjustment to ensure that fees will be collected
that are sufficient to cover the program costs. We are also proposing
that permitting agencies that do not use the presumptive fee approach
can continue to demonstrate that their fee structures are adequate to
implement their title V programs.
    Prior to explaining our proposal in more detail, the following
discussion provides background on the fee requirements of the title V
rules, what those fees cover in terms of agencies' program
implementation, what additional activities agencies might be expected
to have to undertake as a result of GHGs becoming ``regulated
pollutants'' under the NSPS, what the GHG Tailoring Rule said about
title V fees, background on title V fees in the context of the original
proposal for the EGU GHG NSPS, and existing limitations on the
collection of GHG fees.
1. Background
a. The Title V Rules
    Title V is implemented through 40 CFR parts 70 and 71. Part 70
defines the minimum requirements for state, local and tribal (state)
agencies to develop, implement and enforce a title V operating permit
program; these programs are developed by the state and the state
submits a program to EPA for a review of consistency with part 70.
There are about 112 approved part 70 programs in effect, with about
15,000 part 70 permits currently in effect. (See Appendix A of 40 CFR
part 70 for the approval status of each state program). Part 71 is a
federal permit program run by the EPA, primarily where there is no part
70 program in effect (e.g., in Indian country, the federal Outer
Continental Shelf and for offshore Liquified Natural Gas
terminals).\263\ There are about 100 part 71 permits currently in
effect (most are in Indian country).
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    \263\ In some circumstances, EPA may delegate authority for part
71 permitting to another permitting agency, such as a tribal agency
or a state. The EPA has entered into delegation agreements for
certain part 71 permitting activities with at least one tribal
agency. There are currently no states that do not have an approved
part 70 program; thus, there is no need for EPA to delegate part 71
permitting authority to any state at this time.
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b. The Fee Requirements of Title V
    Section 502(b)(3)(A) of the Act requires owners or operators of all
sources subject to permitting to ``pay an annual fee, or the equivalent
over some other period, sufficient to cover all reasonable (direct and
indirect) costs required to develop and administer the permit
program.'' Section 502(b)(3)(B) of the Act generally sets forth the
methods for determining whether a permitting authority is collecting
sufficient fees in total to cover the costs of the program. First,
under the ``presumptive minimum'' approach set forth in section
502(b)(3)(B)(i), a state can satisfy the requirement by showing that
``the program will result in the collection, in the aggregate, from all
sources subject to [the program] of an amount not less than $25 per ton
of each regulated pollutant, or such other amount as the Administrator
may determine adequately reflects the reasonable costs of the permit
program.'' The statute further provides that emissions in excess of
4,000 tpy for any one pollutant need not be included in the
calculation, and that the initial fee rate ($25 per ton) shall be
adjusted for inflation.\264\ See section 502(b)(3)(B)(iii)-(v). Also,
section 502(b)(3)(B)(ii) of the Act sets forth a definition of
``regulated pollutant'' for purposes of the presumptive fee calculation
that includes, in part, each pollutant regulated under section 111 of
the Act, such as any pollutants regulated under any NSPS, which would
make GHG a ``regulated pollutant'' based on our proposal for the EGU
GHG NSPS. Each of the title V rules that implement title V contains a
definition of ``regulated air

pollutant''\265\ (at 40 CFR 70.2 and 71.2) that tracks the Act
definition of ``regulated pollutant.'' The ``regulated air pollutant''
definition is used in the regulatory text for application and other
purposes and it is relevant for fee purposes because it is cross-
referenced as the starting point for two fee-related definitions:
``regulated pollutant (for presumptive fee calculation) \266\'' in 40
CFR 70.2 and ``regulated pollutant (for fee calculation) \267\'' in 40
CFR 71.2.
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    \264\ The current corresponding part 70 fee rate, adjusted for
inflation, is approximately $47 per ton.
    \265\ The definition includes any pollutant that is subject to
any standard promulgated under section 111 of the Act.
