each of the Transport Rule trading programs.
    Under the general applicability provisions of the proposed rule,
the Transport Rule trading programs would cover fossil-fuel-fired
boilers and combustion turbines serving--on any day starting November
15, 1990 or later--an electrical generator with a nameplate capacity
exceeding 25 MWe and producing power for sale, with the exception of
certain cogeneration units and solid waste incineration units.
    EPA requested comment on whether a more recent year should be used
instead. The proposed use of the November 15, 1990 date was consistent
with the use of 1990 as the beginning of the historical period for
which owners and operators would generally be required to have
information about their units for purposes of determining whether the
units were covered by the Transport Rule trading programs. Because unit
information is generally compiled and retained on a calendar year
basis, EPA believes that, for the general applicability provisions, it
is preferable to use January 1, rather than November 15. In determining
which

year should be used as the reference year in the general applicability
provisions, EPA considers several factors.
    First, in order for owners and operators, and EPA, to be able to
determine which units are subject to the Transport Rule trading
programs, EPA believes that the reference year should not be so far in
the past that the unit information necessary to make applicability
determinations is not readily available. This particularly becomes an
issue in cases of older units that have changed ownership over time.
EPA found, in making some applicability determinations under the CAIR
trading programs, that some older units with ownership changes had
difficulty obtaining information back as far as twenty or more years.
Using January 1, 1990 as the reference date in the general
applicability provisions could effectively require some owners and
operators to retain unit information going back as far as 20 years. As
a point of contrast, under the title V permitting rules, owners and
operators are generally required to retain data for 5 years. See 40 CFR
70.6(a)(3)(B).
    Second, EPA also believes that the reference year used in the
applicability provisions should be far enough in the past that the unit
information on which applicability determinations are based provides a
full picture of the nature of the unit and its operations over time,
such as the types of fuels combusted at the unit and whether the unit
has produced electricity for sale.
    Third, EPA considers whether selecting a different reference year
for the applicability provisions than the one in the proposed rule
dramatically changes what units will be covered by the Transport Rule
trading programs. In this case, EPA believes, based on available
information about the units potentially subject to the Transport Rule,
that using a somewhat later year than the one in the proposed rule will
likely have little effect on what units are covered. Balancing these
factors, EPA concludes that it is reasonable to use January 1, 2005,
rather than November 15, 1990, in the general applicability provisions
in the final rule.
    In the final rule, EPA is taking the same approach with regard to
defining whether a boiler or combustion turbine is considered to be
``fossil-fuel-fired'' as the one used in the proposal. Under the
proposed rule, a unit was considered to be ``fossil-fuel-fired'' if it
combusts any amount of fossil fuel at any time in 1990 or later. For
the same reasons that EPA decided to use January 1, 2005 in the general
applicability provisions, and in order to have a consistent reference
year in all applicability-related provisions, the final rule defines a
``fossil-fuel-fired'' unit as one that combusts any amount of fossil
fuel in 2005 or later.
    EPA notes that the final Transport Rule allows a state to submit a
SIP revision (an abbreviated or full SIP) under which the state may--in
addition to making certain types of changes concerning allowance
allocations in the Transport Rule trading programs--expand the general
applicability provisions of the Transport Rule NOX Ozone
Season Trading Program to cover fossil-fuel-fired boilers and
combustion turbines serving--at any time starting January 1, 2005 or
later-- a generator with a nameplate capacity as low as 15 MWe
producing power for sale. The exemptions, discussed below, for
cogeneration units and solid waste incineration units still will
continue to apply.
    Cogeneration unit exemption. Under the final rule (as well as the
proposed rule) certain cogeneration units or solid waste incinerators
are exempt from the FIP requirements. In particular, the final rule
includes an exemption for a unit that qualifies as a cogeneration unit
throughout the later of 2005 or the first 12 months during which the
unit first produces electricity and continues to qualify through each
calendar year ending after the later of 2005 or that 12-month period
and that meets the limitation on electricity sales to the grid. In
order to meet the definition of ``cogeneration unit'' in the final
rules, a unit (i.e., a fossil-fuel-fired boiler or combustion turbine)
must be a topping-cycle or bottoming-cycle that operates as part of a
``cogeneration system,'' which is defined as an integrated group of
equipment at a source (including a boiler, or combustion turbine, and a
steam turbine generator) designed to produce useful thermal energy for
industrial, commercial, heating, or cooling purposes and electricity
through the sequential use of energy. A topping-cycle unit is a unit
where the sequential use of energy results in production of useful
power first and then, through use of reject heat from such production,
in production of useful thermal energy. A bottoming-cycle unit is a
unit where the sequential use of energy results in production of useful
thermal energy first and then, through use of reject heat from such
production, in production of useful power. In order to qualify as a
cogeneration unit, a unit also must meet certain efficiency and
operating standards.
    In the proposed rule, a unit would have to qualify as a
cogeneration unit and meet the limitation on electricity sales starting
the later of 1990 or the year when the unit begins operating. EPA
requested comment on whether a more recent year should be used. For the
reasons discussed above concerning the reference year used in the
general applicability provisions and in order to have a consistent
reference year in all applicability-related provisions, EPA concludes
that it is reasonable to use 2005, rather than 1990, in the
cogeneration unit exemption provisions in the final rule. Consequently,
the final rule provides that the requirements to qualify as a
cogeneration unit and to meet the electricity sales limitation start no
earlier than 2005.
    In the final rule, EPA also clarifies that the electricity sales
limitation under the exemption is applied in the same way whether a
unit serves only one generator or serves more than one generator. In
both cases, the total amount of electricity produced annually by a unit
and sold to the grid cannot exceed the greater of one-third of the
unit's potential electric output capacity or 219,000 MWhr. This is
consistent with the approach taken in the Acid Rain Program (40 CFR
72.7(b)(4)), where the cogeneration unit exemption originated. EPA
believes that this clarification is needed to ensure that a unit
serving, for example, two generators would not have a limit on sales of
electricity to the grid that would be different (i.e., twice as high)
from the limit for a unit serving only one generator with the same
total nameplate capacity as the first unit's two generators.
    EPA also took comment on whether efficiency standards should be
applied on a system-wide basis to bottoming-cycle units (where useful
thermal energy is produced before useful power is produced), as they
are for topping-cycle units (where useful thermal energy is produced
after useful power) and whether to exclude, from the requirement to
meet the operating and efficiency standards, calendar years during
which a cogeneration unit does not operate at all. Several commenters
argued EPA should apply efficiency standards to both types of units.
EPA agrees that applying efficiency standards on a system-wide basis to
both bottoming-cycle and topping-cycle units is reasonable because EPA
sees no technical reason to distinguish between the two types of units
in this instance. EPA further agrees with commenters that excluding
calendar years in which the cogeneration unit does not operate at all,
i.e., does not combust any fuel, from the requirements to meet
operating and efficiency standards is also reasonable. For such a year,
the unit would not produce any useful thermal

energy or useful power and therefore could not meet the minimum output
requirements in the operating and efficiency standards, but the unit
also would not have any emissions. For these reasons, the final rule
expressly provides that the operating and efficiency standards do not
have to be met for a calendar year throughout which a unit did not
operate at all.
    Solid waste incineration unit exemption. The final rule also
includes an exemption for a unit that qualifies as a solid waste
incineration unit during the later of 2005 or the first 12 months
during which the unit first produces electricity, that continues to
qualify throughout each calendar year ending after the later of 2005 or
that 12-month period each year thereafter, and that meets the
limitation on fossil-fuel use. In contrast, the exemption for solid
waste incineration units in the proposed rule distinguished between
units commencing operation before January 1, 1985 and those commencing
operation on or after that date. A unit commencing operation before
January 1, 1985 would be exempt if it qualified as a solid waste
incineration unit starting the later of 1990 or the year when it began
producing electricity and its average annual fuel consumption of non-
fossil fuels exceeded 80 percent of total heat input during 1985-1987
and during any three consecutive calendar years after 1990. A unit
commencing operation on or after January 1, 1985 would be exempt if it
qualified as a solid waste incineration unit starting the later of 1990
or the year when it began producing electricity and its average annual
fuel consumption of non-fossil fuel exceeded 80 percent of total heat
input for the first 3 calendar years of operation and for any 3
consecutive calendar years thereafter.
    In the proposal, EPA requested comment on whether it would be
problematic to obtain sufficiently detailed information about unit
operation potentially as far back as 1985-1987 and 1990, and whether
the fuel consumption standard for each unit should be limited to more
recent years. For the reasons discussed above concerning the reference
year used in the general applicability provisions and in order to have
a consistent reference year for all applicability-related provisions,
EPA concludes that it is reasonable to use 2005, rather than 1990, in
the solid waste incineration unit exemption in the final rule. In
particular, EPA notes that the proposed provisions for units commencing
operation before January 1, 1985 and for units commencing operation on
or after January 1, 1985 could require some owners and operators to
retain unit information going back more than 20 years before the
promulgation of this final rule. Further, EPA believes that removing
the distinction between units commencing operation during these two
periods, and referencing somewhat later years as the earliest years for
which information on fossil-fuel consumption is required, will result
in the exemption still being based on sufficient data to provide a full
picture of the nature and operation of the units involved. EPA also
believes, based on available information about the units potentially
subject to the Transport Rule, that this approach will not
significantly change which units qualify for the exemption.
Consequently, the final rule removes the distinction based on whether a
solid waste incineration unit commences operation before January 1,
1985 or on or after January 1, 1985. In order to be exempt, the unit
must qualify as a solid waste incineration unit during the later of
2005 or the first 12 months during which the unit first produces
electricity, must continue to qualify throughout each calendar year
ending after the later of 2005 or that 12-month period, and must meet
the limitation on fossil-fuel use on a 3-year average basis during the
first 3 years of operation starting no earlier than 2005 and every 3
years of operation thereafter.
    Opt-in units. EPA is not finalizing the opt-in provisions that were
discussed in the Transport Rule proposal. EPA proposed opt-in
provisions to allow non-covered units to voluntarily opt in to any of
the proposed Transport Rule trading programs and receive allocations
reflecting 70 percent of the unit's emissions before opting in. These
allowances were above the state-specific budgets developed under the
Transport Rule to eliminate a state's significant contribution to
nonattainment and interference with maintenance. In theory, an opt-in
unit that makes reductions below its baseline and sells the freed-up
allowances is effectively substituting its new, lower-cost reductions
for higher-cost reductions otherwise required by a covered EGU, with
the result that the state's significant contribution is still
eliminated but at a lower total program cost.
    EPA notes that theoretical benefits anticipated from allowing opt-
ins did not materialize in prior trading programs with opt-in
provisions. The Acid Rain Program has about 23 opt in units; the
NOX Budget Trading Program had five opt-in units; and no
units opted into the CAIR programs. As a group, these opt-in units
neither eased the achievement of required emission reductions in past
trading programs, nor reduced overall program costs.
    In the proposal, EPA requested comment on the opt-in provisions,
specifically regarding: What are the benefits of and concerns about
including opt-in provisions; how to ensure units are not credited for
emission reductions the units would have made anyway; whether the
proposed 30 percent reduction (i.e., application of the 70 percent
multiplier to baseline emissions) or some other percentage reduction,
or no reduction, should be applied to the baseline emission rate used
in determining allocations; and whether any additional percentage
reduction (such as 45 percent) should be applied to SO2
Group 1 opt-in units in Phase II to reflect the stricter limits for
covered units.
    Some commenters argued that increasing the Transport Rule budgets
for opt-ins would undermine the goal of CAA section 110(a)(2)(D)(i)(I)
to eliminate a state's significant contribution to nonattainment and
interference with maintenance. One commenter stated that it does not
favor allowing sources that are not subject to the emission reduction
requirements to be issued allowances that would increase the overall
state emission budgets, due to the uncertainty that any reductions made
by such units would be surplus, verifiable, permanent and enforceable.
This could compromise the integrity of the EGU emission reduction
requirements of the Transport Rule and jeopardize assurance that a
state's significant contribution would be eliminated, as required by
the Court in North Carolina. Other commenters claim that, while no
cheap tons are available from non-EGUs and EPA is right not to require
non-EGU reductions, EPA should nonetheless allow non-EGUs to choose
voluntarily to be covered by opting in.
    As mentioned previously, the final Transport Rule does not include
any opt-in provisions either in the FIPs or in the provisions allowing
modification or replacement of the FIPs through submission of trading
program provisions in SIPs. EPA has several reasons for not adopting
provisions to allow opt-in units. First, as mentioned above,
historically, very few units have opted in. As of 2010, 28 units out of
more than 4,700 covered units (23 units out of a total of about 3,600
covered units in the Acid Rain Program and 5 units out of a total of
about 2,600 covered units in the NOX SIP Call) have opted in
to EPA trading programs over the past 15 years. In the Acid Rain
Program, 3 of the units opted in and

