standard for these sources.

B. What are the energy impacts?

    This proposed rule is not anticipated to have an effect on the
supply, distribution, or use of energy. As previously stated, the EPA
projects few, at most, new reconstructed or modified EGUs.

C. What are the compliance costs?

    The EPA does not believe this proposed rule will have compliance
costs associated with it, because, the EPA projects there to be, at
most, few new, modified, or reconstructed fossil fuel-fired steam
generating units that will trigger the provisions the EPA is proposing.
The economic impact analysis includes an illustrative analysis of the
potential project-level costs of this proposed action relative to the
2015 Rule's standards.

D. What are the economic and employment impacts?

    The EPA does not anticipate that this proposed rule will result in
economic or employment impacts because, the EPA projects there to be,
at most, few new, modified, or reconstructed coal-fired steam
generating units EGUs that will trigger the provisions the EPA is
proposing. Likewise, the EPA believes this rule will not have any
impacts on the price of electricity, employment or labor markets, or
the U.S. economy.

E. What are the benefits of the proposed standards?

    As previously stated, the EPA does not anticipate emission changes
resulting from the rule as the EPA projects there to be, at most, few
new, modified, or reconstructed coal-fired steam generating units that
will trigger the provisions the EPA is proposing. Therefore, there are
no direct climate or human health benefits associated with this
rulemaking.

IX. Request for Comments

    The EPA requests comments on all aspects of the proposed
rulemaking, including the economic impact analysis (Comment C-28). All
significant comments received will be considered in the development and
selection of the final rule. The EPA is specifically soliciting
comments on alternate compliance options (Comment C-29).

A. Subcategorization by Fuel Type

    Except for coal refuse, the EPA is not proposing subcategorization
by fuel type, but the Agency is soliciting comments on that approach
(Comment C-30). The EPA is not proposing to subcategorize by fuel type
for multiple reasons. Subcategorizing by fuel type could have the
perverse impact of both increasing emissions and decreasing compliance
options. Due to averaging, if the subcategorization is based on the
fuel with the highest percentage heat input, owner/operators could have
an incentive to burn sufficient amounts of higher emitting fuels in
order to qualify for the higher emissions standard. For example, a
facility that blends subbituminous and lignite would have a regulatory
incentive to burn higher amounts of lignite than subbituminous coal
(even though coal is lower emitting) in order to have a less stringent
NSPS emissions rate. If the standard is determined based on the actual
percentage of each fuel burned, that would limit the ability of owners/
operators of coal-fired EGUs to use natural gas or other lower emitting
fuels as compliance options because the emissions standard would become
more stringent with increasing percentages of natural gas use. Both of
these subcategorization by fuel type approaches fail to recognize the
environmental benefit of lower emitting (e.g., cleaner) fuels or
integrated non-emitting (i.e., renewable) electric generation. The
proposed fuel neutral standard is consistent with the emissions
standards in the criteria pollutant NSPS and is achievable for all coal
types. This approach both incentivizes the use of lower emitting fuels
and allows the use of natural gas and/or integrated renewable
generation as compliance options.

B. Low Duty Cycle Subcategory

    Due to the low variable operating costs of highly efficient coal-
fired EGUs, any affected coal-fired EGU would likely operate at high
capacity factors. This is confirmed by review of the hourly operating
data from highly efficient coal-fired EGUs. As existing coal-fired
generation EGUs retire and additional energy storage technologies enter
the market, the EPA expects the remaining coal-fired EGUs to continue
to operate at high loads. However, during periods of low electric
demand, coal-fired EGUs may reduce load to approximately 45 percent as
an alternate to shutting down completely. While efficiency is reduced
at this load, it is high enough to maintain power generation, continue
operation of the pollution control equipment, and allow the unit to
ramp up relatively quickly as demand increases. Based on this, the EPA
is soliciting comment on establishing separate emissions standards for
steam generating units operating at partial load (Comment C-31).
    Based on the data reviewed, maximum coal-fired EGU efficiency tends
to be achieved when the EGU operates at between 80 to 90 percent load.
Efficiency is relatively stable down to about 65 percent load \118\ and
up to 100 percent load. EGUs operating above or below those load levels
experience noticeable reductions in efficiency. Due to maintenance
concerns, EGUs would not operate above 100 percent of the rated load
for extended periods of time. Also, brief periods of lower efficiencies
will not have an appreciable impact on a 12-operating month rolling
average emissions rate, so the Agency is not proposing to establish a
subcategory for operation above 100 percent load. However, coal-fired
EGUs operating at low loads (below approximately 65 percent) lose
efficiency and could have difficulty in complying with an emissions
standard that reflects the efficiencies achieved at higher operating
loads unless they co-fire natural gas. Therefore, the EPA is soliciting
comment on whether it would be appropriate to establish a subcategory
for steam generating units during 12-month rolling average periods when
the unit is not operated at high capacity factors (Comment C-32).
Specifically, the Agency is considering a subcategory for units that
operate at less than a 65 percent duty cycle on a rolling average basis
during any 12-operating month period. Duty cycle is defined as the
average operating load. It is different from capacity factor in that
periods of no operation are not considered when calculating the duty
cycle. The EPA is considering using duty cycle instead of capacity
factor for several reasons. First, a standard based on capacity factor
is more difficult to establish since it is a less precise measurement.
A unit operating at a 65 percent capacity factor could either be
operated at a constant 65 percent load or at 100 percent load 65
percent of the time and not operate for 35 percent of the time. For
identical

units, these operating profiles could result in substantially different
emission rates. A duty cycle subcategorization approach assures that
units are not deemed to be in the low load subcategory because of
periods of non-operation. Specifically, the EPA is considering that
during periods when these units are operated as non-base load units
(12-operating month average duty cycle is less than 65 percent) an
alternate emission standard would apply. The emission standards the EPA
is soliciting comment on during non-base load operation for the
subcategorized sources are 2,100 lb CO2/MWh-gross for
sources with a nameplate heat input rating of greater than 2,000 MMBtu/
h, 2,200 lb CO2/MWh-gross for sources with a heat input
rating of less than or equal to 2,000 MMBtu/h, and 2,400 lb
CO2/MWh-gross for coal refuse-fired steam generating units
(Comment C-33).\119\
---------------------------------------------------------------------------

    \118\ Sliding pressure steam generating units are able to
maintain efficiency at part-load operation better then constant
pressure steam generating units.
    \119\ Based on review of hourly emissions data, part load
emission rates are approximately 10 percent higher than the minimum
full load emissions rate. To maintain the minimum full load
emissions rate, a unit would have to co-fire approximately 20
percent natural gas when operating at part load.
---------------------------------------------------------------------------

