Commenters noted that the 219,000 MWh total electric sales
threshold put larger combustion turbines at a competitive disadvantage
by distorting the market and could have the perverse impact of
increasing CO2 emissions. These commenters noted that the
219,000 MWh total electric sales threshold would allow combustion
turbines smaller than approximately 80 MW to sell more than one-third
of their potential electric output, but larger, more efficient
combustion turbines would still be restricted to selling one-third of
their potential electric output to avoid triggering the NSPS. They
argued that this would result in a regulatory incentive for generators
to install multiple, less-efficient combustion turbines instead of
fewer, more-efficient combustion turbines and could have the unintended
consequence of increasing CO2 emissions.
c. Percentage electric sales criterion
    Commenters from the power sector generally supported a complete
exemption for simple cycle turbines. These commenters stated that
simple cycle turbines are uniquely capable of achieving the ramp rates
(the rate at which a power plant can increase or decrease output)
necessary to respond to emergency conditions and hourly variations in
output from intermittent renewables. Commenters noted that simple cycle
combustion turbines serve a different purpose than NGCC power blocks.
In addition, commenters noted that electricity generation dispatch is
based on the incremental cost to generate electricity and that because
NGCC units have a lower incremental generation cost than simple cycle
units, economics will drive the use of NGCC technologies over simple
cycle units. However, commenters also stated that historic simple cycle
operating data may not be representative of future system requirements
as coal units retire, generation from intermittent renewable generation
increases, and numerous market and regulatory drivers impact plant
operations. In the absence of a complete exemption, these commenters
supported a percentage electric sales threshold between 40 to 60
percent of a unit's potential electric output.
    Some commenters said that because the proposed percentage electric
sales criterion applied over a three-year period, it would adversely
affect grid reliability because operators conservatively would hedge
short-term operating decisions to ensure that they have sufficient
capacity to respond to unexpected scenarios during future compliance
periods when the demand for electricity is higher. These commenters
were concerned that such compliance decisions would drive up the cost
of electricity as the most efficient new units are taken out of service
to avoid triggering the NSPS and older, less efficient units with no
capacity factor limitations are ramped up instead.
    Some commenters supported the sliding-scale approach (i.e., a
percentage electric sales threshold based on the design efficiency of
the combustion turbine) and stated that incentives for manufacturers to
develop (and end users to purchase) higher efficiency combustion
turbines could help mitigate concerns about a monolithic national
constraint on simple cycle capacity factors.

    In contrast, others commented that fast-start NGCC units intended
for peaking and intermediate load applications can achieve comparable
ramp rates to simple cycle combustion turbines, but with lower
CO2 emission rates. These commenters said that simple cycle
turbines should be restricted to their historical role as true peaking
units and that the proposed one-third electric sales threshold provided
sufficient flexibility. Some commenters suggested that the one-third
electric sales threshold could be reduced to 20 percent or lower
without adverse impacts on grid reliability.
    Commenters noted that a complete exclusion for simple cycle
turbines would create a regulatory incentive for generators to install
and operate less efficient unaffected units instead of more efficient
affected units, thereby increasing CO2 emissions. According
to these commenters, any applicability distinctions should be based on
utilization and function rather than purpose or technology.
    Commenters in general supported the use of 3-year rolling averages
instead of a single-year average for the percentage and total electric
sales criteria because, in their view, the 3-year rolling averages
would provide a better overall picture of normal operations. Some
commenters stated that a rolling 12-month or calendar-year average
could be severely skewed in a given year because of unforeseen or
unpredicted events. They said that using a 3-year averaging methodology
would provide system operators with needed flexibility to dispatch
simple cycle units at higher than normal capacity factors. In contrast,
some commenters stated that, because capacity is forward-looking (e.g.,
payments for capacity are often made several years in advance), the 3-
year averaging period provides limited benefit because owner/operators
need to reserve the ability to respond to unforeseen events.
    Commenters noted that potential compliance issues could result from
the inconsistent time frame between the 3-calendar-year applicability
period and the 12-operating-month compliance period. For example, a
facility could sell more than one-third of its potential electric
output over a 3-year period, but sell less than one-third of its
potential electric output during any given 12-operating-month
compliance period within that 3-year period. During a 12-operating-
month period with electric sales of less than one-third of potential
electric output, a unit could be operating for long periods at part
load and have multiple starts and stops. These operating conditions
have the potential to increase CO2 emissions, regardless of
the deign efficiency of the turbine. Therefore, a unit could have an
emission rate in excess of the proposed standard.
    Regarding the relationship between the percentage electric sales
criterion and system emergencies, multiple commenters supported
exclusion of electricity generated as a result of a system emergency
from counting towards net sales. These commenters stated that the
exclusion was appropriate because the benefits of operating these units
to generate electrical power during emergency conditions would outweigh
any adverse impacts from short-term increases in CO2
emissions. One commenter stated that, in addition to declared grid
emergencies, other circumstances might warrant emergency exemption
under the rule, including extreme market conditions, limitations on
fuel supply, and reliability responses.
    Multiple commenters opposed the exclusion of system emergencies
when calculating a source's percentage electric sales for applicability
purposes because NSPS must apply continuously, even during system
emergencies. These commenters stated that the EPA does not have the
authority under the CAA to suspend the applicability of a standard
during periods of system emergency. Some commenters stated that an
exclusion would be unnecessary because the EPA Assistant Administrator
for Enforcement has the authority to advise a source that the
government will not sue the source for taking certain actions during an
emergency. Commenters said that this enforcement discretion approach
has provided prompt, flexible relief that is tailored to the needs of
the particular emergency and the communities being served and is only
utilized where the relief will address the particular emergency at
hand.
    Commenters added that this enforcement discretion approach is
consistent with the CAA's mandate that emission limits apply
continuously and provide safeguards against abuse. One commenter stated
that emergencies happen rarely and typically last for short periods,
that the proposed percentage electric sales threshold would allow a
source to operate at its full rated capacity for up to 2,920 hours per
year without triggering applicability, and that the potential
occurrence of grid emergencies would represent a tiny fraction of this
time. Another commenter stated that no emergency short of large scale
destruction of power generating capacity by terrorism, war, accident,
or natural disaster could justify operating a peaking unit above a 10-
percent capacity factor on a 3-year rolling average.
d. Broad applicability approach
    In response to the EPA's request for comments on whether the
proposed applicability requirements that retrospectively look back at
actual events (i.e., the electric sales and fuel use criteria) would
create implementation issues, several permitting authorities opposed
the provisions because units could be subject to coverage one year but
not the next, resulting in compliance issues and difficulties in
determining proper pre-construction and operating permit conditions.
These permitting authorities suggested that in order for a source to
avoid applicability, the source should be subject to a federally
enforceable permit condition with associated monitoring, recordkeeping,
and reporting conditions for assessing applicability on an ongoing
basis. Other commenters stated that an applicability test that
concludes after construction and operation have commenced is
inconsistent with the general purpose of an applicability test--to
provide clear and predictable standards of performance for new sources
that would apply when they begin operations.
    Some commenters opposed the proposed retrospective applicability
criteria related to actual output supplied during a preceding
compliance period because EGUs must know what performance standards
will apply to them during the licensing process, and such criteria do
not allow the permitting authority and the public to know in advance
whether an emission standard applies to a proposed new unit. Other
commenters said that EGUs undergoing permitting should be allowed to
request limits in their operating permit conditions in order to remain
below the applicability thresholds, as this methodology is consistent
with the pre-construction permitting requirements in many federally
approved SIPs and the current approach under the Title V permitting
program.
    Many commenters stated a preference for the ``proposed
applicability approach'' over the ``broad applicability approach.''
These commenters did not think it was necessary to require non-base
load or multi-fuel-fired combustion turbines to be subject to emission
standards. They stated that there is no justification for imposing
burdensome monitoring, reporting, and recordkeeping requirements that
would have no environmental benefit (i.e., would not reduce
CO2 emissions) because these units would be subject to

``no emissions standards.'' Other commenters supported the broad
applicability approach and stated that all new, modified, and
reconstructed units that sell electricity to the grid, including small
EGUs, oil-fired combustion turbines, and simple cycle combustion
turbines should be affected EGUs because they would otherwise have a
competitive advantage in energy markets as they would not be required
to internalize the costs of compliance.
    In contrast, to preserve the discretion of state planners under
section 111(d), many other commenters supported the broad applicability
approach and the inclusion of new simple cycle units within the scope
of the section 111(b) emission standards so that similar, existing
simple cycle units could be subject to the 111(d) standards. Numerous
other commenters stated that all units that sell electricity to the
grid should be subject to a standard, including simple cycle units,
because they view the utility grid as a single integrated system and
that doing so may simplify development of future frameworks for cost-
effective carbon reductions from existing units, such as frameworks
based on system-wide approaches.
3. Final Applicability Criteria and Rationale
    Based on our consideration of the comments received related to the
proposed applicability criteria and practical implementation issues, we
are revising how those criteria will be implemented. The final
applicability criteria for combustion turbines are generally consistent
with the broad applicability approach on which we solicited comment.
Section VIII of this preamble presents each proposed applicability
criterion together with the form of the criterion in the final rule.
The final general applicability framework includes the proposed
criteria based on the combustion turbine's base load rating and the
combustion turbine's total electric sales capacity. The final general
applicability framework also includes multiple exemptions that are
relevant to combustion turbines: combustion turbines that are not
connected to natural gas pipelines; CHP facilities with federally
enforceable limits on total electric sales; dedicated non-fossil units
with federally enforceable limits on the use of fossil fuels; and
municipal waste combustors and incineration units.
    The final applicability framework reflects multiple variations from
the proposal that are responsive to public comments. First, consistent
with the broad applicability approach, we are finalizing the percentage
electric sales and natural gas-use thresholds as subcategorization
criteria instead of as applicability criteria. In addition, for non-CHP
combustion turbines, we are eliminating the proposed 219,000 MWh total
electric sales criterion. Finally, we are eliminating the proposed
``constructed for the purpose of'' qualifier for the total and
percentage electric sales criteria. We are also not finalizing
CO2 standards for dedicated non-fossil fuel-fired or
industrial CHP combustion turbines. The rationale for not finalizing
CO2 standards for dedicated non-fossil and industrial CHP
units is discussed in more detail in Section III.
    The EPA agrees with commenters that the NSPS applicability
framework should be structured so that permitting authorities, the
regulated community, and the public can determine what standards apply
prior to a unit having commenced construction. With this in mind, the
EPA has concluded that the proposed fossil fuel-use, natural gas-use,
percentage electric sales, and total electric sales applicability
criteria for combustion turbines are not ideal approaches. Because
applicability determinations based on these criteria could change from
year to year (i.e., units could move in and out of coverage each year
depending on actual operating parameters), some operators would not
know the extent of their compliance obligations until after the
compliance period.
    Further, from a practical implementation standpoint, existing
permitting rules generally require pre-construction permitting
authorities to include enforceable conditions limiting operations such
that unaffected units will not trigger applicability thresholds. Such
conditions are often called ``avoidance'' or ``synthetic minor''
conditions, and these conditions typically include ongoing monitoring,
recordkeeping, and reporting requirements to ensure that operations
remain below a particular regulatory threshold.
    The following sections provide further discussion of the final
general applicability criteria and the rationale for changing certain
proposed applicability criteria to subcategorization criteria.
a. Base load rating criterion
    We are retaining the applicability criterion that a combustion
turbine must be capable of combusting more than 260 GJ/h (250 MMBtu/h)
heat input of fossil fuel. We revised the proposed 73 MW form of the
base load rating criterion to 260 GJ/h because some commenters
misinterpreted the 73 MW form (which is mathematically equivalent to
250 MMBtu/h) as the electrical output rating of the generator. This
change is a non-substantive unit conversion intended to limit
misinterpretation. While some commenters suggested that we expand this
applicability criterion to cover smaller EGUs as well, we did not
propose to cover smaller units. Because smaller units emit relatively
few CO2 emissions compared to larger units and because we
currently do not have enough information to identify an appropriate
BSER for these units, we are not finalizing CO2 standards
for smaller units.
b. Total electric sales criterion
    The proposed 219,000 MWh total sales criterion was based on a 25 MW
unit operating at base load the entire year (i.e., 25 MW * 8,760 h/y =
219,000 MWh/y). This criterion was included in the original subpart Da
coal-fired EGU criteria pollutant NSPS. Coal-fired EGUs tend to be much
larger than 25 MW, and the criterion's primary purpose was to exempt
industrial CHP facilities from the criteria pollutant NSPS. In the
context of combustion turbines, however, commenters expressed concerns
that the 219,000 MWh electric sales threshold would actually encourage
owners and operators to install multiple, smaller, less-efficient
simple cycle combustion turbines instead of a single, larger, more-
efficient simple cycle turbine. The reason for this is that the 219,000
MWh threshold would allow smaller simple cycle combustion turbines of
less than 80 MW to sell significantly more electricity relative to
their potential electric output than larger turbines. Many commenters
also indicated that having the flexibility to operate a simple cycle
turbine at a higher capacity factor is important because it allows for
capacity payments from the transmission authority. In light of these
comments, we are not finalizing the 219,000 MWh total electric sales
criterion for non-CHP combustion turbines. Instead, we are finalizing a
criterion that will exempt combustion turbines that do not have the
ability to sell at least 25 MW to the grid. This approach will maintain
our goal of exempting smaller EGUs, while avoiding the perverse
environmental incentives mentioned by the commenters. As explained in
Section III, however, industrial CHP units are sized based on demand
for useful thermal output, so there is less of an incentive for owners
and operators to install multiple smaller units. Therefore, we are
maintaining the 219,000 MWh