then, effective for 2005, opted out. Four of the units opted in,
immediately shut down, and continue to receive allowance allocations.
Four of the units opted in and continue to operate and receive
allowance allocations. Finally, 12 of the units opted in, after CAIR
was finalized, in order to receive allowances usable for compliance in
the CAIR SO2 trading program. Because CAIR will be replaced
by this Transport Rule, EPA anticipates that these 12 units will opt
out of the Acid Rain Program. In the NOX Budget Trading
Program, 3 plants with 5 opt-in units received allocations between 2003
and 2008.
    Moreover, EPA has determined that the inclusion of opt-in units in
the Transport Rule trading programs would undermine the rule's
objective of addressing emissions in each state that significantly
contribute to nonattainment or interfere with maintenance in other
states. As explained above, EPA has established budgets plus
variability limits that states must meet to ensure that the significant
contribution to nonattainment and interference with maintenance
identified by EPA is addressed. If EPA were to allow opt-ins, and if
any opt-in unit were to receive an allocation of allowances for
emissions that would be reduced even if the units did not opt in, then
the inclusion of that opt-in unit in the program would allow the
sources covered by the Transport Rule to emit in excess of the budget
plus variability limit with no new, offsetting reduction in emissions.
For example, after a unit would opt in, process or fuel changes made
for economic reasons (rather than due to any regulatory requirements),
or installation of new emission controls or fuel-switching conducted to
meet future, non-Transport Rule regulatory requirements, could result
in emission reductions that would have occurred ``anyway'' (i.e., even
if the unit had not opted in), and the opt-in unit would be allocated
allowances for the portion of its baseline emissions that would be
removed by these ``anyway'' reductions. Allocations above the cap to
opt-in units making ``anyway'' emission reductions would convert these
reductions into extra allowances (i.e., authorizations to emit) usable
by covered EGUs to meet their requirements to hold allowances for
emissions. Because the extra EGU emissions authorized by these extra
allowances would not be offset by any new emission reductions by the
opt-in units, this could threaten a state's ability to eliminate the
significant contribution to nonattainment and interference with
maintenance identified by EPA in the final rule. Also, opt-in units,
which are allocated allowances outside the state budget for covered
units, could increase the possibility that a state's total emissions
would exceed the state budget plus variability and thus that the
assurance provisions would be triggered.
    This problem of allocating allowances for emissions that would have
been reduced anyway is illustrated by the recent promulgation of the
final rule, National Emission Standards for Hazardous Air Pollutants
for Major Sources: Industrial, Commercial, and Institutional Boilers
and Process Heaters (76 FR 15608 (March 21, 2011)) (``final Boiler MACT
rule''), which requires certain industrial, commercial, and
institutional boilers to meet maximum achievable control technology
(MACT) standards for emissions of specified hazardous air pollutants,
such as hydrogen chloride (HCL) and mercury (Hg). Some of the control
technologies that can be used to meet these standards will also provide
significant reductions of SO2 emissions. For example, a
boiler may use a wet scrubber or the combination of a dry sorbent
injection system and a fabric filter (among other options) to meet the
applicable HCL standard or may use a wet scrubber or a combination of
activated carbon injection and a fabric filter (among other options) to
meet the applicable Hg standard. See 76 FR 15614 (describing testing
and compliance requirements when such controls are used to meet these
standards); and Memo from Brian Shrager to Amanda Singleton and Graham
Gibson, Revised Methodology for Estimating Cost and Emissions Impacts
for Industrial, Commercial and Institutional Boilers and Process
Heaters National Emissions Standards for Hazardous Air Pollutants--
Major Source (February 11, 2011), Document ID EPA-HQ-OAR-2009-0491-4036
(section 3.1, describing control options for HCL and Hg control). In
fact, EPA estimated that the new standards would result in emission
reductions of not only the hazardous air pollutants directly subject to
the standards, but also in other air pollutants such as SO2.
Specifically, EPA projected that compliance with the final Boiler MACT
rule standards will result in about 431,000 tons of annual
SO2 reductions from existing boilers subject to the final
Boiler MACT rule. This will comprise on average about a 46 percent
reduction in SO2 emissions for this group of boilers. Coal-
and oil-fired boilers--which are the boilers likely to have the most
uncontrolled SO2 emissions and so would be the most likely
types of units to consider opting into the Transport Rule trading
programs if opting-in were allowed--are projected to reduce about
409,000 tons of annual SO2 as a result of complying with the
final Boiler MACT rule, or about a 50 percent reduction in
SO2 emissions. See Memo from Brian Shrager to Amanda
Singleton and Graham Gibson, Appendix B-1, (where column CE represents
baseline SO2 emissions and column CH represents
SO2 reductions resulting from the final Boiler MACT rule
compliance). The amount of offsetting SO2 increases
projected to result from final Boiler MACT rule compliance, e.g., from
additional fuel being combusted to generate electricity to operate
emission controls, is minor. See 76 FR 15651 (Table 4) and 15653
(showing projected total SO2 reductions for all boilers and
process heaters of about 442,000 tons and net SO2 reductions
of about 440,000 tons).
    Consequently, a boiler subject to the final Boiler MACT rule may
install a wet acid gas scrubber or a bag house in order to meet the HCL
or Hg standard applicable to boilers under the final Boiler MACT rule
and thereby achieve SO2 emission reductions. If that boiler
were to opt in to one of the Transport Rule SO2 trading
programs during the year before installing these controls to comply
with the final Boiler MACT rule, then the boiler would be allocated
allowances for the unit's current tons of SO2 emissions and
would not need to use these allowances for compliance under the
Transport Rule once the final Boiler MACT-related controls were
installed. The allowances allocated to the boiler would be additional
allowances above the Transport Rule trading budget for the state where
the boiler was located. As a result, the boiler would have freed-up
allowances above the state trading budget that represent reductions
that the boiler would have made anyway (i.e., even if the boiler had
not opted in) and that could be sold to EGUs covered by the Transport
Rule. In effect, the opting-in of the boiler would result in the
conversion of the boiler's SO2 reductions from the final
Boiler MACT rule into increased emissions above the state trading
budget from EGUs subject to the Transport Rule.
    Commenters addressed this issue. For instance, one commenter
suggested that SO2 reductions made by a boiler under the
final Boiler MACT rule should be eligible for opt-in provision
allowances under the Transport Rule trading programs. Another commenter
stated that, given the uncertainty that reductions made by opt-in units
would be surplus, verifiable, permanent, and enforceable, opt-in
provisions could

compromise the integrity of the EGU emission reductions.
    For the reasons explained above, EPA agrees with the latter
commenter. Further, EPA notes that none of the commenters supporting
adoption of the opt-in provisions suggested any revision to the
proposed opt-in provisions that would address this problem. While the
proposed opt-in provisions would limit an opt-in unit's allocation for
a control period by calculating the allocation using the lesser of the
unit's pre-opt-in SO2 emission rate or the most stringent
SO2 emission rate applicable in that control period, this
would not address SO2 rate reductions that are not directly
required by the final Boiler MACT rule but that are a secondary result
of using and operating certain emission controls installed to comply
with the HCL or Hg standards under the final Boiler MACT rule. Because
the secondary SO2 reductions will vary depending on the type
of controls installed and on the extent to which the controls are used,
and a boiler may use a combination of emission controls and other
approaches to reduce HCL or Hg emissions (such as fuel switching), EPA
believes that it is highly unlikely that opt-in provisions could
prevent allocation for ``anyway'' emission reductions resulting from
compliance with the final Boiler MACT rule. EPA therefore believes that
the final Boiler MACT rule provides a concrete example of why adoption
of opt-in provisions could undermine the rule's objective of addressing
emissions in each state that significantly contribute to nonattainment
or interfere with maintenance in other states. EPA notes that the final
Boiler MACT rule, of course, is simply one example of how allocations
for ``anyway'' reductions could occur and undermine the statutory
requirements of the Transport Rule.

C. Compliance Deadlines

1. Alignment With NAAQS Attainment Deadlines
    The compliance dates in the final Transport Rule are aligned with
the attainment deadlines for the relevant NAAQS and consistent with the
charges given to EPA by the Court in North Carolina. EPA proposed to
require, and the final rule requires, compliance by 2014 with an
initial phase of reductions in 2012.\57\ Sources are required to comply
with annual SO2 and NOX requirements by January
1, 2012 and January 1, 2014 for the first and second phases,
respectively. Similarly, sources are required to comply with ozone-
season NOX requirements by May 1, 2012, and by May 1, 2014.
In selecting these dates, EPA was mindful of the NAAQS attainment
deadlines which require reductions as expeditiously as practicable and
no later than specified dates (see 42 U.S.C. 7502(a)(2)(A) (general
attainment dates); 42 U.S.C. 7511(a)(1) (attainment dates for ozone
nonattainment areas)), and also mindful of the court's instruction to
``decide what date, whether 2015 or earlier, is as expeditious as
practicable for states to eliminate their significant contributions to
downwind nonattainment.'' North Carolina, 531 F.3d at 930.
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    \57\ For the annual programs, sources are required to have, by
March 1, 2013, sufficient allowances in their accounts to cover
their 2012 emissions. For the ozone-season program, they must have
allowances in their accounts by December 1, 2012 to cover 2012
ozone-season emissions. The state budgets which determine the number
of allowances allocated to units in each state become more stringent
for some states in 2014.
---------------------------------------------------------------------------

    1997 PM2.5 NAAQS Attainment Deadlines. For all areas
designated as nonattainment with respect to the 1997 PM2.5
NAAQS, the deadline for attaining that standard is as expeditious as
practicable but no later than April 2010 (5 years after designation),
with a possible extension to no later than April 2015 (10 years after
designation).\58\ Many areas have already come into attainment by the
April 2010 deadline due in part to reductions achieved under CAIR. The
fact that the 2010 deadline will have passed before the Transport Rule
is finalized emphasizes the importance of obtaining reductions as
expeditiously as practicable. In addition, reductions achieved in
upwind states by the 2014 emissions year will help downwind states
demonstrate attainment by the April 2015 deadline.
---------------------------------------------------------------------------

    \58\ Section 172(a)(2) of the Clean Air Act provides that the
attainment dates for areas designated nonattainment with a NAAQS
shall be the date by which attainment can be achieved as
expeditiously as practicable, but no later than 5 years from the
date of designation. This section also allows the Administrator to
extend the attainment date to the extent she determines appropriate,
for a period no greater than 10 years from the date of designation
as nonattainment, considering the severity of nonattainment and the
availability and feasibility of pollution control measures.
Designations for the 1997 PM2.5 NAAQS became effective on
April 5, 2005. Designations for the 2006 24-hour PM2.5
NAAQS became effective on December 14, 2009.
---------------------------------------------------------------------------