    The EPA is also soliciting comment on establishing a part load heat
input-based standard (similar to the part load standard for combustion
turbines) as an alternate or in place of the low duty cycle output-
based standard (Comment C-34). The advantage of a heat input-based
standard is that it is a constant value based on the fuel burned and is
independent of efficiency and provides a clear compliance option
regardless of the level of degradation of efficiency that results from
operation at low loads. However, this approach does not directly
recognize the environmental benefit of efficient operation at part
load. To incorporate recognition of the environmental benefit of energy
efficiency into the heat input-based standard, the EPA proposes to
conclude that it is not appropriate to base a heat input standard on
the emissions rate of bituminous coal (the lowest emitting coal on a
heat input basis). While compliance would be straight forward for
bituminous-fired EGUs and would only require a small amount of co-
firing for units burning other coals, basing a heat input standard on
the emissions rate of bituminous coal would not recognize the
environmental benefit of efficient part load operation. This could have
the perverse environmental impact of increasing emissions. Owners and
operators of EGUs that are expected to dispatch at part loads would
have limited regulatory incentive to assure that the unit is operated
efficiently. In fact, there would be a regulatory incentive to operate
the unit at lower duty cycles specifically to qualify for the part load
standard.
    Based on this, the EPA solicits comment on whether only a more
stringent heat input-based standard would be appropriate (Comment C-
35). The alternate heat input-based standard the EPA is considering
would be based on the heat input-based emissions rate of 200 lb
CO2/MMBtu. This approach has the advantage of allowing for a
clear path for continuous compliance, while at the same time
recognizing the environmental benefit of efficient operation across all
load levels. Due to the price of natural gas relative to coal, owner/
operators of EGUs would have a financial incentive to operate their
units as efficiently as possible so they could comply with the full
load standard with as low an average duty cycle as possible (i.e.,
below 65 percent) without co-firing natural gas and/or fuel oil. Less
efficient EGUs operating below a 65 percent duty cycle, and well
maintained efficient EGUs operating at substantially lower duty cycles
or idle conditions, could co-fire approximately 15 percent natural gas
to demonstrate compliance. The EPA is soliciting comment on whether
this is a reasonable requirement (Comment C-36). Specifically, as
traditionally coal-fired EGUs shift from base load use towards being
reserved for capacity requirements (e.g., peaking units) natural gas
often becomes the primary fuel due to the ability to reduce expenses
from operation of post-combustion emissions control equipment.
    The EPA is also soliciting comment on several related issues.
First, the Agency soliciting comment on the cutoff point for the low
duty cycle standard (Comment C-37). The EPA is currently considering a
range of between 50 to 70 percent average duty cycle. In addition, the
EPA is soliciting comment on whether the low duty cycle subcategory
should be based on percent of potential electric sales instead of a
heat input-based capacity factor (Comment C-38). While this approach is
similar to a heat input-based capacity factor approach, it would use
the same calculational procedure as for combustion turbines. The
primary difference is that EGUs that generate power for use on site
(e.g., combined heat and power units) would not be subject to the
output-based standard as frequently. Finally, the EPA is soliciting
comment on whether IGCC units should also have a low duty cycle
subcategory or if a single standard should apply at all load levels
(Comment C-39). IGCC units are particularly well suited to burn natural
gas efficiently and co-firing would allow compliance at all load
levels.

C. Commercial Demonstration Permit

    The steam generating unit criteria pollutant NSPS (subpart Da)
includes a provision to assure that NSPS requirements do not discourage
the development and implementation of innovative and emerging
technologies. Specifically, the commercial demonstration permit (40 CFR
60.47Da) provides a procedure for owner/operators of new coal-fired
EGUs proposing to demonstrate an emerging technology to apply to the
Administrator for a slightly less stringent standard than would
otherwise be required. The commercial demonstration permit section of
the EGU criteria pollutant NSPS was included in the original 1979
rulemaking (44 FR 33580) and was later updated in the 2012 amendments
(77 FR 9304) to assure that the NSPS recognizes the environmental
benefit of the development of new and emerging technologies. The
rationale for this provision includes that the innovative technology
waiver under section 111(j) of the CAA does not by itself offer
adequate support for certain capital-intensive technologies, as it does
not provide sufficient time for amortization (44 FR 33580). The
authority to issue these permits is predicated on the D.C. Circuit
Court's opinion in Essex Chemical Corp. v. Ruckelshaus, 486 F. 2d 42
(D.C. Cir. 1973); NSPS should be set to avoid unreasonable costs or
other impacts. Similar provisions for emerging technologies are
included in the industrial-commercial-institutional steam generating
unit criteria pollutant NSPS (52 FR 47839).
    Standards requiring a high level of performance, such as the
proposed standards for GHG emissions, might discourage the continued
development of some new technologies. The EPA recognizes that owners/
operators in the utility sector may not accept the risk of using new
and innovative technologies as the emission reduction efficiencies of
such technologies have not been fully demonstrated. As such, owners/
operators may prefer conventional, demonstrated technologies.
Therefore, it is desirable that standards of performance accommodate
and foster the continued development of emerging technologies. Special
provisions may be needed to encourage the continued development and use
of technologies that show promise in achieving levels of performance
comparable or superior to those achieved by the use of fully
demonstrated conventional technologies, but at reduced cost or with

other offsetting environmental or energy benefits. Establishing less
stringent percent reduction requirements for emerging technologies may
substantially reduce financial risk and increases the likelihood that
owners and operators of new coal-fired EGUs will install and operate
emerging technologies. The experience gained in utilizing emerging
technologies will, in turn, foster their continued development. Unlike
most other air pollutants, GHG pollution has limited direct health
impacts and can persist in the atmosphere for decades or millennia,
depending on the specific GHG. This special characteristic makes
transfer of control technologies and long-term technology innovation
particularly important factors when considering appropriate control
options for GHG emissions.
    To mitigate the potential negative impact on emerging technologies,
the EPA is soliciting comment on whether it should include a commercial
demonstration permit provision in 40 CFR part 60, subpart TTTT (Comment
C-40). The EPA believes that this provision would encourage the
development of new technologies and compensate for problems that may
arise when applying them to commercial-scale units. The technologies
the EPA is currently considering include pressurized fluidized bed
technology, alternate power cycle working fluid (e.g., supercritical
CO2), additional energy recovery using integrated thermo-
electric materials, a supercritical CO2 Brayton cycle, an
integrated organic rankine cycle, integrated hybrid photovoltaic-solar
thermal, integrated novel energy storage technologies, and novel carbon
capture technologies. Specifically, the Administrator (in consultation
with DOE) would issue commercial demonstration permits for the first
1,000 MW of full-scale demonstration units of each emerging technology.
Owners/operators of the units that are granted a commercial
demonstration permit would be exempt from the otherwise applicable
standards of subpart TTTT and would instead be subject to less
stringent emission standards. To encourage the continued development of
emerging technologies, standards should be set low enough to be
reasonably attainable, but stringent enough to ensure a minimum level
of CO2 emissions to protect human health and the
environment. Although there is some uncertainty on setting a precise
standard, the standards the EPA is considering would be 100 lb
CO2/MWh higher than the proposed standards for new and
reconstructed units using conventional technologies. The proposed
commercial demonstration permit standards would provide flexibility for
innovative and emerging technologies and ensure the NSPS does not
preclude the development of these technologies while at the same time
maintaining the emission standards for traditional control
technologies. The EPA is also soliciting comment on whether other
innovative emerging technologies should be included (Comment C-41).
Specifically, the Agency is interested in commenters' views with regard
to other innovative boiler designs, new materials that would allow for
the use of advanced ultra-supercritical steam conditions, supercritical
topping cycles, and alternate cooling technologies.
    The EPA selected these particular technologies for the following
reasons. Pressurized fluidized bed technology combines a pressurized
circulating fluidized bed boiler with a combustion turbine. This
combination essentially creates a coal-fired combined cycle power plant
and has the potential to improve the efficiency and reduce the
environmental impact (on both a criteria pollutant and GHG emissions
basis) of using coal to generate electricity. However, it is still a
relatively developing technology and has only been deployed on a
limited basis worldwide. Traditional coal-fired power plants use water
as the working fluid in a rankine cycle. Water is heated to create
steam that is then expanded through a steam turbine to generate
electricity. The use of alternate working fluids, such as supercritical
CO2, has the potential to increase the efficiency of
converting thermal energy to electricity. However, these systems have
not yet been fully demonstrated.
    Coal-fired power plants generate significant quantities of
relatively low-temperature heat (i.e., waste heat) that cannot be used
by the traditional rankine cycle. This heat is currently sent to the
power plant cooling system (e.g., cooling tower). If this energy could
be recovered to produce additional electricity, it could significantly
reduce the environmental impact of power generation. Thermoelectric
materials are materials that generate electricity due to temperature
differences across the material. Organic rankine cycle use working
fluids with boiler points lower than that of water and can generate
electricity from lower temperature sources of heat. Both of these
technologies have the potential to recover useful energy from the waste
heat from power plants, but neither has been fully demonstrated.
    Hybrid power plants combined multiple forms of power generation in
a single integrated system. The integration of solar thermal with
traditional fossil fuel-fired power plants has been demonstrated at
multiple facilities. A promising technology that could expand the
opportunities for additional hybrid fossil fuel-fired EGUs is the
integration of hybrid photovoltaic-solar thermal. Hybrid photovoltaic-
solar thermal first concentrates the solar energy onto photovoltaic
cells that convert a portion of that energy directly into electricity.
As a result of the concentrated solar energy, the photovoltaic cells
are heated, and additional useful thermal output energy is recovered
from the ``hot'' photovoltaic cells. This approach is potentially more
efficient than either standalone photovoltaic or solar thermal EGUs.
The recovered thermal energy from hybrid photovoltaic-solar thermal is
relatively low and has limited potential for direct integration into
the thermal cycle. However, it could potentially be integrated into
coal-fired power plants for boiler feedwater heating or the generation
of low pressure steam. However, the integration of hybrid photovoltaic-
solar thermal power has not been demonstrated on a fossil fuel-fired
EGU, so the efficiency gains cannot be estimated. A developer of a new
coal-fired EGU would therefore be unable to rely on this technology to
guarantee compliance with the NSPS until the technology is further
developed.
    At the utility level, energy storage devices have historically
provided improved power quality (i.e., frequency and voltage) and help
to manage the amount of power required to supply (i.e., generation) and
load (i.e., customers demand) during periods of peak power demand. With
the advent of increasing amounts of variable generation energy storage
technology can help integrate renewable energy efficiently into the
electric grid. Since renewable generation generally provides
electricity based on local conditions (e.g., when the wind is blowing
or the sun is shining) and is not dispatched by grid operators to
satisfy demand, large amounts of renewable generation can result in
excess power generation (i.e., grid oversupply) that results in
dispatchable generators operating in a non-optimal manner and
decreasing operating efficiency. Low-cost energy storage technologies
with high electricity-in to electricity-out round-trip efficiency \120\
could help to balance load and generation allowing for the integration
of additional renewable