total electric sales criterion for CHP units.
c. Percentage electric sales criterion
    Commenters generally opposed the proposed percentage electric sales
criterion approach because it was based in part on actual electric
sales, meaning applicability could change periodically (i.e., a unit's
electric sales may change over time, rising above and falling below the
electric sales threshold). The EPA agrees this situation is not ideal.
To avoid situations in which applicability changes from year to year,
we first considered two approaches using permit restrictions. Under the
first approach, a standard would apply to all sources with permit
restrictions mandating electric sales above a threshold (i.e., an
approach that closely mirrors the proposed percentage electric sales
criterion). Under the second approach, a standard would apply to all
sources without permit restrictions limiting electric sales to a level
below that threshold (i.e., effectively identifying non-base load units
and excluding them from applicability). As stated in the proposal, we
did not think it was critical to include peaking and cycling units
because peaking turbines operate less and because it would be much more
expensive to lower their emission profile to that of a combined cycle
power plant or a coal-fired plant with CCS.
    The first approach is not practical, however, because new
combustion turbines could avoid applicability by simply not having a
permit restriction at all. Moreover, even if a combustion turbine were
subject to the restriction, it could violate its permit if it did not
operate enough to sell the requisite amount of electricity. This would
be nonsensical, especially because system demand would not always be
sufficient to allow all permitted units to operate above the threshold.
Therefore, we rejected the first permitting approach.
    In contrast, the second approach would be a viable method for
identifying and exempting peaking units from applicability. However,
there are multiple drawbacks to such an applicability approach. First,
this approach would subject those turbines without a permit restricting
electric sales to the final emission standards, which raises concerns
as to whether turbines with lower actual sales could achieve the
standards. For example, new NGCC units tend to dispatch prior to older
existing units and will generally operate for extended periods of time
near full load and sell electricity above the percentage electric sales
threshold. However, as NGCC units age, they tend to start and stop more
frequently and operate at part load. Yet, even if these units sell
below the percentage electric sales threshold, they would still be
affected units if they did not take a permit restriction. As commenters
noted, part-load operation and frequent starts and stops can reduce the
efficiency of a combustion turbine. While we are confident that our
final standards for base load natural gas-fired combustion turbines can
be achieved by units serving either base or intermediate load, we are
not as confident that affected NGCC units that might someday be
operated as non-base load units (e.g., as NSPS units age, their
incremental generating costs will tend to be higher than newer units
and they will dispatch less) could achieve the standards.
    More importantly, however, we are concerned that using a permitting
approach for the percentage electric sales criterion would create
problems due to the interaction between 111(b) and 111(d). Under the
second permitting approach we considered, units with low electric sales
would be excluded from applicability, while units with high electric
sales would be included. While these low-electric sales units would
generally be simple cycle combustion turbines and the high-electric
sales units would generally be NGCC combustion turbines, this would not
always be the case. In contrast, we are finalizing an applicability
approach in the 111(d) emission guidelines that is based on a
combustion turbine's design characteristics rather than electric sales.
Simple cycle combustion turbines are excluded from applicability, while
NGCC units are included. As a result, the universe of sources covered
by the 111(b) standards would not necessarily be the same universe of
sources covered by the 111(d) standards.
    To resolve this issue, we considered whether we could change the
111(d) applicability criteria to be based on historical operation
rather than design characteristics. For example, if an existing
combustion turbine had historically sold less than one-third of its
potential output to the grid, then it would be exempt from the emission
guidelines. However, many existing NGCC units have historically sold
less than this amount of electricity, meaning that they would not be
subject to the rule. We ran into similar issues when considering other
thresholds. For example, a percentage electric sales threshold of 10
percent would still exempt roughly 5 percent of existing NGCC units
from 111(d), while simultaneously raising achievability concerns with
the 111(b) standard. Moreover, even if we had finalized 111(d)
applicability criteria based on historical operations, existing NGCC
units could have decided to take a permit restriction limiting their
electric sales going forward to avoid applicability. Under any of these
scenarios, our goals with respect to 111(d) would not be accomplished.
    To avoid this result, the EPA has concluded that it is appropriate
to finalize the broad applicability approach and set standards for
combustion turbines regardless of what percentage of their potential
electric output they sell to the grid. To accommodate the continued use
of simple cycle and fast-start NGCC combustion turbines for peaking and
cycling applications, however, the EPA has subcategorized natural gas-
fired combustion turbines based on a variation of the proposed
percentage electric sales criterion. Specifically, and as explained in
more detail in Section IX.B.2, we are finalizing the sliding-scale
approach on which we solicited comment.
d. Natural gas-use criterion
    Similar to the proposed electric sales criteria, commenters
generally opposed the proposed natural gas-use criterion being based on
actual operating parameters. As with the electric sales criteria, the
EPA agrees that applicability that can switch periodically due to
operating parameters is not ideal. The EPA evaluated two approaches for
implementing the intent of the proposed natural gas-use criterion
(i.e., to exclude non-natural gas-fired combustion turbines) through
operating permit restrictions. Under the first approach, an emission
standard would apply to all combustion turbines with a permit
restriction mandating that natural gas contribute over 90 percent of
total heat input.\530\ Under the second approach, an emission standard
would apply to all combustion turbines without a permit restriction
limiting natural gas use to 90 percent or less of total heat
input.\531\ As with the percentage electric sales criterion, the first
approach is not practical because combustion turbines could avoid

applicability by simply not having a permit that requires the use of
more than 90 percent natural gas, even if they intend to only burn
natural gas. We disregarded this approach because it would essentially
provide a pathway for all NGCC units to avoid applicability under both
111(b) and 111(d). The second approach is problematic because operating
permit restrictions to improve air quality are typically written to
limit high emission activities (e.g., limiting the use of distillate
oil to 500 hours annually), not to limit lower emitting activities.
This approach could lead to perverse environmental impacts by
incentivizing the use of non-natural gas fuels, which would typically
result in higher CO2 emissions. Furthermore, the second
approach would not limit the fuels that can be burned by affected units
(i.e., combustion turbines not required to use non-natural gas fuels)
and would continue to cover combustion turbines even when they burn
over 10 percent non-natural gas fuels. Because all non-natural gas
fuels except H2 have CO2 emission rates higher
than natural gas, this approach would exacerbate the concerns raised by
commenters about the achievability of the 111(b) requirements when
burning back up fuels.
---------------------------------------------------------------------------

    \530\ This approach could also be written as ``an emission
standard would apply to all combustion turbines with a permit
restriction limiting the use of non-natural gas fuels to 10 percent
or less of the total heat input.'' Applicability could then be
avoided by simply being permitted to burn non-natural gas fuels for
more than 876 hours per year even if they actually intended to
seldom, if ever, combust the alternate fuels.
    \531\ This approach could also be written as ``an emission
standard would apply to all combustion turbines without permit
restrictions mandating that non-natural gas use contribute over 10
percent or more of total heat input.''
---------------------------------------------------------------------------

    In light of these issues, the EPA has concluded that permit
restrictions are not an ideal approach to distinguishing between
natural gas-fired and multi-fuel-fired combustion turbines and are
finalizing a variation of the broad applicability approach. The EPA has
concluded that the only practical approach to implement the natural
gas-use criterion is to look at the turbine's physical ability to burn
natural gas. Therefore, we are not finalizing CO2 standards
for combustion turbines that are not capable of firing any natural gas
(i.e., not connected to a natural gas pipeline). From a practical
standpoint, the burners of most combustion turbines can be modified to
burn natural gas, so this exemption is essentially limited to
combustion turbines that are built in remote or offshore locations
without access to natural gas. Consistent with the broad applicability
approach, we are finalizing standards for all other combustion
turbines, but are subcategorizing between natural gas-fired turbines
and multi-fuel-fired turbines. Specifically, and as explained in more
detail in Section IX.B.3, we are distinguishing between these classes
of turbines based on whether they burn greater than 90 percent natural
gas or not.

B. Subcategories

    We are finalizing a variation of the broad applicability approach
for combustion turbines where the percentage electric sales and natural
gas-use criteria serve as thresholds that distinguish between three
subcategories. These subcategories are base load natural gas-fired
units, non-base load natural gas-fired units, and multi-fuel-fired
units. Under the final subcategorization approach, multi-fuel-fired
combustion turbines are distinguished from natural gas-fired turbines
if fuels other than natural gas (e.g., distillate oil) supply 10
percent or more of heat input. Natural gas-fired turbines are further
subcategorized as base load or non-base load units based on the
percentage electric sales criterion. The percentage electric sales
threshold that distinguishes base load and non-base load units is based
on the specific turbine's design efficiency (i.e., the sliding-scale
approach). The percentage electric sales threshold is capped at 50
percent.
    This section describes comments we received regarding the proposed
size-based subcategories and our rationale for not finalizing them. In
addition, it describes comments we received regarding sales-based
subcategories and our rationale for adopting the sliding scale to
distinguish between subcategories. Finally, it describes comments we
received regarding fuel-based subcategories and our rationale for
adopting fuel-based subcategories.
1. Size-Based Subcategories
    At proposal, the EPA identified two size-based subcategories: (1)
large natural gas-fired stationary combustion turbines with a base load
rating greater than 850 MMBtu/h and (2) small natural gas-fired
stationary combustion turbines with a base load rating of 850 MMBtu/h
or less. The EPA received numerous comments regarding our proposal to
subcategorize combustion turbines by size. Some commenters agreed with
the 850 MMBtu/h cut-point between large and small units, some suggested
increasing it to 1,500 MMBtu/h, and others suggested eliminating size-
based subcategorization altogether. For example, some commenters stated
that the 850 MMBtu/h cut-point was inappropriate because it was
originally calculated based on NOX performance, not
CO2 performance. These commenters stated that 850 MMBtu/h
was not a logical demarcation between more efficient and less efficient
combustion turbines, but rather would divide the units into arbitrary
size classifications. These commenters suggested that 1,500 MMBtu/h
would be a better cut-point because data reported to Gas Turbine World
(GTW) showed that new combustion turbines are not currently offered
with a heat input rating between 1,300 MMBtu/h and 1,800 MMBtu/h, so
the higher cut-point would more accurately reflect when more efficient
technologies are available.
    In contrast, other commenters said that differentiation between
small and large combustion turbines was not justified at all because
many of the same efficiency technologies that reduce the emission rates
of larger units could be incorporated into smaller units (e.g.,
upgrades that increase the turbine engine operating temperature,
increase the turbine engine pressure ratio, or add multi-pressure steam
and a steam reheat cycle). These commenters also said that separate
standards for small and large turbines would undermine the incentive
for technology innovation, which they described as a key purpose of the
NSPS program, and that relaxing standards for smaller units would
discourage investment in more efficient technologies, resulting in
increased CO2 emissions. These commenters recommended that
the limit for both large and small units be no higher than 1,000 lb
CO2/MWh-g.
    After evaluating these comments, the EPA has decided not to
subcategorize combustion turbines based on size for several reasons.
First, the heat input values listed in Gas Turbine World do not include
potential heat input from duct burners.\532\ Because the heat input
from duct burners is necessary to accurately determine potential
electric output, our definition of ``base load rating'' includes the
heat input from any installed duct burners. The EPA reviewed the heat
input data for existing NGCC units that has been submitted to CAMD.
These data include the heat input from duct burners and show that
multiple NGCC power blocks have been built in the past with heat input
capacities that fall within the range that commenters suggested new
turbines are not offered. Therefore, the EPA has concluded that the
regulated community uses various sizes of NGCC turbines and when the
heat input from duct burners is included, there is no clear break
between the NGCC unit sizes that could distinguish between small and
large units. In fact, subcategorizing

by size could unduly influence the development of future NGCC offerings
because manufacturers could be incentivized to design new products at
the top end of the small subcategory to take advantage of the less
stringent emission standard.
---------------------------------------------------------------------------