    2006 PM2.5 NAAQS Attainment Deadlines. For all areas
designated as nonattainment with respect to the 2006 24-hour
PM2.5 NAAQS, the attainment deadline must be as expeditious
as practicable but no later than December 2014. Areas that fail to meet
that deadline can request an extension to as late as December 2019.
    Upwind emission reductions achieved by the 2014 emissions year will
help meet the December 2014 attainment deadline. In addition, the first
phase of reductions in 2012 will help many areas attain in a more
expeditious manner.
    Further, a deadline of January 1, 2014 also provides adequate and
reasonable time for sources to plan for compliance with the Transport
Rule and install any necessary controls. EPA believes that this
deadline is as expeditious as practicable for the installation of the
controls, if any, needed for compliance with the 2014 state emission
budgets. (See further discussion in section V.C.2.)
    1997 Ozone NAAQS Attainment Deadlines. Ozone nonattainment areas
must attain permissible levels of ozone ``as expeditiously as
practicable,'' but no later than the date assigned by EPA in the ozone
implementation rule. 40 CFR 51.903. The areas designated nonattainment
in 2004 with respect to the 1997 8-hour ozone NAAQS in the eastern
United States were assigned maximum attainment dates effectively
corresponding to the end of the 2006, 2009, and 2012 ozone seasons. The
maximum attainment deadlines for the 1997 standard run from the June
15, 2004 effective date of designation for that standard. The time
periods are based on the time periods provided for these
classifications in section 181 of the Act, 45 U.S.C. 7511(a). However,
instead of running from the 1990 date of enactment of the CAA as
specified in section 181, our regulation provides that they run from
the date of designation. An area's maximum attainment date is based on
its nonattainment classification--that is, whether it is classified as
a marginal, moderate, serious, severe, or extreme ozone nonattainment
area. Marginal areas have three years from designation to attain the
standard. Moderate, serious, severe, and extreme areas have 6, 9, 15,
and 20 years, respectively. The maximum attainment deadlines associated
with the 1997 ozone standards are June 15, 2007 for marginal areas,
June 15, 2010 for moderate areas, and June 15, 2013 for serious areas.
Because the actual deadline occurs in the middle of an ozone season,
data from that ozone season is not considered when determining whether
the area has attained by the deadline. Thus, these maximum attainment
deadline dates effectively correspond with the end of the 2006, 2009,
and 2012 ozone seasons. Reductions achieved or air quality improvements
realized after those dates will not help the areas meet their maximum
attainment deadlines.
    Many areas have already attained the standard due in part to CAIR,
federal

mobile source standards, and other local, state, and federal measures.
Other areas, however, have been reclassified to a higher classification
either because they failed to attain by their attainment date or
because the state requested reclassification to avoid missing an
attainment date. Those that have not yet attained the standard now have
maximum attainment dates ranging from June 2011 (these are the moderate
areas that have been granted a 1-year extension due to clean data for
the 2009 ozone season) to June 2024. The areas classified as
``serious'' nonattainment areas have a June 2013 maximum attainment
deadline. Areas that missed their earlier deadlines and have been
reclassified as ``severe'' or ``extreme'' nonattainment areas now have
maximum nonattainment deadlines of June 2019 and June 2024
respectively. As explained above, an area with a June 2013 deadline
would need to attain based on ozone data from the 2010-2012 ozone
seasons, an area with a June 2019 deadline would need to attain based
on ozone data from the 2016-2018 ozone seasons, and an area with a June
2024 deadline would need to attain based on ozone data from the 2021-
2023 ozone seasons.
    The Transport Rule's first phase of reductions in 2012 will help
the remaining areas with June 2013 maximum attainment deadlines attain
the 1997 8-hour ozone NAAQS by their deadline. If EPA determines that
an area failed to attain by the 2013 deadline, the area would be
reclassified to severe and would be subject to the more stringent
emission control requirements that apply to the severe classification.
The reductions will also help areas with later deadlines attain as
expeditiously as practicable and improve air quality in those areas.
    2012 Interim Compliance Deadline. EPA is requiring an initial phase
of reductions starting in 2012. These reductions are necessary to
ensure that significant contribution to nonattainment and interference
with maintenance are eliminated as expeditiously as practicable and in
time to help states meet their attainment deadlines. As the court
emphasized in North Carolina, the significant contribution to
nonattainment and interference with maintenance from upwind states must
be eliminated as expeditiously as practicable to help downwind states
to achieve attainment as expeditiously as practicable as required by
the CAA. Further, reductions are needed by 2012 to help states attain
before the June 2013 maximum attainment date for ``serious'' ozone
nonattainment areas, to ensure states attain as soon after the original
April 2010 attainment deadline for the 1997 PM2.5 NAAQS, and
to help states attain before the December 2014 attainment deadline for
the 2006 PM2.5 NAAQS.
    In addition, because this final rule will replace CAIR, EPA could
not assume that after this rule is finalized, EGUs would continue to
emit at the reduced emission levels achieved by CAIR. Instead, it is
the emission reduction requirements in the proposed FIPs that will
determine the level of EGU emissions in the eastern United States. For
this reason also, EPA concludes that it is appropriate to require an
initial phase of reductions by 2012 to ensure that existing and planned
SO2 and NOX controls operate as anticipated.
    Addressing the Court's Concern about Timing. As directed by the
Court in North Carolina, 531 F.3d 896, and as described previously, EPA
established the compliance deadlines in the Transport Rule based on the
respective NAAQS attainment requirements and deadlines applicable to
the downwind nonattainment and maintenance sites.
    The 2012 deadline for compliance with the limits on ozone-season
NOX emissions is necessary to ensure that states with June
2013 maximum attainment deadlines get the assistance needed from upwind
states to meet those deadlines. The 2012 deadline for compliance with
the limits on annual NOX and annual SO2 emissions
is necessary to ensure attainment as expeditiously as practicable in
areas which failed to attain by the 2010 attainment deadline for the
1997 PM2.5 NAAQS and had to request an extension to 2015.
    Similarly, the 2014 deadline for compliance with the limits on
annual NOX and annual SO2 emissions is necessary
to ensure that downwind states get the benefit of upwind reductions
prior to the December 2014 maximum attainment deadline for the 2006
PM2.5 NAAQS. It is also necessary to ensure reductions occur
in time to assist with attainment in downwind areas that received the
maximum 5-year extension of the 5-year attainment deadline for the 1997
PM2.5 NAAQS (taking into account the need for reductions by
2014 to demonstrate attainment by April 2015).
    The 2012 compliance deadline for the first-phase of annual
NOX and annual SO2 emission reductions will
assure the reductions are achieved as expeditiously as practicable. A
significant amount of the emissions identified as significantly
contributing to nonattainment or interfering with maintenance in other
states can be eliminated by 2012. EPA believes it is appropriate to do
so in light of the court's direction to EPA to ensure states eliminate
such emissions as expeditiously as practicable. North Carolina 531,
F.3d at 930. Given the time needed to design and construct scrubbers at
a large number of facilities, EPA believes the 2014 compliance date is
as expeditious as practicable for the full quantity of SO2
reductions necessary to fully address the significant contribution to
nonattainment and interference with maintenance. Requiring reductions
in transported pollution as expeditiously as practicable, as well as
within maximum deadlines, helps to promote attainment as expeditiously
as practicable. This is consistent with statutory provisions that
require states to adopt SIPs that provide for attainment as
expeditiously as practicable and within the applicable maximum
deadlines.
b. Public Comments and EPA Responses
    EPA received numerous comments on the proposed compliance dates. A
number of commenters supported EPA's compliance schedule and rationale.
Other commenters supported extending the compliance deadlines to later
dates.
    Many commenters questioned the technical feasibility of achieving
the required reductions by the 2012 and 2014 dates. EPA's responses to
those comments are discussed below in section VII.C.2.
    Other commenters provided policy and legal arguments for allowing
states to develop SIP alternatives to the FIP, and to build time for
that SIP development and review process into the compliance schedule.
For example, some commenters asserted that the requirement in the CAA
for providing reductions ``as expeditiously as practicable'' must be
balanced with CAA provisions allowing states to develop state
implementation plans prior to EPA imposing FIPs. EPA responses to those
comments are discussed in section X.
    Some commenters suggested that EPA had the ability to leave CAIR in
place for a transition period, and by doing this EPA could allow for a
longer compliance period for this rule. EPA does not believe it would
be appropriate, in light of the Court's decision in North Carolina, to
establish a lengthy transition period to the rule that will replace
CAIR. Although the Court decided on rehearing to remand CAIR without
vacatur, the Court stressed its prior decision that CAIR was deeply
flawed and EPA's obligation to remedy those flaws. North Carolina, 550

F.3d 1176. Although the Court did not set a definitive deadline for
corrective action, the Court took care to note that the effectiveness
of its opinion would not be delayed ``indefinitely'' and that
petitioners could bring a mandamus petition if EPA were to fail to
modify CAIR in a manner consistent with its prior opinion. Id. Given
the Court's emphasis on remedying CAIR's flaws expeditiously, EPA does
not believe it would be appropriate to establish a lengthy transition
period to the rule which is to replace CAIR.
    As relates to PM2.5, EPA received a number of comments
on its proposal to include a 2012 deadline to ensure that emission
reductions needed to reduce PM2.5 be achieved ``as
expeditiously as practicable.'' Some commenters supported EPA's 2012
deadline. Other commenters believed that it was unnecessary and
unwarranted for EPA to impose emission reduction requirements in
advance of the 2014 attainment date. In light of the 2014 five-year
attainment date for the 2006 PM2.5 NAAQS (with a possible
extension to 2019), and the possible extension to April 2015 for the
1997 PM2.5 NAAQS, these commenters believed EPA's 2012
emission reduction requirements for annual PM2.5 and
NOX were not necessary. EPA disagrees with these commenters,
for a number of reasons. First, EPA notes (supported by commenters)
that there is a clear statutory obligation to attain ``as expeditiously
as practicable.'' Second, EPA notes that there are feasible reductions
available by 2012. Third, EPA believes that the substantial health and
environmental benefits achieved by the rule underscore the importance
of achieving the reductions as soon as possible.
    With respect to ozone, some commenters noted that the proposed rule
required ozone reductions by 2012 for states impacting areas which
EPA's analysis shows will attain the 1997 ozone NAAQS by 2014 without
further controls. Those commenters questioned the importance of getting
reductions in such states and whether the 2012 deadline is necessary.
EPA disagrees with those comments. Except for Houston, all ozone areas
within the region addressed by this rule have attainment dates no later
than 2013. In effect, this means that emission reductions needed to
attain the 1997 ozone NAAQS must be in place by the 2012 ozone season.
EPA believes that if there are reductions available by 2012, and those
emission reductions have in fact been identified, it is appropriate and
necessary to ensure that those reductions are in place.
2. Compliance and Deployment of Pollution Control Technologies
    The power industry will undertake a diverse set of actions to
comply with the Transport Rule at the start of 2012 and another set of
actions when companies in Group 1 states comply with more stringent
SO2 budgets at the start of 2014. In 2012, the industry will
largely meet the rule's NOX requirements by: Operating an
extensive existing set of combustion and post-combustion controls on
fossil fuel-fired generators; dispatching lower emitting units more
often; and installing and operating a limited amount of relatively
simple NOX pollution controls in states not previously
subject to CAIR. For the SO2 requirements, EPA anticipates
at a minimum that coal-fired generators will operate the substantial
capacity of advanced pollution controls already in place or scheduled
for 2012 use; some units will also elect to burn lower-sulfur coals;
and the fleet will increase dispatch from lower-sulfur-emitting units
as well as from natural gas-fired generators. EPA provides a more
detailed explanation below of how fuel switching to lower sulfur coals
factored in to the design of the final Transport Rule.
    By 2014, EPA's budgets under the Transport Rule will sustain
previous NOX and SO2 reductions as well as
account for reductions from additional advanced NOX and
SO2 controls that are driven by other state and federal
requirements. In addition to these reductions, companies in Group 1
states are also projected to add a limited amount of advanced
SO2 controls in 2014 that will be discussed below.
    EPA's expectations are supported by the IPM analysis reported in
this rule's RIA (see Chapter 7). Notably, since EPA has established a
cap and trade control system for lowering NOX and
SO2 emissions, individual owners and operators of covered
units have some flexibility in meeting the program's requirements as
needed and are free to find alternative ways to comply. The RIA clearly
shows a viable known pathway for owners and operators to comply at
reasonable costs, although it is not the only compliance pathway
possible under this flexible regulation that could deliver the emission
reductions required under the rule. Notably, by 2014 and beyond, the
power industry may also augment the projected compliance efforts with
programs aimed at improving energy efficiency.
    Table VII.C.2-1--shows EPA's projection of the amount of existing
coal-fired generating capacity in gigawatts (GW) that may retrofit
various systems for compliance with this rule.