generation while maintaining a dependable power supply and allowing for
the operation of dispatchable power plants at peak operating
efficiencies. A high round trip efficiency is necessary to assure that
the losses in the energy storage technology are less than the increase
in emissions that would result from operating the dispatchable fossil
fuel-fired EGUs under conditions that result in lower operating
efficiencies.
---------------------------------------------------------------------------

    \120\ Round-trip efficiency is the ratio of the energy recovered
from the energy storage device and the energy put into the device.
---------------------------------------------------------------------------

    Utility scale energy storage systems are classified into
mechanical, electrochemical, chemical, electrical, and thermal energy
storage systems. While some of these technologies are well demonstrated
(e.g., pumped storage), other novel technologies are still in
development. A developer installing a novel energy storage device to
allow the EGU to operate at closer to maximum efficiency would not be
able to guarantee the cycle efficiency or reliability of the energy
storage technology and would therefore not be able to rely on the
integration for compliance purposes. Demonstrating innovative energy
storage technologies could help address barriers reducing costs and
accelerating market acceptance.
    An owner or operator of a new or reconstructed coal-fired EGU who
wished to demonstrate a novel carbon capture technology could face
multiple difficulties in demonstrating continuous compliance. First,
novel carbon capture technologies by nature prevent quantitative
assessment of their continuous performance. If the capture system were
taken down for repair or modification, the entire facility might have
to be taken off line to assure continuous compliance. In addition, due
to the additional auxiliary load and increased stack emissions per MWh
of electricity generated, the captured CO2 would need to be
sequestered for the unit to demonstrate continuous compliance.
Sequestering relatively small amounts of CO2 could be
technically challenging and cost prohibitive, therefore limiting the
development of more cost-effective capture technologies. Without the
commercial demonstration permit provision, it would be difficult for an
owner/operator of a coal-fired EGU to support a CCS demonstration
project while still maintaining compliance with the NSPS emissions
standard.
    Allowing the Administrator to approve commercial demonstration
permits would limit regulatory impediments to improvements in GHG
reduction technologies. If the Administrator finds (in consultation
with DOE) that a given emerging technology (taking into consideration
all areas of environmental impact, including air, water, solid waste,
toxics, and land use) offers superior overall environmental
performance, permission to operate in compliance with alternative
standards could then be granted by the Administrator. A mere
modification of an existing demonstrated technology will not be viewed
as emerging technologies and will not be approved for a commercial
demonstration permit. The EPA is requesting comment on additional
technologies that should be considered, as well as the maximum
magnitude of the demonstration permits (Comment C-42). In particular,
the Agency is considering including DOE demonstration projects as
emerging technologies and potential candidates for the commercial
demonstration permit. This would assure that the NSPS would continue to
accommodate alternate technologies as they become available.

D. Applicability to Industrial EGUs

    In simple terms, the current applicability provisions require that
an EGU be capable of combusting over 250 MMBtu/h of fossil fuel and be
capable of selling 25 MW to a utility distribution system in order to
be subject to 40 CFR part 60, subpart TTTT. These applicability
provisions exclude industrial EGUs. However, since the affected EGU
includes ``integrated equipment that provides electricity or useful
thermal output,'' certain large processes might be included as part of
the EGU and meet the applicability criteria. For example, the high-
temperature exhaust from an industrial process (e.g., calcining kilns,
dryer, or metals processing) that consumes fossil fuel could be sent to
a heat recovery steam generator. If the industrial process is over 250
MMBtu/h heat input and the electric sales exceed the applicability
criteria, then the unit could be subject to 40 CFR part 60, subpart
TTTT. This is potentially problematic for multiple reasons. First, it
is difficult to determine the useful output of the EGU since part of
the useful output is included in the industrial process. In addition,
the fossil fuel that is combusted might have a relatively high
CO2 emissions rate on a lb/MMBtu basis, making it
problematic to meet the emissions standard. Finally, the compliance
costs associated with 40 CFR part 60, subpart TTTT could discourage the
development of environmentally beneficial projects.
    To avoid these outcomes, the EPA is soliciting comment on
amendments to the applicability provisions (Comment C-43). One option
the Agency considering is amending the provisions to include an
industrial unit exemption (Comment C-44). This exemption would apply to
any EGU where greater than 50 percent of the heat input is derived from
an industrial process that does not produce any electrical or
mechanical output or useful thermal output that is used outside the
affected EGU. In addition, the EPA soliciting comment on excluding
fuels that are combusted to comply with another EPA regulation (e.g.,
control of HAP emissions) from being considered a fossil fuel (Comment
C-45).
    The current approach owner/operators of CHP units use to calculate
net-electric sales and net energy output includes that ``at least 20.0
percent of the total gross or net energy output consists of electric or
direct mechanical output.'' It is unlikely that a CHP with a relatively
low electric output (i.e., less than 20 percent) would meet the
applicability criteria. However, if a CHP unit with less than 20
percent of the total output consisting of electricity were to meet the
applicability criteria, the net-electric sales and net energy output
would be calculated the same as for a traditional non-CHP EGU. Even so,
it is not clear that these CHP units would have less environmental
benefit per unit of electricity produced than more traditional CHP
units. The EPA is therefore soliciting comment on eliminating the
restriction that CHP produce at least 20 percent electrical or
mechanical output to qualify for the CHP specific method for
calculating net-electric sales and net energy output (Comment C-46).
    The current electric sales applicability exemption for non-CHP
steam generating units includes the provision that steam generating
units have ``always been subject to a federally enforceable permit
limiting annual net electric sales to one-third or less of their
potential electric output (e.g., limiting hours of operation to less
than 2,920 hours annually) or limiting annual electric sales to 219,000
MWh or less'' (emphasis added). The justification for this restriction
includes that the 40 CFR part 60 subpart Da applicability language
includes ``constructed for the purpose of . . .'' and the Agency
concluded that the intent was defined by permit conditions (80 FR
64544). This applicability criterion is important for determining
applicability with both the new source section 111(b) requirements and
if existing steam generating units are subject to the existing source
section 111(d) requirements. For steam generating units that commenced
construction after September 18, 1978, the applicability date of 40 CFR
part 60 subpart Da,

applicability would be relatively clear by what criteria pollutant NSPS
is applicable to the facility. However, for steam generating units that
commenced construction prior to September 18, 1978 or where the owner/
operator determined that criteria pollutant NSPS applicability was not
critical to the project (e.g., emission controls were sufficient to
comply with either the EGU or industrial boiler criteria pollutant
NSPS) owners/operators might not have requested an electric sales
permit restriction be included in the operating permit. Under the
current applicability language, some onsite steam generating unit
electric generators could be covered by the existing source section
111(d) requirements even if they have never sold electricity to the
grid. The EPA is soliciting comment on amending the electric sales
exemption to read have ``have never sold more than one-third of their
potential electric output or 219,000 MWh, whichever is greater, and are
always been subject to a federally enforceable permit limiting annual
net electric sales to one-third or less of their potential electric
output (e.g., limiting hours of operation to less than 2,920 hours
annually) or limiting annual electric sales to 219,000 MWh or less''
(emphasis added) (Comment C-47). EGUs that reduce current generation
would continue to be covered as long as they sold more than \1/3\ of
their potential electric output at some time in the past.