    \532\ Duct burners are optional supplemental burners located in
the HRSG that are used to generate additional steam. Heat input to
duct burners could in theory be twice that of the combustion turbine
engine, but are more commonly sized at 10 to 30 percent of the heat
input to the combustion turbine engine.
---------------------------------------------------------------------------

    Second, commenters suggested that a cut-point of 1,500 MMBtu/h
reflects when more efficient technologies become available. However,
when we reviewed actual operating data and design data, we only found a
relatively weak correlation between turbine size and CO2
emission rates and did not see a dramatic drop in CO2
emission rates at 1,500 MMBtu/h. The variability of emission rates
among similar size units far exceeds any difference that could be
attributed to a difference in size. In addition, the most efficient
one-to-one configuration NGCC power block with a base load rating of
1,500 MMBtu/h or less has a design emission rate of the 767 lb
CO2/MWh-n (984 MMBtu/h). The most efficient one-to-one
configuration NGCC power block with a base load rating just greater
than 1,500 MMBtu/h has a design emission rate of 772 lb CO2/
MWh-n (1,825 MMBtu/h). Because the smaller unit has a lower design
emission rate than the larger unit, increasing the cut-point does not
make sense.
    Finally, the EPA has concluded that, while certain smaller NGCC
designs may be less efficient than larger NGCC designs, most existing
small units have demonstrated emission rates below the range of
emission rates on which we solicited comment. We have concluded that
the lower design efficiencies of some small NGCC units are primarily
related to model-specific design choices in both the turbine engine and
HRSG, not an inherent limitation in the ability of small NGCC units to
have comparable efficiencies to large NGCC units. Specifically,
manufacturers could improve the efficiency of the turbine engine by
using turbine engines with higher firing temperatures and high
compression ratios and could improve the efficiency of the steam cycle
by switching from single or double-pressure steam to triple-pressure
steam and adding a reheat cycle. For all of these reasons, we have
decided against subcategorizing combustion turbines based on size. Our
rationale for setting a single standard for small and large combustion
turbines is explained in more detail in Section IX.D.3.a below.
2. Sales-Based Subcategories
    As described above in Section IX.A.3.c, the final applicability
criteria do not include an exemption for non-CHP units based on actual
electric sales or permit restrictions limiting the amount of
electricity that can be sold. Instead, we are finalizing the percentage
electric sales criterion as a threshold to distinguish between two
natural gas-fired combustion turbine subcategories. The industry uses a
number of terms to describe combustion turbines with different
operating characteristics based on electric sales (e.g., capacity
factors). Combustion turbines that operate at near-steady, high loads
are generally referred to as ``base load'' or ``intermediate load''
units, depending on how many hours the units operate annually.
Combustion turbines that operate continuously with variable loads that
correspond to variable demand are referred to as ``load following'' or
``cycling'' units. Combustion turbines that only operate during periods
with the highest electricity demand are referred to as ``peaking''
units. However, it is difficult to characterize a particular unit using
just one of these terms. For example, a particular unit may serve as a
load following unit during winter, but serve as a base load unit during
summer. In addition, none of these terms has a precise universal
definition. In this preamble, we refer to the subcategory of combustion
turbines that sell a significant portion of their potential electric
output as ``base load units.'' This subcategory includes units that
would colloquially be referred to as base load units, as well as some
intermediate load and load following units. We refer to all other units
as ``non-base load units.'' This subcategory includes peaking units, as
well as some load following and intermediate load units. The threshold
that distinguishes between these two subcategories is determined by a
unit's design efficiency and varies from 33 to 50 percent, hence the
term ``slide scale'' approach.
    Numerous commenters supported three sales-based subcategories for
peaking, intermediate load, and base load units. These commenters said
that each subcategory should be distinguished by annual hours of
operation and that each should have a different BSER and emission
standard. Other commenters opposed the tiered approach. These
commenters said that separate standards for different operating
conditions would be complicated to implement and enforce, while
providing few benefits. These commenters said that a tiered approach
could also have the unintended consequence of encouraging less
efficient technologies because it would create a regulatory incentive
to install lower-capital-cost, less-efficient units that would operate
under the percentage electric sales threshold instead of higher-
capital-cost, more-efficient units that would operate above the
threshold.
    After evaluating these comments, the EPA has concluded that it is
appropriate to adopt a two-tiered subcategorization approach based on a
percentage electric sales threshold to distinguish between non-base
load and base load units. While we agree with commenters that separate
standards for peaking, intermediate, and base load units is attractive
on the surface, we ultimately concluded that a three-tiered approach is
not appropriate for several reasons. First, the increased generation
from renewable sources that is anticipated in the coming years makes it
very difficult to determine appropriate thresholds to distinguish among
peaking, intermediate, and base load subcategories. Indeed, the
boundaries between these demand-serving functions may blur or shift in
the years to come. The task is further complicated because each
transmission region has a different mix of generation technologies and
load profiles with different peaking, intermediate, and base load
requirements.
    Second, there are only two distinct combustion turbine
technologies--simple cycle units and NGCC units. In theory, the BSER
for the intermediate load subcategory could be based on high-efficiency
simple cycle units or fast-start NGCC units, but these are variations
on traditional technologies and not necessarily distinct. Moreover, we
do not have specific cost information on either high-efficiency simple
cycle turbines or fast-start NGCC units, so our ability to make cost
comparisons to conventional designs is limited.
    Finally, even if we could identify appropriate sales thresholds to
distinguish between peaking, intermediate load, and base load
subcategories, we do not have sufficient information to establish a
meaningful output-based standard for an intermediate load subcategory
at this time. In the transition zone from peaking to base load
operation (i.e., cycling and intermediate load), combustion turbines
may have similar electric sales, but very different operating
characteristics. For example, despite having similar sales, one unit
might have relatively steady operation for a short period of time,
while another could have variable operation throughout the entire year.
The latter unit would likely have a higher CO2 emission
rate. For all of these reasons, the EPA has concluded that we do not
have sufficient information at this time

to establish three sales-based subcategories.
    Instead, as we explained above, we are finalizing two sales-based
subcategories. To determine an appropriate threshold to distinguish
between base load and non-base load units, the EPA considered the
important characteristics of the combustion turbines that serve each
type of demand. For non-base load units, low capital costs and the
ability to start, stop, and change load quickly are key. Simple cycle
combustion turbines meet these criteria and thus serve the bulk of peak
demand. In contrast, for base load units, efficiency is the key
consideration, while capital costs and the ability to start and stop
quickly are less important. While NGCC units have relatively high
capital costs and are less flexible operationally, they are more
efficient than simple cycle units. NGCC units recover the exhaust heat
from the combustion turbine with a HRSG to power a steam turbine, which
reduces fuel use and CO2 emissions by approximately one-
third compared to a simple cycle design. Consequently, base load units
use NGCC technology. Because simple cycle turbines have historically
been non-base load units, we have concluded that it is appropriate to
distinguish between the non-base load and base load subcategories in a
way that recognizes the distinct roles of the different turbine designs
on the market.
    The challenge, however, is setting a threshold that will not
distort the market. The future distinction between non-base load and
base load units is unclear. For example, some commenters indicated that
increased generation from intermittent renewable sources has created a
perceived need for additional cycling and load following generation
that will operate between the traditional roles of peaking and base
load units. To fulfill this perceived need, some manufacturers have
developed high-efficiency simple cycle turbines. These high-efficiency
turbines have higher capital costs than traditional simple cycle
turbine designs, but maintain similar flexibilities, such as the
ability to start, stop, and change load rapidly. Other manufacturers
have developed fast-start NGCC turbines to fill the same role. These
newer NGCC designs have lower design efficiencies than NGCC designs
intended to only operate as base load units, but are able to startup
more quickly to respond to rapid changes in electricity demand. As a
result of these new technological developments, both high-efficiency
simple cycle and fast-start NGCC units can be used for traditional
peaking applications, as well as for higher capacity applications, such
as supporting the growth of intermittent renewable generation.
    With the changing electric sector in mind, we set out to identify
an appropriate percentage electric sales threshold to distinguish
between non-base load and base load natural gas-fired units. Two
factors were of primary importance to our decision. First, the
threshold needed to be high enough to address commenters' concerns
about the need to maintain flexibility for simple cycle units to
support the growth of intermittent renewable generation. Second, the
threshold needed to be low enough to avoid creating a perverse
incentive for owners and operators to avoid the base load subcategory
by installing multiple, less efficient turbines instead of fewer, more
efficient turbines.
    To determine the potential impact of intermittent renewable
generation on the operation of simple cycle units, we examined the
average electric sales of simple cycle turbines in the lower 48 states
between 2005 and 2014 using information submitted to CAMD. We combined
this data with information reported to the EIA on total in-state
electricity generation, including wind and solar, from 2008 through
2014. We focused on data from the Southwest Power Pool (data
approximated by EGUs in Nebraska, Kansas, and Oklahoma), Texas, and
California. All of these regions have relatively large amounts of
generation from wind and solar and experienced increases in the portion
of total electric generation provided by wind and solar during the
2008-2014 period.
a. Southwest Power Pool
    The portion of in-state generation from wind and solar in the
Southwest Power Pool increased from 3 to 16 percent between 2008 and
2014. The average growth rate of wind and solar was 28 percent, while
overall electricity demand grew 1 percent annually on average. Based on
statements in some of the comments, we expected to see a large change
in the operation of simple cycle turbines in this region. However, the
average electric sales from simple cycle turbines only increased at an
annual rate of 1.7 percent, and remained essentially unchanged at 3
percent of potential electric output between 2008 and 2014. Total
generation from simple cycle turbines in the Southwest Power Pool
increased slightly more, at an annual rate of 2.5 percent, which was
the result of additional simple cycle capacity being added to address
increased electricity demand.
    This lack of a significant change in the operation of simple cycle
turbines could be explained by the Southwest Power Pool's relatively
large amount of exported power. If most of the region's renewable
generation was being exported, the intermittent nature of this power
would primarily impact other transmission regions. An alternate
explanation, however, is that other generating assets are flexible
enough to respond to the intermittent nature of wind and solar
generation and that simple cycle turbines are not necessary to back up
these assets to the degree some commenters suggested. If this is the
case, then new simple cycle turbines may primarily continue to fill
their historical role as peaking units going forward, while other
technologies, such as fast-start NGCC units, may provide the primary
back up capacity for new wind and solar.
b. Texas
    The portion of in-state generation from wind and solar in Texas
increased from 4 to 9 percent between 2008 and 2014. The average growth
rate of wind and solar was 13 percent, while overall demand grew at an
average rate of 2 percent annually. Similar to the Southwest Power
Pool, the average electric sales of simple cycle turbines has remained
relatively unchanged. In fact, the average electric sales of these
turbines decreased at an annual rate of 1.1 percent. Total generation
from simple cycle turbines increased at an annual rate of 6.6 percent,
however, due to simple cycle capacity additions that occurred at
approximately four times the rate one would expect from the growth in
overall demand.
    The most likely technologies to back up intermittent renewable
generation have low incremental generating costs and can start up and
stop quickly. Highly efficient simple cycle units meet these criteria.
As such, the EPA has concluded that the most efficient simple cycle
turbines in a given region are the most likely to support intermittent
renewable generation. Focusing on these simple cycle turbines will
address concerns raised by commenters about the future percentage
electric sales of highly efficient simple cycle turbines and give an
indication of the impact of increased renewable generation on non-base
load units intended to back up wind and solar. There are two highly
efficient intercooled simple cycle turbines installed in Texas. These
two combustion turbines sell an average of 10 percent of their
potential electric output annually, compared to an average of 3 percent
for the remaining simple cycle turbines. No simple cycle