                           Table VII.C.2-1--Projected Potential Air Pollution Control (APC) Retrofits for Transport Rule \59\
--------------------------------------------------------------------------------------------------------------------------------------------------------
     Capacity retrofitted by              Wet FGD                 Dry FGD                   DSI                     SCR            LNB/OFA  improvements
--------------------------------------------------------------------------------------------------------------------------------------------------------
January 1, 2012.................  ......................  ......................  ......................  ......................  10 GW
January 1, 2014.................  5.7 GW................  0.2 GW................  3.0 GW................  0 GW..................
--------------------------------------------------------------------------------------------------------------------------------------------------------

    EPA received proposal comments expressing a concern about the
feasibility of deploying retrofit air pollution control (APC)
technologies in the time frames available between the final date of
this rule and the compliance dates. As discussed below, EPA believes
that it is feasible for the electric power sector and its APC supply
chain to either make most of the projected retrofits in time to meet
the 2012 and 2014 compliance deadlines, or to comply by other means.
---------------------------------------------------------------------------

    \59\ GW: Gigawatts of capacity retrofitted; FGD: Flue gas
desulfurization (SO2 control); DSI: Dry sorbent injection
(SO2 control); SCR: Selective catalytic reduction
(NOX control); LNB/OFA: Low-NOX burner and/or
overfire air (NOX controls).
---------------------------------------------------------------------------

a. 2012 Power Industry Compliance
    EPA's analysis of emission reductions available in 2012 assumes
year-round operation of existing post-combustion pollution controls in
states covered for PM2.5 and ozone-season operation of
NOX post-combustion controls in states covered for ozone.
EPA also modeled emission reductions available in 2012 at the $500/ton
threshold for SO2, $500/ton for annual NOX, and
$500/ton for ozone-season NOX.
    For SO2, EPA believes that reductions associated with
the following methods of control are available and will be used

as compliance strategies to meet the 2012/2013 budgets: (1) Operation
of existing controls year-round in PM2.5 states, (2)
operation of scrubbers that are currently scheduled to come online by
2012, (3) some sources switching to lower-sulfur coal (see section
VII.C.2.c that follows), and (4) changes in dispatch and generation
shifting from higher emitting units to lower emitting units. EPA
modeling and selection of a $500/ton cost threshold includes all
existing and planned controls operating year round (items 1 and 2). It
also reflects an amount of coal switching and generation shifting that
can be achieved for $500/ton. This set of expected actions was
confirmed in the detailed modeling of EPA's final remedy in the RIA and
can be reviewed there.
    The power sector is already strongly positioned to achieve the
Transport Rule state budgets presented in section VI.D through at least
three distinct strategies. First, the sector will optimize its use of
the large proportions of advanced pollution controls already present
throughout the fleet. Second, the sector will take advantage of the
substantial new pollution control technology that is already on the way
for deployment by 2012. Third, the remainder of the fleet will flexibly
adopt the most economic low-emitting fuel mix available at each unit to
deliver cost-effective emission reductions complementing the reductions
achieved from optimized use of the fleet's pollution control
technology. The state maps in Chapter 7 of this rule's Regulatory
Impact Analysis demonstrate how these emission reduction strategies for
2012 will build off of the sector's historic trend toward cleaner
generation profiles. Also, the detailed unit-level projection files
from EPA's IPM power sector modeling of the Transport Rule remedy
(found in the docket for this rulemaking) show how EGUs adopt these
strategies to not only reach the 2012 budgets, but in fact in many
states overcomply with the budgets and build up a bank of allowances
under the programs for future flexibility.
    The following paragraphs illustrate the degree to which the
existing fleet is already prepared to adopt these emission reductions
in 2012 in order to attain the required emission reductions for
SO2, annual NOX, and ozone-season NOX
under the Transport Rule. More specifically, the illustrative
paragraphs demonstrate emission reduction pathways for coal capacity to
optimize or increase operation of existing control technology, timely
implement existing plans to bring additional control technology on
line, and to cost-effectively make use of lower-emitting fuel
alternatives.
    Of the 240 GW of coal capacity in the Transport Rule region covered
for fine particles, approximately 110 GW--more than 45 percent--had
existing advanced pollution control for SO2 already in place
in 2010, including scrubbers (FGD), dry sorbent injection (DSI), or
circulating fluidized bed boilers. Of this controlled coal capacity,
EPA expects a significant portion will improve emission rates through
either increased use of control technology and/or additional fuel
switching. EPA notes that an additional 39 GW of advanced
SO2 controls in the region are scheduled to come online over
the 2010-2012 timeframe and will also assist in meeting 2012 emission
reduction requirements. Thus, by 2012 more than half of affected coal
capacity--152 GW--will be operating with advanced SO2
control equipment. Additionally, EPA expects approximately 40 GW of
uncontrolled coal capacity in the region to take advantage of the
existing coal supply infrastructure, possibly switching coal use or
coal blending behaviors to make cost-effective reductions in
SO2 emission rates where economic to respond to the
Transport Rule 2012 emission reduction requirements.
    EPA notes that approximately 136 GW of the 240 GW--more than 56
percent--of coal capacity in the Transport Rule region covered for fine
particles had existing advanced pollution control for NOX
already in place in 2010, including selective catalytic reduction
(SCR), selective non-catalytic reduction (SNCR), or circulating
fluidized bed boilers. Of this capacity, EPA anticipates a significant
portion will improve their NOX emission rate through
increased operation of these existing controls. Additionally, EPA notes
that an additional 21 GW of SCR and 4 GW of enhanced combustion
controls (including low-NOX burners and overfire air) are
scheduled to come online in the region during the 2010-2012 timeframe,
bringing the total region's coal capacity operating with NOX
emission reduction technology to 158 GW (more than 65 percent of total
coal capacity in the Transport Rule fine particle region). EPA also
projects that approximately 13 GW of coal capacity will make some
reduction in their NOX emission rates by enhancing
performance of existing combustion controls or SNCR, or by fuel
switching.
    In the Transport Rule states covered under the ozone-season
program, approximately 145 GW of the 260 GW (more than 55 percent) of
coal capacity had existing NOX control technology in place
in 2010. EPA expects a significant portion of that capacity to achieve
emission reductions during the 2012 ozone-season through improved
operation of SCR. Additionally, in the Transport Rule ozone region
there will be approximately 21 GW of additional advanced NOX
control installations and 7 GW of additional combustion control
improvements or installations coming online during the 2010 to 2012
time frame. EPA projects that 17 GW of coal capacity in the Transport
Rule ozone region will reduce NOX emission rates by
enhancing performance of existing combustion controls or SNCR or by
fuel switching.
    For NOX, EPA has also concluded that it is appropriate
to require reductions through a limited amount of combustion control
improvements, and in some cases, retrofits such as low-NOX
burners (LNB) and/or overfire air (OFA). EPA recognizes that the 6-
month time frame between rule finalization and start of the first
compliance period would not allow for the installation of a major post-
combustion NOX control such as SCR. Assumed improvements and
retrofits for the January 1, 2012 deadline for annual NOX
reductions therefore only involve the much simpler LNB/OFA control
modifications or installations. Alternatively, some plant owners might
choose to achieve NOX reductions in a similar time period
through an even simpler retrofit--SNCR.\60\
---------------------------------------------------------------------------

    \60\ David L. Wojichowski, SNCR System--Design, Installation,
and Operating Experience http://www.netl.doe.gov/publications/proceedings/02/scr-sncr/wojichowski-1.pdf.
---------------------------------------------------------------------------

    Although the improvements, and in some cases, installation of
combustion controls would be an economic means of achieving emission
reductions, these specific controls are not required for compliance
purposes under the final Transport Rule remedy. Individual sources may
comply through other measures (such as purchasing additional
allowances) in the event that it takes more than 6 months for
installation of a given combustion control. The vast majority of
covered sources already have combustion controls installed; therefore,
the NOX reductions associated with these incremental control
improvements and installations are small.

    Based on the Transport Rule's geography, EPA estimates that
approximately 10 GW of coal-fired units may improve, and in some cases,
install LNB/OFA specifically in reaction to the Transport Rule
NOX caps. EPA reflects the effects of these installations in
the 2012 annual and ozone-season NOX budgets, which would
yield reductions of approximately 28,000 tons of annual NOX
and 14,000 tons of ozone-season NOX. EPA assumes these
controls are cost effective at $500/ton and that they should be
incentivized through budgets given the 2013 attainment deadline for
ozone areas classified as ``serious.'' Once installed, LNB/OFA operates
any time the boiler is fired and thus yields NOX reductions
beyond the ozone season alone.
    In the proposal's LNB technical support document,\61\ EPA observes
that LNB and/or OFA installations, burner modifications, or other
NOX reduction controls would likely have to be installed
during fall 2011 or spring 2012 outages in order to achieve significant
reductions for 2012. While this 6-month schedule is aggressive,
industry has shown that it can be met. For example, Limestone Electric
Generating Station Unit 2, an 820 MW tangentially-fired lignite unit,
was retrofitted with Foster Wheeler's Tangential Low NOX
(TLN3) system in less than six months, including engineering,
fabrication, delivery and installation.\62\ Harlee Branch Unit 4, a 535
MW cell-fired unit, was retrofitted with Riley Power's low-
NOX Dual Air Zone CCV burners on a similar schedule.\63\
These are tangentially-fired and wall-fired units, respectively,
representative of the unit types that might make LNB/OFA improvements
for compliance with this rule. Although such 6-month schedules can be
achieved on some units, under favorable circumstances, historical
projects suggest a more typical schedule would be 12 to 16 months for
the contractor's portion of the work.\64\ A plant owner's project
planning and procurement work in advance of a contract award would
typically involve several additional months. On the other hand, there
are other approaches that can also be implemented in a short time frame
to achieve significant NOX reduction. As mentioned above,
relatively simple SNCR systems can be installed quickly; and the re-
tuning or upgrading of existing combustion control systems can often
provide significant NOX reductions and can be performed
quickly.\65\
---------------------------------------------------------------------------

    \61\ Technical Support Document (TSD) for the Transport Rule,
Docket ID No. EPA-HQ-OAR-2009-0491, Installation Timing for Low
NOX Burners (LNB).
    \62\ R. Pearce, J. Grusha, Reliant Energy Tangential Low
NOX System at Limestone Unit 2 Cuts Texas Lignite, PRB
and Pet Coke NOX, http://www.fwc.com/publications/tech_papers/files/tp_firsys_01_02.pdf.
    \63\ B. Courtemanche, et al., Reducing NOX Emissions
and Commissioning Time on Southern Company Coal Fired Boilers With
Low NOX Burners and CFD Analysis, http://www.babcockpower.com/pdf/t-182.pdf.
    \64\ M. O'Donnell, Babcock & Wilcox Company, (personal
communication with EPA staff, February 22, 2011).
    \65\ N.C Widmer, et al., Coal Power, October 8, 2009, http://www.coalpowermag.com/ops_and_maintenance/Zonal-Combustion-Tuning-Systems-Improve-Coal-Fired-Boiler-Performance_226.html.
---------------------------------------------------------------------------

    As stated above, EPA believes that LNB/OFA modifications or
retrofits would be possible during the 6-month interim between rule
signature and the start of the first compliance period, particularly
for those ``early movers'' who have initiated LNB projects based on the
proposed rule. However, as shown in Table VII.C.2-2, below, even if all
LNB modifications or installations are delayed until the beginning of
the 2012 ozone season, the reductions only represent 1 percent of most
covered states' annual NOX budgets, and no more than 11
percent of any affected state's annual NOX budget. Under
such a scenario, these delayed reductions would still be well within
the 18 percent variability limit applied to each state's annual
NOX budget. In light of this limited consequence and the
supporting material above, EPA includes LNB-driven NOX
reductions in both annual and ozone-season NOX budgets for
2012.

 Table VII.C.2-2--Earliest Reductions Assumed From LNB Installations in the Transport Rule States Subject to the
                                              Annual NOX Program *
----------------------------------------------------------------------------------------------------------------
                                                             NOX reductions                        Percent of
                                                                from LNB                          budget met by
                                                             operation from   Annual NOX state    earliest LNB
                                                              January-April    budget  (tons)      reductions
                                                                 (tons)                             (percent)
----------------------------------------------------------------------------------------------------------------
Georgia...................................................               646            62,010                 1
Iowa......................................................               567            38,335                 1
Kansas....................................................             2,131            30,714                 7
Minnesota.................................................             2,303            29,572                 8
Nebraska..................................................             3,008            26,440                11
                                                           -----------------------------------------------------
    Region-wide Total.....................................             8,656         1,245,869                 1
----------------------------------------------------------------------------------------------------------------
* Based on EPA IPM Analysis of Final Transport Rule.

b. 2014 Power Industry Compliance
    EPA projects that compliance with 2014 requirements for
NOX will result largely from operation of existing and
future controls required by state and other federal requirements, as
well as the appropriate dispatch of the electric generation fleet. EPA
does not project additional NOX pollution control retrofits
aside from about 10 GWs of combustion control improvements or retrofits
projected for the 2012 compliance period. To comply with the rule's
SO2 requirements, EPA projects that the power industry will
rely on existing controls, operate newly installed advanced controls
necessary for other binding state and federal requirements, rely more
on relatively lower sulfur coals, and dispatch lower-emitting
generation units. In Group 1 states, industry is projected to increase
switching to lower sulfur coals and install a limited amount of
additional scrubbers and other advanced pollution control technology.
EPA's assessment of the industry's ability to install SO2
pollution controls in 2014 and undertake the projected coal switching
follows below.
    EPA's modeling of least-cost compliance with the state budgets
under the Transport Rule projects approximately 5.9 GW of FGD systems
and lesser amounts of other technologies will be retrofitted by 2014

for compliance with the Transport Rule.66 67 EPA's schedule
assumptions for these larger more complex projects were developed in an
earlier study and mentioned in the proposal: 27 months for retrofitted
wet FGD and 21 months for SCR.\68\ Note that a dry FGD system, due to
its relatively simpler configuration and lesser cost, would typically
take somewhat less time to retrofit than wet FGD.
---------------------------------------------------------------------------