    \266\ 40 CFR 70.2 defines regulated pollutant (for presumptive
fee calculation) to include any regulated air pollutant except
carbon monoxide, any pollutant that is a regulated air pollutant
solely because it is a Class I or II substance subject to a standard
promulgated under or established by title VI of the Act and any
pollutant that is a regulated air pollutant solely because it is
subject to a standard or regulation under section 112(r) of the Act.
    \267\ 40 CFR 71.2 defines regulated pollutant (for fee
calculation) the same as reegulated pollutant (for presumptive fee
calculation) in 40 CFR 70.2.
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    Alternatively, if a state does not wish to show it collects an
amount of fees at least equal to the presumptive minimum amount,
section 502(b)(3)(B)(iv) provides that a program may be approved if the
state demonstrates that it collects sufficient fees to cover the costs
of the program, even if that amount is below the presumptive minimum.
    The presumptive fee approach of the statute is reflected in the
part 70 regulations for those states that wish to use it for fee
adequacy purposes. In addition, for the federal part 71 permitting
program, which the EPA implements directly, the EPA has adopted rules
to ensure that it collects adequate fees, consistent with the statute.
These statutory requirements for fees are reflected in 40 CFR 70.9 and
71.9, respectively.
    Although the Clean Air Act and part 70 require that a title V
permit program must collect sufficient fees to cover the costs of the
program, neither the Act nor part 70 specifies the details of how those
fees must be charged to particular sources in their fee schedules. The
part 70 regulations specifically provide, at 40 CFR 70.9(b)(3), that a
``state program's fee schedule may include emission fees, application
fees, service fees or other types of fees, or any combination
thereof.'' Many states use emission fees and other types of fees in
combination in their fee schedules and we understand that some state
fee schedules are structured such that they would result in GHG fees
being required when GHGs are regulated under any NSPS. For example,
states may have chosen for convenience sake to use the ``regulated
pollutant (for presumptive fee calculation)'' definition of part 70, or
a similar state definition, to identify the pollutants subject to fees
as part of their fee schedule. For part 71, the EPA chose to promulgate
an emissions-based fee schedule that uses the definition of ``regulated
pollutants (for fee calculation)'' to identify the pollutants subject
to fees, and thus, part 71 is structured such that GHG fees would be
required when GHGs are regulated under any NSPS.
    State fee schedules charge emissions-based fees that range from
about $15 to $100 or more per ton for each air pollutant for which they
charge a fee, while part 71 charges about $48 per ton,\268\ effective
for calendar year 2013, for each of the ``regulated pollutants (for fee
calculation).'' See 40 CFR 71.9(c)(1). Most part 70 and part 71
programs require sources to pay the fees on an annual basis, initially
with the submittal of its permit application, and thereafter, on the
anniversary of application submittal. See 40 CFR 70.9(a), 71.9(e).
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    \268\ Note that the part 71 fee rate and the part 70 presumptive
fee rate are slightly different because the part 71 rate was set
based on an analysis that showed that the EPA needed slightly more
than the presumptive minimum to collect sufficient revenue to fund
the program.
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    Section 502(b)(3)(A) of the CAA broadly requires permit fees
``sufficient to cover all reasonable (direct and indirect) costs
required to develop and administer the permit program'' including the
reasonable costs of: ``(i) reviewing and acting upon any application
for such a permit, (ii) implementing and enforcing the terms and
conditions of any such permit (not including any court costs or other
costs associated with any enforcement action), (iii) emissions and
ambient monitoring, (iv) preparing generally applicable regulations, or
guidance, (v) modeling, analyses, and demonstrations, and (vi)
preparing inventories and tracking emissions.'' These statutory
requirements were incorporated into the regulations at 40 CFR
70.9(b)(1) and 71.9(b), EPA has provided detailed guidance on EPA's
interpretation of this list of activities in several memoranda,\269\
and these activities have been considered in the context of the ICR
development and renewal process for part 70 and 71.