E. Non-Sequestration of Captured Carbon

    While carbon capture technology is not included in the proposed
BSER, the EPA recognizes that there are potential site-specific
situations where a developer elects to install carbon capture
technology. For example, a developer might wish to evaluate a
particular capture technology or to sell the captured CO2.
However, 40 CFR part 60, subpart TTTT as currently written requires
that captured CO2 be geologically sequestered or stored in a
different manner that is as effective as geologic sequestration.
Captured CO2 that is sold to the food industry would not
currently qualify for emission reduction because it results in near
term releases rather than in permanent sequestration. However, a
different situation can be envisioned in which the captured
CO2 could be considered to offset CO2 generated
specifically for the food industry and from a life cycle perspective it
would be as effective as sequestration at reducing emissions.
Therefore, to accommodate non geologic sequestration and to support the
effective utilization and management of CO2, the EPA is
soliciting comment on amending the second sentence of paragraph
60.555(g) to read ``To receive a waiver, the applicant must demonstrate
to the Administrator that its technology will store captured
CO2 as effectively as geologic sequestration or the CO2 will
be used as an input to an industrial process where the life cycle
emissions are reducing emissions as effective as geologic
sequestration, and that the proposed technology will not cause or
contribute to an unreasonable risk to public health, welfare, or
safety.'' (emphasis added) (Comment C-48)

F. Additional Amendments

    The EPA is soliciting comment on multiple less significant
amendments. These amendments either would be either strictly editorial
and would not change any of the requirements of subpart TTTT or are
intended to add additional compliance flexibility. For additional
information on these amendments, see the regulatory text track changes
technical support document. First, the EPA is considering editorial
amendments to define acronyms the first time they are used in the
regulatory text (Comment C-49). Second, the EPA is considering adding
International System of Units (SI) equivalent for owners/operators of
stationary combustion turbines complying with a heat input-based
standard (Comment C-50). Third, the EPA is considering fixing errors in
the current subpart TTTT regulatory text referring to part 63 instead
of part 60 (Comment C-51). Fourth, as a practical matter owners/
operators of stationary combustion turbines subject to the heat input-
based emissions standard need to maintain records of electric sales to
demonstrate that they are not subject to the output-based emissions
standard. Therefore, the EPA is soliciting comment on adding specific
requirement that owner/operators maintain records of electric sales to
demonstrate they did not sell electricity above the threshold that
would trigger the output-based standard (Comment C-52). Next, the EPA
is soliciting comment on if the ANSI, ASME, and ASTM test methods
should be updated to include more recent versions of the test methods
(Comment C-53). Finally, the EPA is soliciting comment on adding
additional compliance flexibilities for EGUs either serving a common
electric generator or using a common stack (Comment C-54).
Specifically, for EGUs serving a common electric generator should the
Administrator be able to approve alternate methods for determining
energy output? For EGUs using a common stack, the EPA is soliciting
comment on if specific procedures should be added for apportioning the
emissions and/or if the Administrator should be able to approve site
specific alternate procedures.

G. Non-Base Load Combustion Turbines

    As noted in the General Information section above, in the 2015
Rule, the EPA set separate standards for base load and non-base load
stationary combustion turbines. The electric sales threshold between
the two subcategories is based on the design efficiency of the
combustion turbine. Stationary combustion turbines qualify as non-base
load, and thus for a less stringent standard of performance, if they
have net electric sales equal to or below their design efficiency (not
to exceed 50 percent) multiplied by their potential electric output, 80
FR at 64,601 (e.g., a 40 percent efficient combustion turbine can sell
up to 40 percent of its potential electrical output), but if their
sales exceed that level, they are treated as base load and subject to a
more stringent standard of performance. For additional discussion on
this approach, see the 2015 Rule (80 FR 64609 to 64612).
    Recently, stakeholders have expressed concerns about this approach
for distinguishing between base load and non-base load turbines. They
posit a scenario under which increased utilization of wind and solar
resources, combined with low natural gas prices, would result in
certain types of simple cycle turbines being deemed attractive to
operate for a longer period of time than had been contemplated at the
time the 2015 Rule was being developed. Specifically, stakeholders have
observed that in some regional electricity markets with large amounts
of wind generation, some of the most efficient new simple cycle
turbines--aeroderivative turbines--could be called on to operate at
capacity factors greater than their design efficiency; however, if they
were to be operated at those higher capacity factors, they would become
subject to the more stringent standard of performance for base load
turbines, which they would not be able to meet. As a result, according
to these stakeholders, the owners or operators of the aeroderivative
turbines would have to curtail their generation and less efficient
turbines would be called on to run, which would result in higher
emissions.
    Although, as noted above, the EPA is not re-opening the standards
promulgated in the 2015 Rule for combustion turbines, the EPA is
soliciting comment on the concerns identified by stakeholders to
determine the extent of the potential issue

identified above and, if necessary, potential remedies. Specifically,
the EPA is soliciting information, including seeking supporting data
and documentation, on whether there have been, or are anticipated to
be, circumstances (e.g., high utilization of wind or solar resources or
low natural gas prices) in which simple cycle stationary combustion
aeroderivative turbines (i.e., those that are subject to standards of
performance in 40 CFR part 60 subpart TTTT) have been or may be called
upon to operate in excess of the non-base load threshold described in
the 2015 Rule (Comment C-55). The EPA is also requesting information on
whether, and the extent to which, these aeroderivative turbines are
different in design and operation than frame simple cycle turbines and
NGCC units, including fast start NGCC units (Comment C-56). The EPA is
also requesting information on the environmental consequences, if any,
of the aeroderivative combustion turbines having to forego continued
operation in such circumstances (e.g., is a more efficient turbine
being displaced by a higher emitting turbine or utility boiler?)
(Comment C-57). The EPA is also soliciting comment on remedies that the
Agency should consider, if necessary, to address this potential
concern. For example, should the EPA consider creating a separate
subcategory and standard of performance for simple cycle aeroderivative
turbines? Should the EPA consider changing the formula used to
calculate allowable operating hours for non-baseload combustion
turbines? Should the Agency consider creating a process by which owners
or operators could petition the EPA to increase the allowable operating
hours for non-baseload combustion turbines on a case-by-case basis if
they could demonstrate that, given the composition of the regional grid
they belong to, the increase would result in better overall
environmental outcome? (Comment C-58). The EPA will evaluate all
comments and any new information and, if warranted, will initiate a
subsequent rulemaking to address any issues raised from this
solicitation of comment.

X. Statutory and Executive Order Reviews

    Additional information about these statutes and Executive Orders
can be found at https://www.epa.gov/laws-regulations/laws-and-executive-orders.

A. Executive Order 12866: Regulatory Planning and Review and Executive
Order 13563: Improving Regulation and Regulatory Review

    This action is a significant regulatory action that was submitted
to the Office of Management and Budget (OMB) for review. Any changes
made in response to OMB recommendations have been documented in the
docket. The EPA prepared an economic impact analysis of the potential
costs and benefits associated with this action. This analysis is
contained in the Economic Impact Analysis for the Review of Standards
of Performance for Greenhouse Gas Emissions from New, Modified, and
Reconstructed Stationary Sources: Electric Utility Generating Units.
The economic impact analysis includes an illustrative analysis of the
potential difference in project-level costs of constructing a coal-
fired EGU under this proposed standard relative to the 2015 standard.

