8. For each unit, the maximum annual historic SO2 and
NOX emissions are identified within the 8-year baseline.
Similarly, the maximum ozone season NOX emissions from the
8-year baseline for each unit are identified. These values are referred
to as the ``maximum historic baseline emissions'' for each unit.
    9. If a unit has an initial historic heat-input based allocation
(as determined in step 6) that exceeds its maximum historic baseline
emissions (as determined in step 8), then its allocation equals the
maximum historic baseline emissions for that unit.
    10. The difference (if positive) under step 9 between a unit's
historic heat-input-based allocation and its ``maximum historic
baseline emissions'' is reapportioned on the same basis as described in
steps 1 through 6 to units whose historic heat-input-based allocation
does not exceed its maximum historic baseline emissions. Steps 7, 8,
and 9 are repeated with each revised allocation distribution until the
entire existing-unit portion of the state budget is allocated. The
resulting allocation value is rounded to the nearest whole ton using
conventional rounding.
    Table VI.D-1 below provides an illustrative application of the
steps 1-10 in a hypothetical state.

 Table VI.D-1--Demonstration of Allocations Using Final Allocation Methodology in a Three-Unit State With an 80-
                                                Ton State Budget
----------------------------------------------------------------------------------------------------------------
                                                 Steps 1-6      Steps 7, 8, 9      Steps 1-9         Step 10
                                             ----------------------------------    reiterated   ----------------
                                                                               -----------------
                                                  Initial          Maximum          Revised
                                               historic heat       historic      historic heat        Final
                                                input-based        baseline       input-based       allocation
                                                 allocation       emissions        allocation
----------------------------------------------------------------------------------------------------------------
Unit A......................................               20               16              N/A               16
Unit B......................................               30               50               32               32
Unit C......................................               30               50               32               32
----------------------------------------------------------------------------------------------------------------

2. Allocations to New Units
    EPA is finalizing--similar to the proposal (75 FR 45310)--an
approach to allocate emission allowances to new units from new unit
set-asides in each state. A ``new unit'' may be any of the following:
(1) A covered unit commencing commercial operation on or after January
1, 2010; (2) any unit that becomes a covered unit by meeting
applicability criteria subsequent to January 1, 2010; (3) any unit that
relocates into a different state covered by the Transport Rule; \81\
and (4) any existing covered unit that stopped operating for 2
consecutive years but resumes commercial operation at some point
thereafter.
---------------------------------------------------------------------------

    \81\ Existing- or new-unit allocations drawn from the budget of
the relocated unit's original state are replaced by new unit set-
aside allocations from the budget of the unit's relocation state in
order to generally ensure that allocations are drawn from the
correct state budget.
---------------------------------------------------------------------------

    The proposed Transport Rule would have required that owners and
operators initially request allowances from the new unit set-aside when
the unit first became eligible for an allocation. EPA now believes that
it can identify which units become eligible and when they become
eligible, based on information provided in other submissions (e.g.,
certificates of representation, monitoring system certifications, and
quarterly emissions reports) that the final rule already requires such
units to make to EPA. EPA concludes that requiring owners and operators
to submit requests of new unit set-aside allocations would impose an
unnecessary burden on the owners and operators, as well as on EPA, and
therefore EPA has removed this requirement in the final rule.
    The following sections describe the methodology in the final
Transport Rule for allocating to new units, how EPA determined the size
of new unit set-asides in the final rule, and how EPA has provided for
allocations to new units that locate in Indian Country.
a. New Unit Allocation Methodology
    The proposal's new unit allocation methodology did not provide any
allocation for a new unit's first control period of commercial
operation. Some commenters expressed concern about the lack of new unit
allocations the first year of commercial operation. In order to address
this concern, EPA is modifying the new unit allocation methodology in
this final rule to include allocations to new units for the first
control period in which the units are in commercial operation, as well
as for control periods in subsequent years.

    The final rule's allocation to new units is performed in two
``rounds.'' The first round is the same as the new unit allocation
procedures in the proposal (except for elimination of the requirements
that owners and operators request the allocations) and occurs during
the control period for which the allocations are made. These first
round allocations are based on new unit emissions during the prior
control period and are recorded in allowance accounts in the Allowance
Management System for the units by August 1 of each control period. For
example, for the 2012 vintage year, ``first-round'' allocations would
be made to new units by August 1, 2012 based on their emissions in the
2011 control period (as monitored and reported in accordance with Part
75 of the Acid Rain Program regulations). If the new unit set-aside is
insufficient to accommodate first round allocations reflecting all new
units' prior control period emissions, the first round allocations are
made pro rata to new units based on their share of total new unit
emissions in the prior control period.
    The second round of allocations accommodates new units that come
online during the control period for which the allocations are made and
did not therefore receive any allocation in the first round. The second
round also accommodates new units that come online partway into the
prior control period and therefore received an allocation in the first
round that did not extend to cover operations in a full control period.
This second round of new unit allocation is therefore applicable only
to new units coming online either during the control period of the
allocation or during the control period immediately prior. New units
coming online earlier than the previous control period only receive
first-round allocations from the new unit set-asides, as first-round
allocations to those units are based on operational data spanning an
entire control period.
    Second-round allocations are based on new unit emissions during the
same control period as the vintage year of the allowances allocated.
For example, for the 2012 vintage year, ``second-round'' allocations
are based on the difference between the new unit's emissions in the
2012 control period and the new unit allocation (if any) that the unit
received in the first round of allocations. For a unit coming online in
2012, this amount equals its total emissions during the 2012 control
period. For a unit coming online in 2011, this amount equals its
incremental emissions in 2012 beyond its emissions in 2011, as such a
unit would have already received a first-round allocation from the new
unit set-aside based on its emissions in 2011. Second-round allocations
are recorded in allowance accounts by November 15 for the
NOX ozone season trading program (ahead of the December 1
compliance deadline) and by February 15 of the following calendar year
for NOX and SO2 annual trading programs (ahead of
the March 1 compliance deadline).
    This methodology only allocates in the second round whatever
allowances remain in the new unit set-asides after the first-round
allocations have been recorded. If the new unit set-aside available for
second round allocations is insufficient to accommodate allocations
based on the difference between control period emissions and any first
round allocations for the units involved, then the second round
allocations are made pro rate to the new units based on their share of
the total of such differences.
b. Determination of New Unit Set-Asides
    The proposed Transport Rule identified new units using a threshold
online date of January 1, 2012, whereas the final Transport Rule uses a
threshold online date of January 1, 2010. As explained above, EPA
adjusted this cutoff date because the final Transport Rule's allocation
methodology for existing units requires that EPA possess at least 1
full year of historic data in order to calculate allocations. As a
consequence, EPA recognizes that the proposal's methodology to
determine the size of the new unit set-asides based only on new EGUs
forecast by the model would fail to account for known EGUs that have
come online, or are planned to come online, after January 1, 2010.
Therefore, EPA has modified its approach to determining the size of the
new unit set-asides in the final rule to account for both ``potential''
units (i.e., those that are not yet planned or under construction but
are projected by modeling to be built) and ''planned'' units (i.e.,
those that are known units with planned online dates after January 1,
2010). EPA uses the distinction between ``potential'' and ``planned''
new units to determine the ultimate size of each state's new unit set-
aside (as a percentage of that state's budgets for each pollutant
covered); however, the new unit allocation methodology described above
applies the same to ``potential'' and ``planned'' new units.
    The first step of EPA's analysis to determine the new unit set-
asides accounts for likely future emissions from potential units, and
its methodology is taken directly from the Transport Rule proposal but
reflects updated modeling (see ``Allowance Allocation to Existing and
New Units Under the Transport Rule Federal Implementation Plans'' TSD
for detailed findings). This analysis informed EPA's decision to
establish a minimum new unit set-aside size of 2 percent of each
state's budget for each pollutant that is configured to accommodate
future emissions from potential units.
    For the final rule, EPA augmented its new unit set-aside
determination to account for ``planned'' units through an additional
step. Because the location of these ``planned'' units is known and
identified in EPA modeling, this second step is a state-specific
modification of the size of the new unit set-asides. That is, EPA only
increased new unit set-asides above the 2 percent minimum established
in the first step for states that had additional known units coming
online between January 1, 2010, and January 1, 2012.
    The increases made to the new unit set-asides for these planned
units reflect the projected emissions from these units. Therefore, if
the expected emissions of a given pollutant from all ``planned'' new
units in a given state were equal to 3 percent of that state's budget
for that pollutant, then EPA added that amount to the base 2 percent
new unit set-aside (creating a hypothetical new unit set-aside of 5
percent for that pollutant in that state). See ``Allowance Allocation
to Existing and New Units Under the Transport Rule Federal
Implementation Plans'' TSD for detailed results showing how EPA
determined the size of each new unit set-aside reflecting the
application of both of the steps described above. This approach to
determining the size of state new unit set-asides is a logical
outgrowth of the proposal, the NODA on allowance allocations, and
updated modeling results. In fact, EPA received comments that using a
January 1, 2010 cutoff date for distinguishing between existing and new
units would result in the new unit set-aside, as proposed, being
insufficient to meet the needs of units already under construction. EPA
believes that the approach adopted in the final rule results in new
unit set-asides that reasonably accommodate the foreseeable emissions
from both planned and potential new units in each state.
    The new unit allocation percentages for each state are shown in
Table VII.D.2-1.