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    \269\ For example, see ``Reissuance of Guidance on Agency Review
of State Fee Schedules for Operating Permits Programs Under Title
V''; from John S. Seitz, Director, Office of Air Quality Planning
and standards, to Air Division Directors, Regions I-X; August 4,
1993; available at http://www.epa.gov/region07/air/title5/t5memos/fees.pdf.
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c. How EPA Addressed Title V Fees in the Tailoring Rule
    The GHG Tailoring Rule concerned when sources are required to
obtain permits under prevention of significant deterioration (PSD) and
title V due to emissions of GHGs. (See Prevention of Significant
Deterioration and Title V Greenhouse Tailoring Rule; Final Rule [the
Tailoring Rule]; 75 FR 31514, June 3, 2010.) GHGs became subject to
regulation as a result of the Light Duty Vehicle Rule (75 FR 25234, May
7, 2010), and the Tailoring Rule established emissions thresholds for
purposes of PSD and title V. Neither the Light Duty Vehicle Rule nor
the Tailoring Rule made any changes that would cause GHGs to meet the
definition of ``regulated air pollutant,'' or related fee definitions
in the title V regulations. The EPA has promulgated no other standards
that would trigger fee requirements for GHGs in title V programs.
    The GHG Tailoring Rule addressed the possible need for states and
the EPA to charge fees for GHG emissions based on the burdens imposed
under the Tailoring Rule for states to incorporate GHGs into permits or
to issue permits to sources based on GHG emissions. We did not revise
the part 70 rules to require fees for GHGs, although we did clarify
that states have the option of charging fees to recover the costs of
permitting related to GHGs. Also, we did not revise part 71 to require
GHG fees, and we stated that we would review the need for additional
fees to cover program costs for GHGs over time. (See 75 FR 31526 and
31584.) We retained this approach in last year's Step 3 Tailoring Rule.
(See Prevention of Significant Deterioration and Title V Greenhouse
Tailoring Rule Step 3, GHG Plantwide Applicability Limitations and GHG
Synthetic Minor Limitations, (Step 3 of the Tailoring Rule), 77 FR
41051, July 12, 2012).
d. Title V Fees in the Previous EGU GHG NSPS Proposal
    The previous EGU GHG NSPS proposal did not discuss any title V fee
issues related to regulating GHGs under a section 111 standard;
however, several public commenters (two state agencies and one industry
group) raised several concerns or asked for clarification on a number
of issues related to title V fees during the public comment period. Two
of these commenters requested clarification as to whether the issuance
of the EGU GHG NSPS would make either GHGs or CO2 subject to
regulation such that title V fee requirements would be triggered for
either of these

pollutants. One commenter requested clarification on whether fees are
required for ``regulated NSR pollutants,'' such as GHG. One commenter
questioned whether the rationale of the Tailoring Rule for deferring
fees for GHGs would also apply to the EGU GHG NSPS. Finally, one
commenter asked us to clarify if a state could refrain from charging a
fee for CO2 (based on the issuance of the EGU GHG NSPS) if
the state otherwise generates a fee sufficient to meet the ``program
support requirements'' of title V. Note that we address the substance
of several of these comments related to title V fees in section B of
this portion of the proposal.
e. Unique Characteristics of GHGs Relative to Fees
    There are a number of provisions in part 70 and part 71 and
characteristics of GHGs that are relevant to any discussion related to
charging fees for GHGs. First, it should be noted that GHG are emitted
in extremely high quantities relative to other air pollutants, such as
the criteria pollutants, which are typically emitted by combustion
sources that also emit GHGs. A review of emission factors in EPA's AP-
42 shows that GHGs are typically emitted in quantities as much as one
thousand or more times higher than CO or NOX and many other
pollutants as a product of combustion for a given mass of fuel.\270\
Thus, we expect that charging fees for GHGs at the same rate (in
dollars per ton) as other regulated air pollutants would lead to fee
revenue that would be excessive, far beyond the reasonable costs of the
program. Even though most part 70 and 71 programs cap total fees at
4,000 tons per air pollutant per year \271\ we note that the total GHG
fee for a particular source under the current part 71 rule could still
be significant, up to about $194,000 per year for GHGs alone, if GHGs
are charged at the same rate as for other ``regulated pollutants (for
fee calculation).'' \272\
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    \270\ See AP-42, Compilation of Air Pollution Emission Factors,
Volume I, Stationary and Area Sources, Fifth Edition. For example,
for external combustion of bituminous and subbituminous coals, see
table 1.1-3 for NOX and CO emission factors and table
1.1-20 for CO2 emissions factors.