B. Executive Order 13771: Reducing Regulation and Controlling
Regulatory Costs

    This action is expected to be an Executive Order 13771 regulatory
action. There are no quantified cost estimates for this proposed rule
because the EPA does not anticipate this action to result in costs or
cost savings. For more information on this conclusion please see the
Economic Impact Analysis for the Review of Standards of Performance for
Greenhouse Gas Emissions from New, Modified, and Reconstructed
Stationary Sources: Electric Utility Generating Units.

C. Paperwork Reduction Act (PRA)

    This action does not impose any new information collection burden
under the provisions of the PRA. The information required by the rule
is already collected and reported by other regulatory programs. OMB has
previously approved the information collection activities contained in
the existing 40 CFR part 75 and 98 regulations and has assigned OMB
control numbers 2060-0626 and 2060-0629, respectively.

D. Regulatory Flexibility Act (RFA)

    I certify that this action will not have a significant economic
impact on a substantial number of small entities under the RFA. In
making this determination, the impact of concern is any significant
adverse economic impact on small entities. An agency mat certify that a
rule will not have a significant economic impact on a substantial
number of small entities if the rule relieves regulatory burden, has no
net burden, or otherwise has a positive economic effect on the small
entities subject to the rule. The EPA does not project any new,
modified, or reconstructed coal-fired electric utility steam generating
units. As such, this proposed rule would not impose significant
requirements on those sources, including any that are owned by small
entities. The EPA has, therefore, concluded that this action will have
no net regulatory burden for all directly regulated small entities.

E. Unfunded Mandates Reform Act (UMRA)

    This action does not contain an unfunded mandate of $100 million or
more as described in UMRA, 2 U.S.C. 1531-1538, and does not
significantly or uniquely affect small governments. This action is not
expected to impact state, local, or tribal governments.

F. Executive Order 13132: Federalism

    This action does not have federalism implications. It would not
have substantial direct effects on the states, on the relationship
between the national government and the states, or on the distribution
of power and responsibilities among the various levels of government.

G. Executive Order 13175: Consultation and Coordination With Indian
Tribal Governments

    This action does not have tribal implications, as specified in
Executive Order 13175. It would neither impose substantial direct
compliance costs on tribal governments, nor preempt Tribal law. The EPA
is aware of three coal-fired EGUs located in Indian Country, but is not
aware of any EGUs owned or operated by tribal entities. The EPA notes
that this action would only affect existing sources such as the three
coal-fired EGUs located in Indian Country, if those EGUs were to take
actions constituting modifications or reconstructions as defined under
the EPA's NSPS regulations. However, as previously stated, the EPA does
not project any new, reconstructed, or modified EGUs. Thus, Executive
Order 13175 does not apply to this action.
    The EPA will hold meetings with tribal environmental staff during
the public comment period to inform them of the content of this
proposal and will offer further consultation with tribal elected
officials where it is appropriate. The EPA specifically solicits
additional comment from tribal officials on this proposed rule.

H. Executive Order 13045: Protection of Children From Environmental
Health Risks and Safety Risks

    The EPA interprets Executive Order 13045 as applying only to those
regulatory actions that concern health or safety risks that the EPA has
reason to believe may disproportionately affect children, per the
definition of ``covered regulatory action'' in section 2-202 of the
Executive Order. This action is not subject to Executive Order 13045
because it does not concern an environmental health or safety risk.

I. Executive Order 13211: Actions Concerning Regulations That
Significantly Affect Energy Supply, Distribution, or Use

    This action is not a ``significant energy action'' because it is
not likely to have a significant adverse effect on the supply,
distribution, or use of energy. This proposed action is not anticipated
to have impacts on emissions, costs, or energy supply decisions for the
affected electric utility industry.

J. National Technology Transfer and Advancement Act (NTTAA)

    This action involves technical standards. Therefore, the EPA
conducted a search to identify potentially applicable voluntary
consensus standards (VCS). However, the Agency identified no such
standards. Therefore, the EPA has decided to continue to use technical
standard Method 19 of 40 CFR part 60, appendix A. The EPA invites the
public to identify potentially applicable VCS and to explain why such
standards should be used in this action (Comment C-59).

K. Executive Order 12898: Federal Actions To Address Environmental
Justice in Minority Populations and Low-Income Populations

    The EPA believes that this action does not have disproportionately
high and adverse human health or environmental effects on minority
populations, low-income populations, and/or indigenous peoples, as
specific in Executive Order 12898 (59 FR 7629, February 16, 1994),
because it does not affect the level of protection provided to human
health or the environment. As previously stated, the EPA does not
project any fossil fuel-fired electric utility steam generating units
would be affected by this action.

XI. Statutory Authority

    The statutory authority for this action is provided by sections
111, 301, 302, and 307(d)(1)(C) of the CAA as amended (42 U.S.C. 7411,
7601, 7602, 7607(d)(1)(C)). This action is also subject to section
307(d) of the CAA (42 U.S.C. 7607(d)).

List of Subjects in 40 CFR Part 60

    Environmental protection, Administrative practice and procedure,
Air pollution control, Intergovernmental relations, Reporting and
recordkeeping requirements.

    Dated: December 6, 2018.
Andrew R. Wheeler,
Acting Administrator.

    For the reasons set out in the preamble, title 40, chapter I, part
60 of the Code of Federal Regulations is proposed to be amended as
follows:

PART 60--Standards of Performance for New Stationary Sources

0
1. The authority citation for part 60 continues to read as follows:

    Authority: 42 U.S.C. 7401 et seq.

Subpart TTTT--[Amended]

0
2. Section 60.5509 is amended by revising paragraph (b)(2) to read as
follows:

Sec.  60.5509  Am I subject to this subpart?

* * * * *
    (b) * * *
    (2) Your EGU is capable of deriving 50 percent or more of the heat
input from non-fossil fuel at the base load rating and is also subject
to a federally enforceable permit condition limiting the annual
capacity factor for all fossil fuels combined of 10 percent (0.10) or
less.
* * * * *
0
3. Section 60.5520 is amended by revising paragraphs (a) and (c) to
read as follows:

Sec.  60.5520  What CO2 emissions standard must I meet?

    (a) For each affected EGU subject to this subpart, you must not
discharge from the affected EGU any gases that contain CO2
in excess of the applicable CO2 emission standard specified
in Table 1, 2, or 3 of this subpart, consistent with paragraphs (b),
(c), and (d) of this section, as applicable.
* * * * *
    (c) As an alternate to meeting the requirements in paragraph (b) of
this section, an owner or operator of an EGU may petition the
Administrator in writing to comply with the alternate applicable net
energy output standard. If the Administrator grants the petition,
beginning on the date the Administrator grants the petition, the
affected EGU must comply with the applicable net energy output-based
standard included in this subpart. Your operating permit must include
monitoring, recordkeeping, and reporting methodologies based on the
applicable net energy output standard. For the remainder of this
subpart, where the term ``gross or net energy output'' is used, the
term that applies to you is ``net energy output.'' Owners or operators
complying with the net output-based standard must petition the
Administrator to switch back to complying with the gross energy output-
based standard.
* * * * *
0
4. Section 60.5525 is amended by revising the introductory text, the
introductory text of paragraph (c), and paragraphs (c)(1)(i) and (ii),
(c)(2), and (c)(3) to read as follows:

Sec.  60.5525  What are my general requirements for complying with this
subpart?