        Table VII.D.2-1--Percentage of State Emission Budgets for Allowances in State New Unit Set-Asides
----------------------------------------------------------------------------------------------------------------
                                                                                Ozone-season
                                                                    Annual SO2      Annual NOX          NOX
----------------------------------------------------------------------------------------------------------------
Alabama.........................................................              2%              2%              2%
Arkansas........................................................  ..............  ..............              2%
Florida.........................................................  ..............  ..............              2%
Georgia.........................................................              2%              2%              2%
Illinois........................................................              5%              8%              8%
Indiana.........................................................              3%              3%              3%
Iowa............................................................              2%              2%  ..............
Kansas..........................................................              2%              2%  ..............
Kentucky........................................................              6%              4%              4%
Louisiana.......................................................  ..............  ..............              3%
Maryland........................................................              2%              2%              2%
Michigan........................................................              2%              2%  ..............
Minnesota.......................................................              2%              2%  ..............
Mississippi.....................................................  ..............  ..............              2%
Missouri........................................................              2%              3%  ..............
Nebraska........................................................              4%              7%  ..............
New Jersey......................................................              2%              2%              2%
New York........................................................              2%              3%              3%
North Carolina..................................................              8%              6%              6%
Ohio............................................................              2%              2%              2%
Pennsylvania....................................................              2%              2%              2%
South Carolina..................................................              2%              2%              2%
Tennessee.......................................................              2%              2%              2%
Texas...........................................................              5%              3%              3%
Virginia........................................................              4%              5%              5%
West Virginia...................................................              7%              5%              5%
Wisconsin.......................................................              5%              6%  ..............
----------------------------------------------------------------------------------------------------------------

c. Procedures for Allocating New Unit Set-Asides
    For the first round of new unit set-aside allocations, the
Administrator will promulgate a notice of data availability informing
the public of the specific new unit allocations and provide an
opportunity for submission of objections on the grounds that the
allocations are not consistent with the requirements of the relevant
final rule provisions. A second notice of data availability will
subsequently be promulgated in order to make any necessary corrections
in the specific new unit allocations. As discussed elsewhere in this
preamble, the final rule establishes a different schedule for
promulgation of these notices of data availability than the proposed
rule. In particular, a single set of deadlines (i.e., for the first
notice in the first round of allocations, June 1 of the year for which
the new unit allocations are described in the notice and, for the
second notice of the first round, August 1 of that year) for
promulgation of the notices is established for all of the Transport
Rule trading programs. EPA believes that these deadlines will provide
sufficient time for EPA to obtain final emissions data for the prior
year for the units involved and to calculate the allocations and
promulgate the notices. Further, the approach of using the same
deadline for all of the Transport Rule trading programs will simplify
EPA's implementation and reduce the complexity of the process for
source owners and operators.
    For the second round of new unit set-aside allocations, the
Administrator will also promulgate two notices of data availability.
However, the deadlines for the notices differ for the NOX
ozone season trading program and for the SO2 and
NOX annual trading programs because control period emissions
data (used in making second round allocations) become available sooner,
and the compliance deadline for holding allowances covering emissions
is sooner, in the NOX ozone season trading program. The
control period in the NOX ozone season program ends on
September 30, and fourth quarter emissions reports must be submitted to
EPA by October 30, while the control periods in the SO2 and
NOX annual programs end on December 31 and fourth quarter
emission reports are due by January 30. Further, in order for the
second round allocations to be available to be used for compliance with
the allowance-holding requirement, the second round needs to be
completed before the compliance dates, which are December 1 in the
NOX ozone season program and March 1 in the SO2
and NOX annual programs. Consequently, for the
NOX ozone season program the Administrator will promulgate
by September 15 a notice of data availability identifying the units
eligible for second round allocations and by November 15 a second NODA
of the list of eligible units and their second round allocations, which
will also be recorded in the allowance accounts by that date. The
comparable deadlines for the SO2 and NOX annual
programs are December 15 and February 15. EPA believes that these
deadlines will provide sufficient time for EPA to identify the units
and obtain their needed emissions data and to calculate the allocations
and promulgate the notices.
d. Addition of Allowances to New Unit Set-Asides
    As discussed elsewhere in this preamble, EPA proposed that, if a
unit with an existing-unit allocation does not operate for 3
consecutive years, the allowances that would otherwise have been
allocated to that unit, starting in the seventh year after the first
year of non-operation, would be allocated to the new unit set-aside for
the state in which the retired unit is located. EPA is retaining this
provision in the final rule but is changing the time of non-operation
to 2 years and the time of allowance allocation to a non-operating unit
to 4 years. Starting in the fifth year of non-operation, allowances
will be allocated to the new unit set-aside for the state in which the
non-operating unit is located.
    EPA received comments that the new unit set-asides were not
sufficient to

encourage the operation of new units. One commenter suggested that
allowance allocations should cease after 3 years of non-operation
because the financial incentive gained from receiving allowances beyond
the 3-year period is insignificant relative to operating and fuel
costs. Another commenter said that providing allowances to non-
operating units is unnecessary and distorts the market.
    In addition to increasing the size of the new unit set-aside in
this final rule, as described above, EPA is terminating existing unit
allocations starting in the fifth year after the unit does not operate
for 2 consecutive years and reallocating to the new unit set-aside the
allowances that the unit otherwise would have received for the fifth
and subsequent years in order to make them available for new units in
the state. This approach allows the new unit set-asides to grow over
time.
e. Allocations to New Units Locating in Indian Country
    EPA received several comments on the proposed rule that it did not
explicitly address the distribution of allowances to potential new
units built in Indian country. EPA recognized this concern and
requested comment on this topic in the January 7, 2011 NODA.
    In the final rule, EPA is providing a mechanism to make allowances
available in the future for new units built in Indian country. The
final rule establishes an Indian country new unit set-aside for each
pollutant in each state whose borders encompass Indian country (i.e.,
Florida, Iowa, Kansas, Louisiana, Michigan, Minnesota, Mississippi,
Nebraska, New York, North Carolina, South Carolina, Texas, and
Wisconsin). EPA will retain administration of these Indian country new
unit set-asides as part of the Transport Rule trading programs whether
or not a Transport Rule state elects to modify or replace the Transport
Rule FIPs through approved SIP revisions. EPA does not create Indian
country new unit set-asides for states lacking Indian country within
their borders.
    EPA determined the size of each Indian country new unit set-aside
by calculating the ratio of square mileage of Indian country to the
square mileage of the state within whose borders Indian country is
located. This calculation yielded a maximum percentage of 5 percent
when assessing all of the states encompassing Indian country subject to
the final Transport Rule; this is referred to as the ``5 percent Indian
country factor'' below. To determine the maximum percentage, EPA used
the American Indian Reservations/Federally Recognized Tribal Entities
dataset, which contains data for the 562 federally recognized tribal
entities in the contiguous U.S. and Alaska. EPA accessed the data to
analyze the Transport Rule region and compare the square miles of
Indian country with the square miles of the Transport Rule state that
includes the Indian country. EPA then took the highest percentage as
the number to be applied across all states with Indian country to
determine the size of the Indian country new unit set-aside pertinent
to that state's budgets under the Transport Rule. EPA chose to use the
maximum percentage (5 percent) from the Indian country analysis to
determine the Indian country set-aside for each state on the basis that
this approach would reserve a reasonable number of allowances from each
state's budget for potential allocation to new units that may locate in
Indian country within that state's borders. Any allowances from the
Indian country new unit set-aside that are not allocated in a given
control period are redistributed into the state's new unit set-aside.
As discussed above, any allowances not allocated from that new unit
set-aside are redistributed to existing units based on the existing
units' share of the total existing unit allocations.
    To calculate the size of each tribal new unit set-aside, EPA
applied this 5 percent Indian country factor to the portion of the
state's new unit set-aside originally determined by accounting for
``potential'' new units, which as described above was set at 2 percent
of each pollutant's budget in each state. Therefore, the Indian country
new unit set-aside is 5 percent of 2 percent of a state's budget, or
0.1 percent of that total state budget. EPA did not apply the 5 percent
Indian country factor to the state-specific planned unit portion of
each state's new unit set-aside because the planned unit portion is
determined using projected emissions from specific, known units coming
online after January 1, 2010, and none of these known units are located
in Indian country.
    The Indian country new unit set-asides in the following Transport
Rule states with Indian Country are shown in Table VII.D.2-2.

                        Table VII.D.2-2--New Unit Set-Aside Allowances for Indian Country
                                                     [Tons]
----------------------------------------------------------------------------------------------------------------
                                                                                Ozone-
                                                                   SO2                Annual    Ozone-    season
                                                      SO2 2012-    2014     Annual     NOX      season     NOX
                                                         2013      and    NOX 2012-    2014   NOX 2012-    2014
                                                                  beyond     2013      and       2013      and
                                                                                beyond              beyond
----------------------------------------------------------------------------------------------------------------
Florida.............................................  .........  .......  .........  .......        28        28
Iowa................................................       107        75        38        38  .........  .......
Kansas..............................................        42        42        31        26  .........  .......
Louisiana...........................................  .........  .......  .........  .......        13        13
Michigan............................................       229       144        60        58  .........  .......
Minnesota...........................................        42        42        30        30  .........  .......
Mississippi.........................................  .........  .......  .........  .......        10        10
Nebraska............................................        65        65        26        26  .........  .......
New York............................................        27        19        18        18         8         8
North Carolina......................................       137        58        51        42        22        18
South Carolina......................................        89        89        32        32        14        14
Texas...............................................       244       244       134       134        63        63
Wisconsin...........................................        80        40        32        30  .........  .......
----------------------------------------------------------------------------------------------------------------

    Under the FIPs, EPA allocates allowances from Indian country new
unit set-asides in essentially the same manner as it allocates
allowances from state new unit set-asides. The approach for
identifying, and determining the number of allowances allocated to, new
units in Indian country is the same as the approach for identifying and
determining allocations for non-Indian country new units covered by the
state new unit set-aside, and allocations are made in two rounds using
the same schedules for promulgation of notices of data availability.
However, as discussed above, unallocated allowances in the Indian
country set-asides are handled differently from unallocated allowances
in the state new unit set-asides in that unallocated Indian country new
unit set-aside allowances are first transferred back into the state new
unit set-aside and then, if still not allocated to new units, are
distributed to existing units in the state. EPA believes that the
above-described approach in establishing and handling the Indian
country new unit set-asides and state new unit set-asides is a
reasonable way of making a sufficient amount of allowances available
for new units in the state and Indian country located in the state and
ensuring that the entire state budget is available to either new or
existing units in the state and Indian country. EPA retains
administration of these Indian country new unit set-asides (and, of
course, the portions of state budgets that comprise these set-asides)
as part of the Transport Rule trading programs even if a state elects
to modify or replace the Transport Rule FIPs through approved SIP
revisions. EPA continues to manage and distribute the Indian country
new unit set-aside allowances in the same manner as under the FIPs.
Unallocated allowances in the Indian country new unit set-aside will be
returned to the portion of the state budget allocated under the
approved SIP's allocation provisions. EPA believes that this approach
is reasonable because EPA, rather than the states, has the authority
and responsibility of administering the Transport Rule with regard to
new units that locate in Indian country.