    \271\ Consistent with the option afforded states at 40 CFR
70.9(b)(2)(ii)(B) and the EPA's fee schedule at 40 CFR 71.9(c)(5).
    \272\ Note that most sources that emit GHGs, particularly major
sources of GHG, also emit other regulated air pollutants subject to
fees; thus, they would pay significant title V fees even if a fee
for GHGs is not charged.
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    Second, unlike other pollutants, GHGs can be estimated in two ways:
by mass or by CO2 equivalent (CO2e). While the
title V permitting threshold for the Tailoring Rule was established at
100,000 CO2e and 100 tpy mass, the fee provisions of part 70
and 71, and we believe the fee provisions of the majority, if not all,
state programs, charge fees on a mass (per ton), rather than on a
CO2e,\273\ basis. See 40 CFR 70.9(b)(2)(i) and 40 CFR
71.9(c)(1).
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    \273\ The term ``tpy CO2 equivalent emissions'' (or
``CO2e'') is defined within the definition of ``subject
to regulation'' in 40 CFR 70.2 and 71.2. The definitions read, in
relevant part, ``[CO2e] shall represent an amount of GHGs emitted,
and shall be computed by multiplying the mass amount of emissions
(tpy), for each of the six greenhouse gases in the pollutant GHGs,
by the gas's associated global warming potential published at Table
A-1 to subpart A of part 98 of this chapter--Global Warming
Potentials, and summing the resultant value for each to compute a
tpy CO2e.
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2. Response to Comments on Fees From the Previous EGU GHG NSPS Proposal
    In response to concerns raised by commenters, and because response
to certain of these issues will help to provide a better proposal, we
respond to several of these comments at this time. In response to the
question as to whether CO2 or GHGs would be regulated by the
EGU GHG NSPS, we clarify that GHG would be regulated under section 111
of the Act and that this does not affect the applicability thresholds
previously established for PSD and title V in the Tailoring Rule.
First, the EPA considers the pollutant being regulated by the NSPS for
the purposes of PSD and title V to be GHG, rather than CO2.
Thus, under this interpretation, this NSPS has not caused
CO2 to be treated as a ``regulated air pollutant'' under the
third prong of the definition of ``regulated air pollutant'' contained
in 40 CFR 70.2 and 71.2, which includes ``[a]ny pollutant that is
subject to any standard promulgated under section 111 of the Act,''
because it causes GHG, rather than CO2, to be the
``regulated air pollutant.'' Second, although EPA's PSD regulations
provide that regulation of GHGs under CAA section 111 triggers PSD
applicability, the Tailoring Rule thresholds for GHG continue to apply
for major source applicability for both the PSD and Title V permitting
programs.\274\ In addition, we are proposing regulatory text in section
60.46Da(f) and section 60.4315(b) to make clear that for purposes of
PSD and title V, greenhouse gases (not carbon dioxide) is the pollutant
subject to a standard promulgated under section 111.
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    \274\ We have clarified these points further in a memorandum
added to the docket for this rulemaking (``PSD Threshold
Memorandum,'' dated May 8, 2012). See document number EPA-HQ-OAR-
2011-0660-7602.
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    In response to the comment inquiring whether the rationale of the
Tailoring Rule remains relevant for deferring action on fees, we are