    Combustion turbines qualifying under Sec.  60.5520(d)(1) are not
subject to any requirements in this section other than the requirement
to maintain fuel purchase records for permitted fuel(s). For all other
affected sources, compliance with the applicable CO2
emission standard of this subpart shall be determined on a 12-
operating-month rolling average basis. See Table 1, 2, or 3 of this
subpart for the applicable CO2 emission standards.
* * * * *
    (c) Within 30 days after the end of the initial compliance period
(i.e., no more than 30 days after the first 12-operating-month
compliance period), you must make an initial compliance determination
for your affected EGU(s) with respect to the applicable emissions
standard in Table 1, 2, or 3 of this subpart, in accordance with the
requirements in this subpart. The first operating month included in the
initial 12-operating-month compliance period shall be determined as
follows:
    (1) * * *
    (i) Section 60.5555(c)(3)(i), for units subject to the Acid Rain
Program; or
    (ii) Section 60.5555(c)(3)(ii)(A), for units that are not in the
Acid Rain Program.
    (2) For an affected EGU that has commenced commercial operation (as
defined in Sec.  72.2 of this chapter) prior to October 23, 2015:
    (i) If the date on which emissions reporting is required to begin
under Sec.  75.64(a) of this chapter has passed prior to October 23,
2015, emissions reporting shall begin according to Sec.
60.5555(c)(3)(i) (for Acid Rain program units), or according to Sec.
60.5555(c)(3)(ii)(B) (for units that are not subject to the Acid Rain
Program). The first month of the initial

compliance period shall be the first operating month (as defined in
Sec.  60.5580) after the calendar month in which the rule becomes
effective; or
    (ii) If the date on which emissions reporting is required to begin
under Sec.  75.64(a) of this chapter occurs on or after October 23,
2015, then the first month of the initial compliance period shall be
the first operating month (as defined in Sec.  60.5580) after the
calendar month in which emissions reporting is required to begin under
Sec.  60.5555(c)(3)(ii)(A).
    (3) For a modified or reconstructed EGU that becomes subject to
this subpart, the first month of the initial compliance period shall be
the first operating month (as defined in Sec.  60.5580) after the
calendar month in which emissions reporting is required to begin under
Sec.  60.5555(c)(3)(iii).
0
5. Section 60.5535 is amended by revising paragraphs (f) and (g) to
read as follows:

Sec.  60.5535   How do I monitor and collect data to demonstrate
compliance?

* * * * *
    (f) In accordance with Sec. Sec.  60.13(g) and 60.5520, if two or
more affected EGUs that implement the continuous emission monitoring
provisions in paragraph (b) of this section share a common exhaust gas
stack and are subject to the same emissions standard in Table 1, 2, or
3 of this subpart, you may monitor the hourly CO2 mass
emissions at the common stack in lieu of monitoring each EGU
separately. If you choose this option, the hourly gross or net energy
output (electric, thermal, and/or mechanical, as applicable) must be
the sum of the hourly loads for the individual affected EGUs and you
must express the operating time as ``stack operating hours'' (as
defined in Sec.  72.2 of this chapter). If you attain compliance with
the applicable emissions standard in Sec.  60.5520 at the common stack,
each affected EGU sharing the stack is in compliance.
    (g) In accordance with Sec. Sec.  60.13(g) and 60.5520 if the
exhaust gases from an affected EGU that implements the continuous
emission monitoring provisions in paragraph (b) of this section are
emitted to the atmosphere through multiple stacks (or if the exhaust
gases are routed to a common stack through multiple ducts and you elect
to monitor in the ducts), you must monitor the hourly CO2
mass emissions and the ``stack operating time'' (as defined in Sec.
72.2 of this chapter) at each stack or duct separately. In this case,
you must determine compliance with the applicable emissions standard in
Table 1, 2, or 3 of this subpart by summing the CO2 mass
emissions measured at the individual stacks or ducts and dividing by
the total gross or net energy output for the affected EGU.
0
6. Section 60.5540 is amended by revising the introductory text of
paragraph (a) and paragraph (b) to read as follows:

Sec.  60.5540   How do I demonstrate compliance with my CO2 emissions
standard and determine excess emissions?

    (a) In accordance with Sec.  60.5520, if you are subject to an
output-based emission standard or you burn non-uniform fuels as
specified in Sec.  60.5520(d)(2), you must demonstrate compliance with
the applicable CO2 emission standard in Table 1, 2, or 3 of
this subpart as required in this section. For the initial and each
subsequent 12-operating-month rolling average compliance period, you
must follow the procedures in paragraphs (a)(1) through (7) of this
section to calculate the CO2 mass emissions rate for your
affected EGU(s) in units of the applicable emissions standard (i.e.,
either kg/MWh or lb/MMBtu). You must use the hourly CO2 mass
emissions calculated under Sec.  60.5535(b) or (c), as applicable, and
either the generating load data from Sec.  60.5535(d)(1) for output-
based calculations or the heat input data from Sec.  60.5535(d)(2) for
heat-input-based calculations. Combustion turbines firing non-uniform
fuels that contain CO2 prior to combustion (e.g., blast
furnace gas or landfill gas) may sample the fuel stream to determine
the quantity of CO2 present in the fuel prior to combustion
and exclude this portion of the CO2 mass emissions from
compliance determinations.
* * * * *
    (b) In accordance with Sec.  60.5520, to demonstrate compliance
with the applicable CO2 emission standard, for the initial
and each subsequent 12-operating-month compliance period, the
CO2 mass emissions rate for your affected EGU must be
determined according to the procedures specified in paragraph (a)(1)
through (7) of this section and must be less than or equal to the
applicable CO2 emissions standard in Table 1, 2, or 3 of
this part, or the emissions standard calculated in accordance with
Sec.  60.5525(a)(2).
0
7. Section 60.5555 is amended by revising paragraph (a)(2)(v) to read
as follows:

Sec.  60.5555  What reports must I submit and when?

    (a) * * *
    (2) * * *
    (v) Consistent with Sec.  60.5520, the CO2 emissions
standard (as identified in Table 1, 2, or 3 of this part) with which
your affected EGU must comply; and
* * * * *
0
8. Section 60.5560 is amended by revising paragraph (f) to read as
follows:

Sec.  60.5560  What records must I maintain?

* * * * *
    (f) You must keep records of the calculations you performed to
assess compliance with each applicable CO2 mass emissions
standard in Table 1, 2, or 3 of this subpart.
* * * * *
0
9. Section 60.5580 is amended by revising the definitions for ``Base
load rating'' and ``Design efficiency,'' revising paragraph (2) of the
definition for ``Net-electric sales,'' and revising the definition for
``Violation'' to read as follows:

Sec.  60.5580  What definitions apply to this subpart?

* * * * *
    Base load rating means the maximum amount of heat input (fuel) that
an EGU can combust on a steady state basis plus the maximum amount of
heat input derived from non-combustion source (e.g., solar thermal), as
determined by the physical design and characteristics of the EGU at ISO
conditions. For a stationary combustion turbine, base load rating
includes the heat input from duct burners.
* * * * *
    Design efficiency means the rated overall net efficiency (e.g.,
electric plus useful thermal output) on a lower heating value basis at
the base load rating, at ISO conditions, and at the maximum useful
thermal output (e.g., CHP unit with condensing steam turbines would
determine the design efficiency at the maximum level of extraction and/
or bypass). Design efficiency shall be determined using one of the
following methods: ASME PTC 22 Gas Turbines (incorporated by reference,
see Sec.  60.17), ASME PTC 46 Overall Plant Performance (incorporated
by reference, see Sec.  60.17), ISO 2314 Gas turbines--acceptance tests
(incorporated by reference, see Sec.  60.17), or an alternative
approved by the Administrator.
* * * * *
    Net-electric sales means: * * *
    (2) For combined heat and power facilities where at least 20.0
percent of the total gross energy output consists of electric or direct
mechanical output and at least 20.0 percent of the total gross energy
output consists of useful thermal output on an annual basis, the gross
electric sales to the utility power distribution system minus the

applicable percentage of purchased power of the thermal host facility
or facilities. The applicable percentage of purchase power for CHP
facilities is determined based on the percentage of the total thermal
load of the host facility supplied to the host facility by the CHP
facility. For example, if a CHP facility serves 50 percent of a thermal
hosts thermal demand, the owner/operator of the CHP facility would
subtract 50 percent of the thermal hosts electric purchased power when
determining net-electric sales.
* * * * *
    Violation means a specified averaging period over which the
CO2 emissions rate is higher than the applicable emissions
standard located in Table 1, 2, or 3 of this subpart.
0
10. Re-designate Table 3 of Subpart TTTT of Part 60 as Table 4 of
Subpart TTTT of Part 60.
0
11. Revise the heading of Table 1 of Subpart TTTT of Part 60 to read as
follows:

Table 1 of Subpart TTTT of Part 60--CO2 Emission Standards for Affected
Steam Generating Units and Integrated Gasification Combined Cycle
Facilities That Commenced Construction After January 8, 2014, but
Before December 21, 2018, and Reconstruction or Modification After June
18, 2014, but Before December 21, 2018

    [Note: Numerical values of 1,000 or greater have a minimum of 3
significant figures and numerical values of less than 1,000 have a
minimum of 2 significant figures]
* * * * *
0
12. Add new Table 3 of Subpart TTTT of Part 60 to read as follows:

Table 3 of Subpart TTTT of Part 60--CO2 Emission Standards for Affected
Steam Generating Units and Integrated Gasification Combined Cycle
Facilities That Commenced Construction, Reconstruction, or Modification
After December 21, 2018 (Net Energy Output-Based Standards Applicable
as Approved by the Administrator)

    [Note: Numerical values of 1,000 or greater have a minimum of 3
significant figures and numerical values of less than 1,000 have a
minimum of 2 significant figures]

------------------------------------------------------------------------
              Affected EGU                    CO2 emission standard
------------------------------------------------------------------------
Newly constructed and reconstructed      910 kg CO2/MWh (2,000 lb CO2/
 steam generating unit or IGCC that has   MWh) of gross energy output;
 base load rating of 2,100 GJ/h (2,000    or 980 kg CO2/MWh (2,160 lb
 MMBtu/h) or less.                        CO2/MWh) of net energy output.
Newly constructed and reconstructed      870 kg CO2/MWh (1,900 lb CO2/
 steam generating unit or IGCC that has   MWh) of gross energy output;
 base load rating greater than 2,100 GJ/  or 940 kg CO2/MWh (2,070 lb
 h (2,000 MMBtu/h).                       CO2/MWh) of net energy output.
Newly constructed and reconstructed      1,000 kg CO2/MWh (2,200 lb CO2/
 steam generating unit or IGCC units      MWh) of gross energy output;
 that burn 75 percent or more (by heat    or 1,080 kg CO2/MWh (2,380 lb
 input) coal refuse on a 12-operating     CO2/MWh) of net energy output.
 month rolling average basis.
Modified steam generating unit or IGCC.  A unit-specific emission limit
                                          determined by the unit's best
                                          historical annual CO2 emission
                                          rate (from 2002 to the date of
                                          the modification); the
                                          emission limit will be no more
                                          stringent than:
                                         1. 910 kg CO2/MWh (2,000 lb CO2/
                                          MWh) of gross energy output;
                                          or 980 kg CO2/MWh (2,160 lb
                                          CO2/MWh) of net energy output
                                          for units with a base load
                                          rating of 2,100 GJ/h (2,000
                                          MMBtu/h) or less; or
                                         2. 870 kg CO2/MWh (1,900 lb CO2/
                                          MWh) of gross energy output;
                                          or 940 kg CO2/MWh (2,070 lb
                                          CO2/MWh) of net energy output
                                          for units with a base load
                                          rating of greater than 2,100
                                          GJ/h (2,000 MMBtu/h); or
                                         3. 1,000 kg CO2/MWh (2,200 lb
                                          CO2/MWh) of gross energy
                                          output; or 1,080 kg CO2/MWh
                                          (2,380 lb CO2/MWh) of net
                                          energy output for units that
                                          burn 75 percent or more (by
                                          heat input) coal refuse on a
                                          12-operating month rolling
                                          average basis.
------------------------------------------------------------------------

[FR Doc. 2018-27052 Filed 12-19-18; 8:45 am]
 BILLING CODE 6560-50-P


[Federal Register: June 21, 2007 (Volume 72, Number 119)]
[Notices]
[Page 34323-34325]
[DOCID:fr21jn07-73]

=======================================================================
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SECURITIES AND EXCHANGE COMMISSION

[Release No. 34-55913; File No. SR-Amex-2007-13]

Self-Regulatory Organizations; American Stock Exchange LLC; Order
Approving Proposed Rule Change as Modified by Amendment No. 1 Relating
to the Codification of Exchange Policy Regarding Specialist Commissions

June 15, 2007.

I. Introduction

    On January 29, 2007, the American Stock Exchange LLC (``Amex'' or
``Exchange'') filed with the Securities and Exchange Commission
(``Commission''), pursuant to Section 19(b)(1) of the Securities
Exchange Act of 1934 (``Act'') \1\ and Rule 19b-4 thereunder,\2\ a
proposed rule change to amend Amex Rule 154--AEMI and Amex Rule 154--
AEMI-One to expand the scope of its rules that specify when specialists
may charge commissions. The proposed rule change was published for
comment in the Federal Register on April 2, 2007.\3\ The Commission
received three comment letters regarding the proposal.\4\ On May 29,
2007, Amex filed Amendment No. 1 to the proposed rule change.\5\ This
order approves the proposed rule change, as modified by Amendment No.
1.
---------------------------------------------------------------------------

    \1\ 15 U.S.C. 78s(b)(1).
    \2\ 17 CFR 240.19b-4.
    \3\ See Securities Exchange Act Release No. 55533 (March 26,
2007), 72 FR 15733.
    \4\ See letters to Nancy M. Morris, Secretary, Commission, from
Samuel F. Lek, Lek Securities Corporation, dated April 26, 2007
(``Lek Letter''); from Jonathan Q. Frey, Managing Partner, J.
Streicher & Co. L.L.C., Brendan E. Cryan, Brendan E. Cryan and
Company, LLC, Robert B. Nunn, Cohen Specialists LLC, and Michael
Marchisi, AIM Specialists, dated April 17, 2007 (``Equity Specialist
Firms Letter''); and from Jerry O'Connell, Chief Regulatory Officer,
Susquehanna Investment Group, to, dated February 13, 2007
(``Susquehanna Letter'').
    \5\ In Amendment No. 1, Amex removed all references to Amex Rule
154--AEMI-One in the proposed rule change because the AEMI-One rules
have been replaced by the AEMI rules. This is a technical amendment
and is not subject to notice and comment.
---------------------------------------------------------------------------

II. Description

    The Exchange proposes to adopt Amex Rule 154-AEMI(k) to prohibit
specialists from charging a commission for orders or portions of orders
that have not been executed. The proposed rule would extend the
prohibitions on specialist commissions contained in Amex Rule 154(b) to
Exchange-Traded Funds (``ETFs'') and equities trading on the AEMI
System. These restrictions prohibit specialists from (i) charging a
commission on off floor orders that are electronically delivered to the
specialist except in cases of orders that require special handling by
the specialist or for which the specialist provides a service, and (ii)
billing customers for electronically delivered orders that are executed
automatically by the Exchange's order processing facilities upon
receipt. In addition, proposed Rule 154-AEMI(k) would reference Rule
152-AEMI(c), which prohibits specialists from charging a commission
where they act as principal in the execution of an order entrusted to
them as agent. Lastly, the proposed rule sets forth the types of orders
specialists would be allowed to bill a commission. These orders would
include: (i) Limit orders that remain on the book for more than two
minutes; (ii) tick sensitive orders (e.g., an order to sell short in a
security subject to the Commission's ``tick-test''); (iii) stop or stop
limit orders; (iv) fill-or-kill and immediate-or-

cancel orders; and (v) orders for the account of a competing market
maker.