E. Assurance Provisions

    To ensure that the FIPs require the elimination of all emissions
that EPA has identified that significantly contribute to nonattainment
or interfere with maintenance within each individual state, the Agency
is adopting assurance provisions in addition to the requirement that
sources hold allowances sufficient to cover their emissions. These
assurance provisions limit emissions from each state to an amount equal
to that state's trading budget plus the variability limit for that
state (i.e., the state assurance level). As discussed in section VI of
this preamble, this variability limit takes into account the inherent
variability in baseline EGU emissions and recognizes that state
emissions may vary somewhat after all significant contribution to
nonattainment and interference with maintenance are eliminated. This
approach also provides sources with flexibility to manage growth and
electric reliability requirements, thereby ensuring the country's
electric demand will be met, while meeting the statutory requirement of
eliminating significant contribution to nonattainment and interference
with maintenance.
    Starting in 2012, EPA is establishing, as part of the FIPs, limits
on the total emissions that may be emitted from EGUs at sources in each
state. For any single year, the state's emissions must not exceed the
state budget with the variability limit allowed for any single year for
that state (i.e., the state's 1-year variability limit). In other
words, in addition to covered sources being required to hold allowances
sufficient to cover their emissions, the total sum of EGU emissions in
a particular state cannot exceed the state budget with the state's 1-
year variability limit in any 1 year (i.e., the state's assurance
level). EPA is not finalizing 3-year variability limits that were
included in the proposal for the reasons explained previously in
section VI.E of this preamble. The state budgets, variability limits,
and state assurance levels for each state are shown in Tables VI.F-1,
VI.F-2 and VI.F-3 in section VI.F of this preamble. The basis for the
variability limits is also described in section VI.E of this preamble.
Additional details may be found in the Power Sector Variability Final
Rule TSD in the docket to this rule.
    To implement this requirement, EPA first evaluates whether any
state's total EGU emissions in a control period exceeded the state's
assurance level. If any state's EGU emissions in a control period
exceed the state assurance level, then EPA applies additional criteria
to determine which owners and operators of units in the state will be
subject to an allowance surrender requirement. In applying the
additional criteria, EPA evaluates which groups of units at the common
designated representative (DR) level had emissions exceeding the
respective common DR's share of the state assurance level (regardless
of whether the source had enough allowances to cover its emissions)
during the control period.\82\
---------------------------------------------------------------------------

    \82\ A group of one or more sources and units in a state has a
common designated representative where the same individual is
authorized as the designated representative (not the alternate
designated representative) for that group of sources and units as of
April 1 immediately following the allowance transfer deadline for
the control period involved.
---------------------------------------------------------------------------

    The requirement that owners and operators surrender allowances
under the assurance provisions will be triggered only if two criteria
are met: (1) The group of sources and units with a common DR are
located in a state where the total state EGU emissions for a control
period exceed the state assurance level; and (2) that group with the
common DR had emissions exceeding the respective DR's share of the
state assurance level. The share of the assurance penalty borne by the
owners and operators will be based on the amount by which the total
emissions for the units in the group exceed the common DR's share of
the state assurance level as a percentage of the total calculated for
all such groups of sources and units in the state. Thus, the owners and
operators of each such group of sources and units must surrender an
amount of allowances equal to the excess of state EGU emissions over
the state assurance level multiplied by the owners' and operators'
percentage and multiplied by two (to reflect the penalty of two
allowances for each ton of the state's excess EGU emissions). See Table
VII.E-1 below for an illustrative example.
    This approach in the final rule of implementing the assurance
provisions on a common designated representative basis contrasts with
the approach in the proposed rule of implementing the assurance
provisions on an owner basis. In the January 7, 2011 NODA, EPA
requested comment on the alternative of basing the assurance provision
penalty using common designated representatives, and some commenters
supported this alternative. The common designated representative
approach is simpler and avoids the need to collect information on
percentage ownership (which information is not used in any other
provisions of the Transport Rule trading programs).
    In addition, the common designated representative approach provides
additional flexibility to owners and operators who have only one or a
few units in a given state but have the option of selecting a common
designated representative with owners and operators of other units in
the state. EPA expects companies in various states will readily be able
to manage their

emissions to stay collectively below their state's assurance levels as
they track emissions quarterly throughout the year and manage their
generation units and pollution control efforts accordingly. However, if
the state appears to be approaching its assurance level, this final
rule also gives companies the ability to further ensure that they will
not have excess emissions by combining multiple units under a common
DR. This flexibility allows utilities to re-balance allowances and
emissions to mitigate penalty risk if the state violates its assurance
level. In a state that does not appear to risk violating its assurance
level in a given period, utilities would not need to consider the
assurance aspect of selecting DRs. However, EPA anticipates that in the
event utilities desire additional certainty or mitigation of assurance
penalty risk, they will take advantage of this common DR provision or
pursue similar private arrangements with each other to cover their
emissions at the lowest possible cost.
    While the DR provision could benefit utilities by allowing them to
pool their penalty risk, the utilities would still be subject to the
antitrust laws. As with any joint venture between competitors, the
efficiency benefits of pooling risk would be weighed against any
anticompetitive harm associated with DRs.
    This new feature in the final rule, in conjunction with the
simplifications to the final rule's variability limits described in
section VI.E, will give companies under the air quality-assured trading
program greater flexibility in each state to determine the most cost-
effective pattern of emission reductions while EPA ensures each state
meets its assurance level needed to address the significant
contribution in each state.
    In the January 7, 2011 NODA, EPA also requested comment on
continuing to link allocations to assurance provision allowance
surrender requirements. Even though the final rule uses a different
allowance allocation methodology than the allocation methodology that
was proposed, the final rule continues to treat the groups of units
with greater emissions than their allocations plus share of state
variability as responsible for the state's excess of emissions over the
state assurance level. EPA believes that this approach is reasonable
because any state that exceeds its state assurance level likely does so
because not all units have made the reductions necessary to eliminate
the state's contribution to nonattainment or interference with
maintenance. Moreover, the groups of units with emissions exceeding
their allocations plus share of variability are the units most likely
to have contributed to the state's exceedance of its state assurance
level and thus to the state's triggering of the assurance provisions.
Consequently, EPA concludes that it is reasonable to penalize owners
and operators of those sources and units (grouped by common DR) for the
state's exceedance through application of the assurance provision
allowance surrender requirement. Some commenters stated that this is a
reasonable approach.
    While a few commenters suggested alternative approaches to the
assurance provisions, EPA believes that the suggested alternatives are
not workable and are likely to create implementation problems. These
commenters suggested variations of approaches that would have created
state-specific and vintage year-specific allowances that would have
been traded independently of compliance allowances. These
differentiated allowances would have fragmented the allowance markets
and made the programs resemble the intrastate trading option that EPA
rejected because of market power and other concerns described in the
proposal.
    The existence of the assurance provisions with significant
penalties imposed if a state's emissions exceed the state budget with
the variability limit, along with other features of the Transport Rule
trading programs discussed below, will ensure that state emissions stay
below the level of the budget with the variability limit. In making
compliance decisions and determining to what extent to rely on
purchased or banked allowances, owners and operators will have to take
into account the risk of triggering the assurance provisions in the
state involved and of incurring significant assurance provision
penalties. The greater the extent to which units sharing a common DR
have emissions exceeding the DR units' allocations plus share of the
state variability limit, the greater the risk of being subject to the
assurance provision penalties.
    As discussed previously in section VII.D.2, EPA allocates
allowances to a new unit for the control period during which the unit
commences commercial operation from the new unit set-aside based on its
emissions. In the case where assurance provisions for a state are
triggered in the year that a new unit commences operation, the unit's
share of the state assurance level is calculated using the unit's
allocation from the new unit set-aside plus its proportional share of
the variability limit. There is the possibility that a new unit would
receive no allocation for the control period during which the unit
commences commercial operation. EPA sees no reasonable basis for
disadvantaging owners and operators because they started up a new unit
and EPA had no emissions data on which to base an allocation from the
new unit set-aside or no allowances were available for the unit in the
state's new unit set-aside.\83\ For these new units, EPA would use a
specific surrogate number to calculate the maximum amount of emissions
that the unit would likely have had during that year. The surrogate
emission number applies only if the state's assurance provisions are
triggered and only in the first year of the new unit's commercial
operation for a new unit that did not receive an allocation from the
set-aside. The methodology for calculating the surrogate emission
number is essentially unchanged from the proposal (75 FR 45313). For
more details on capacity factors for new units, see ``Capacity Factors
Analysis for New Units Final Rule TSD.''
---------------------------------------------------------------------------

    \83\ Some other units (e.g., those units with no data for the
2006-2010 base period) may have a zero allocation for a control
period. However, those are highly likely to be units that will
continue to operate rarely or not at all and so will incur little or
none of the assurance provision penalties.
---------------------------------------------------------------------------

    These assurance provisions are above and beyond the fundamental
requirement for each source to hold enough allowances to cover its
emissions in the control period. Failure to hold enough allowances to
cover emissions is a violation of the CAA, subject to an automatic
penalty and discretionary civil penalties, as described in section
VII.F of this preamble.
    Several features of the air quality-assured trading programs work
in conjunction with the assurance provisions to ensure state emissions
do not exceed state assurance levels. The air quality-assured trading
programs have: State-specific budgets that do not include the
variability limits and that are the basis for allocating allowances in
each state so that total allocations in a state cannot exceed the state
budget; a requirement that owners and operators of each source hold
enough allowances to cover source emissions for each control period;
assurance provisions that require owners and operators to hold a
significant amount of additional allowances in a state if the assurance
provisions are triggered; and additional penalties for failing to hold
sufficient allowances under the assurance provisions. The underlying
mechanism of cap and trade--with a cap on allowances issued and a
requirement to

hold allowances covering emissions--has succeeded, even without
assurance provisions, in broadly reducing emissions below allowance
allocation levels. The accumulated data, history, and experience from
cap and trade programs underscore that emission reduction requirements
and environmental and public health goals of the programs have been met
and, in many instances, exceeded. Additionally, EPA has now added
assurance provisions to ensure that emissions within a state do not
exceed the state budget with the variability limitation that eliminates
the state's significant contribution to nonattainment and interference
with maintenance in downwind states.
    Emissions from a common DR's group of units in excess of the DR's
share of the state budget with the variability limit are not a
violation of the rule or the CAA, but do lead to strict allowance
surrender requirements. Specifically, the owners and operators with a
common DR will be required to surrender two allowances for each ton of
their proportional share of the exceedance of the state budget with the
variability limit. Failing to hold sufficient allowances to meet the
allowance surrender requirement will be a violation of the regulations
and the CAA and subject to discretionary civil penalties under CAA
section 113. Allowances surrendered to meet an assurance provision
penalty may be from the year immediately following the control period
in which the state assurance level was exceeded (i.e., the year during
which the penalty is assessed) or any prior year. Any future vintage
allowances beyond the year in which the penalty is assessed may not be
used to meet an assurance provision penalty.
    This penalty level is a change from the proposal, in which one
allowance was to be surrendered for each ton of emissions over the
state assurance level. EPA ran an IPM modeling scenario in order to
assess the level of penalty that would be sufficient to deter sources
from exceeding state assurance levels. According to the model, no state
would exceed its assurance level and incur the two-for-one allowance
penalty in either 2012 or 2014, although some states emit up to the
assurance level. The two-for-one allowance surrender requirement is
significant, and EPA believes that this penalty--along with the other
elements of the Transport Rule discussed above--will be sufficient to
ensure that the state emissions will not exceed the budgets plus the
variability limits. See the Assurance Penalty Level Analysis Final Rule
TSD for further details of the analysis.
    Below are examples of how the penalty will be assessed for four
common designated representatives in the same state if the assurance
provisions are triggered. In the first case, DR1's combined units were
allowed to emit up to 71 tons of SO2 (60 * 118 percent), but
actually emitted 75 tons during the control period, or 4 more than
their share of the state assurance level. Since the state, as a whole
exceeded the state assurance level by 15 tons, DR1's share of the
penalty is 25 percent of the total penalty, or 8 allowances (25 percent
of 30).