turbine in Texas sold more than 25 percent of its potential electric
output annually. The rapid growth in simple cycle capacity, but not
overall capacity factors, could indicate that the additional generation
assets are providing firm capacity for intermittent generation sources
such as wind and solar, but that capacity is infrequently required.
Based on the data, even highly efficient simple cycle turbines are
expected to continue to sell less than one-third of their potential
electric output.
c. California
    The portion of in-state generation from wind and solar in
California increased from 3 to 11 percent between 2008 and 2014. The
average growth rate of wind and solar was 25 percent, while overall
demand has remained stable. The operation of simple cycle turbines in
California has changed more significantly than in the other evaluated
regions. The average electric sales from simple cycle turbines
increased from 5.1 to 5.9 percent, an annual rate increase of 4.5
percent. As in Texas, considerable additional simple cycle capacity has
been added in recent years. The total capacity of simple cycle turbines
is increasing at 15 percent annually even though overall demand has
remained relatively steady. In addition, the newest simple cycle
turbines are operating at higher capacity factors than the existing
fleet of simple cycle turbines, resulting in an average increase in
generation from simple cycle turbines of 21 percent. Many of the new
additions are intercooled simple cycle turbines that may have been
installed with the specific intent to back up wind and solar
generation.
    The average electric sales for the intercooled turbines ranged from
3 to 25 percent, with a 7 percent average. No simple cycle turbines in
California have sold more than one-third of their potential electric
output on an annual basis. The operation of simple cycle turbines that
existed prior to 2008 has not changed significantly. Average electric
sales for these turbines increased at an annual rate of 0.1 percent.
This indicates that support for new renewable generation is being
provided by new units and not by the installed base of simple cycle
units. These units are still serving their historical role of providing
power during peak periods of demand.
    Based on our data analysis, the proposed one-third electric sales
threshold would appear to offer sufficient operational flexibility for
new simple cycle turbines. Existing NGCC units, other generation
assets, and demand-response programs are currently providing adequate
back up to intermittent renewable generation. In the future, however,
existing NGCC units will likely operate at higher capacity factors.
They will therefore be less available to provide back up power for
intermittent generation. In addition, the amount of power generated by
intermittent sources is expected to increase in the future. Both of
these factors could require additional flexibility from the remaining
generation sources to maintain grid reliability.
    Even though fast-start NGCC units, reciprocating internal
combustion engines, energy storage technologies, and demand-response
programs are promising technologies for providing back up power for
renewable generation, none of them historically have been deployed in
sufficient capacity to provide the potential capacity needed in the
future to facilitate the continued growth of renewable generation.
While we anticipate that state and federally issued permits for new
electric generating sources will consider the CO2 benefits
of these technologies compared to simple cycle turbines, the EPA has
concluded at this time that it is appropriate to finalize a percentage
electric sales threshold that provides additional flexibility for
simple cycle turbines.
    Specifically, we have concluded that a percentage electric sales
threshold based on a unit's design net efficiency at standard
conditions is appropriate. This is the sliding-scale approach on which
we solicited comment. Several commenters supported this approach
because it provides sufficient operational flexibility for new simple
cycle and fast-start NGCC combustion turbines and simultaneously
promotes the installation of the most efficient generating
technologies. By allowing more efficient turbines to sell more
electricity before becoming subject to the standard for the base load
subcategory, the sliding scale should reduce the perverse incentive for
owners and operators to install more lower-capital-cost, less-efficient
units instead of fewer higher-capital-cost, more-efficient units. At
the same time, the sliding scale should incentivize turbine
manufacturers to design higher efficiency simple cycle turbines that
owners and operators can run more frequently.
    The net design efficiencies for aeroderivative simple cycle
combustion turbines range from approximately 32 percent for smaller
designs to 39 percent for the largest intercooled designs. The net
design efficiencies of industrial frame units range from 30 percent for
smaller designs to 36 percent for the largest designs. These efficiency
values follow the methodology the EPA has historically used and are
based on the higher heating value (HHV) of the fuel. In contrast,
combustion turbine vendors in the U.S. often quote efficiencies based
on the lower heating value (LHV) of the fuel. The LHV of a fuel is
determined by subtracting the heat of vaporization of water vapor
generated during combustion of fuel from the HHV. For natural gas, the
LHV is approximately 10 percent lower than the HHV. Therefore, the
corresponding LHV efficiency ranges would be 35 to 44 percent for
aeroderivative designs and 33 to 40 percent for frame designs. We
considered basing the percentage electric sales threshold on both the
HHV and LHV. The EPA typically uses the HHV, but in light of
commenters' concerns regarding uncertainty in the operation of non-base
load units in the future, we opted to be conservative and use the LHV
efficiency.
    We anticipate that high-efficiency simple cycle and fast-start NGCC
turbines will make up the majority of new capacity intended for non-
base load applications. Based on the sliding-scale approach, owners and
operators of new simple cycle combustion turbines will be able to sell
between 33 to 44 percent of the turbine's potential electric output.
Our analysis showed that 99.5 percent of existing simple cycle turbines
have not sold more than one-third of their potential electric output on
an annual basis. In addition, 99.9 percent of existing simple cycle
turbines have not sold more than 36 percent of their potential electric
output on an annual basis. The two simple cycle turbines that exceeded
the 36 percent threshold had annual electric sales of 39 and 45 percent
and are located in Montana and New York, respectively. As noted
earlier, the most efficient simple cycle turbine currently available is
44 percent efficient and would accommodate the operations at the
Montana facility. The only existing simple cycle turbine that exceeded
the maximum allowable percentage electric sales threshold of 44
percent, which is based on current simple cycle designs, sold an
abnormally high amount of electricity in 2014. It is possible that this
unit was operating under emergency conditions. As explained below, the
incremental generation due to the emergency would not have counted
against the percentage electric sales threshold.
    We are capping the percentage electric sales threshold at 50
percent of potential electric output for multiple reasons. First, NGCC
emission rates are

relatively steady above 50 percent electric sales, so there is no
reason that a NGCC unit with sales greater than this amount should not
have to comply with the output-based standard for the base load
subcategory. Second, the net design efficiency of the fast-start NGCC
units intended for peaking and intermediate load applications is 49
percent. As described earlier, this technology can serve the same
purpose as high-efficiency simple cycle turbines. If we were to set a
cap any lower than 50 percent, it could create a disincentive for
owners and operators to choose this promising new technology.
    Finally, the EPA solicited comment on excluding electricity sold
during system emergencies from counting towards the percentage electric
sales threshold. After considering the comments, we have concluded that
this exclusion is necessary to provide flexibility, maintain system
reliability, and minimize overall costs to the sector. We disagree with
commenters that suggested that the EPA's existing enforcement
discretion would be a viable alternative. An enforcement discretion-
based approach would not provide certainty to the regulated community,
public, and regulatory authorities on the applicability of the emission
standards, which is a primary reason why we are finalizing the broad
applicability approach. Moreover, system emergencies are defined
events, so commenters' fears that the exclusion will be subject to
abuse are overstated. Therefore, electricity sold during hours of
operation when a unit is called upon to operate due to a system
emergency will not be counted toward the percentage electric sales
threshold. However, electricity sold by units that are not called upon
to operate due to a system emergency (e.g., units already operating
when the system emergency is declared) will be counted toward the
percentage electric sales threshold.
    In summary, the EPA is finalizing the percentage electric sales
criterion as a threshold to distinguish between two natural gas-fired
combustion turbine subcategories. Specifically, all units that have
electric sales greater than their net LHV design efficiencies (as a
percentage of potential electric output) are base load units. All units
that have electric sales less than or equal to their net LHV design
efficiencies are non-base load units. We are capping the percentage
electric sales threshold at 50 percent of potential electric output.
This sliding-scale approach will limit the operation of the least
efficient units, provide flexibility for renewable energy growth, and
incentivize the development of more efficient simple cycle units.
3. Fuel-Based Subcategories
    As described in Section IX.A.3.d, we are finalizing a version of
the broad applicability approach. Under the broad applicability
approach, the EPA solicited comment on a subcategorization approach
based in part on natural gas-use. We received few comments on this
issue. One of the comments we did receive was that combustion turbines
that burn fuels other than natural gas have higher CO2
emissions due to the higher relative carbon content of alternate fuels.
Besides hydrogen,\533\ natural gas has the lowest CO2
emission rate on a lb/MMBtu basis of any fossil fuel. Therefore,
burning fuels other than natural gas will result in a higher
CO2 emission rate. We interpret this comment to mean that,
if we were to subcategorize based on fuel use, turbines that burn non-
natural gas fuels should receive a less stringent emission standard.
---------------------------------------------------------------------------

    \533\ Hydrogen would only be considered a fossil fuel if it were
derived for the purpose of creating useful heat from coal, oil, or
natural gas.
---------------------------------------------------------------------------

    For the reasons described in the applicability section, we have
decided to set emission standards for all combustion turbines capable
of burning natural gas, regardless of the actual fuel burned, to avoid
the practical problems that would have arisen under the proposed
approach. However, as commenters explained, multi-fuel-fired combustion
turbines cannot achieve the emission standards achieved by natural-gas
fired turbines. For this reason, it would not be reasonable to require
affected EGUs to comply with a standard based on the use of natural gas
during periods when significant quantities of non-natural gas fuels are
being burned. If we did not subcategorize, owners and operators would
not be able to combust other fuels in their turbines, including process
gas, blast furnace gas, and petroleum-based liquid wastes, which might
otherwise be wasted. In addition, without the ability to burn back up
fuels during natural gas curtailments, grid reliability could be
jeopardized. Therefore, we are finalizing a separate fuel-based
subcategory for multi-fuel-fired combustion turbines. To distinguish
between this subcategory and the natural gas-fired subcategories, we
are using the same threshold as proposed. Specifically, combustion
turbines that burn ninety percent or less natural gas on a 12-
operating-month rolling average basis will be included in this
subcategory and subject to a separate emission standard, which is
discussed in Section IX.D.3.d.

C. Identification of the Best System of Emission Reduction

    This section summarizes the EPA's proposed BSER determinations for
stationary combustion turbines, provides a summary of the comments we
received, and explains our final BSER determinations for each of the
three subcategories we are now finalizing. For natural gas-fired
stationary combustion turbines operating as base load units, we
proposed and are finalizing the use of NGCC technology as the BSER. For
the other two subcategories of affected combustion turbines--non-base
load natural gas-fired combustion turbines and multi-fuel-fired
combustion turbines--we are finalizing the use of clean fuels as the
BSER.
1. Proposed BSER
    We considered three alternatives in evaluating the BSER for base
load natural gas-fired combustion turbines: (1) Partial CCS, (2) high-
efficiency simple cycle aeroderivative turbines, and (3) modern,
efficient NGCC turbines. We rejected partial CCS as the BSER because we
concluded that we did not have sufficient information to determine
whether implementing CCS for combustion turbines was technically
feasible. We rejected high-efficiency simple cycle aeroderivative
turbines as the BSER because this standalone technology does not
provide emission reductions and generally is more expensive than NGCC
technology for base load applications. In contrast, NGCC is the most
common type of new fossil fuel-fired EGU currently being planned and
built for generating base load power. NGCC is technically feasible, and
NGCC units are currently the lowest-cost, most efficient option for new
base load fossil fuel-fired power generation. After considering the
options, the EPA proposed to find that modern, efficient NGCC
technology is the BSER for base load natural gas-fired combustion
turbines.
    For non-base load natural gas-fired units and multi-fuel-fired
units, we did not propose a specific BSER or associated numeric
emission standards, but instead solicited comment on these issues.
2. Comments on the Proposed BSER for Base Load Natural Gas-Fired
Combustion Turbines
    This section summarizes the differing comments submitted on the
proposed BSER for base load natural gas-fired combustion turbines. Some
commenters supported partial CCS as the BSER, others supported advanced
NGCC