    \66\ Nearly all of the 5.9 GW of FGD retrofits are comprised by
some 12 units at 7 plants (Beckjord, Muskingum River, Homer City,
Rockport, Kammer, Danskammer, and Will County).
    \67\ As noted elsewhere in this preamble, the projected impacts
of this final rule presented in the preamble do not reflect minor
technical corrections to SO2 budgets in three states (KY,
MI, and NY) and assumed preliminary variability limits that were
smaller than the variability limits finalized in this rule. EPA
conducted sensitivity analysis factoring in these corrections; the
results of this analysis include a small increase of about 700 MW of
additional wet FGD retrofit projected for 2014. This projected
additional retrofitting capacity is already required to retrofit
under a consent decree and should therefore have already conducted
advanced retrofit planning. EPA therefore believes that this
incremental projected retrofit behavior (factoring in the technical
corrections made after the main impact analyses were conducted) is
feasible by 2014 for the same reasons presented in this section
regarding the projected retrofit behavior from the main analysis of
the final rule.
    \68\ EPA, Engineering and Economic Factors Affecting the
Installation of Control Technologies for Multipollutant Strategies;
EPA-600/R-02/073 October 2002.
---------------------------------------------------------------------------

    As discussed below, EPA believes that its schedule assumptions
remain reasonable expectations for sources that have completed most of
their preliminary project planning and can quickly make commitments to
proceed. These schedules do not include the extensive time that some
plant owners might spend in making a decision on whether or not to
retrofit. They do include the time needed to make a final confirmation
of the type of technology to be used at a particular site, to prepare
bid requests, award contracts, perform engineering, obtain construction
and operating permits (in parallel with project activities), perform
construction, tie-in to the existing plant systems, and perform
integrated systems testing.
    EPA received comments on the proposed rule indicating that some
past single-unit APC retrofits had considerably longer schedules, with
a few exceeding 48 months. EPA engineering staff have extensive
experience with power plant and APC system design, construction, and
operation. Based on that experience, EPA can observe that in the
absence of a compelling deadline or major economic incentive, many
large project schedules are considerably longer than necessary. Given
further observations as explained below, EPA believes it is reasonable
to expect that almost all future APC retrofits can be completed far
more quickly than they were in recent history. EPA's perspective on
this matter derives in part from a comparison of longer APC schedules
(as provided by some commenters) to the project schedule for an entire
new coal-fired unit, including its APC systems. Springerville Unit 3,
for example, is a new 400 MW subbituminous coal-fired unit with SCR and
dry FGD that became operational in July 2006, some 33 months after the
turnkey engineering-construction contractor was given a notice to
proceed with engineering.\69\ Springerville was clearly on an
accelerated schedule, as its original planned schedule was about 38
months. Another example is Dallman Unit 4, a high-sulfur bituminous
coal-fired 200 MW unit with SCR, fabric filter, wet FGD, and wet ESP.
Dallman Unit 4 was first synchronized in May 2009, several months ahead
of schedule, and about 36 months after its turnkey contractor placed
initial major equipment orders.\70\ The main point here is that recent
APC project schedules, and those of large complex power projects, can
be significantly accelerated. Because the scope and complexity of the
work involved for an entire new coal unit and its APC systems is
perhaps five times greater than that of a retrofit wet FGD system
alone, EPA believes it is reasonable to expect that even the most
complex retrofit APC project can be significantly accelerated as well.
Additional factors are discussed below that further support the
feasibility of installing by 2014 the 5.9 GW of FGD retrofits projected
for this rule.
---------------------------------------------------------------------------

    \69\ Best Coal-fired Projects, Springerville Unit 3 Expansion
Project, Power Engineering, November 2006, http://www.powergenworldwide.com/index/display/articledisplay/282547/articles/power-engineering/volume-111/issue-1/features/projects-of-the-year.html.
    \70\ http://www.cwlp.com/electric_division/generation/Dallman%204%20Power%20Plant%20of%20the%20Year.pdf.
---------------------------------------------------------------------------

    Although IPM modeling provides reliable estimates on a regional
basis, and cannot be as accurate at the level of individual plants or
units, it is informative and relevant to consider IPM's plant level
projections in this case. Although the IPM-projected retrofits named
below may not actually occur, IPM projects that they would be economic
and would allow industry to meet the tighter SO2 emission
standards in Group 1 states in 2014. EPA notes that the owners of the
particular plants mentioned below (Duke Energy, AEP, Edison
International) are large, experienced, versatile utilities that have
done considerable advance planning and should also have above-average
flexibility to comply with state budgets across their fleets. EPA would
expect such owners to have relatively little difficulty in permitting
and financing FGD retrofits.
    Of the Transport Rule-related FGD retrofits, 0.2 GW is projected to
use dry FGD, which EPA expects to be simpler and quicker to install
than wet FGD. Half of the 5.9 GW (Muskingum, Rockport) has already been
committed under consent decrees to add controls or retire; \71\ and EPA
reasonably believes that significant preliminary project planning work
has already been done for those projects. An additional 1,200 MW (Homer
City) had completed project planning and was ready to proceed in 2007,
before putting the project on hold.\72\ The latter plant is now facing
EPA legal action and the possibility of a required expeditious FGD
retrofit.\73\ Thus, of the 5.9 GW of projected FGD retrofits resulting
from this rule, nearly 75 percent appears to be in good position for an
early start of construction, and over 3 GW of that would be bringing
forward already committed compliance start dates.
---------------------------------------------------------------------------

    \71\ http://www.epa.gov/compliance/resources/decrees/civil/caa/americanelectricpower-cd.pdf.
    \72\ http://www.businesswire.com/news/home/20060731005193/en/Contractors-Selected-Install-Emissions-Control-System-Pennsylvania.
    \73\ http://www.epa.gov/Compliance/resources/complaints/civil/caa/homercity-cp.pdf.
---------------------------------------------------------------------------

    Any of the above mentioned potential retrofits or any other unit
that might choose to retrofit FGD for a January 2014 compliance date
will likely have to use various methods to accelerate the project
schedule. Such methods could include the use of parallel permitting,
overtime and/or two-shift work schedules during construction, and 5- or
6-day work weeks instead of the 4-day x 10-hour schedules often used to
minimize cost when time is not of the essence. Increased use of offsite
modularization and pre-fabrication of APC components could also shorten
schedules and reduce job hours.
    EPA believes that the January 1, 2014 compliance date is as
expeditious as practicable for the sources installing large, complex
control systems. The following additional observations support EPA's
expectation that the limited 5.9 GW of FGD retrofits can be realized in
the 30 month interim between rule signature and the start of 2014:
     There are documented instances of large, complex wet FGD
retrofits being deployed in less than 30-months (excluding the time for
owners' project

planning). Examples are Killen Station Unit 2,\74\ and Asheville Unit
1.\75\
---------------------------------------------------------------------------

    \74\ Black & Veatch, http://www.bv.com/News_3_Publications/News_Releases/2005/0503.aspx (start), http://www.bv.com/wcm/press_release/07252007_9767.aspx (completion).
    \75\ PowerGenWorldwide, Projects of the Year, January 1, 2007,
http://www.powergenworldwide.com/index/display/articledisplay/282547/articles/power-engineering/volume-111/issue-1/features/projects-of-the-year.html.
---------------------------------------------------------------------------

     In 2009 the APC supply chain deployed more than six times
more GW capacity of FGD and SCR controls than the 5.9 GW of FGD that
would be deployed by 2014 under this Rule.
     The APC supply chain has seen a 2-year decline in
deployments since its peak in 2009, but in 2011 is nonetheless putting
into service about three times more GW capacity of FGD and SCR controls
than the 5.9 of FGD that would be deployed under this Rule.
     Because the supply chain has been in decline, but remains
quite active, there are now adequate supply chain resources available
that can be quickly reengaged to support a rapid deployment of 5.9 GW
of FGD.
    EPA recognizes that the installation of any amount of scrubbers in
this short time frame will require aggressive action by plant owners
and that the owners who can meet this schedule will already have done
their project planning and will be ready to place orders. An example of
such ``early movers'' was seen in the power sector's anticipation of
CAIR. EPA data indicate that solely CAIR-driven FGD and SCR deployments
of about 6 GW occurred within two and one-half years after CAIR's
finalization in mid-2005, showing that at least 20 percent of the total
CAIR-only controls effort through a 2010 compliance date was
sufficiently planned for installation to start before or immediately
upon finalization of the rule. EPA reasonably expects that similar
advance planning has already been done for units that would retrofit
under this rule.
    In the event that a particular control installation requires
additional time into 2014 to come online, EPA believes compliance would
not be jeopardized given the ability of sources to purchase allowances
during that time. This approach could be supported by some sources with
FGD that have the ability to increase their SO2 removal
above historic rates, perhaps through relatively low cost upgrades to
improve scrubber effectiveness, or by operating scrubbers at higher
chemistry ratios. The ability of sources to temporarily or permanently
substitute dry DSI for FGD serves as another backstop for any
feasibility issues regarding FGD. Note that the updated modeling for
this rule projects the addition by 2014 of about 3 GW of DSI for
SO2 control using trona or other sorbent. DSI is a
relatively low capital cost technology that readily can be installed in
the time frame available for compliance.76 77
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    \76\ ICAC letter to Senator Carper, November 3, 2010, http://www.icac.com/files/public/ICAC_Carper_Response_110310.pdf.
    \77\ Assessment of Technology Options Available to Achieve
Reductions of Hazardous Air Pollutants, URS Corporation, April 5,
2011, http://www.supportcleanair.com/resources/studies/file/4-8-11-URSTechnologyReport.pdf.
---------------------------------------------------------------------------

    It should also be noted that most APC retrofits will involve a
source outage for final ``tie-in'' of retrofitted systems to existing
systems, during which time emissions from the affected units are zero.
For some sources, the duration of this tie-in outage may effectively
extend the deadline by which all of the projected emission reductions
need to occur.
    Although EPA believes that installation of 5.9 GW of FGD at
facilities by January 1, 2014 is feasible, EPA also conducted an IPM
sensitivity analysis to examine a scenario in which FGD retrofitting by
2014 is not allowed. Results of EPA's ``no FGD build in 2014'' analysis
indicate that if the power industry were subjected to the requirements
of this rule without an FGD retrofit option for compliance until after
2014, covered units would still be able to meet the Transport Rule
requirements in every state while respecting each state's assurance
level. (See the docket to this rulemaking for the IPM run titled ``TR--
No--FGD-- in2014--Scenario--Final.'')
    In this scenario without the availability of new FGD by 2014,
sources in covered states complied with the Transport Rule budgets by
using moderate additional amounts of DSI retrofits, switching to larger
shares of sub-bituminous coal, and dispatching larger amounts of
natural gas-fired generation in lieu of the FGD retrofits that are
projected as being most economic under modeling of the Transport Rule
remedy. Because new FGD capacity is included in EPA's projection of the
least-cost set of SO2 emission reductions required in Group
1 states, the ``no FGD'' sensitivity scenario did project higher system
costs, although these costs were still substantially lower than the
remedy EPA modeled in the Transport Rule proposal.
    The ``no FGD'' analysis indicates that while the ability of Group 1
states to meet their 2014 SO2 budgets is facilitated by FGD
retrofits, they are by no means required, nor is Transport Rule
compliance jeopardized by their absence. Even under a scenario in which
sources fail to complete FGD retrofits by 2014, sources in the affected
states would have other compliance options available at reasonable cost
to meet the state's budget requirements. This analysis shows that Group
1 states would be able to comply with their 2014 SO2 budgets
by relying on other emission reduction opportunities that do not
require FGD retrofits. EPA analysis confirms that those alternatives
are feasible both in terms of cost and timing.
    Finally, EPA recognizes that, when finalized later this year as
currently scheduled, the Mercury and Air Toxics Standards (MATS) will
require significant retrofit activity at covered sources in the power
sector with a 2015 compliance date for that rule. EPA's projections of
retrofit activity under the final Transport Rule are highly compatible
with its projections of retrofit activity under the proposed MATS
(which included the proposed Transport Rule in its baseline). EPA
therefore anticipates that the Transport Rule's projected retrofit
activity will not only be the least-cost compliance pathway to meeting
state budgets in 2014 but will also accelerate emission reductions
subsequently required by the effective date of MATS. The final
Transport Rule's projected 2014 retrofit installations will also
further incentivize the power sector to ramp up its retrofit
installation capabilities to achieve broader deployment of the
projected pollution control retrofits under the proposed MATS.
    Considering all the reasons given above, EPA has concluded that the
2014 requirements for SO2 emissions in the states covered by
the Transport Rule are reasonable and can be met by the power industry
by a variety of means.
c. Coal Switching for SO2 Compliance in 2012 and 2014
    Coal switching is another mechanism which can be used along with
operating pollution controls in 2012 for compliance. It will be a
complementary activity by many coal-fired units alongside of operating
pollution controls and the addition of more scrubbers and DSI in 2014.
    In the proposal, EPA noted that coal switching could serve as a
compliance mechanism for 2012. EPA requested comment on the
reasonableness of EPA's assumption that coal switching will have
relatively little cost or schedule impact on most units. EPA received
substantial comment suggesting that the coal switching and coal
blending projected by EPA modeling are not feasible for all units,