                                             Figure VII.E-1--Assurance Provision Allowance Surrender Example
--------------------------------------------------------------------------------------------------------------------------------------------------------
                                                                                Emissions
                                                           Allocation +                      Emissions         above                          Penalty
                                            Allowances       share of          Total           above       allocation +   Share of state    (allowances
                                             allocated      variability      emissions      allocation       share of     exceedance (%)   surrendered)
                                                                                variability
--------------------------------------------------------------------------------------------------------------------------------------------------------
DR1.....................................              60              71              75              15               4             25%               8
DR2.....................................              20              24              33              13               9             56%              17
DR3.....................................              10              12              15               5               3             19%               6
DR4.....................................              10              12              10               0              -2              0%               -
                                         ---------------------------------------------------------------------------------------------------------------
Total...................................             100             118             133              33              15            100%              30
--------------------------------------------------------------------------------------------------------------------------------------------------------
DR1, DR2, DR3, and DR4 are all in the same state.
State budget plus 18 percent variability limit is 118 tons (100 + 18 = 118).
State exceeded its assurance level by 15 tons (133-118 = 15).
Penalty is 2 allowances per ton over the assurance level (2 x 15 = 30).
Some numbers may not add up due to rounding.

    In the proposal, EPA took comment on whether assurance provisions
should be implemented starting in 2012 or 2014. While a number of
commenters supported the proposal to start in 2014, EPA received
several comments making the case that starting assurance provisions in
2012 would be more compatible with the Court's opinion in North
Carolina, which emphasized EPA's obligation to require elimination of
emissions within the states that significantly contribute to
nonattainment or interfere with maintenance. In this final rule, EPA
makes the assurance provisions effective starting in 2012 because this
approach provides even further assurance, consistent with North
Carolina, that each state's prohibited emissions will be eliminated
from the start of the Transport Rule trading programs.

F. Penalties

    Under the final Transport Rule FIPs (like under the proposed rule),
the owners and operators of each covered source must hold, as of the
allowance transfer deadline, an allowance for each ton of
SO2 or NOX emitted by the source and are subject
to penalties if they fail to comply with this allowance-holding
requirement.
    In particular, the owners and operators must hold in the source's
compliance account in the Allowance Management System enough allowances
issued for the respective Transport Rule annual trading program
(SO2 Group 1, SO2 Group 2, or annual
NOX program) to cover the annual emissions of the relevant
pollutant from all covered units at the source. The allowances must
have been issued for the year in which the emissions occurred or a
prior year. If the owners and operators fail to meet this allowance-
holding requirement, they must provide--for deduction by the
Administrator from the source's compliance account--one allowance as an
offset, and one allowance as an excess emissions penalty, for each ton
of emissions (i.e., excess emissions) in excess of the amount of
allowances held. The allowances surrendered for the excess emissions
penalty must be allocated for the control period in the year
immediately following the year when the excess emissions occurred or
for a control period in any prior year. The offset and the excess
emissions penalty are automatic requirements in

that they must be met without any further action by EPA (e.g., any
additional proceedings) regardless of the reason for the occurrence of
the excess emissions. In addition, each ton of excess emissions, as
well as each day in the averaging period (i.e., the control period of
one calendar year), constitute a violation of the CAA, and the maximum
discretionary civil penalty is $25,000 (inflation-adjusted to $37,500
for 2010) per violation under CAA section 113. This means that, if a
source has emissions in excess of allowances held for the source as of
the allowance transfer deadline for a control period, the number of
tons of excess emissions multiplied by the total number of days in that
control period and multiplied by $25,000 (inflation adjusted) equals
the maximum discretionary civil penalty for that occurrence of excess
emissions.
    For the ozone-season NOX trading program, the same
provisions apply as for an annual program, except that the averaging
period (i.e., the control period) is the ozone season, not a calendar
year. Consequently, the relevant emissions are for an ozone season, the
allowances usable to meet the allowance-holding requirement are
allowances issued for Transport Rule ozone-season NOX
trading program for the ozone season involved or a prior ozone season,
and the number of days used in calculating the maximum civil penalty is
the number in the ozone season.
    Commenters expressed concern that the proposed FIPs expressly
stated that, for purposes of determining the maximum discretionary
civil penalty for failure to meet the allowance-holding requirement,
each ton of emissions lacking a held allowance would be a violation and
each day in the averaging period involved would be a violation. Some
commenters compared the proposed penalty provisions for excess
emissions with the excess emissions penalty provisions under the Acid
Rain Program and claimed that the proposed penalty provisions differed
from the Acid Rain Program provisions and were excessive.
    In fact, however, the final FIP provisions concerning discretionary
civil penalties are essentially the same as those under the Acid Rain
Program, as well as those under the NOX Budget Trading
Program and the CAIR trading programs. In particular, the Acid Rain
Program regulations state that each ton of SO2 excess
emissions constitutes ``a separate violation'' of the CAA. 40 CFR
72.9(c)(2). Moreover, while the Acid Rain Program regulations do not
expressly address that each day in the averaging period (i.e., a
calendar year control period under the Acid Rain Program) constitutes a
separate violation when a unit has excess emissions for the calendar
year, the courts have addressed this question. In decisions applying
the discretionary civil penalty provisions in section 309(d) of the
Clean Water Act, which are analogous to the civil penalty provisions in
CAA section 113, the courts have interpreted the provisions to mean
that, when a source violates the emission limitation for a multi-day
control period, the source has a violation for each day in the control
period, as well as for each ton of excess emissions on each such day.
See, e.g., Chesapeake Bay Foun. v. Gwaltney of Smithfield, 791 F.2d
304, 313-15 (4th Cir. 1986), Atlantic States Legal Foun. v. Tyson
Foods, 897 F.2d 1128, 1139-40 (11th Cir. 1990), and U.S. v.  Allegheny
Ludlum Corp., 366 F.3d 164, 169 (3d. Cir. 2004). As noted by the
courts, the treatment of each ton and each day as a separate violation
is used for purposes of setting the maximum discretionary civil
penalty. Because CAA section 113 sets the maximum civil penalty, EPA,
of course, has the discretion to tailor the penalty amount that it
seeks in any specific occurrence of excess emissions to reflect the
circumstances of that excess emission occurrence. See 42 U.S.C. 7413(b)
(stating that the Administrator may commence a civil action ``to assess
and recover a civil penalty of not more than $25,000 per day for each
violation''). Moreover, when a district court imposes a civil penalty,
the court ``retains discretion to assess a penalty much smaller than
the maximum, as the situation requires.'' Chesapeake Bay, 791 F.2d at
316. In addition, the Acid Rain Program regulations state that any
allowance deduction, excess emission penalty, or interest under the
Acid Rain Program regulations ``shall not affect liability'' of the
owners and operators ``for any additional fine, penalty, or assessment,
or their obligation to comply with any other remedy, for the same
violation, as ordered under the [CAA],'' including under CAA section
113 providing for discretionary civil penalties. 40 CFR 77.1(b). In
summary, under the Acid Rain Program, each ton of excess emissions and
each day in the averaging period (i.e., the calendar year) constitute a
violation, the resulting number of violations times $2,000 is the
maximum civil penalty for violating owners and operators, and EPA has
the discretion to impose a civil penalty at or below such maximum, in
addition to the automatic requirement to surrender one allowance and
pay $2,000 (inflation adjusted) for each ton of excess emissions.
    The final FIPs take an analogous approach to that under the Acid
Rain Program. Specifically, the final FIPs state both that each ton of
excess emissions is a violation of the CAA and that each day in the
averaging period (i.e., a calendar year under the annual programs and
the ozone season under the ozone-season program) is a violation.
Moreover, the imposition of civil penalties at or below the maximum
amount resulting from the maximum penalty calculation is in addition to
the automatic allowance surrender and penalty totaling 2 allowances per
ton of excess emissions. Thus, commenters' assertion that the approach
in the final FIPs is inconsistent with the approach in the Acid Rain
Program is incorrect. Moreover, EPA has taken this same general
approach in two other trading programs (i.e., the NOX Budget
Trading Program and the CAIR trading programs), whose regulations
explicitly state that each ton and each day of the averaging period
constitute a violation. See 40 CFR 96.54(d)(3) (NOX Budget
Trading Program); and 40 CFR 96.106(d) (CAIR).
    In any event, EPA maintains that the approach of treating each
excess emission ton and each day in the averaging period as a violation
for purposes of calculating the maximum discretionary civil penalty is
reasonable. Some commenters suggested that only the days on which a
source's cumulative control period emissions exceed the amount of
allowances that the source then holds for that control period should be
treated as a violation. However, this suggested approach makes little
sense in the context of the Transport Rule trading programs.
    In order to provide owners and operators compliance flexibility,
the Transport Rule trading programs do not require source owners and
operators to hold any amount of allowances to cover emissions until the
allowance transfer deadline, no matter what the source's cumulative
control period emissions are before that deadline. The commenters'
approach of comparing--each day, cumulative emissions and allowances
held--for purposes of calculating maximum civil penalties would be
inconsistent with the flexibility that EPA intends to provide owners
and operators. For example, under the commenters' suggested approach,
owners and operators that buy or sell allowances in the allowance
market or hold allowances in a company-wide account, do not transfer
allowances into their source's compliance account until just before the
allowance transfer deadline, and end up with some excess emissions for
the calendar year would

face a significantly higher maximum civil penalty than owners and
operators that every day increase the amount of allowances held in
their source's compliance account as the source's cumulative emissions
increase and end up with the same amount of excess emissions for the
calendar year. In short, the commenters' approach would penalize owners
and operators that use some of the compliance flexibility that the
trading programs are intended to provide.
    EPA also maintains that it is reasonable to both impose the
automatic allowance surrender and penalty provisions and to retain the
discretion to impose civil penalties for the same occurrence of excess
emissions. This approach encourages compliance with the allowance-
holding requirement by ensuring that violating owners and operators are
penalized automatically (i.e., without any further administrative or
judicial proceedings, except for appeals) and that EPA can seek
additional penalties where the circumstances warrant discretionary
civil penalties. In fact, the Acid Rain Program, for which CAA Title IV
mandated this approach, has achieved a very high level of compliance
with the requirement to hold allowances covering SO2
emissions and therefore resulted in major reductions in utility
SO2 emissions. See 42 U.S.C.7651j(a). Similarly, the
NOX Budget Trading Program and CAIR trading programs, which
took the same approach, also have achieved very high compliance levels
and major utility emission reductions.
    EPA notes that, in calculating maximum civil penalties when owners
and operators fail to hold allowances required under the assurance
provisions in the final FIPs, EPA takes a similar approach in
determining the number of violations. Each ton for which an allowance
is not held as required and each day in the control period involved
constitute a violation of the CAA. As discussed elsewhere in this
preamble, EPA believes that this calculation approach is also
reasonable in the context of the assurance provisions and that taking
an approach like the commenters' suggested approach described above
would be inconsistent with some of the flexibility that the Transport
Rule trading programs are intended to provide.