designs as the BSER, and others supported the proposed BSER.
a. Partial CCS
    Some commenters stated that our proposed BSER analysis for
stationary combustion turbines was inconsistent with our proposed BSER
analysis for coal-fired units. They stated that the EPA had determined
that the use of CCS was feasible for coal-fired generation based on
current CCS projects under development at coal-fired generating
stations, but did not come to the same conclusion for combustion
turbines. These commenters stated that CO2 removal is just
as technologically feasible and economically reasonable for a natural
gas-fired EGU as for a coal-fired EGU. While some of these commenters
wanted the EPA to reconsider CCS as the BSER for NGCC, many of these
commenters were attempting to prove that if the agency did not choose
CCS as the BSER for NGCC units, then the agency should not for coal-
fired units either.
    Some commenters referenced the Northeast Energy Association NGCC
plant in Bellingham, MA, which operated from 1991-2005 with 85-95
percent carbon capture on a 320 MW unit for use in the food and
beverage industry, that was referred to in the proposal. This plant
captured 330 tons of CO2 per day from a 40 MW slip stream
and was decommissioned as a result of financial difficulties, including
rising gas prices and discontinuation of tax credits. According to
these commenters, this plant provided sufficient proof that CCS
technology is adequately demonstrated for NGCC units. Additionally,
these commenters referred to other NGCC plants that are planned or in
development that will incorporate CCS. The plants mentioned were the
Sumitomo Chemical Plant in Japan, the Peterhead CCS project in
Scotland, and the GE-Sargas Plant in Texas. The Sumitomo Chemical Plant
has a base load NGCC unit with CCS operating on an 8 MW slip-stream
that captures about 150 tons of CO2 per day for commercial
use in the food and beverage industry. This carbon capture system has
been operating since 1994. The Peterhead CCS project in Scotland is in
the planning stages. It is a collaboration between Shell and SSE to
provide 320 MW of electricity to its customers from a base load NGCC
unit with 90 percent carbon capture. The CO2 will be
transported to the depleted Goldeneye reservoir in the ocean where it
will be stored and continuously monitored. The GE-Sargas Plant in Texas
is a planned joint venture that does not currently have a location
selected, but is intended to be a base load NGCC unit with CCS used for
EOR.
    These commenters also referenced reports authored by DOE, NETL, the
Clean Air Task Force (CATF), CCS Task Force, ICF Inc., and Global CCS
Institute, suggesting that, because CCS technology for NGCC is included
in these reports, it is adequately demonstrated. Some commenters
referred to a DOE/NETL study that suggested that the cost of CCS for
NGCC units would be more cost-effective than for coal-fired EGUs. One
non-industry commenter emphasized that a technology does not have to be
in use to be considered adequately demonstrated.
    In addition, some commenters disagreed with the EPA's decision to
treat combustion turbines differently than coal-fired units with
respect to CCS on the basis that combustion turbines startup, shutdown,
and cycle load more frequently than coal-fired units. According to
these commenters, the operating characteristics of combustion turbines
do fluctuate, but so do those of coal-fired units. Another commenter
said that even if NGCC operations vary more than they do for coal-fired
units, it is not an impediment to using CCS because combustion turbine
operators could bypass the carbon capture system during startup and
shutdown modes (which are typically shorter and less intensive efforts
compared to the startup or shutdown of a coal facility) and then employ
the carbon capture system when operating normally. One commenter stated
that most future base load fossil fuel-fired generation will be NGCC
and that not making CCS the BSER for NGCC would result in significant
CO2 emissions.
    Other commenters supported the EPA's determination that CCS is not
the BSER for combustion turbines. These commenters said that CCS is not
adequately demonstrated for combustion turbines because none are
currently operating, under construction, or in the advanced stages of
development. They also noted that CCS would have to be demonstrated for
the range of facilities included in the regulated source category,
which they alleged includes both simple cycle and NGCC units. They
specifically noted that the Bellingham, MA demonstration facility was
not a full-scale commercial NGCC power plant operating with CCS.
    These commenters agreed with the EPA that CCS does not match well
with the operating flexibilities of NGCC and simple cycle units. They
agreed with the EPA that frequent cycling restricts the efficacy of CCS
on these units, a problem which would only get worse as more renewable
energy sources are integrated into the grid. These commenters added
that NGCC units operate differently than coal-fired units because the
former start, stop, and cycle frequently, whereas the latter tend to
operate at relatively steady loads and do not start and stop
frequently. They stated that even if technical barriers could be
overcome, the application of CCS to combustion turbines would be more
costly (compared to the application of CCS to coal-fired units) on a
dollars-per-ton basis. In addition, these commenters said that other
industries' experience with CCS could not be transferred to NGCC units
due to differences in flue gas CO2 concentration.
    Some commenters stated that CAA section 111(a) requires the EPA to
account not only for the cost of achieving emission reductions, but
also for impacts on energy requirements and the environment. The
commenters cited to Sierra Club v. Costle, where the D.C. Circuit
observed that the EPA ``must exercise its discretion to choose an
achievable emission level which represents the best balance of
economic, environmental, and energy considerations.'' \534\ The
commenters stated that requiring CCS on combustion turbines would
adversely affect the nation's energy needs and the environment because
imposing CCS on combustion turbines would invariably delay the emission
reductions that can be obtained from new NGCC projects that displace
load from older, less efficient generating technologies. In addition,
the commenters stated that, because combustion turbines are projected
to provide a significant share of new power generation, the EPA should
recognize that requiring CCS on these units would have a
disproportionally higher impact on electricity prices when compared to
the projected number of new coal-fired projects. These commenters
concluded that the EPA could not determine that CCS is the BSER for
combustion turbines without producing severe and unacceptable
consequences for the availability of affordable electricity in the U.S.
---------------------------------------------------------------------------

    \534\ Sierra Club v. Costle, 657 F.2d 298, 330 (D.C. Cir. 1981).
---------------------------------------------------------------------------

b. NGCC Turbines
    Some commenters stated that the proposed BSER analysis should have
reflected the emission rates achieved by the latest designs deployed at
advanced, state-of-the-art NGCC installations. These commenters stated
that advanced NGCC technologies are the best system

for reducing CO2 emissions with no negative environmental
impacts and no negative economic impacts on rate payers. They stated
that advanced NGCC technologies are capable of achieving emission rates
that are 8 percent lower than conventional NGCC facilities. They also
said that the majority of existing sources that do not deploy these
advanced technologies are currently able to meet the standard and that
the proposal failed to explain why these lower-emitting advanced
technologies that are more than adequately demonstrated were not
selected as the BSER.
c. Simple Cycle Turbines
    Many commenters opposed the EPA's proposal to set emission
standards for combustion turbines based on their function rather than
based on their design. These commenters stated that the EPA's
determination that NGCC technology is the BSER for base load natural
gas-fired combustion turbines would apply equally to simple cycle
turbines if they sell electricity in excess of the percentage electric
sales threshold. They pointed to the word ``achievable'' in CAA section
111(a)(1) and stated that applying an emission standard based on NGCC
technology to simple cycle units was legally indefensible because
simple cycle units cannot achieve emission rates as low as NGCC units.
In contrast, many other commenters agreed with the EPA's basic approach
and stated that NGCC technology should be the BSER for base-load
functions, while simple cycle technology should be the BSER for peak-
load functions.
3. Comments on Non-Base Load and Multi-Fuel-Fired Combustion Turbines
    Multiple commenters suggested that high efficiency simple cycle or
fast-start NGCC technologies should be the BSER for non-base natural
gas-fired load units. They explained that high efficiency simple cycle
units and fast-start NGCC units are actually more efficient when
serving non-base load demand than NGCC units that are designed strictly
for base load operation. Some commenters also suggested that we should
subcategorize multi-fuel-fired combustion turbines, but did not provide
any specific technologies that should be considered in the BSER
analysis.
4. Identification of the BSER
    After our evaluation of the comments and additional analysis, we
identified the BSER for each subcategory of combustion turbine that we
are finalizing: base load natural gas-fired units, non-base load
natural gas-fired units, and multi-fuel-fired units.
a. Base Load Natural Gas-Fired Units
    As described in the proposal, we evaluated CCS, NGCC, and high-
efficiency simple cycle combustion turbines as the potential BSER for
this subcategory. We selected NGCC as the BSER because it met all the
BSER criteria. This section describes our response to issues raised by
commenters and our rationale for maintaining that NGCC is the BSER for
base load natural gas-fried combustion turbines.
(1) Partial CCS
    Some commenters stated that CCS could be applied equally to both
coal-fired and natural gas-fired EGUs. To support this conclusion, the
commenters pointed to a retired NGCC-with-CCS demonstration project, as
well as a few overseas projects and projects in the early stages of
development. While we have concluded that these commenters made strong
arguments that the technical issues we raised at proposal could in many
instances be overcome, we have concluded that there is not sufficient
information at this time for us to determine that CCS is adequately
demonstrated for all base load natural-gas fired combustion turbines.
    While the commenters make a strong case that the existing and
planned NGCC-with-CCS projects demonstrate the feasibility of CCS for
NGCC units operating at steady state conditions, many NGCC units do not
operate this way. For example, the Bellingham, MA and Sumitomo NGCC
units cited by the commenters operated at steady load conditions with a
limited number of starts and stops, similar to the operation of coal-
fired boilers.\535\ In contrast, our base load natural gas-fired
combustion turbine subcategory includes not only true base load units,
but also some intermediate units that cycle more frequently, including
fast-start NGCC units that sell more than 50 percent of their potential
output to the grid. Fast-start NGCC units are designed to be able to
start and stop multiple times in a single day and can ramp to full load
in less than an hour. In contrast, coal-fired EGUs take multiple hours
to start and ramp relatively slowly. These differences are important
because we are not aware of any pilot-scale CCS projects that have
demonstrated how fast and frequent starts, stops, and cycling will
impact the efficiency and reliability of CCS. Furthermore, for those
periods in which a NGCC unit is operating infrequently, the CCS system
might not have sufficient time to startup. During these periods, no
CO2 control would occur. Thus, if the NGCC unit is intended
to operate for relatively short intervals for at least a portion of the
year, the owner or operator could have to oversize the CCS to increase
control during periods of steady-state operation to make up for those
periods when no control is achieved by the CCS, leading to increased
costs and energy penalties. While we are optimistic that these hurdles
are surmountable, it is simply premature at this point to make a
finding that CCS is technically feasible for the universe of combustion
turbines that are covered by this rule.
---------------------------------------------------------------------------

    \535\ As explained in Section V.J above, a new fossil fuel-fired
steam generating EGU would, most likely, be built to serve base load
power demand exclusively and would not be expected to routinely
startup, shut down, or ramp its capacity factor in order to follow
load demand. Thus, planned start-up and shutdown events would only
be expected to occur a few times during the course of a 12-
operating-month compliance period.
---------------------------------------------------------------------------

    Notably, the Department of Energy has not yet funded a CCS
demonstration project for a NGCC unit, and no NGCC-with-CCS
demonstration projects are currently operational or being constructed
in the U.S. In contrast, multiple CCS demonstration projects for coal-
fired units are in various stages of development throughout the U.S.,
and a full-capture system is in operation at the Boundary Dam facility
in Canada. See Sections V.E and D above.
    One commenter suggested that not having CCS as the BSER for
combustion turbines would ultimately halt the development of CCS in the
U.S. We disagree. A number of coal-fired power plants are currently
being built with CSS, while some existing plants are considering CCS
retrofits. Moreover, the NSPS sets the minimum level of control for new
sources. We expect that state air agencies and other air permitting
authorities will evaluate CCS when permitting new NGCC power plants,
taking into consideration case-specific parameters, like operating
characteristics, to determine whether CCS could be BACT or LAER in
specific instances. While the NGCC-with-CCS units that currently are in
the planning stages do not provide us with enough assurance to
determine that CCS is adequately demonstrated for combustion turbines,
it is our expectation that these units and others to come will provide
additional information for both permitting reviews and the next NSPS
review in eight years.
(2) NGCC Turbines
    Regarding the advanced NGCC technologies advocated by several
commenters, the EPA has concluded