and that, if feasible, would often incur a cost through the derating of
the unit associated with the switch to a lower sulfur coal or coal
blend. Additionally, sources indicated that coal switching by 2012
would not always be possible in the six month window between final rule
signature and start of compliance. These feasibility concerns stemmed
from restrictions included in existing coal supply contracts and from
boiler design constraints that may hinder coal switching within a 6
month window.
    EPA agrees with these concerns and revised its IPM modeling to
limit coal switching capability in 2012 for particular units that may
have trouble switching coals or coal blends in a six month time frame.
A cost adder was also included in the IPM modeling for coal switching
to capture the potential cost burden of deratings that might accompany
switching to a very low sulfur subbituminous coal or coal blend.
    A particular commenter concern regarding switching to lower sulfur
within the eastern bituminous coals related to a possible impact on the
performance of a cold-side electrostatic precipitator (ESP). Some ESPs
that operate at acceptably high collection efficiency when using a
high- or medium-sulfur bituminous coal may experience some loss in
collection efficiency when a lower sulfur coal is used. Whether this
occurs on a specific unit, and the extent to which it occurs, would
depend on the design margins built into the existing ESP, the
percentage change in coal sulfur content, and other factors. In any
case, industry experience indicates that relatively inexpensive
practices to maintain high ESP performance on lower sulfur bituminous
coals are available and can be used successfully where necessary. These
include a range of upgrades to ESP components and flue gas
conditioning.\78\ EPA therefore assumes that it will not be necessary
for units that switch from higher to lower sulfur bituminous to make a
costly replacement of the ESP.
---------------------------------------------------------------------------

    \78\ Assessment of Technology Options Available to Achieve
Reductions of Hazardous Air Pollutants, URS Corporation, April 5,
2011, http://www.supportcleanair.com/resources/studies/file/4-8-11-URSTechnologyReport.pdf.
---------------------------------------------------------------------------

    Coal switching as a SO2 compliance option might also
include switching from bituminous to subbituminous coal. EPA's analysis
does not assume that a unit designed for bituminous can switch to (very
low sulfur) subbituminous coal unless the unit's historical data
demonstrate that capability in the past. EPA assumes that units with
that demonstrated capability have already made any investments needed
to handle a switch back to the use of subbituminous coal at a similar
percentage of its heat input as in the past. For IPM analysis in the
final rule EPA also introduced a coal switching option that assumes
that units can increase a historically low percentage use of
subbituminous to a ``maximum'' level, if economic. This option includes
an appropriate derate in output, increase in heat rate, and additional
capital and operating costs. Details of this and other IPM updates for
this rule are provided in the IPM Modeling Documentation in the docket
for this rulemaking (``Documentation Supplement for EPA Base Case
v.4.10--FTransport--Updates for Final Transport Rule'').
    Some commenters also expressed concern with the assumption that
coal-switching from lignite to subbituminous is a cost-effective or
feasible emission reduction strategy, particularly at Texas EGUs. EPA
carefully considered these comments and adjusted its modeling of cost-
effective reductions to address this concern. Specifically, EPA made
adjustment in the model so that it assumes coal-switching is not a
compliance option at the specific units where commenters identified
technical barriers to subbituminous coal consumption. The Transport
Rule emission budgets are based on this adjusted modeling which does
not assume any infeasible coal-switching from lignite to subbituminous.
In addition, EPA's analysis of cost-effective reductions in each state
presented in section VI.B shows that Texas is capable of cost-
effectively meeting its Transport Rule emission budgets; however, EPA
also conducted sensitivity analysis that shows Texas can also achieve
the required cost-effective emission reductions even while maintaining
current levels of lignite consumption at affected EGUs. More details
regarding this analysis, including a table comparing key parameters
between the main Transport Rule remedy analysis and this Texas lignite
sensitivity, can be found in the response to comments document and the
IPM model output files included in the docket for this rulemaking.

D. Allocation of Emission Allowances

    Under the final rule, EPA distributes a number of SO2,
annual NOX, and ozone-season NOX emission
allowances to covered units in each state equal to the SO2,
annual NOX, and ozone-season NOX budgets for
those states. These budgets are addressed in section VI.D of this
preamble. This section discusses the methodology EPA uses to allocate
allowances to covered units in each state.
    As discussed later in section VII.D.2, EPA is setting aside a base
2 percent of each state's budgets for allowance allocations for new
units, with 5 percent of that 2 percent, or 0.1 percent of the total
state budget being set aside for new units located in Indian country.
To this base 2 percent, EPA is setting aside an additional percentage
on a state-by-state basis, ranging from 0 to 6 percent (yielding total
set asides of 2 percent to 8 percent), for units planned to be built.
The remainder of the state budget is allocated to existing units.
Tables VI.D.-3 and VI.D.-4 in this preamble show the SO2,
annual NOX, and ozone-season NOX budgets for each
covered state (without the variability limits). In allocating
allowances to existing and new units, EPA distributes four discrete
types of emission allowances for four separate programs: SO2
Group 1 allowances, SO2 Group 2 allowances, annual
NOX allowances, and ozone-season NOX allowances.
    In the SO2 Group 1 and SO2 Group 2 programs,
each SO2 allowance authorizes the emission of one ton of
SO2 in that vintage year or earlier and is usable for
compliance only in the program for which the allowance was issued. In
the annual NOX program, each annual NOX allowance
authorizes the emission of one ton of NOX in that vintage
year or earlier in that program. In the ozone-season NOX
program, each ozone-season NOX allowance authorizes the
emission of one ton of NOX during the regulatory ozone
season (May through September for this final rule) in that vintage year
or earlier for that program.
    In each of the four trading programs, a covered source is required
to hold sufficient allowances (issued in the respective trading
program) to cover the emissions from all covered units at the source
during the control period. EPA assesses compliance with these
allowance-holding requirements at the source (i.e., facility) level.
    This section explains how, in this final rule, EPA allocates a
state's budget to existing units and new units in that state. This
section also describes the new unit set-asides and Indian country new
unit set-asides in each state, allocations to units that are not
operating, and the recordation of allowance allocations in source
compliance accounts.
1. Allocations to Existing Units
    This subsection describes the methodology EPA will use in the FIPs
finalized in this action to allocate to

existing units.\79\ The same methodology will be used to allocate
allowances to existing units for all four trading programs.
---------------------------------------------------------------------------

    \79\ In this rule, existing units are defined as covered units
that commenced commercial operation prior to January 1, 2010. As
explained in greater detail in Section VII.B. of this preamble, EPA
decided to use this definition to ensure that EPA would have at
least 1 full year of quality-assured data on which to base a unit's
allocation.
---------------------------------------------------------------------------

    For the reasons explained below, EPA has decided to base
allocations made under the FIPs on historic heat input, subject to a
maximum allocation limit to any individual unit based on that unit's
maximum historic emissions. This methodology gives each existing unit
an allocation equal to its share of the state's historic heat input for
all the covered units in the program, except where that allocation
would exceed its maximum historic emissions; this methodology
constrains the heat input-based allocations from exceeding any unit's
maximum historic emissions. Further detail on the implementation of
this approach is provided in section VII.D.1.c below as well as in the
Allowance Allocation Final Rule TSD in the docket for this rulemaking.
All existing-unit allocations for 2012 will be made pursuant to the
FIPs. However, as described in section X, states may submit SIPs or
abbreviated SIPs to use different allocation methodologies for
allowances of vintage year 2013 and later.
a. Summary of Allocation Methodologies and Comments
    EPA took comment on three distinct allocation methodologies for
existing units. The first--an emissions-based option--was presented in
the original Transport Rule proposal (75 FR 45309). The second and
third--heat input option 1 and heat input option 2--were presented in a
Notice of Data Availability (76 FR 1113). EPA received numerous
comments on all three options.
i. Emission-Based Allocation Methodology
    The emission-based option presented in the original Transport Rule
proposal would base allowance allocations to existing units on each
covered unit's calculated emission ``share'' of that state's budget for
a given pollutant under the Transport Rule. The proposed rule stated
that ``for 2012, each existing unit in a given state receives
allowances commensurate with the unit's emissions reflected in
whichever total emissions amount is lower for the state, 2009 emissions
or 2012 base case emissions projections. In either case, the allocation
is adjusted downward, if the unit has additional pollution controls
projected to be online by 2012. * * * For states with lower
SO2 budgets in 2014 (SO2 Group 1 states), each
unit's allocation for 2014 and later is determined in proportion to its
share of the 2014 state budget, as projected by IPM'' (75 FR 45309).
    Many commenters objected to this projected emission allocation
methodology. Commenters offered two principle objections. First, they
argued EPA should not use unit-level model projections to allocate
allowances. Second, they argued the use of any emission-based allowance
methodology is improper. Many of these commenters argued that instead
of an emission-based allocation methodology, EPA should use a heat-
input-based allocation methodology.
    Commenters' objections to the use of unit level model projections
focused primarily on the accuracy of such projections. While many
commenters supported the use of modeling projections in determining
state emission budgets, they argued that the unit-level model
projections were not sufficiently accurate to use as a basis for
allocating allowances to individual units. Among other things, they
argued that the modeling used for the proposal did not recognize
certain non-economic factors that may cause individual units to operate
differently than the model projects. Commenters also argued that EPA's
modeling does not capture all up-to-date contracts and other economic
arrangements made at the unit-level which may affect operational
decision-making. Some of these commenters continued to support the use
of an emission-based allocation approach, but urged EPA to use more up-
to-date and specific unit-level data in its modeling projections.
Others opposed the use of any emission-based allocation approach.
    EPA acknowledges that the model may not, at this time, capture all
relevant operational decision factors for each individual unit. EPA
also recognizes that there are unit-level details of operational
decision-making and economic arrangements (such as certain contracts
for electricity sales) that are private and thus unavailable to EPA on
an ongoing basis for modeling purposes. EPA believes these potential
omissions would not have a significant impact on EPA's determination of
significant contribution at the state level; however, EPA recognizes
they could conceivably have a significant impact on projections at the
individual unit level. EPA thus agrees with commenters that the unit-
level emission projections from its modeling may not reflect all
possible operational decisions at a given unit and are therefore not an
appropriate proxy measure to use as a basis for allocating allowances
to individual units.
    Many commenters also argued that, even if the emission projections
could be adjusted to capture all known and up-to-date unit-level
operational factors, EPA should not use any emission-based allocation
approach. They argued that an emission-based approach should not be
used because it is not fuel-neutral. That is to say, the type of fuel
consumed significantly affects the emissions from, and therefore the
allocation to, a given unit under an emission-based approach.
Commenters argued that an approach that is not fuel-neutral effectively
awards higher-emitting units. Commenters also argued that a projected
emission-based approach should not be used because it is not control-
neutral. In other words, whether or not a unit has installed controls
would significantly affect the allocation for a given unit under an
emission-based approach. Under an emission-based approach, controlled
units receive significantly fewer allowances than uncontrolled units.
Such an approach, commenters pointed out, effectively penalizes sources
who have taken action to reduce emissions.
    EPA acknowledges that an emission-based approach would not be fuel-
neutral or control-neutral. EPA notes that the DC Circuit rejected the
fuel adjustment factors that were used in CAIR to adjust state budgets
based on the type of fuel burned at each covered unit. North Carolina,
531 F.3d 918-21 (rejecting use of fuel adjustments in setting state
NOX budgets). While the proposal's allocation methodology
did not explicitly adopt ``fuel adjustment factors'' for allocation
purposes, EPA recognizes that an emission-based allocation methodology
effectively advantages or disadvantages units based on the type of fuel
they combust.
    In addition, several commenters argued that the proposal's
emission-based methodology would inappropriately reward the highest
emitters under the program with more allowances than their lower-
emitting counterparts would receive. EPA acknowledges that such a
methodology would allocate more allowances to units whose emissions
make up a larger share of the proposed Transport Rule programs' state
budgets. EPA notes that because any allocation patterns under the
Transport Rule FIPs would be established in advance of covered sources'
compliance decisions (i.e., decisions regarding how much to emit under
the programs), covered sources