G. Allowance Management System

    The final Transport Rule trading programs, like the proposed
preferred remedy, utilize EPA's allowance management system (AMS),
which currently supports allowance surrender, transfer, and tracking
activity under the Acid Rain Program and CAIR. EPA received no adverse
comment on this aspect of the proposed rule.
    The primary role of AMS is to provide an efficient, automated means
for covered sources to comply and for EPA to determine whether covered
sources are complying, with the emissions-related provisions of the
Transport Rule trading programs. As was proposed, each of the final
SO2 trading programs and final NOX trading
programs is separately handled in the AMS, which is used to track
Transport Rule trading program SO2 and NOX
allowances held by covered sources, as well as such allowances held by
other entities or individuals.
    In addition, the AMS tracks: The allocation of all SO2
and NOX allowances; holdings of SO2 and
NOX allowances in compliance accounts (i.e., accounts for
individual covered sources), general accounts (i.e., accounts for other
entities such as companies and brokers), and assurance accounts (i.e.,
accounts for allowance surrender by owners and operators of groups of
sources and units with common designated representatives under the
assurance provisions); deduction of SO2 and NOX
allowances for compliance purposes (including deductions from assurance
accounts where necessary); and transfers of allowances between
accounts. The AMS also allows the public to see whether each source is
in compliance and provides information to the allowance market and the
public in general, including information on ownership of allowances,
dates of allowance transfers, buyer and seller information, and the
serial numbers of allowances transferred.

H. Emissions Monitoring and Reporting

    Under the proposed rule, units subject to the Transport Rule
trading programs would monitor and report NOX and
SO2 mass emissions in accordance with 40 CFR part 75, as
incorporated in the proposed rule, and with certain other specified
requirements, such as compliance deadlines.
    In the final rule, like the proposed rule, covered units must
comply with emissions monitoring and reporting requirements that are
largely incorporated from Part 75 monitoring and reporting
requirements.
    Under the final rule and under Part 75, a unit has several options
for monitoring and reporting, namely the use of: a CEMS; an excepted
monitoring methodology (NOX mass monitoring for certain
peaking units and SO2 mass monitoring for certain oil- and
gas-fired units); low mass emissions monitoring for certain non-coal-
fired, low emitting units; or an alternative monitoring system approved
by the Administrator through a petition process. In addition, the
Administrator can approve petitions for alternatives to Transport Rule
and Part 75 monitoring, recordkeeping, and reporting requirements.
    Further, the final rule and Part 75 specify that each CEMS must
undergo rigorous initial certification testing and periodic quality
assurance testing thereafter, including the use of relative accuracy
test audits (RATAs) and 24-hour calibrations. In addition, when a
monitoring system is not operating properly, standard substitute data
procedures are applied and result in a conservative estimate of
emissions for the period involved.
    In addition, the final rule and Part 75 require electronic
submission, to the Administrator and in a format prescribed by the
Administrator, of a quarterly emissions report. The report must contain
all of the data required concerning NOX annual and ozone-
season and SO2 annual emissions.
    Most Transport Rule units are in states subject to CAIR and are
already monitoring and reporting NOX and/or SO2
under CAIR and the Acid Rain Program, which programs also use Part 75
monitoring and reporting. Units under the Transport Rule annual trading
programs and in states subject to CAIR generally have no changes to
their monitoring and reporting requirements. These units must continue
to monitor and submit reports on a year-round basis as they have under
CAIR. Therefore, units in the following states must monitor and report
both SO2 and NOX year-round under the Transport
Rule: Alabama, Georgia, Illinois, Indiana, Iowa, Kansas, Kentucky,
Maryland, Michigan, Minnesota, Missouri, Nebraska, New Jersey, New
York, North Carolina, Ohio, Pennsylvania, South Carolina, Tennessee,
Texas, Virginia, West Virginia and Wisconsin.
    Some states (Kansas, Minnesota, and Nebraska) subject to the
Transport Rule annual trading programs were not subject to CAIR.
Transport Rule units in those states must meet monitoring and reporting
requirements that are new except to the extent the units were subject
to Part 75 under some other program (such as the Acid Rain Program).
    Further, some states (Florida, Louisiana, and Mississippi) subject
to the Transport Rule ozone-season trading program but not the
Transport Rule annual trading programs were subject to the annual and
ozone-season trading programs under CAIR. Transport Rule

units in those states must continue to monitor and report in accordance
with Part 75 but have the option of monitoring and reporting on a year-
round or ozone-season-only basis.
    In addition, one state (Arkansas) subject to the Transport Rule
ozone-season trading program but not to the Transport Rule annual
trading program was similarly subject to only the ozone-season trading
program in CAIR. Transport Rule units in that state continue to have
the option of monitoring and reporting NOX on a year-round
or ozone-season-only basis.
    Finally, some states (Connecticut, Delaware, District of Columbia,
and Massachusetts) that were subject to CAIR are not subject to the
Transport Rule. Electric generating units in those states must continue
to meet monitoring and reporting requirements only to the extent the
units are subject to Part 75 under some other program (such as the Acid
Rain Program or a state adopted program requiring such monitoring and
reporting).
    EPA is finalizing requirements for existing Transport Rule units in
states covered by the Transport Rule annual trading programs to monitor
and report SO2 and NOX emissions by January 1,
2012 programs and for existing Transport Rule units in states covered
by the Transport Rule ozone-season trading program to monitor
NOX emissions by May 1, 2012. The use of Part 75 certified
monitoring methodologies is required in both cases. As discussed
previously, most covered existing units will generally have no changes
to their monitoring and reporting requirements and will continue to
monitor and submit reports under Part 75 as they have under CAIR.
Existing units that have not been subject to Part 75 monitoring and
reporting requirements in the past have less than 1 year to install,
certify, and operate the required monitoring systems. EPA believes that
these units will be able to comply with this requirement because the
monitoring equipment needed is not extensive or is largely in place
already for the purpose of meeting other requirements. Quality
assurance and reporting provisions and data system upgrades may be
necessary, but EPA believes that there is sufficient time to accomplish
this by the deadline for existing units in the final rule.
    In the proposed rule, the compliance deadline for installing,
certifying, and operating the required monitoring systems at new units
was based upon the date of commencement of commercial operation. A new
unit would have to install and certify its monitoring system within 180
days of the commencement of commercial operation. The final rule adopts
this deadline, which is consistent with the approach recently adopted
in Part 75 under the Acid Rain Program. See 76 FR 17288, 17289 (March
28, 2011).
    Using this deadline (rather than a deadline, used previously in
Part 75, of the earlier of the unit's 90th operating day or 180 days
after the unit's commencement of commercial operation) ensures that new
units have sufficient time to complete installation and certification
of monitoring systems and facilitates units' compliance. Because of
unit shakedown problems, some new units have had difficulty meeting a
deadline earlier than 180 days after commencement of commercial
operation. Further, using this deadline facilitates owners' and
operators, and EPA's, ability to track important dates related to
monitoring, reporting, and allowance holding. Under the final rule, the
requirement that a unit hold enough allowances to cover its emissions
starts on the later of the commencement of the Transport Rule trading
program involved or the deadline for installation and certification of
the monitoring system. Having a simple, easily determined deadline (180
days after the commencement of commercial operation) makes it easier
for owners and operators and EPA to determine when allowance-holding
requirements begin, as well as when monitoring and reporting
requirements begin. In contrast, using a deadline involving
determination of a unit's 90th operating day required keeping track of
any days on which the unit did not operate (e.g., due to problems
associated with shakedown of the unit). EPA found that owners and
operators have had more difficulty reporting the 90th operating day
than in reporting the commencement of commercial operation, and once
the latter date is reported, EPA can independently determine the 180th
calendar day after the reported date.

I. Permitting

1. Title V Permitting
    The final Transport Rule (like the proposed rule) does not
establish any permitting requirements independent of those under Title
V of the CAA and the regulations implementing Title V, 40 CFR Parts 70
and 71.\84\ All major stationary sources of air pollution and certain
other sources are required to apply for title V operating permits that
include emission limitations and other conditions as necessary to
assure compliance with applicable requirements of the CAA, including
the requirements of the applicable State Implementation Plan. CAA
Sec. Sec.  502(a) and 504(a), 42 U.S.C. 7661a(a) and 7661c(a). The
``applicable requirements,'' that must be addressed in title V permits
are defined in the Title V regulations (40 CFR 70.2 and 71.2
(definition of ``applicable requirement'')).
---------------------------------------------------------------------------

    \84\ Part 70 addresses requirements for state Title V programs,
and Part 71 governs the federal Title V program.
---------------------------------------------------------------------------

    EPA anticipates that, given the nature of the units covered by the
final Transport Rule, most of the sources at which they are located are
already or will be subject to Title V permitting requirements. For
sources subject to Title V, the requirements applicable to them under
the final FIPs will be ``applicable requirements'' under Title V and
therefore will need to be addressed in the Title V permits. For
example, requirements under the final FIPs concerning designated
representatives, monitoring, reporting, and recordkeeping, the
requirement to hold allowances covering emissions, the assurance
provisions, and liability will be ``applicable requirements'' to be
addressed in the permits.
    The Title V permits program includes, among other things,
provisions for permit applications, permit content, and permit
revisions that will address the applicable requirements under the final
FIPs in a manner that will provide the flexibility necessary to
implement market-based programs such as the Transport Rule trading
programs. For example, the Title V regulations provide that a permit
issued under Title V must include, for any ``approved * * * emissions
trading and other similar programs or processes'' applicable to the
source, a provision stating that no permit revision is required ``for
changes that are provided for in the permit.'' 40 CFR 70.6(a)(8) and
71.6(a)(8). Consistent with this provision in the Title V regulations,
the Transport Rule trading program regulations include a provision
stating that no permit revision is necessary for the allocation,
holding, deduction, or transfer of allowances. Consistent with the
Title V regulations, this provision will also be included in each Title
V permit for a covered source. As a result, allowances can be traded
(or allocated, held, or deducted) under the final FIPs without a
revision of the Title V permit of any of the sources involved.
    As a further example of flexibility under Title V, the Title V
regulations allow the use of the minor permit modification procedures
for permit modifications ``involving the use of economic incentives,
marketable permits, emissions trading, and other