that the term ``advanced'' simply refers to incremental improvements to
traditional NGCC designs, not a new and unique technology. These
incremental improvements include higher firing temperatures in the
turbine engine, increasing the number of steam pressures, and adding a
reheat cycle to the steam cycle. The emission rates achieved by these
so-called ``advanced'' technologies were included within the data set
of newer NGCC designs that we used to establish the final emission
standards. In addition, our review of the operating data for NGCC power
blocks installed since 2000 indicates that a unit's mode of operation
in response to system demand (e.g., capacity factor) affects
efficiencies achieved to the extent that we cannot evaluate the impact
of particular subcomponents used within the power block. As a result, a
conventional NGCC power block located in a region of the country where
system demand requires the power block to run continuously at a steady
high load can achieve higher efficiencies than an ``advanced'' NGCC
power block located in a region where system demand requires the power
block to cycle on and off to match system demand. For this reason, our
data set included a large population of technologies and load
conditions to ensure that new NGCC power blocks can achieve the final
emission standards in all regions of the country.
    As we explained in the proposal, NGCC technology meets all of the
BSER criteria. For base load functions, NGCC units are technically
feasible, cost-effective (indeed, less expensive than simple cycle
combustion turbines), and have no adverse energy or environmental
impacts. Moreover, NGCC units reduce emissions because they have a
lower CO2 emission rate than simple cycle units. Finally,
selecting NGCC as the BSER will promote the development of new
technology, such as the incremental improvements advocated by the
commenters, which will further reduce emissions in the future.
    Some commenters suggested that the costs and efficiency impacts of
startup and shutdown events are higher for NGCC units than for simple
cycle units. Consequently, we refined the LCOE costing approach used at
proposal by adding these additional costs and efficiency impacts to our
cost comparison. Even accounting for these new costs and impacts, we
found that NGCC technology results in a lower cost of electricity than
simple cycle technology when a unit's electric sales exceed
approximately one-third of its potential electric output. The final
percentage electric sales criterion for the base load natural gas-fired
combustion turbine subcategory is based on the sliding scale. This
means that the dividing line between the base load subcategory and the
non-base load subcategory will change depending on a unit's nameplate
design efficiency. For a conventional simple cycle turbine, the base
load subcategory will begin at around 33 percent electric sales, while
for a newer fast-start NGCC turbine, the base load subcategory will
begin at approximately 50 percent electric sales. Anywhere within this
range, our cost calculations have shown that NGCC technology is more
cost-effective than simple cycle technology. Therefore, we are
finalizing our determination that modern, efficient NGCC technology is
the BSER for base load natural-gas fired combustion turbines.
(3) Simple Cycle Turbines
    Many commenters mistakenly thought that the EPA proposed to require
some simple cycle combustion turbines to meet an emission standard of
1,000 lb CO2/MWh-g, a level that they assert is
unachievable. On the contrary, the EPA is not finding that NGCC
technology and a corresponding emission standard of 1,000 lb
CO2/MWh-g is the BSER for simple cycle turbines. Instead,
the EPA is finding that NGCC technology is the BSER for base load
turbine applications. This means that if an owner or operator wants to
sell more electricity to the grid than the amount derived from a unit's
nameplate design efficiency calculated as a percentage of potential
electric output, then the owner or operator should install a NGCC unit.
If the owner or operator elects to install a simple cycle turbine
instead, then the practical effect of our final standards will be to
limit the electric sales of that unit so that it serves primarily peak
demand, not to subject it to an unachievable emission standard.
b. Non-base Load Natural Gas-Fired Load Units
    To identify the BSER for non-base load natural gas-fired units, we
evaluated a range of technologies, including partial CCS, high-
efficiency NGCC technology designed for base load applications, fast-
start NGCC, high-efficiency simple cycle units (i.e., aeroderivative
turbines), and clean fuels. For each of these technologies, we
considered technical feasibility, costs, energy and non-air quality
impacts, potential for emission reductions, and ability to promote
technology.
    While CCS would result in emission reductions and promote the
development of new technology, we concluded that CCS does not meet the
BSER criteria because the low capacity factors and irregular operating
patterns (e.g., frequent starting and stopping and operating at part
load) of non-base load units make the technical challenges associated
with CCS even greater than those associated with base load units. In
addition, because the CCS system would remain idle for much of the time
while these units are not running, CCS would be less cost-effective for
these units than for base load units.
    We have also concluded that the high-efficiency NGCC units designed
for base load applications do not meet any of the BSER criteria for
non-base load units. First, non-base load units need to be able to
start and stop quickly, and NGCC units designed for base load
applications require relatively long startup and shutdown periods.
Therefore, conventional NGCC designs are not technically feasible for
the non-base load subcategory. Also, non-base load units operate less
than 10 percent of the time on average. As a result, conventional NGCC
units designed for base load applications, which have relatively high
capital costs, will not be cost-effective if operated as non-base load
units. In addition, it is not clear that a conventional NGCC unit will
lead to emission reductions if used for non-base load applications. As
some commenters noted, conventional NGCC units have relatively high
startup and shutdown emissions and poor part-load efficiency, so
emissions may actually be higher compared with simple cycle
technologies that have lower overall design efficiencies but better
cycling efficiencies. Finally, requiring conventional NGCC units as the
BSER for non-base load combustion turbines would not promote technology
because these units would not be fulfilling their intended role. In
fact, it could hamper the development of technologies with lower design
efficiencies that are specifically designed to operate efficiently as
non-base load units (i.e., high-efficiency simple cycle and fast-start
NGCC units). For all these reasons, we have concluded that conventional
NGCC units designed for base load applications are not the BSER for
non-base load natural gas-fired units.
    Compared to conventional NGCC technology, fast-start NGCC units
have lower design efficiencies, but are able to start and ramp to full
load more quickly. Therefore, it is possible that requiring fast-start
NGCC as the BSER for non-base load units would result in emission
reductions and further promote the development of fast-start NGCC
technology, which is relatively new and advanced. However, because the

majority of non-base load combustion turbines operate less than 10
percent of the time, it would be cost-prohibitive to require fast-start
NGCC, which have relatively high capital costs compared to simple cycle
turbines, as the BSER for all non-base load applications. Also, as we
explained above in Section IX.B.2, we do not have sufficient emissions
data for fast-start NGCC units operating over the full range of non-
base load conditions (e.g., peaking, cycling, etc.), so we would not be
able to establish a reasonable emission standard.
    High-efficiency simple cycle turbines are primarily used for
peaking applications. High-efficiency simple cycle turbines often
employ aeroderivative designs because they are more efficient at a
given size and are able to startup and ramp to full load more quickly
than industrial frame designs. Requiring high-efficiency simple cycle
turbines as the BSER could result in some emission reductions compared
with conventional simple cycle turbines. It would also promote
technology development by incentivizing manufacturers to increase the
efficiency of their simple cycle turbine models. However,
aeroderivative designs have higher initial costs that must be weighed
against the specific peak-load profiles anticipated for a particular
new non-base load unit. Many utility companies have elected to install
the heavier industrial frame turbines because the ramping capabilities
of aeroderivative turbines are not required for their system demand
profiles (i.e., the speed and durations of daily changes in electricity
demand), and the fuel savings do not justify the higher initial costs.
We currently do not have precise enough costing information to compare
the cost-effectiveness of aeroderivative turbines and industrial frame
turbines for all non-base load applications. Determining cost-
effectiveness is further complicated because the efficiencies of the
available aeroderivative and industrial frame technologies
significantly overlap. For example, the efficiencies of aeroderivative
turbines range from 32 to 39 percent, while the efficiencies of
industrial frame turbines range from 30 to 36 percent. Based on these
cost uncertainties, we cannot conclude that high-efficiency simple
cycle turbines are the BSER for natural gas-fired non-base load
applications at this time.
    The final option that we considered for the BSER was clean fuels,
specifically natural gas with a small allowance for distillate oil. The
use of clean fuels is technically feasible for non-base load units.
Based on available EIA data,\536\ natural gas comprises more than 96
percent of total heat input for simple cycle combustion turbines. In
addition, natural gas is frequently the lowest cost fossil fuel used in
combustion turbines, so it is cost-effective. Clean fuels will also
result in some emission reductions by limiting the use of fuels with
higher carbon content, such as residual oil. Finally, the use of clean
fuels will not have any significant energy or non-air quality impacts.
Based on these factors, the EPA has determined that the BSER for non-
base load natural gas-fired units is the use of clean fuels,
specifically natural gas with a small allowance for distillate oil.
Natural gas has approximately thirty percent lower CO2
emissions per million Btu than other fossil fuels commonly used by
utility sector non-base load units.
---------------------------------------------------------------------------

    \536\ http://www.eia.gov/electricity/data/eia923/.
---------------------------------------------------------------------------

c. Multi-Fuel-Fired Units
    To identify the BSER for multi-fuel-fired units, we again evaluated
CCS, NGCC technology, high-efficiency simple cycle units (i.e.,
aeroderivative turbines), and clean fuels. For each of these
technologies we considered technical feasibility, costs, energy and
non-air quality impacts, emission reductions, and technology promotion.
For many of the same reasons we provided above in our discussion of the
BSER for non-base load natural gas-fired combustion turbines, only
clean fuels meets the BSER criteria for multi-fuel-fired units.
    While CCS would result in emission reductions and the promotion of
technology, we concluded that CCS does not meet the BSER criteria
because multi-fuel-fired units tend to start, stop, and operate at part
load frequently. Also, there are impurities and contaminants in some
alternate fuels which make the technical challenges of applying CCS to
multi-fuel-fired units greater than for natural gas-fired units.
    In regards to NGCC technology, we have concluded that it is
technically feasible, would result in emission reductions, is cost-
effective, and would promote the development of technology. However, a
BSER determination based on the use of NGCC technology could pose
challenges for facilities operating in remote locations and certain
industrial facilities. In remote locations, the construction of a NGCC
facility is often not practical because it requires larger capital
investments and significant staffing for construction and operation. In
contrast, simple cycle turbines are cheaper and can be operated with
minimal staffing. Also, many industrial facilities do not have the
space available to build a HRSG and the associated cooling tower.
Therefore, requiring NGCC as the BSER could have unforeseen energy
impacts at these types of facilities. Moreover, these same kinds of
facilities also burn by-product fuels. Faced with a decision to install
an NGCC unit, these facilities might seek alternative energy options,
which could lead to increased flaring or venting of by-product fuels
because they are no longer being burned onsite for energy recovery.
Therefore, in light of these potential energy and non-air quality
impacts, we have concluded that NGCC technology is not the BSER for
multi-fuel-fired combustion turbines.
    Similarly, while high-efficiency simple cycle turbines would result
in emission reductions and promote the advancement of this technology,
we are not confident that high-efficiency simple cycle units are
technically feasible or cost-effective for this subcategory.
Aeroderivative turbines are not as flexible with regards to what fuels
that can be burned. Because by-product fuels vary in composition, it is
not clear that all by-products fuels could be burned in a high-
efficiency simple cycle turbine. In addition, even if a by-product fuel
could be burned in an aeroderivative turbine, we do not have
information on the potential for increased maintenance costs, so we
cannot determine whether using high-efficiency simple cycle turbines
would be cost-effective.
    The final option that we considered for the BSER was clean fuels.
The use of clean fuels is technically feasible and cost-effective. The
use of clean fuels also provides an environmentally beneficial
alternative to the flaring or venting of by-product fuels and limits
the use of dirtier fuels with higher CO2 emission rates,
such as residual oils. Clean fuels also promote technology development
by allowing manufacturers to develop new combustion turbine designs
that are capable of burning by-product fuels that currently cannot be
burned in combustion turbines. Finally, the use of clean fuels does not
have any significant energy or non-air quality impacts. Based on these
factors, the EPA has determined that the BSER for multi-fuel-fired
combustion turbines is the use of clean fuels.

D. Achievability of the Final Standards

    We are finalizing emission standards for three subcategories of
combustion turbines. Specifically, units that sell electricity in
excess of a threshold based on their design efficiency and that burn
more than 90 percent natural gas (i.e., base load natural gas-fired
units) will be