cannot be ``rewarded'' by adjusting their future emissions. However,
EPA notes commenters' observations that the proposal's methodology
would reduce allocations to units that previously installed pollution
control technology or invested in cleaner forms of generation in
anticipation of CAIR. EPA concluded in review of these comments that
the proposed Transport Rule's allocation methodology unintentionally
yielded this distributional outcome. EPA therefore considered
alternative allocation methodologies described below.
    A substantial portion of the commenters who objected to the
proposal's emission-based allocation option urged EPA to consider
historic heat input based approaches. EPA agreed it should accept
comment on the use of historic heat input-based approaches and
published a NODA to provide an opportunity for comment on two specific
heat input options and the allocations that would result from
application of those options to the proposed Transport Rule state
budgets.
ii. Heat Input Allocation Option 1
    The first heat input option presented by EPA in the NODA (``Option
1'') allocates allowances to units based solely on their historic heat
input. Under this option, EPA would establish a 5-year historic heat
input baseline for each covered unit and allocate allowances to sources
at levels proportional to the each unit's share of the total historic
heat input at all covered units in that state.
    Numerous commenters supported the use of a heat-input based
allocation methodology. These commenters stated that basing allocations
on historic heat input has the following advantages over the proposal's
emission-based allocation methodology:
    (A) For certain types of units, historic heat input data may offer
a better representation of unit-level operation than model projections
of unit-level emissions; furthermore, for all units, historic heat
input is typically represented by quality-assured data reported by
sources from continuous emission monitoring systems, which strengthens
its accuracy.
    (B) Historic heat input data are generally fuel-neutral in that
they do not generally yield higher allocations for units burning or
projected to burn higher emitting fuels.
    (C) Historic heat input data are generally emission-control-neutral
in that they do not generally yield reduced allocations for units that
installed or are projected to install pollution control technology.
    Many commenters also argued that a heat input-based allocation
methodology should be used because, unlike the proposal's emission-
based methodology, a heat-input based methodology would be generally
fuel-neutral and control-neutral and would rely on unit-level quality-
assured data instead of on modeling projections.
    Several commenters expressed support for specific aspects of heat
input option number one. From a technical standpoint, commenters noted
that heat input option 1 relied on the highest-quality and most
transparent data EPA had provided as a basis for allocating allowances
under the Transport Rule programs. They argued that the calculation
methodology for heat input option 1 is more readily re-created and
understood by sources than either the proposal's methodology or EPA's
application of the ``reasonable upper-bound capacity utilization factor
and a well-controlled emission rate'' in heat input option 2 (described
in greater detail below). They also pointed out that it is similar to
methodologies used in previous trading programs, such as the
NOX Budget Trading Program (see 40 CFR 96.42(a) & (b)
(calculating each existing EGU's allocation by multiplying each unit's
historic heat input by 0.15 lb/mmBtu)). In addition, commenters
supported the reliance of heat input option 1 on continuous emission
monitoring system (CEMS) data that are reported to EPA and certified by
the source's designated representative (DR) as accurate and complete.
In addition, many commenters supported EPA's use of historic data
without further transformation by any calculation factors created by
EPA.
    From a policy perspective, commenters highlighted the fuel
neutrality and emission-control neutrality aspects of heat input option
1. They noted that this option does not, in contrast to the proposal's
emission-based methodology, penalize a source, through a reduced
allowance allocation, for having chosen a generation technology or
emission control technology that was more favorable to public health
and the environment. EPA agrees with these observations. The allocation
pattern associated with this option does not advantage or disadvantage
units based on either the fuel consumed or the presence or absence of a
pollution control technology. In this respect, it is a neutral approach
that does not ``reward'' high-emitting units or ``penalize'' low-
emitting units, including, for example, those units on which pollution
control technology was installed in anticipation of CAIR.
    EPA agrees with the aforementioned arguments from these commenters
regarding the technical and policy merits of this heat input-based
allocation methodology. EPA believes that the quality-assured heat
input data reported by EGUs under its programs are among the most
detailed and sound unit-level data accessible by EPA. EPA believes the
calculation of any individual unit's share of this historic heat input
data is a straightforward, clear, and simple calculation to perform,
such that EPA's calculated allowance allocations under this approach
can be relatively easily replicated.
    EPA also agrees with commenters that such data has previously
supported allowance allocation procedures for highly successful program
implementation of the ARP and the NOX Budget Trading Program
(NBP). Notably, Congress chose a heat input-based allocation approach
when authorizing the ARP in title IV of the Clean Air Act, suggesting
that Congress viewed heat input as a reasonable basis for allocation.
Additionally, EPA's selection of a heat input-based approach for the
NBP was not legally challenged, implying that stakeholders generally
saw a heat input-based approach as reasonable.
    EPA also agrees with comments observing that allocations made under
this heat input approach do not advantage or disadvantage units based
on their choice of fuel combustion or pollution control technology, and
that allocations under this approach would thus be ``fuel-neutral'' and
``control-neutral.'' EPA also agrees with commenters that unlike the
proposed rule's emission-based methodology, this heat input methodology
does not yield lower allocation to units that reduced emissions in
advance of the Transport Rule relative to units that did not make such
emission reductions.
    Other commenters objected to the use of a heat-input based
allocation methodology. These commenters argued that the allocation
pattern associated with a heat-input allocation methodology would yield
``windfall profits''--in the form of allowance allocations greatly in
excess of likely emissions--for certain units, particularly with regard
to SO2 allowance allocations for units combusting natural
gas. EPA disagrees with the characterization of the excess allowances
as ``windfall profits.'' Allocations based on heat-input alone are
fuel-neutral and control-neutral. The characterization of the heat-
input allocation methodology as creating ``windfall profits'' for any
unit is based on the assumption that all units should

be allocated allowances based on emissions, not heat input. In arguing
the heat-input approach creates a ``windfall'' for some units,
commenters are assuming that the allocation of allowances above a
unit's projected emissions constitutes a ``windfall''--a conclusion EPA
does not accept. EPA believes that under market-based regulatory
programs, it is appropriate to base initial allowance allocations on a
neutral factor and allow the market to determine the least-cost pattern
of emission reductions in each state to achieve the reductions that
address the state's significant contribution and interference with
maintenance under the final Transport Rule programs. EPA disagrees that
future allowance transactions (following a neutral-factor initial
allocation) in response to these market forces can be characterized as
``windfall profits.'' As explained above, EPA believes it is
appropriate to allocate allowances based on a neutral factor.
Commenters appear to ask EPA, instead of allocating based on a neutral
factor, to consider the unit-level distributional impacts of each
allocation methodology and to select an allocation methodology on the
basis of equity. EPA does not believe it would be appropriate for the
agency to pick an allocation methodology to achieve any particular
distributional outcome as such considerations are not related to the
statutory mandate of CAA section 110(a)(2)(D)(i)(I). Instead, EPA
believes it is appropriate to allocate allowances to sources covered by
its trading programs based on a neutral factor. Furthermore, CAA
section 110(a)(2)(D)(i)(I) requires prohibition of certain emissions
within a state (i.e., a state's significant contribution and
interference with maintenance). It does not direct EPA to use any
particular methodology for allocating allowances under a trading
program designed to ensure all such emissions are prohibited. As such,
EPA believes it is appropriate to allocate allowances based on a
neutral factor representing fossil energy content used to produce
electricity. Detailed considerations of equity, as the DC Circuit
reminded EPA, are not related to the statutory mandate of section
110(a)(2)(D)(i)(I). North Carolina, 531 F.3d 921.
    Some commenters objected to the use of a heat input-based approach
by arguing that higher-emitting units would not receive an initial
allocation sufficient to cover their emissions. EPA does not believe it
is reasonable to expect initial allocations to cover each unit's
emissions under a trading program aimed at producing meaningful
emission reductions. In its administration of prior trading programs
such as the ARP and the NBP, EPA has made initial allowance allocations
using a heat input-based approach, and virtually all covered sources
have successfully complied at the end of each compliance period by
making cost-effective emission reductions, purchasing additional
allowances through robust markets to cover emissions, or undertaking
both types of activities. EPA disagrees with commenters' arguments that
allowance allocations should be used to compensate units with higher
emissions.
iii. Heat Input Allocation Methodology Option 2
    The second heat input option presented by EPA for public comment
also would use historic heat input but would apply a constraint to
unit-level allocations under certain circumstances. Specifically, under
this option unit-level allocations would not be allowed to exceed what
EPA determines, based on historic emissions and other factors, to be
the units' ``reasonably foreseeable maximum emissions.''
    To apply this constraint, EPA first would determine whether the
allocation to a unit under an unconstrained heat-input methodology
would exceed that unit's maximum historic emissions of the relevant
pollutant since 2003 ``in order to reflect unit-level emissions before
and after the promulgation of the CAIR'' (76 FR 1115). Using this
baseline would enhance the neutrality of the maximum historic emissions
data because it would capture the highest emissions of the unit during
that period regardless of what fuels it combusted or what pollution
control devices were installed and used at any particular time during
that period. In other words, a unit's allocation would not be reduced
due to a recent decision to switch fuels or install pollution controls.
    Second, for this option, EPA then would adjust that maximum
historic emissions data by applying a ``well-controlled rate maximum,''
designed to place ``a reasonably foreseeable maximum emissions level
reflecting a reasonable upper-bound capacity utilization factor and a
well-controlled emission rate that all units (regardless of the type of
fuel they combust) can meet for the pollutant'' (76 FR 1115). This
option would constrain certain units' allocations that, if based solely
on historic heat input, would be determined by EPA to be ``in excess of
their reasonably foreseeable maximum emissions'' under the Transport
Rule programs (76 FR 1115).
    As noted above, commenters offered numerous arguments in favor of
using a historic heat input approach. These arguments apply equally to
heat input option 1 and heat input option 2. EPA also received numerous
comments comparing the two heat input options presented.
    Many commenters preferred heat input option 1's reliance purely on
historic data as compared with heat input option 2's reliance on that
data modified by the application of EPA-determined ``reasonable upper
bound capacity factors'' and ``well-controlled emission rates.''
Commenters also criticized the complexity of these modification factors
in heat input option 2. While EPA believes both options represent
viable approaches, the Agency agrees with commenters that the
application of these factors increase the complexity of allocation
determinations and would adjust unit-specific historic data by applying
EPA-created factors generically determined for broad categories of
units.
    Some commenters suggested that EPA's application of these
modification factors could also represent legal vulnerabilities for the
Transport Rule. In particular, they were concerned that the capacity
factors and well controlled emission rates presented as part of heat
input option 2 could be perceived as arbitrary. While EPA does not
agree that these modification factors are arbitrary, the Agency does
recognize that application of such EPA-created generic factors in
determining unit-specific allocations increases the complexity of the
allocation approach and raises issues regarding whether such generic
factors are appropriately applied to each individual unit.
iv. General Comments on EPA's Authority To Allocate Allowances
    Numerous commenters also noted that EPA has generally broad
authority in selecting an allocation methodology under CAA sections
110(a)(2)(D)(i)(I) and 302(y).\80\ EPA agrees with commenters that the
Agency has broad discretion in this area. Neither the CAA nor the D.C.
Circuit Court's opinion in North Carolina specifies a particular
methodology that EPA must use to allocate allowances to individual
units.