similar approaches, to the extent that such minor permit modification
procedures are explicitly provided for in an applicable implementation
plan or in applicable requirements promulgated by EPA.'' 40 CFR
70.7(e)(2)(i)(B) and 40 CFR 71.7(e)(1)(i)(B). The final FIPs set forth
in detail, and reference relevant provisions in Part 75 concerning, the
approaches that are available for covered units to use for monitoring
and reporting emissions (i.e., approaches using a continuous emission
monitoring system, an excepted monitoring system under appendices D and
E to Part 75, a low mass emissions excepted monitoring methodology
under Sec.  75.19, or an alternative monitoring system under subpart E
of Part 75). The final FIPs also require unit owners and operators to
submit monitoring system certification applications (or, for
alternative monitoring systems, petitions) to EPA establishing the
monitoring and reporting approach actually to be used by the unit and
allow owners and operators to submit petitions for alternatives to any
specific monitoring and reporting requirement. These applications and
petitions are subject to EPA review and approval to ensure consistency
in monitoring and reporting among all trading program participants, and
EPA's responses to any petitions for alternative monitoring systems or
for alternatives to specific monitoring or reporting requirements are
to be posted on EPA's Web site. Moreover, EPA intends that each covered
unit's Title V permit will include a description of the general
approach that the covered unit is required to use for monitoring and
reporting emissions and that the description will reference the
relevant sections of the Transport Rule trading program regulations and
Part 75 and will state that the requirements may be modified through
EPA approval of petitions for alternatives to specific requirements.
Finally, consistent with Sec. Sec.  70.7(e)(2)(i)(B) and
71.7(e)(1)(i)(B) of the Title V regulations, the final FIPs provide
that a description of the general monitoring and reporting approach for
a covered unit can be added to, or an existing description of a unit's
general monitoring and reporting approach can be changed, in a Title V
permit, using minor permit modification procedures, provided that the
approach being described in the changed or new general description and
the requirements applicable to that approach are already incorporated
elsewhere in the permit. As a result, minor permit modification
procedures can be used to revise a covered unit's Title V permit to be
consistent with the monitoring and reporting approach, or any changes
in the approach, allowed for the unit by EPA through the monitoring
system certification or petition process under the Transport Rule
trading programs.
    As new applicable requirements under Title V, the requirements for
covered units under the final FIPs will be incorporated into covered
sources' existing Title V permits either pursuant to the provisions for
reopening for cause (40 CFR 70.7(f) and 40 CFR 71.7(f)) or the permit
renewal provisions (40 CFR 70.7(c) and 71.7(c)).\85\ In contrast to the
approach in CAIR of imposing permitting requirements and deadlines
independent of those under Title V, the approach to permitting under
the final FIPS of imposing no independent permitting requirements
should reduce the burden on sources already required to be permitted
under Title V and on permitting authorities. For sources newly subject
to Title V that will also be covered sources under the final FIPs, the
initial Title V permit issued pursuant to 40 CFR 70.7(a) will address
the final FIP requirements.
---------------------------------------------------------------------------

    \85\ A permit is reopened for cause if any new applicable
requirements (such as those under a FIP) become applicable to a
covered source with a remaining permit term of 3 or more years. If
the remaining permit term is less than 3 years, such new applicable
requirements will be added to the permit during permit renewal. See
40 CFR 70.7(f)(1)(i) and 71.7(f)(1)(i).
---------------------------------------------------------------------------

    In order to ensure that covered sources' Title V permit provisions
concerning the final FIPs will reflect the Transport Rule trading
program requirements and flexibilities properly and in a manner
consistent from permit to permit, EPA intends to issue guidance to
assist permitting authorities. This guidance would include information
on permit issuance and permit modification requirements, as well as a
permit content template that will identify the applicable requirements
under the applicable Transport Rule trading program and thereby ensure
that they will be correctly and comprehensively reflected in each
permit in a manner that will reduce the burden on sources and
permitting authorities related to the issuance of the permit and will
reduce the need for permit revisions.

2. New Source Review

a. Background
    EPA recognizes that, following the vacatur of the new source review
(NSR) pollution control project exemption in New York v. EPA, 413 F.3d
3, 40-41 (D.C. Cir. 2005), pollution control projects, including
pollution control projects constructed to comply with this rule, have
the potential to trigger NSR permitting.
    This issue was previously addressed in the context of CAIR. On
December 20, 2005, the EPA agreed to reconsider one specific aspect of
CAIR. In that notice, EPA granted reconsideration and sought comment on
the potential impact of the opinion in New York v. EPA, which vacated
the previously existing NSR exemption for certain environmentally
beneficial pollution control projects. For this reconsideration, EPA
conducted an analysis which showed that the court decision did not
impact the CAIR analyses. Details of this analysis can be found in a
technical support document which is available on EPA's Web site at:
http://epa.gov/cair/pdfs/0053-2263.pdf
    Because GHG emissions were not considered by EPA to be air
pollutants within the meaning of the CAA at the time of CAIR, GHG
emissions were not addressed in the 2005 analysis. GHG requirements
related to the component of NSR concerning the Prevention of
Significant Deterioration (``PSD'') program are addressed in EPA's
``Interpretation of Regulations that Determine Pollutants Covered by
Clean Air Act Permitting Programs,'' 75 FR 17004 (April 2, 2010), and
``Prevention of Significant Deterioration and Title V Greenhouse Gas
Tailoring Rule,'' 75 FR (June 3, 2010) (``Tailoring Rule''). Generally,
as discussed in those actions, major stationary sources will be
required to address GHG emissions as part of the PSD program if these
sources emit GHG in amounts that equal or exceed the thresholds in the
Tailoring Rule. Major sources that undergo a modification, including
the addition of pollution control equipment, will trigger PSD
requirements for their emissions of GHG if such emissions increase by
at least 75,000 \86\ tons per year of CO2 equivalent
(CO2e).
---------------------------------------------------------------------------

    \86\ We note that, for sources that are modifying and are not
subject to PSD for emissions of a non-GHG pollutant, in order to be
subject to PSD for GHGs the source must not only have an emissions
increase of 75,000 TPY CO2e, but must also have a PTE of
at least 100,000 TPY CO2e and 100 TPY mass GHG. See 40
CFR 52.21(b)(49)(v)(b). However, since it is reasonable to assume
that all sources that are potentially subject to the Transport Rule
will have a PTE of at least 100,000 TPY CO2e and 100 TPY,
for the purposes of discussions in this section we will only note
the requirement to have an emissions increase of 75,000 TPY
CO2e.
---------------------------------------------------------------------------

b. Proposed Rule
    In the proposed rule, EPA presented the following conclusions:
    (1) The 2005 analysis remains current and relevant for all
pollutants except for GHG, and it shows that NSR requirements would not
significantly impact the construction of controls that

are installed to comply with the proposed Transport Rule.
    (2) It is very unlikely that pollution control projects would cause
GHG increases that would exceed the 75,000 tons per year threshold.
    Consistent with these proposed conclusions, EPA also concluded that
there would be no significant impacts from NSR for any pollution
control projects resulting from the proposed rule such as low-
NOX burners, SO2 scrubbers, or SCR. EPA requested
comment on this issue.
c. Public Comments
    EPA received a number of comments on the NSR issue, which can be
divided into four types of comments: (1) Comments related to GHGs, (2)
comments related to sulfuric acid mist, (3) comments related to CO
emission increases from low-NOX burners, and (4) suggested
changes to the EPA rules.
    Greenhouse Gases. A number of commenters recommended that EPA
should document and substantiate its conclusion that greenhouse gases
would be unlikely to trigger NSR requirements. Other commenters
suggested that some units installing a FGD scrubber could exceed the
75,000 ton threshold for GHGs in the Tailoring Rule by emitting
CO2 produced from the chemical reaction of SO2
with limestone. Commenters also suggested that NSR applicability for
GHGs would also need to consider that an FGD would consume 1-3 percent
of a scrubbed unit's generation, referred to as ``parasitic load,''
which (all else held equal) lowers that unit's net generation.\87\
Commenters argued that any post-retrofit increase in generation to
offset that ``parasitic load'' could lead to GHG increases potentially
exceeding the 75,000 ton threshold.
---------------------------------------------------------------------------

    \87\ ``Net generation'' refers to total generation minus the
amount of power consumed on-site for various purposes, including
operation of pollution control equipment.
---------------------------------------------------------------------------

    Sulfuric Acid Mist. Two commenters noted that use of high sulfur
fuels, in combination with SCR, can lead to increases in sulfuric acid
mist, a pollutant regulated under NSR. One of these commenters noted
that reagent injection was necessary to avoid triggering NSR for
sulfuric acid mist when their SCR was installed.
    Carbon Monoxide (CO). One commenter believed that EPA's 2005
analysis may not be adequate as it related to carbon monoxide emission
increases that result from installation of low-NOX burners.
The commenter noted EPA's statement in the 2005 analysis that read as
follows: ``Since the NOX removal efficiencies used in EPA's
analysis are not aggressive, it is believed that the units installing
combustion controls can opt for moderate levels of overfire air flow
rates and still achieve the NOX reduction levels projected
in EPA's analysis, without causing significant increases in the CO and
unburned carbon emissions.'' The commenter suggested that the transport
rule NOX may be more aggressive than CAIR and thus EPA
should conduct a review to determine whether EPA retains the same
conclusion regarding CO emissions.
    Recommended Rule Changes. Some commenters suggested changes to EPA
rules to address their concerns that control equipment installed as a
result of the Transport Rule could trigger NSR. Some commenters
suggested that EPA craft an exclusion from NSR in the Transport Rule.
One of these commenters suggested that EPA could do this by: (1)
Providing special definition of baseline actual emissions; (2) a
causation determination specifically tied to the Transport Rule; or (3)
interpret the term ``stationary source'' in CAA 110(a)(4) in a way that
doesn't impede Transport Rule compliance.
    Other commenters expressed the concern that if NSR is triggered,
the proposed Transport Rule did not allow enough time for compliance
for sources needing to install control equipment. These commenters
recommend that EPA should waive Transport Rule requirements or provide
extra allowances until NSR review is complete.
d. Final Rule and Responses to Comments
    Greenhouse Gases. EPA has carefully reviewed relevant data in
assessing the comments suggesting that NSR permitting would likely be
triggered for facilities installing FGD scrubbers to comply with this
rule. EPA believes that sources installing FGD to comply with the
Transport Rule can achieve those installations without triggering NSR.
    EPA notes that its forecast of the number and extent of FGD
scrubber installations substantially decreased since the time of
proposal. For the proposed rule, EPA modeled 14 GW of FGD retrofit
installations by 2014. For the final rule, EPA models a total of 5.7 GW
of wet FGD installations from 7 units at 5 plants.
    There are two factors associated with wet FGD scrubbers that
commenters suggested individually or in combination could lead to
increases above the 75,000 tons per year threshold in the Tailoring
Rule. The first is the CO2 chemically produced from the
reaction of SO2 with limestone in wet FGD scrubbers. The
second is that owners or operators of the affected units may desire to
increase coal usage after the retrofit is made to offset the
``parasitic load'' that is consumed on-site in order to operate the
scrubber.
    With respect to chemically produced CO2, EPA concludes
that only in very limited circumstances when installation of a scrubber
is coupled with a change to considerably higher sulfur coal could
installation of a wet limestone scrubber be associated with a more than
75,000 ton increase in CO2 emissions. EPA finds this
possibility unlikely to occur. For example, EPA's acid rain emissions
reporting system shows that the plant with the greatest emissions from
unscrubbed units in 2009 emitted about 103,000 tons of SO2
from those units. If this plant installed a wet limestone scrubber
assumed to reduce those SO2 emissions by 96 percent, EPA
calculates that chemically produced CO2 could increase
emissions by:

103,000 x (0.96) x (44/64) = 67,980 tons CO2.\88\
---------------------------------------------------------------------------

    \88\ The factor 44/64 reflects the relative molecular weight of
CO2 and SO2, respectively. A wet FGD's removal
of one ton of SO2 involves a chemical reaction that
releases the equivalent molecular weight of CO2 (thus
equaling 44/64 of a ton of CO2 emissions).