subject to an output- based standard. The output-based standard is
based on the performance of existing NGCC units and takes into account
a range of operating conditions, future degradation, etc. Units not
meeting either the percentage electric sales or natural gas-use
criteria (i.e., non-base load natural gas-fired and multi-fuel units,
respectively) will be subject to an input-based standard based on the
use of clean fuels. This section summarizes what emission standards we
proposed and related issues we solicited comment on, describes the
comments we received regarding the proposed emission standards and our
responses to those comments, and provides our rationale for the final
emission standards.
1. Proposed Standards
    For large newly constructed, modified, and reconstructed stationary
combustion turbines (base load rating greater than 850 MMBtu/h), we
proposed an emission standard of 1,000 lb CO2/MWh-g. For
small stationary combustion turbines (base load rating of 850 MMBtu/h
or less), we proposed an emission standard of 1,100 lb CO2/
MWh-g. We also solicited comment on a range of 950-1,100 lb
CO2/MWh-g for large stationary combustion turbines and a
range of 1,000-1,200 lb CO2/MWh-g for small stationary
combustion turbines.
    In addition, we solicited comment on increasing the size
distinction between large and small stationary combustion turbines to
900 MMBtu/h to account for larger aeroderivative designs; increasing
the size distinction to 1,000 MMBtu/h to account for future incremental
increases in base load ratings; increasing the size distinction to
between 1,300 to 1,800 MMBtu/h; and eliminating the size subcategories
altogether. To account for potential reduced efficiencies when units
are not operating at base load, we also solicited comment on whether a
separate, less stringent standard should be established for non-base
load combustion turbines.
2. Comments
    As described previously, we are not finalizing the size-based
subcategories that we proposed and instead are finalizing emission
standards for sales- and fuel-based subcategories. Specifically, we are
finalizing emission standards for three subcategories of stationary
combustion turbines: base load natural-gas fired units, non-base load
natural gas-fired units and multi-fuel-fired units. The relevant
comments concerning the emission standards for the first two
subcategories are discussed below. Any comments we received supporting
tiered emission standards are included in the discussion of non-base
load natural gas-fired units. We did not receive comments on an
appropriate emission standard for multi-fuel-fired units.
a. Emission standards for Base Load Natural Gas-Fired Units
    Many commenters stated that the proposed emission standards did not
properly take into account the losses in efficiency that occur due to
long-term degradation over multiple decades, operation at non-base load
conditions (load cycling, frequent startups and shutdowns, and part-
load operations), site-specific factors such as ambient conditions and
cooling technology, and secondary fuel use (e.g., distillate oil).
These commenters stated that the EPA should conduct a more
comprehensive analysis that addresses worst-case conditions for each of
these factors. They also stated that all of the units included in the
analysis supporting the proposal were relatively new and therefore have
experienced limited degradation. The commenters stated that, while some
degradation in efficiency can be recovered during periodic maintenance
outages, it is not always possible or feasible to repair a degraded
component immediately because repairs often involve extended outages
that must be scheduled well in advance. They stated that a new unit
that initially could meet the standard at base load conditions can
experience increasing heat rates with age even when adhering to the
manufacturer's recommended maintenance program.
    Some commenters stated that the proposed standards were derived by
looking at emissions data from years with historically low natural gas
prices. They surmised that the NGCC units were taking advantage of
these prices by running at historically high capacity factors and
concluded that the efficiencies and CO2 emission rates
underlying the proposed standards were not representative of periods
with higher natural gas prices. Other commenters said that many NGCC
units are increasingly required to cycle and operate at lower
capacities (compared to the proposal's baseline) to accommodate hourly
variations in intermittent renewable generation. They anticipated that
this type of generation will increase, requiring NGCC units to start,
stop, and operate at part load more frequently than in the past,
increasing CO2 emissions.
    Some commenters indicated that, during startup, combustion turbines
must be operated at low load for extended periods to gradually warm up
the HRSG to minimize thermal stresses on pressure vessels and boiler
tubes. During these startup periods, significant CO2
emissions occur, but steam production is not sufficient for the steam
turbine generator to produce electricity. They also stated that a
similar situation occurs during shutdown when the steam cycle does not
generate electricity, but the combustion turbine is still combusting
fuel as it proceeds through the shutdown process. These commenters
recommended that the EPA could address these issues by creating a
subcategory for NGCC units that cycle and operate at intermediate load.
    Many commenters said that site-specific factors can often preclude
operators from achieving design efficiencies based on ISO conditions.
These factors include high elevations, high ambient temperatures, and
cooling system constraints. They stated that local water temperatures
can impact condenser operating pressure and heat rates. They also said
that areas with limited water resources could require systems that rely
on air-cooled condensers, which cannot achieve thermal efficiencies
comparable to water-cooled plants. These commenters stated that the
final rule should include provisions for addressing site-specific
constraints that preclude individual affected EGUs from achieving the
emissions rates achieved on average by other sources.
    Some commenters stated that the proposed standards for modified and
reconstructed combustion turbines would foreclose future opportunities
for operators to undertake projects to restore the performance of both
degraded units subject to the NSPS and existing, pre-NSPS units. They
said that it is not possible to bring older combustion turbines (built
prior to the year 2000) up to the efficiency levels of modern units
because many newer technological options that deploy higher
temperatures are not available for pre-2000 combustion turbines.
    Commenters from the power sector generally supported increasing the
standards to 1,100 lb CO2/MWh-g and 1,200 lb CO2/
MWh-g for the newly constructed large and small turbines, respectively.
They also advocated finalizing standards for modified and reconstructed
standards that are 10 percent higher than the final standards for new
sources because combustion turbines constructed prior to 2000 were not
included in the EPA's analysis.
    Conversely, some commenters stated that the proposed standards for
combustion turbines do not reflect the emission rates that are
achievable by

modern, efficient NGCC power blocks. These commenters stated that the
appropriate standard, consistent with Congressional objectives under
CAA section 111, should be 800 lb CO2/MWh-g based on the
performance of the lowest emitters in the CAMD database. Some
commenters stated that a standard of 850 lb CO2/MWh-g
reflects BSER for high-capacity factor units because half of the NGCC
units in the CAMD database are achieving this level of emissions. One
commenter from the power sector who operates NGCC power plants stated
that the final standard for new large combustion turbines should be 925
lb CO2/MWh-g. Another commenter also supported an emission
standard of 925 lb CO2/MWh-g, which is consistent with
recent BACT determinations in the state of New York. Several other
commenters stated that a reasonable standard for new large combustion
turbines should be 950 lb CO2/MWh-g and that the final
standard for new small combustion turbines should be 1,000 lb
CO2/MWh-g. Numerous commenters stated that the final
standards for new sources should not exceed 1,000 lb CO2/
MWh-g for either large or small combustion turbines. Other commenters
stated that, because the standards were developed based on emission
rates that are being achieved by the majority of existing units, the
final standards should be the same for new, modified, and reconstructed
units.
b. Emission Standards for Non-Base Load Natural Gas-Fired Units and
Multi-Fuel-Fired Units
    Many commenters stated that the EPA cannot finalize ``no emission
standard'' for non-base load units, which the EPA solicited comment on
in the broad applicability approach. They argued that this approach was
not consistent with the definition of ``standard of performance'' in
CAA section 111(a)(1), which requires there to be an ``emission
limitation'' that reflects a ``system of emission reduction.'' Some
commenters recommended that non-base load units should be subject to
work practice standards, such as operating safely with good air
pollution control practices, including CO2 monitoring and
reporting requirements. Other commenters pointed to recent PSD permits
that include tiered emission limits for the different roles served by
combustion turbines. They cited BACT limits from 1,328 to 1,450 lb
CO2/MWh-g for peaking units. One commenter supported tiered
limits consistent with recent BACT determinations in the state of New
York, which include limits for simple cycle combustion turbines of
1,450 lb CO2/MWh-g. An air quality regulator from a state
with rapidly increasing renewable generation supported a limit of 825
lb CO2/MWh-g for all base load NGCC units; 1,000 lb
CO2/MWh-g for large intermediate load NGCC units; 1,100 lb
CO2/MWh-g for small intermediate load NGCC units. This
commenter also recommended that the EPA set a numerical limit
specifically for peaking units after the completion of a peaking unit-
specific BSER analysis. Several commenters supported tiered standards
based on capacity factor. They proposed 825 lb CO2/MWh-g for
base load units (those operating over 4,000 hours annually), 875 lb
CO2/MWh-g for intermediate and load-following units (those
operating between 1,200 and 4,000 hours annually), and 1,100 lb
CO2/MWh-g for peaking units (those operating less than 1,200
hours per year).
3. Final Standards
a. Newly Constructed Base Load Natural Gas-Fired Units
    In evaluating the achievability of the base load natural gas-fired
emission standard, we focused on three types of data. Specifically, we
looked at existing NGCC emission rates, recent PSD permit limits for
CO2 emissions, and NGCC design efficiency data and
specifications. Based on this analysis, we have concluded that an
emission rate of 1,000 lb CO2/MWh-g is appropriate for all
base load natural gas-fired combustion turbines, regardless of size.
    Since the standards were proposed, the EPA has expanded the NGCC
emission rate analysis that supported the proposed emission standards
to include emissions information for NGCC units that commenced
operation in 2011, 2012, and 2013, and updated the emissions data to
include emissions through 2014. In our analysis, we evaluated 345 NGCC
units with online dates ranging from 2000 to 2013. The analysis
included emissions data from 2007 to 2014 as submitted to the EPA's
CAMD. The average maximum 12-operating-month CO2 emission
rate for all NGCC units was 897 lb CO2/MWh-g, with
individual unit maximums ranging from 751 to 1,334 lb CO2/
MWh-g.
    Consistent with our proposed size-based subcategories, we also
reviewed the emissions data for small and large NGCC units separately.
For small units, we evaluated emissions data from 17 NGCC units with
heat input ratings of 850 MMBtu/h or less. These units had an average
maximum 12-operating-month CO2 emission rate of 953 lb/MWh-
g. Individual unit maximum emission rates ranged from 898 to 1,175 lb
CO2/MWh-g. Two of the units had a maximum emissions rate
equal to or greater than 1,000 lb CO2/MWh-g.\537\ However,
one of the units with a maximum emission rate above 1,000 lb
CO2/MWh-g was only selling approximately 20 percent of its
potential electric output (significantly below the design-specific
percentage electric sales threshold) when the emission rate occurred.
If this unit were a new unit, the applicable emission standard would be
the heat input-based clean fuels standard, and the unit would not be
out of compliance. Therefore, 16 of the 17 existing small NGCC units
have demonstrated that an emission rate of 1,000 lb CO2/MWh-
g is achievable. In addition, the six newest units, which commenced
construction between 2007 and 2012, all have maximum 12-operating-month
emission rates of less than 950 lb CO2/MWh-g. While these
units might not be old enough to have experienced degradation, their
maximum emission rates demonstrate that the final standard of 1,000 lb
CO2/MWh-g includes a significant compliance margin for any
future degradation.
---------------------------------------------------------------------------

    \537\ For emission standards of 1,000 lb CO2/MWh-g
and above, the emission standard uses three significant figures. See
Section X.D.
---------------------------------------------------------------------------

    For large units, the average maximum 12-operating-month emission
rate was 895 lb CO2/MWh-g, with individual unit maximum
emission rates ranging from 751 to 1,334 lb CO2/MWh-g.
Twenty-three of the 328 large NGCC units had maximum 12-operating-month
emission rates greater than 1,000 lb CO2/MWh-g. While we do
not have precise design efficiency information for each of these units,
and thus cannot calculate the precise percentage electric sales
threshold to which each unit would be subject, it appears that all of
the emission rates in excess of 1,000 lb CO2/MWh-g occurred
during periods when electric sales were low and would be below the
threshold. Thus, if these units were new units, they would only have to
comply with the heat input-based clean fuels standard. Therefore,
essentially all existing NGCC units would have been in compliance with
the final emission standard. We note also that there are 51 new NGCC
units that have started operation since 2010, and the average maximum
12-operating-month emission rate for these units is 833 lb
CO2/MWh-g. Therefore, the final emission standard includes a
very significant compliance margin to account for any potential future
degradation of large units.