CAA section 110(a)(2)(D)(i)(I) requires prohibition of emissions
``within the state'' that significantly contribute to nonattainment or
interfere with maintenance and gives states broad discretion to develop
a control program in a SIP that achieves this objective. EPA has
similarly broad discretion when issuing a FIP to realize this
objective. Moreover, while the definition of FIP in CAA section 302(y)
clarifies that a FIP may include ``enforceable emission limitations or
other control measures, means or techniques (including economic
incentives, such as marketable permits or auctions of emissions
allowances),'' this section does not require EPA to use any particular
methodology to allocate allowances under a FIP trading program. In
light of this lack of direction in the CAA concerning allowance
allocation, EPA has broad discretion to select an allocation
methodology that is reasonable and consistent with the goals of CAA
section 110(a)(2)(D)(i)(I).
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    \80\ CAA section 302(y) defines the term ``Federal
implementation plan'' as ``a plan (or portion thereof) promulgated
by the Administrator to fill all or a portion of a gap or otherwise
correct all or a portion of an inadequacy in a State implementation
plan, and which includes enforceable emission limitations or other
control measures, means or techniques (including economic
incentives, such as marketable permits or auctions of emissions
allowances), and provides for attainment of the relevant national
ambient air quality standard.''
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    The body of public comment makes it clear that no allocation option
could be deemed satisfactory from the perspective of all stakeholders.
Public comments from most states and industrial stakeholders with a
substantial interest in how EPA allocates allowances under the
Transport Rule FIPs expressed support for an historical heat input-
based approach as opposed to the proposal's emission-based approach.
Most commenters favored this historical heat input data basis as the
most sound and offered technical data corrections, which EPA considered
and generally used in the final rule. EPA believes it is reasonable to
select a heat input-based approach for the final Transport Rule because
this approach is consistent with the rule's statutory objectives and
has been found, when implemented in prior trading programs, to be a
credible, workable allocation approach.
b. Final FIP Allocation Methodology
    After consideration of all comments, EPA decided to allocate
allowances to individual units based on that units' share of the
state's historic heat-input, but to ensure that no unit's allocations
exceed that unit's historic emissions. EPA decided to use the
allocation methodology originally presented as heat input option 2,
modified in response to public comments. EPA decided to use heat input
option 2 but without the application of the ``reasonable upper-bound
capacity utilization factor and a well-controlled emission rate''
factors. This allocation approach reflects the Agency's response to
extensive public comment on the options presented in the proposed
Transport Rule and subsequent NODAs and is a logical outgrowth of those
actions. EPA is using this approach to allocate allowances under the
FIPs for all four trading programs. Further details on the calculation
and implementation of this approach are provided below in section
VII.D.1.c and can also be found in the Allowance Allocation Final Rule
TSD in the docket for this rulemaking.
    The principal reasons for this decision are:
     EPA believes that existing-unit allowance allocation under
the Transport Rule should not generally advantage or disadvantage units
based on the selection of fuels consumed or of pollution controls
installed at a given unit in anticipation of either the Clean Air
Interstate Rule or the Transport Rule, i.e., fuel or control decisions
taken from 2003 onward. An approach that does not advantage or
disadvantage units in this way avoids allocating in a way that would
effectively penalize units that have already invested in cleaner fuels
or other pollution reduction measures that will continue to deliver
important emission reductions under this rulemaking. The approach
selected in the final rule generally does not penalize such units and
is thus generally fuel-neutral and control-neutral in its allocation
determinations.
     EPA finds that the selected approach maximizes
transparency and clarity of allowance allocations. EPA has already made
public the historic heat input and historic emissions data on which
this approach is based, and its application to calculate unit-level
allocations in each state under that state's emission budgets finalized
in this Transport Rule can be relatively easily replicated.
     EPA finds that quality-assured historic CEMS-quality data
used to implement this approach represent the most technically superior
data available to EPA at the time of this rulemaking for calculating
unit-level allocations. The selected approach relies on unmodified
historic data reported directly by the vast majority of covered
sources, whose designated representatives have already attested to the
validity and accuracy of this data. EPA agrees with commenters that
allowance allocations should be based on quality-assured data to the
maximum extent possible. This approach uses the most accurate data
currently available to EPA.
     Heat-input based approaches were used to allocate
allowances under both the NOX Budget Trading Program and the
Acid Rain Program. Allocation under these programs was readily and
easily administered, and the programs achieved or exceeded their
environmental goals. The selected approach's use of heat input as a
basis for allocations builds on prior legislative and administrative
approaches to allowance allocations for trading programs.
     EPA also finds that the selected approach's addition of a
constraint to heat input-based allocations where such allocations would
otherwise exceed a unit's maximum historic emissions is a reasonable
extension of a heat input-based allocation approach. The Transport Rule
trading programs are established to achieve overall emission reductions
in each covered state. As a group, covered sources within each state
must make the necessary reductions under these programs. In light of
each program's goal to reduce each state's overall emissions, it is
logical and consistent with that goal that the starting point for each
source under these programs--i.e., the initial allocations of shares of
the state budget to covered units--be an amount of allowances no
greater than each unit's maximum historic emissions. Under the trading
programs, any source may emit a ton of SO2 or NOX
for which it holds a corresponding allowance, which it may acquire
either by initial allocation or by subsequent purchase, to the extent
consistent with the assurance provisions (discussed elsewhere in this
preamble) that ensure achievement of the requisite overall reductions
in each state. Consequently, the initial allocations to the units at
each source are the starting point for each source's efforts to comply
with the allowance-holding and assurance provision requirements, but do
not determine the source's strategies for compliance and ultimate level
of emissions. EPA believes that a starting point of unit-level heat
input-based allocations constrained not to exceed each specific units'
maximum historic emissions is reasonable and consistent with the
program goals of reducing overall emissions in each state: Each
existing unit is allocated an amount that either reflects reduced unit
emissions or does not exceed historic emissions, and, from that
starting point, the units, as a group, reduce overall emissions to the
level required for each state. Conversely, EPA believes that a starting
point allocating some units more than they have ever emitted would be
illogical in programs aimed at reducing overall emissions.
    EPA believes that this selected allocation methodology for the
final Transport Rule FIPs is within its authority under the Clean Air
Act. Section 110(a)(2)(D)(i)(I) of the CAA

requires that emissions ``within a state'' that significantly
contribute to nonattainment or interfere with maintenance in another
state be prohibited. In the final Transport Rule, EPA analyzed each
individual state's significant contribution and interference with
maintenance and calculated budgets that represent each state's
emissions after the elimination of prohibited emissions in an average
year. The methodology used to allocate allowances in a state budget to
individual units in the state has no impact on that state's budget or
on the requirement that the state's emissions not exceed that budget
plus variability. Regardless of the allocation methodology used, the
state's responsibility for eliminating its significant contribution and
interference with maintenance remains unchanged. This is reflected by
the fact that allocations under each state's budget, regardless of how
they are made, cannot change that state's budget. In sum, the
allocation methodology has no impact on the final rule's ability to
satisfy the statutory mandate of CAA section 110(a)(2)(D)(i)(I) to
eliminate significant contribution to nonattainment and interference
with maintenance.
    Consistent with its broad authority in CAA sections
110(a)(2)(D)(i)(II) and 302(y), EPA believes that data quality, fuel-
neutrality, control-neutrality, transparency, clarity, consistency with
program goals, and successful experience in previous trading programs
are reasonable factors on which to base the selection of an allowance
allocation methodology for existing units for the final Transport Rule.
EPA believes that the transparency and clarity of this allocation
approach builds credibility with the public that the government is
distributing a public resource--i.e., allowances--precisely as stated
in this rulemaking, with clear execution that can be relatively easily
verified.
    EPA also believes that the final Transport Rule's heat input-based
approach for existing units is consistent with the goals of the Clean
Air Act because it allocates allowances to existing units on the basis
of a neutral factor that does not advantage or disadvantage a unit
based on what fuel the unit burns or whether or not a unit has
installed controls in anticipation of these regulations. In contrast,
allocations under the proposal's emission-based methodology would give
a greater share of allowances to units with higher emission rates,
which are generally responsible for a greater share of a state's total
emissions. Because these higher-emitting rate units are generally
responsible for a greater share of emissions, it follows that they are
also responsible for a greater share of a state's significant
contribution to nonattainment and interference with maintenance. The
proposal's emission-based allocation methodology would disadvantage one
of two otherwise identical existing units if it invested in emission
reductions in anticipation of the Clean Air Interstate Rule or this
final Transport Rule.
    The heat-input allocation methodology selected for the final
Transport Rule does not have this flaw. In contrast to the proposal's
emission-based allocation approach, the heat input allocation
methodology selected by EPA yields a smaller proportion of allowances
relative to emissions to higher-emission-rate units and a higher
proportion of allowances relative to emissions to lower-emission-rate
units. For example, assume that in a state with two units and in a
baseline year, Unit A combusts 100 mmBtu of heat input and emits 1,000
tons while Unit B combusts 100 mmBtu of heat input and emits only 500
tons. Assume also that this state's future Transport Rule emissions
budget for this pollutant is only 500 tons. Because Units A and B each
make up an even share of historic heat input for the state, the final
rule's heat input-based approach would allocate the same share of
allowances (250 tons) to each unit. In this example, Unit A's initial
allocation of 250 is a smaller proportion of its historic emissions (25
percent of its baseline 1,000-ton emissions), while Unit B's initial
allocation of 250 is a larger proportion of its historic emissions (50
percent of its baseline 500-ton emissions). Therefore, Unit B's ability
to emit fewer tons per mmBtu of heat content used for generating
electricity (as compared with Unit A) results in Unit B receiving a
larger proportion of its historic emissions as an initial allocation
share than Unit A receives.
    This relative distributional pattern yielded is consistent with the
goals of CAA section 110(a)(2)(D)(i)(I) because under this
distribution, higher-emitting units, which are responsible for a
greater share of the state's significant contribution to nonattainment
and interference with maintenance, would require relatively more
allowances in order to cover their pre-existing emissions than would
lower-emitting units. EPA believes this initial allocation pattern is
an appropriate reflection of the goals of CAA section
110(a)(2)(D)(i)(I).
    The heat input-based allowance methodology selected by EPA is fuel-
neutral, control-neutral, transparent, based on reliable data, and
similar to the allocation methodologies used in the NOX SIP
Call and Acid Rain Program. For all these reasons, EPA determined that
it is appropriate to use a heat input-based allocation methodology in
this rule.
    In addition, this allocation methodology is similar to an output-
based allocation approach, which would base allocations on the quantity
of electricity generated (rather than energy content combusted) and
would also be fuel-neutral, control-neutral, and able to reward
generation units that operate the most efficiently. Many state and
industry commenters advocated using an output-based approach due to its
reported strong value in promoting efficiency. However, at this time
EPA does not have access to unit-level output data that is as quality-
assured or comprehensive as its data sets on heat input across the
units considered. Therefore, EPA is using a heat input-based approach
under the Transport Rule in part due to its ability to serve as a
reasonable proxy for an output-based standard using the most quality-
assured data that EPA has to date.
    In the NODA, EPA noted that final state budgets and allocations may
differ from the proposed budgets and allocations because EPA was still
in the process of updating its emission inventories and modeling in
response to public comments, including comments on IPM. Thus, unit-
level allocations in the NODA provided an indication of the
proportional share of a state's budget that would be allocated to
individual existing units if the alternative methodologies were used.
The allocations made final today are based on budgets that reflect the
updated modeling and comments received during the comment period.
c. Calculation of Existing Unit Allocations Under the Final Transport
Rule FIPs
    Allocations under this final methodology for each existing unit are
determined by applying the following steps.
    1. For each unit in the list of potential existing Transport Rule
units, annual heat input values for the baseline period of 2006 through
2010 are identified using data reported to EPA or, where EPA data is
unavailable, using data reported to the Energy Information
Administration (EIA). For a baseline year for which a unit has no data
on heat input (e.g., for a baseline year before the year when a unit
started operating), the unit is assigned a zero value. (Step 2 explains
how such zero values are treated in the calculations.) The allocation
method uses a 5-year

baseline to approximate a unit's normal operating conditions over time.
    2. For each unit, the three highest, non-zero annual heat input
values within the 5-year baseline are selected and averaged. Selecting
the three highest, non-zero annual heat input values within the five-
year baseline reduces the likelihood that any particular single year's
operations (which might be negatively affected by outages or other
unusual events) would determine a unit's allocation. If a unit does not
have three non-zero heat input values during the 5-year baseline
period, EPA averages only those years for which a unit does have non-
zero heat input values. For example, if a unit has only reported data
for 2008 and 2009 among the baseline years and the reported heat input
values are 2 and 4 mmBtus, respectively, then the unit's average heat
input used to determine its pro-rata share of the state budget is
(2+4)/2 = 3.
    3. Each unit is assigned a baseline heat input value calculated as
described in step 2, above, referred to as the ``3-year average heat
input.''
    4. The 3-year average heat inputs of all covered existing units in
a state are summed to obtain that state's total ``3-year average heat
input.''
    5. Each unit's 3-year average heat input is divided by the state's
total 3-year average heat input to determine that unit's share of the
state's total 3-year average heat input.
    6. Each unit's share of the state's total 3-year average heat input
is multiplied by the existing-unit portion of the state budget (i.e.,
the state budget minus the state's new unit set-aside and, if
applicable, minus the Indian country new unit set-aside) to determine
that unit's initial allocation.
    7. An 8-year (2003-2010) historic emissions baseline is established
for SO2, NOX, and ozone-season NOX
based on data reported to EPA or, where EPA data is unavailable, based
on EIA data. This approach uses this 8-year historic emissions baseline
in order to capture the unit-level emissions before and after the
promulgation of CAIR.