    Therefore, EPA finds that all currently uncontrolled units are
technically capable of retrofitting with wet FGD without chemically
produced CO2 increases leading to a triggering of NSR. In
limited circumstances, an owner or operator may elect to switch fuels
to a significantly higher-sulfur coal subsequent to FGD installation
and may risk an increase in chemically produced CO2
emissions that would trigger NSR, but such a decision is not necessary
in order to successfully install and operate the scrubber as a strategy
for compliance with Transport Rule requirements.
    With respect to the ``parasitic load'' issue, EPA estimates that
today's wet FGD retrofit technology would consume typically about 1.7
percent of on-site generation.\89\ If a facility made no other changes
to its operation other than installing an FGD retrofit, that facility's
CO2 emissions from fuel combustion would remain constant. It
is possible, however, that a source's owner or operator may elect to
increase coal usage by some amount after retrofitting FGD, if for
example the owner or operator desires to increase net generation after
retrofitting. Under NSR, any such source would be able to

compare such a CO2 emissions increase against the highest
average annual emissions in any consecutive 24-month period from a 5-
year historic baseline. Therefore, a unit retrofitting a scrubber under
the Transport Rule may be able to increase its CO2 emissions
by more than 75,000 tons without triggering NSR if that increase would
register as less than 75,000 tons against a higher emissions level in
the aforementioned NSR baseline.
---------------------------------------------------------------------------

    \89\ Documentation Supplement for EPA Base Case v.4.10--
FTransport--Updates for Final Transport Rule.
---------------------------------------------------------------------------

    EPA also notes that scrubber installations provide facilities with
the opportunity to make other capital improvements at the unit on which
the scrubber is installed to improve the efficiency of boilers, steam
turbines, motors, other auxiliary equipment, and plant control systems.
Such improvements could allow a retrofitting unit to lower its
CO2 output rate such that a subsequent decision to increase
net generation may not result in increased coal use, or may limit any
CO2 emission increase to less than the 75,000 tons per year
threshold for triggering NSR.
    As discussed in section VII.C, EPA notes that the Transport Rule
does not mandate any specific control activity, including scrubber
retrofitting, as a compliance strategy for units within a state to meet
that state's SO2 budget. As demonstrated by EPA's ``no FGD''
sensitivity analysis described in VII.C, covered sources within the
Group 1 states are capable of meeting their emission reduction
obligations through a variety of emission reduction strategies even if
no unit is able to complete a scrubber installation by 2014. Therefore,
EPA does not believe that NSR permitting presents an obstacle in any
way to Transport Rule compliance, even if a given unit retrofitting
with FGD triggers NSR for CO2.
    For some plants, EPA's IPM modeling forecasts installation and
operation of dry sorbent injection (DSI) systems. EPA does not believe
any of these systems would result in CO2 emission increases
above the 75,000 ton threshold. Moreover, given the relatively short
construction schedule for DSI systems, EPA believes that if any of the
plants did require NSR permitting, installation of DSI could still be
accomplished by 2014.
    In summary, EPA believes that the operators of plants projected to
install scrubbers for Transport Rule SO2 reductions could
readily develop workable compliance strategies whether or not such an
installation would trigger NSR. Plant owners could readily develop
strategies to avoid emission increases that would trigger NSR,
including but not limited to alternative SO2 reduction
strategies or technologies, efficiency improvements, or the ability to
adjust net electricity generation to prevent a 75,000 ton increase in
CO2 emissions. EPA believes that projected scrubber
installations under the Transport Rule are broadly unlikely to trigger
NSR, but even in the limited conditions where such a triggering may
occur, the NSR permitting process would not infringe on a state's
ability to comply with its budgets under the Transport Rule. (See
section VII.C for more details on EPA's analysis of a ``no FGD''
sensitivity supporting these points.)
    Sulfuric Acid Mist. EPA continues to conclude that, consistent with
the 2005 TSD, sulfuric acid mist increases due to compliance with this
rule are very unlikely to trigger NSR permitting. Such increases are
most commonly seen from installation of SCR units on facilities with
relatively high sulfur coal. However, as acknowledged by one of the
commenters, engineering solutions have been developed to prevent such
increases, and EPA believes that facility owners would take this into
account in designing such an SCR system. Moreover, EPA's IPM modeling
of the NOX budgets in the final rule suggests that no new
SCR units will result from the final rule.
    Carbon Monoxide. EPA concludes that any NSR permitting required due
to CO increases associated with NOX controls should not
hinder the ability of sources to comply with Transport Rule
requirements. For states that were included in the CAIR for either
ozone, PM2.5, or both, EPA finds no evidence to suggest that
the NOX control requirements of the Transport Rule would
require more aggressive controls triggering NSR. As EPA's baseline
analysis acknowledges, many sources in these states installed
NOX controls to comply with CAIR. In addition, their
historic emissions reflect operation of these controls and there is no
evidence to suggest that the Transport Rule will require sources to
operate these controls more aggressively, thereby increasing CO
emissions above the relevant threshold and triggering NSR. In a few
states that were not covered by CAIR, a limited number of facilities
may install new combustion controls (such as low-NOX
burners, overfire air, or other combustion controls or upgrades) as a
result of the Transport Rule. EPA expects relatively few such
installations, and believes that NSR permitting, if required, is not an
obstacle to compliance with the rule. First, EPA believes that NSR
permitting should be relatively straightforward for these installations
and that the BACT determination for CO will be very straightforward.
EPA expects a relatively short time period for permitting, and as
discussed later, EPA is planning to initiate actions that will further
expedite any required permitting.
    Second, EPA notes that the rule achieves reductions through a
trading program rather than direct control requirements. Accordingly,
even if a few installations do not have controls in place at the very
beginning of the compliance period, this should not hinder the ability
of states to meet their ozone-season NOX budgets. Covered
sources have a suite of NOX pollution control strategies and
technologies available to them, including coal selection, selective
non-catalytic reduction, gas re-burn, low-NOX burner and
overfire air installations or upgrades, and neural network optimization
of combustion controls operation. Sources may consider all of these
technologies and strategies, which can be designed and operated so as
to minimize CO emission increases that may otherwise trigger NSR. EPA
also notes that during the downtime for installation of the
construction controls, there would be no NOX emissions, and
thus the source's allowance holding requirements would also be lower
for that period.
    Recommended Rule Changes. EPA disagrees with commenters who
suggested rule changes, either to the NSR program or to this rule, to
account for installations triggering NSR. As noted above, EPA concludes
that NSR would be triggered at most for just a few of the projected
control installations. EPA believes, however, that even if required
these NSR permits would likely be issued in a timely manner given the
overall environmental benefits resulting from the control equipment
installation. In addition, this rule's requirements are based on a
flexible trading approach rather than a direct control approach.
Accordingly, if this affect occurs for only a few installations, EPA
believes that any extra emissions that occur during the relatively
short time needed to obtain an NSR permit could be accommodated within
the overall trading system.
    Expediting Permitting. In the limited circumstances where pollution
control installations under the Transport Rule may trigger NSR, we also
note that an expedited permitting process can occur with sufficient
time to obtain permits and achieve emission reductions under the
Transport Rule programs. For this reason, we strongly encourage
permitting authorities to expedite

permitting for any such projects, which are likely to be very limited
in number. To ensure that the permitting decisions are expedited,
separate from this rulemaking EPA will provide assistance and guidance
in order to expedite issuance of any such permits. For example, we are
considering assistance that would serve to expedite BACT reviews or
required air quality analysis. EPA requests early notification of any
specific cases where such guidance and assistance may be needed.

J. How the Program Structure Is Consistent With Judicial Opinions
Interpreting the Clean Air Act

    The air quality-assured trading programs established by this rule
eliminate all of the emissions that EPA has identified as significantly
contributing to downwind nonattainment or interference with maintenance
\90\ in a manner that is consistent with section 110(a)(2)(D)(i) of the
CAA as interpreted by the DC Circuit in North Carolina, 531 F.3d 896.
The FIPs finalized in this action require sources to participate in air
quality-assured interstate emission trading programs that include
provisions to ensure that no state's emissions exceed that state's
budget with variability limit. These assurance provisions, combined
with the requirement that all sources hold emission allowances
sufficient to cover their emissions, effectuate the requirement that
emission reductions occur within the state. See 42 U.S.C.
7410(a)(1)(2)(D).
---------------------------------------------------------------------------

    \90\ As explained in greater detail in Section VI of this
notice, for each covered state, EPA has identified emissions that
must be prohibited pursuant to section 110(a)(2)(D)(i)(I). In most
instances, EPA has determined that elimination of such emissions is
sufficient to satisfy the requirements of that section. Thus, in
these instances, the budgets represent an estimate of the emissions
that will remain after the elimination of all emissions in that
state that significantly contribute to nonattainment or interfere
with maintenance of the NAAQS in another state. In a few limited
instances, however, EPA determined that elimination of the emissions
is necessary but may not be sufficient to satisfy the requirements
of that section. In these instances, the budgets represent an
estimate of the emissions that will remain after the elimination of
all emissions that EPA, at this time, has determined must be
eliminated.
---------------------------------------------------------------------------