    To evaluate degradation further, the EPA reviewed the emission rate
information for the 55 oldest NGCC units in our data set (i.e., units
that came online in 2000 and 2001). According to the commenters, we
should expect to see degradation when reviewing the annual emissions
data for these turbines because they are 14 to 15 years old. However,
we did not see any sign of degradation. The CO2 rates for
these turbines have little standard deviation between 2007 and 2014. In
addition, there were many instances where the CO2 emission
rate of a unit actually decreased with age. This indicates that the
efficiency of the unit is increasing, possibly as a result of good
operating and maintenance procedures or upgrades to equipment that
improved efficiency beyond the original design. Based on these
findings, we have concluded that our analysis adequately accounts for
potential degradation.
    We also evaluated the impact of elevation, ambient temperature,
cooling type, and operating conditions (startups, shutdowns, and
average run time per start) because commenters indicated that these
could affect a unit's ability to achieve the standard. We saw little
correlation between elevation or ambient temperature and emission rate.
In addition, any correlation was relatively small and would have an
insignificant impact on the ability of a unit to achieve the final
standard. We identified 32 large NGCC units with dry cooling towers.
The average maximum 12-operating-month emission rate for this group of
units was 875 lb CO2/MWh. This rate was actually lower than
the average rate for the large NGCC group as a whole. Based on these
findings, we have concluded that the final emission standard will not
limit the use of dry cooling technologies. Finally, the EPA evaluated
the impact of run time per start, average duty cycle, and number of
starts on emission rates. While these factors do influence emission
rates, the non-base load natural gas-fired subcategory inherently
addresses efficiency issues related to operating conditions.
    In addition to evaluating existing NGCC emissions data, the EPA
reviewed the CO2 emission limits included in PSD
preconstruction permits issued since January 1, 2011. We evaluated all
permit limits over an annual period. In total, we identified 31 major
source PSD permits with 39 discrete limits on CO2 emissions.
Eight of the limits were expressed in terms of lb/h or tons per year,
so we did not include them in the analysis. In addition, one CHP unit
that generates electricity and supplies steam to a chemical plant was
in the data set. This facility had a permit limit of 1,362 lb
CO2/MWh based only on gross electrical output and does not
account for useful thermal output. Therefore, we did not include it in
the analysis either. Finally, we excluded two permits that did not
clearly specify if the output-based standard was on a gross or net
basis.
    The remaining 28 permit limits were expressed in lb CO2/
MWh or a heat rate basis that could be converted to lb CO2/
MWh. Eight permit limits were based on net output, ranging from 774-936
lb CO2/MWh-n. The lowest emission limit was for a hybrid
power plant with a solar component that could contribute up to 50 MW.
Twenty permit limits were based on gross output, ranging from 833-1,100
lb CO2/MWh-g. Of these 28 permit limits, the only limit in
excess of our final emission standard of 1,000 lb CO2/MWh-g
is for a relatively small NGCC unit (base load rating of 366 MMBtu/h)
that commenced construction prior to the proposal and thus will not be
subject to the requirements of this final rule.
    Each of the permit limits discussed above that is 1,000 lb
CO2/MWh or less includes all periods of operation, including
startup, shutdown, and malfunction events. In addition, each permit
limit was set after back up and additional fuel use were taken into
consideration. While some permits restrict fuel use to only natural
gas, others allow limited usage (duration and type) of back up and
other fuels. For example, the Pioneer Valley Energy Center has
unrestricted use of natural gas, but can burn ultra-low sulfur diesel
(ULSD) for up to 1,440 hours per 12-month period. This permit requires
the unit to comply with a limit of 895 lb CO2/MWh-n even
when burning up to 16 percent distillate oil. Each permit limit takes
into account the mode of operation for the combustion turbine. For
example, the permit for the Lower Colorado River Authority's Ferguson
plant evaluated emission limits for the plant at 50, 75, and 100
percent gross load. The emission limit of 918 lb CO2/MWh-n
accounts for the unit's expected operation at 50 percent gross load.
For NGCC units with duct burners on their HRSGs, the permit limits
account for the hours of operation with duct burners firing. Finally,
most of these permits include compliance margins to account for
efficiency losses due to degradation and other factors (e.g., actual
operating parameters, site-specific design considerations, and the use
of back up fuel). In total, these compliance margins result in a 10 to
13 percent increase in the permitted CO2 emission limits,
yet all of the limits except one were still below 1,000 lb
CO2/MWh-g.
    Finally, we also reviewed NGCC design efficiency data and
specifications submitted to Gas Turbine World. Specifically, we
reviewed the reported efficiency data for 88 different 60 Hz NGCC units
manufactured by Alstom, GE Energy Aeroderivative and Heavy Duty,
Mitsubishi Heavy Industries, Pratt & Whitney, Rolls-Royce, and Siemens
Energy. The designs ranged in model year from 1977 to 2011, capacities
ranged from 31 to 1,026 MW, and base load ratings ranged from 236 to
3,551 MMBtu/h. The average reported design emission rate for these
units was 834 lb CO2/MWh-n and ranged from 725 to 941 lb
CO2/MWh-n. Therefore, our optional standard of 1,030 lb
CO2/MWh-n would allow for an average compliance margin of 24
percent, with a range from 10 to 42 percent, over the design rate.
Ninety-five percent of designs would have a compliance margin of 13
percent or more, the top end of the range of compliance margins
determined to be appropriate in the PSD permits we reviewed.
    Because some commenters were concerned that smaller NGCC units will
not be able to achieve the emission standard, we specifically
considered the design rates for smaller units. For the 52 small units
(base load rating of 850 MMBtu/h or less), the average design emission
rate was 865 lb CO2/MWh and ranged from 796 to 941 lb
CO2/MWh-n. Therefore, our optional standard of 1,030 lb
CO2/MWh-n would allow for an average compliance margin of 19
percent, with a range of 10 to 29 percent, over the design rate.
Ninety-five percent of small NGCC designs would have a compliance
margin of 13 percent or more.
    We further refined our analysis by only considering the most
efficient design for a given combustion turbine engine. For example, GE
Energy Aeroderivative offers four design options for its LM2500 model-
type, all with a rating of approximately 45 MW. The design emission
rates for these various options range from 827 to 914 lb
CO2/MWh-n. When only the most efficient models for a
particular combustion turbine engine design are considered, all NGCC
models have over a 13 percent compliance margin. In other words,
developers of new base load natural gas-fired combustion turbines
concerned about the achievability of the final standard have multiple
more efficient options offered by the same manufacturer. Therefore, we
have concluded that the final emission standard allows sufficient
flexibility for end users to select an

NGCC design appropriate for their specific requirements.
    After considering these three sources of information--actual NGCC
emission rate data, PSD permit limits for NGCC facilities, and NGCC
design information--we have concluded that a standard of 1,000 lb
CO2/MWh is both achievable and appropriate for newly
constructed base load natural gas-fired combustion turbines. While we
anticipate that the large majority of new NGCC units will operate well
below this emission rate, this standard provides flexibility for
developers to take into account site-specific conditions (e.g., ambient
conditions and cooling system), operating characteristics (e.g., part-
load operation and frequent starting and stopping), and reduced
efficiency due to degradation. The standard also accommodates the full
size range of turbines.
    We also expect multiple technology developments to further increase
the performance of new base load natural gas-fired stationary
combustion turbines. Vendors continue to improve the single cycle
efficiency of combustion turbines. The use of more efficient combustion
turbine engines improves the overall efficiency of NGCC facilities. In
addition, existing smaller NGCC facilities were likely designed using
single or dual pressure HRSGs without a reheat cycle. New designs can
incorporate three pressure steam generators with a reheat cycle to
improve the overall efficiency of the NGCC facility. Finally,
additional technologies to reduce emission rates for new combustion
turbines include CHP and integrated non-emitting technologies. For
example, an NGCC unit that is designed as a CHP unit where ten percent
of the overall output is useful thermal output would have an emission
rate approximately five percent less than an electric-only NGCC. In
sum, we believe that our final emission standards of 1,000 lb
CO2/MWh-g and 1,030 lb CO2/MW-n are not only
readily achievable, but likely conservative.
b. Reconstructed Base Load Natural Gas-Fired Units
    We disagree with commenters that stated that reconstructed
combustion turbines will not be able to achieve the proposed emission
standards. For the reasons listed below, we have concluded that an
existing base load natural-gas fired unit that reconstructs can achieve
an emission rate of 1,000 lb CO2/MWh-g, regardless of its
size.
    Highly efficient NGCC units include (1) an efficient combustion
turbine engine, (2) an efficient steam cycle, and (3) a combustion
turbine exhaust system that is ``matched'' to the steam cycle for
maximum efficiency. In order for an existing NGCC unit to trigger the
reconstruction provisions, the unit would have to essentially be
entirely rebuilt. This would involve extensive upgrades to both the
combustion turbine engine and the HRSG. Therefore, a reconstructed NGCC
unit will be able to maximize the efficiency of the turbine engine and
the steam cycle and match the two for maximum efficiency.
    According to comments submitted in response to the proposal for
existing sources under CAA section 111(d), there are various options
available to improve the efficiency of existing combustion turbines.
One combustion turbine manufacturer provided comments describing
specific technology upgrades for the compressor, combustor, and gas
turbine components. This manufacturer stated that operators of existing
turbines can replace older internal components along the gas path with
state-of-the-art components that have higher aerodynamic efficiencies
and improved seal designs. These gas-path enhancements enable existing
sources to both improve the efficiency of the turbine engine and
improve the systems used for cooling the metal parts along the hot-gas
path to allow existing systems to achieve higher operating
temperatures. In total, the manufacturer stated that utilities
deploying these gas-path improvements on reconstructed industrial frame
combustion turbines with nominal output ratings of 170 to 180 MW can
increase their output by 10 MW while reducing CO2 emissions
by more than 2.6 percent compared to baseline. In addition to gas-path
and software improvements, the manufacturer stated that the newest low-
NOX combustor designs can be retrofitted on modified and
reconstructed turbines to achieve lower NOX emissions, which
improves turndown (i.e., to enable stable operations at lower loads
compared to the lowest stable load achievable at baseline conditions)
and efficiencies across all load conditions. The manufacturer indicated
that operators of existing combustion turbines deploying both state-of-
the-art gas-path and software upgrades and combustor upgrades can
increase output on frame-style turbines with nominal output ratings of
170 to 180 MW by 14 MW, while reducing CO2 emissions by 2.8
percent. In addition to the preceding upgrades, the manufacturer stated
that existing combustion turbines can achieve the largest efficiency
improvements by upgrading existing compressors with more advanced
compressor technologies, potentially improving the combustion turbine's
efficiency by an additional 3.8 percent. Thus, the total potential
CO2 emissions reductions for just the combustion turbine
portion of a combined cycle unit is 6.6 percent.
    In addition to upgrades to the combustion turbine engine, an
operator reconstructing a NGCC unit will have the opportunity to
improve the efficiency of the HRSG and steam cycle. For example, a
steam turbine manufacturer identified three retrofit technologies
available for reducing the CO2 emissions rate of existing
steam turbines by 1.5 to 3 percent: (1) Steam-path upgrades can
minimize aerodynamic and steam leakage losses; (2) replacement of the
existing high pressure turbine stages with state-of-the-art stages
capable of extracting more energy from the same steam supply; and (3)
replacement of low-pressure turbine stages with larger diameter
components that extract additional energy and that reduce velocities,
wear, and corrosion.
    In addition, an operator reconstructing a NGCC unit could upgrade
the entire steam cycle. For example, combined cycle units originally
constructed with only a single pressure level can be upgraded to also
include second and third pressure levels. Studies
538 539 540 show that converting a single pressure HRSG with
steam reheat to a double pressure configuration with steam reheat can
reduce the CO2 emission rate of a NGCC unit by 1.5 to 1.7
percent. These same studies show that converting from a single pressure
configuration with reheat to a triple pressure configuration with
reheat can yield a 1.8 to 2 percent reduction in the CO2
emission rate. Similarly, units constructed with only a double pressure
configuration without reheat can obtain a 0.4 percent reduction by
adding a reheat cycle or a 0.9 percent reduction by converting to a
triple pressure configuration and adding a reheat cycle. Existing NGCC
turbines that convert to these advanced HRSG configurations and that
deploy the previously discussed combustion turbine and steam turbine
upgrades can

realize CO2 emission rate reductions ranging from 6 to 10
percent, depending on their baseline design and condition. Based on the
available options to improve the efficiency of existing NGCC units and
the fact that the vast majority of existing NGCC units are already
achieving emission rates of 1,000 lb CO2/MWh-g or less, we
have concluded that all reconstructed NGCC units can achieve this
emission rate.
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    \538\ ``Exergetic and Economic Evaluation of the Effects of HRSG
Configurations on the Performance of Combined Cycle Power Plants.''
M. Mansouri, et al. Energy Conversion and Management 58:47-58, 2012.
    \539\ ``Combined Cycle Power Plant Performance Analyses Based on
Single-Pressure and Multipressure Heat Recovery Steam Generator.''
M. Rahim, Journal of Energy Engineering, 138:136-145, 2012.
    \540\ ``Thermodynamic Evaluation of Combined Cycle Plants.'' N.
Woudstras et al. Energy Conversion and Management 51:1099-1110,
2010.
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    Finally, we note that an owner or operator that is considering
reconstructing an existing simple cycle turbine should decide how they
wish to operate that turbine in the future. If they anticipate
operating above the percentage electric sales threshold, then they
should install a HRSG and steam turbine and convert to a NGCC power
block in accordance with our determination that NGCC is the BSER for
base load applications. If they intend to operate the turbine below the
percentage electric sales threshold, however, then the clean fuels
standard, described below, will apply.
c. Newly Constructed and Reconstructed Non-Base Load Natural Gas-Fired
Units
    The EPA agrees with the commenters who stated that ``no emission
limit'' would be inconsistent with the requirements of CAA 111(a)(1).
We therefore are finalizing an input-based standard based on the use of
clean fuels for non-base load natural gas-fired combustion turbines in
recognition that efficiency can be reduced due to operation at low
loads, cycling, and frequent startups. The EPA has concluded that, at
this time, we do not have sufficient information to set a meaningful
output-based standard for non-base load natural gas-fired combustion
turbines. The input-based standard requires non-base load units to burn
fuels with an average emission rate of 120 lb CO2/MMBtu or
less. This standard is readily achievable because the CO2
emission rate of natural gas is 117 lb CO2/MMBtu. The most