III. Summary of Comments

    The Commission received three comment letters regarding the
proposed rule change. One comment letter, submitted by Lek Securities
Corporation, supported the proposed rule change, agreeing with the
Exchange's rationale for the proposed rule change.\6\ In this regard,
the commenter asserted that commissions on cancellations are
particularly harmful to fair and orderly markets'' and that
cancellation fees ``amount to a tax or toll on an instrumentality of
the exchange.'' \7\ This commenter also asserted that permitting a
specialist ``to bill for transactions that involve no work sanctions an
abuse of the specialist's privileged position.'' \8\
---------------------------------------------------------------------------

    \6\ See Lek Letter at 2.
    \7\ Id. at 2.
    \8\ Id. at 3.
---------------------------------------------------------------------------

    Another comment letter, submitted by a group of equity specialist
firms active on Amex, stated that they are not taking a position
regarding the ``substantive terms'' of the proposed rule change but,
rather, are expressing ``strong disagreement with the Exchange's stated
rationale'' for the proposed rule change.\9\ The specialist firms noted
that Amex's stated rationale for the proposed rule change is that
``specialist commissions weaken the Exchange's competitive position.''
\10\ The specialist firms suggested that, rather than focusing on
costs, the focus should be on whether specialists bring value in excess
of their costs.\11\ These specialist firms also suggested that it
``might be more productive for the Amex to focus on reducing its own
rather more significant costs rather than specialist commissions.''
\12\
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    \9\ See Equity Specialist Firms Letter at 1.
    \10\ Id. at 1-2.
    \11\ Id. at 2-4.
    \12\ Id. at 2.
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    The third comment letter, submitted by Susquehanna, opposed the
Exchange's proposal. Susquehanna, in particular, expressed concern
about the timing of the proposal, as it believed ``exponential
increases in order and cancel volume levels are expected with the
implementation of Regulation NMS.'' \13\ Susquehanna asserted that
these increased levels of volume on the Exchange could have a
significant impact on the ability of specialists to fulfill their
agency obligations.\14\ In this regard, Susquehanna asserted that the
Exchange should not eliminate the ability of specialists ``to charge
for providing agency functions'' until the Exchange determines whether
the increased order and cancel volume levels significantly affect the
ability of specialists to perform their agency obligations.\15\
Susquehanna also requested that ``[i]f this proposal is approved * * *
any specialist agency responsibility for orders and cancels on AEMI be
set forth so that the respective specialist is duly advised as to such
attendant obligations.'' \16\
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    \13\ See Susquehanna Letter at 1-2.
    \14\ Id. at 1-3.
    \15\ Id. at 2-4.
    \16\ Id. at 4.
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IV. Discussion

    The Commission has carefully reviewed the proposed rule change and
the comment letters received, and the Commission finds that the
proposed rule change is consistent with the requirements of Section 6
of the Act \17\ and the rules and regulations thereunder applicable to
a national securities exchange.\18\ In particular, the Commission finds
that the proposal is consistent with Section 6(b)(5) of the Act,\19\
because it is designed to promote just and equitable principles of
trade, to remove impediments to and perfect the mechanism of a free and
open market and a national market system, and, in general, to protect
investors and the public interest. The Commission also believes that
the proposed rule change is consistent with Section 11(A)(a)(1)(C) of
the Act \20\ which states that it is in the public interest and
appropriate for the protection of investors and the maintenance of fair
and orderly markets to assure, among other things, economically
efficient execution of securities transactions, and fair competition
among brokers and dealers, among exchange markets, and between exchange
markets and markets other than exchange markets.
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    \17\ 15 U.S.C. 78f.
    \18\ In approving this proposed rule change the Commission has
considered the proposed rule's impact on efficiency, competition,
and capital formation. 15 U.S.C. 78c(f).
    \19\ 15 U.S.C. 78f(b)(5).
    \20\ 15 U.S.C. 78k-1(a)(1)(C).
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    The Commission notes that it previously approved a substantially
similar Amex rule that prohibited specialist commissions for equities
traded on the Exchange's legacy system.\21\ The Exchange is now
proposing to: (i) Apply the prohibition on specialist commissions to
equities and ETFs traded on the AEMI System; (ii) expand the
prohibition on specialist commissions to market at the close orders and
limit at the close order; and (iii) specify that specialist commissions
can only be charged for orders that are executed and not for orders
that are cancelled or expire unexecuted. One commenter, Susquehanna,
expressed concern about the timing of the proposal in light of the
implementation of Regulation NMS.\22\ The Commission notes that Amex-
traded equities and ETFs have been trading on the AEMI System, which
the Exchange designed to comply with Regulation NMS, since February 5,
2007, a period of nearly four months. In response to Susquehanna's
request that it be advised of its specialist agency responsibilities
for orders and cancels on AEMI if the proposed rule change is
approved,\23\ the Commission notes that its approval of the proposed
rule change does not change a specialist's agency responsibilities
under the federal securities laws or agency law principles.
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    \21\ See Securities Exchange Act Release No. 55008 (December 22,
2006), 72 FR 597 (January 5, 2007) (Approval of amendment to Amex
Rule 154 regarding prohibition of specialist commissions for equity
orders). The Commission also approved a rule prohibiting specialist
commissions on options orders. See Securities Exchange Act Release
No. 51235 (February 22, 2005), 70 FR 9687 (February 28, 2005)
(Approval of CBOE Rule 8.85(b)(iv)). The New York Stock Exchange,
Inc. (``NYSE'') recently adopted a rule prohibiting specialists from
charging commissions on orders in their speciality securities. See
Securities Exchange Act Release No. 54850 (November 30, 2006), 71 FR
71217 (December 8, 2006) (Notice of Filing and Immediate
Effectiveness of Amendments to NYSE Rule 123B and Adoption of NYSE
Rule 104B).
    \22\ See Susquehanna Letter at 1-2.
    \23\ Id. at 4.
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    In addition, the Commission finds that the proposal is consistent
with Section 6(e)(1) of the Act,\24\ because it is not designed to
permit unfair discrimination between customers, issuers, brokers and
dealers, or to impose any schedule or fix rates of commissions,
allowances, discounts, or other fees to be charged by its members.
Section 6(e) of the Act \25\ was adopted by Congress in 1975 to
statutorily prohibit the fixed minimum commission rate system. As noted
on a report of the House of Representatives one of the purposes of the
legislation was to ``reverse the industry practice of charging fixed
rates of commission for transaction on the securities exchanges.'' \26\
The fixed minimum commission rate system allowed exchanges to set
minimum commission rates that their members had to charge their
customers, but allowed members to charge more. Amex's proposal, by
contrast, does not establish a minimum commission rate, but instead
prohibits the Exchange's specialists from charging a commission for
handling an equity

order that is executed on an opening or reopening or an equity order
(or portion thereof) that is executed against the specialist as
principal, or for the execution of an off-floor equities order
delivered to the specialist through the Exchange's electronic order
routing systems, subject to certain exceptions. Accordingly, the
Commission does not believe that the Amex's proposal constitutes fixing
commissions, allowances, discounts, or other fees for purposes of
Section 6(e)(1) of the Act.\27\ The Commission also notes that Amex's
limits on fees that specialists may charge applies only to members who
choose to be specialists on Amex. By limiting fees, the Amex is merely
imposing a condition, which is consistent with the Act, on a member's
appointment as a specialist.
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    \24\ 15 U.S.C. 78f(e)(1).
    \25\ U.S.C. 78f(e).
    \26\ H.R. Rep. No. 94-123, 94th Cong., 1st Sess. 42 (1975).
    \27\ 15 U.S.C. 78f(e)(1).
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V. Conclusion

    For the foregoing reasons, the Commission finds that the proposed
rule change is consistent with the Act and the rules and regulations
thereunder applicable to a national securities exchange, and, in
particular, with Sections 6(b)(5) and 6(e)(1) of the Act.\28\
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    \28\ 15 U.S.C. 78f(b)(5) and 78f(e)(1).
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    It is therefore ordered, pursuant to Section 19(b)(2) of the
Act,\29\ that the proposed rule change (SR-Amex-2007-13), as modified
by Amendment No. 1, is approved.
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    \29\15 U.S.C. 78s(b)(2).

    For the Commission, by the Division of Market Regulation,
pursuant to delegated authority.\30\
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    \30\ 17 CFR 200.30-3(a)(12).
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Florence E. Harmon,
Deputy Secretary.
[FR Doc. E7-12015 Filed 6-20-07; 8:45 am]

BILLING CODE 8010-01-P