    The state budgets developed in this rule represent an estimate of
the emissions that will remain in a given state after the elimination
of all emissions in that state that EPA has determined must be
prohibited pursuant to section 110(a)(2)(D)(i)(I). However, for the
reasons explained above, the amount of emissions that remain after the
requirements of 110(a)(2)(D)(i)(I) are satisfied may vary. EPA
recognizes that shifts in generation due to, among other things,
changing weather patterns, demand growth, or disruptions in electricity
supply from other units can affect the amount of generation needed in a
specific state and thus baseline EGU emissions from that state. Because
a state's significant contribution to nonattainment or interference
with maintenance is defined by EPA as all emissions that can be
eliminated for a specific cost (as explained above, using air quality
considerations to identify this cost threshold), and because EGU
baseline emissions are variable, the amount of emissions remaining in a
state after all significant contribution or interference with
maintenance is eliminated is also variable. In other words, EGU
emissions in a state whose sources have installed all controls and
taken all measures necessary to eliminate its significant contribution
to nonattainment or interference with maintenance could exceed the
state budget without variability.
    For this reason, EPA determined that it is appropriate for the
program to recognize the inherent variability in state EGU emissions.
The program does so by identifying a variability range for each state
in the program. The assurance provisions in the program, in turn, limit
a state's emissions to the state's budget with variability limit.
    In addition, the requirement that all sources hold emission
allowances sufficient to cover their emissions (and the fact that the
total number of emission allowances allocated will be equal to the sum
of all state budgets without variability) ensures that the use of
variability limits both takes into account the inherent variability of
baseline EGU emissions in individual states (i.e., the variability of
total state EGU emissions before the elimination of significant
contribution or interference with maintenance) and recognizes that this
variability is not as great in a larger region. The variability of
emissions across a larger region is not as large as the variability of
emissions in a single state for several reasons. Increased EGU
emissions in one state in one control period often are offset by
reduced EGU emissions in another state within the control region in the
same control period. In a larger region that includes multiple states,
factors that affect electricity generation, and thus EGU emission
levels, are more likely to vary significantly within the region so that
resulting emission changes in different parts of the region are more
likely to offset each other. For example, a broad region can encompass
states with differing weather patterns, with the result that increased
electricity demand and emissions due to weather in one state may be
offset by decreased demand and emissions due to weather in another
state. By further example, a broad region can encompass states with
differing types of industrial and commercial electricity end-users,
with the result that changes in electricity demand and emissions among
the states due to the effect of economic changes on industrial and
commercial companies may be offsetting. Similarly, because states in a
broad region may vary in their degree of dependence on fossil-fuel-
based electric generation, the impact of an outage of non-fossil-fuel-
based generation (e.g., a nuclear plant) in one state may have a very
different impact in that state than on other states in the region.
Thus, EPA does not believe it is necessary to allow total regional
allowance allocations for the states covered by a given trading program
to exceed the sum of all state budgets without variability for these
states.
    For these reasons, the fact that the use of state budgets with
variability limits may allow limited shifting of emissions between
states is not inconsistent with the court's holding that emission
reductions must occur ``within the state.'' North Carolina, 531 F.3d at
907. Under the FIPs, no state may emit more than its budget with
variability limit and total emissions cannot exceed the sum of all
state budgets without variability. This approach takes into account the
inherent variability of the baseline emissions without excusing any
state from eliminating its significant contribution to nonattainment or
interference with maintenance. It is thus consistent with the statutory
mandate of section 110(a)(2)(D)(i)(I) as interpreted by the Court.
    Most commenters voiced support for a remedy option that allows some
degree of interstate trading. However, one commenter argued that the
structure of the preferred trading remedy that EPA proposed is legally
problematic. The program, the commenter argues, provides no legal
assurance that the variability margins will be used by market
participants to account for variability. The commenter does not suggest
a solution, but instead says, if a solution cannot be found, EPA should
not allow any amount of interstate trading.
    EPA disagrees with the commenter that the structure of the
preferred interstate trading program is legally problematic. In North
Carolina, the Court held that the CAIR interstate trading programs were
inconsistent with section 110(a)(2)(D)(i)(I), concluding that ``EPA's
apportionment decisions have nothing to do with each state's
`significant contribution' '' (531 F.3d at

907) and that ``EPA is not exercising its section 110(a)(2)(D)(i)(I)
duty unless it is promulgating a rule that achieves something
measurable toward the goal of prohibiting sources `within the State'
from contributing to nonattainment or interfering with maintenance `in
any other State.' '' (531 F.3d at 908). It emphasized that ``[t]he
trading program is unlawful, because it does not connect states'
emission reductions to any measure of their own significant
contributions. To the contrary, it relates their SO2
reductions to their Title IV allowances. * * * The allocation of
NOX caps is similarly arbitrary because EPA distributed
allowances simply in the interest of fairness.'' 531 F.3d at 930. As
explained in this rule, EPA has addressed these concerns by using
source specific analysis to identify each individual state's
significant contribution to nonattainment and interference with
maintenance, and including assurance provisions to ensure that the
necessary reductions occur in each state. The Court did not go further
to prohibit all interstate trading. In fact, it notes that ``after
rebuilding, a somewhat similar CAIR may emerge'' (531 F.3d at 930). For
all of these reasons, EPA does not believe the opinion in North
Carolina can be read to stand for the proposition that no interstate
trading can be allowed unless the specific reasons behind market
participants' decisions to purchase allowances can be ascertained.
Because allowance purchase decisions are likely to be based on multiple
factors, which can include the desire to hedge against potential
emission variability as well as to address actually occurring
variability, requiring ascertainment of the specific reasons for
allowance purchases would be tantamount to prohibiting all interstate
trading.
    Moreover, as discussed above, variability is inherent to the
operation of the electric generation system and thus to emissions from
this sector. In fact, variability in emissions occurs every year in
every state and, like variability of year-to-year weather conditions
(which is a major cause of emission variability), cannot be accurately
predicted. See the Power Sector Variability Final Rule TSD in the
docket for this rulemaking. EPA maintains that its approach of allowing
state EGU emissions each year to vary by up to the historically
representative, annual amount of inherent, emission variability
reasonably reflects the realities of the electric generation system and
is consistent with the North Carolina decision. In summary, the
variability limits take into account inherent variability over time of
emissions in each state from this sector while also ensuring that each
state makes necessary emission reductions to eliminate significant
contribution and interference with maintenance. EPA thus concludes that
the commenter's argument that the use of variability limits allows
sources ``within the state'' to avoid eliminating their significant
contribution or interference with maintenance is without merit.

VIII. Economic Impacts of the Transport Rule

A. Emission Reductions

    The projected impacts of this final rule as presented throughout
the preamble do not reflect minor technical corrections to
SO2 budgets in three states (KY, MI, and NY) made after the
impact analyses were conducted. These projections also assumed
preliminary variability limits that were smaller than the variability
limits finalized in this rule. EPA conducted sensitivity analysis
confirming that these differences do not meaningfully alter any of the
Agency's findings or conclusions based on the projected cost, benefit,
and air quality impacts presented for the final Transport Rule. The
results of this sensitivity analysis are presented in Appendix F in the
final Transport Rule RIA.
    Table VIII.A-1 presents projected power sector emissions in the
base case (i.e., without the Transport Rule or CAIR) compared to
projected emissions with the Transport Rule in 2012 and 2014 for all
covered states. Table VIII.A-2 presents 2005 historical power sector
emissions compared to projected emissions with the Transport Rule in
2012 and 2014. Note that for ozone-season emissions, these tables
present results from a modeling scenario that reflects ozone-season
NOX requirements in 26 states. This modeling differs from
the final Transport Rule because it includes ozone-season
NOX requirements for six states (Iowa, Kansas, Michigan,
Missouri, Oklahoma, and Wisconsin) that the final Transport Rule does
not cover (as discussed previously, EPA is issuing a supplemental
proposal to request comment on inclusion of these six states).

  Table VIII.A-1--Projected SO2 and NOX Electric Generating Unit Emission Reductions in Covered States With the
                       Transport Rule Compared to Base Case Without Transport Rule or CAIR
                                                 [Million tons]
----------------------------------------------------------------------------------------------------------------
                                                     2012                                   2014
                                     2012  Base   Transport       2012      2014  Base   Transport       2014
                                        case         rule       Emission       case         rule       Emission
                                     emissions    emissions    reductions   emissions    emissions    reductions
----------------------------------------------------------------------------------------------------------------
SO2...............................          7.0          3.0          4.0          6.2          2.4          3.9
Annual NOX........................          1.4          1.3          0.1          1.4          1.2          0.2
Ozone-Season NOX..................          0.7          0.6          0.1          0.7          0.6          0.1
----------------------------------------------------------------------------------------------------------------

    Notes: The SO2 and annual NOX emissions in
this table reflect EGUs in the 23 states covered by this rule for
purposes of the 24-hour and/or annual PM2.5 NAAQS
(Alabama, Georgia, Illinois, Indiana, Iowa, Kansas, Kentucky,
Maryland, Michigan, Minnesota, Missouri, Nebraska, New Jersey, New
York, North Carolina, Ohio, Pennsylvania, South Carolina, Tennessee,
Texas, Virginia, West Virginia, and Wisconsin).
    The ozone-season NOX emissions reflect EGUs in the 20
states covered by this rule for purposes of the ozone NAAQS
(Alabama, Arkansas, Florida, Georgia, Illinois, Indiana, Kentucky,
Louisiana, Maryland, Mississippi, New Jersey, New York, North
Carolina, Ohio, Pennsylvania, South Carolina, Tennessee, Texas,
Virginia, and West Virginia) and the six states that would be
covered for the ozone NAAQS if EPA finalizes its supplemental
proposal (Iowa, Kansas, Michigan, Missouri, Oklahoma, and
Wisconsin).

    Tables VIII.A-3 through VIII.A-5 present projected state-level
emissions with and without the Transport Rule in 2012 and 2014 from
fossil-fuel-fired EGUs greater than 25 MW in covered states.

  Table VIII.A-2--Projected SO2 and NOX Electric Generating Unit Emission Reductions in Covered States With the
                                Transport Rule Compared to 2005 Actual Emissions
                                                 [Million tons]
----------------------------------------------------------------------------------------------------------------
                                                                  2012         2012         2014         2014
                                                     2005      Transport     Emission    Transport     Emission
                                                    Actual        rule      reductions      rule      reductions
                                                  emissions    emissions    from 2005    emissions    from 2005
----------------------------------------------------------------------------------------------------------------
SO2............................................          8.8          3.0          5.8          2.4          6.4
Annual NOX.....................................          2.6          1.3          1.3          1.2          1.4
Ozone-Season NOX...............................          0.9          0.6          0.3          0.6          0.3
----------------------------------------------------------------------------------------------------------------

    Notes: The SO2 and annual NOX emissions in
this table reflect EGUs in the 23 states covered by this rule for
purposes of the 24-hour and/or annual PM2.5 NAAQS
(Alabama, Georgia, Illinois, Indiana, Iowa, Kansas, Kentucky,
Maryland, Michigan, Minnesota, Missouri, Nebraska, New Jersey, New
York, North Carolina, Ohio, Pennsylvania, South Carolina, Tennessee,
Texas, Virginia, West Virginia, and Wisconsin).
    The ozone-season NOX emissions reflect EGUs in the 20
states covered by this rule for purposes of the ozone NAAQS
(Alabama, Arkansas, Florida, Georgia, Illinois, Indiana, Kentucky,
Louisiana, Maryland, Mississippi, New Jersey, New York, North
Carolina, Ohio, Pennsylvania, South Carolina, Tennessee, Texas,
Virginia, and West Virginia) and the six states that would be
covered for the ozone NAAQS if EPA finalizes its supplemental
proposal (Iowa, Kansas, Michigan, Missouri, Oklahoma, and
Wisconsin).

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BILLING CODE 6560-50-C

B. The Impacts on PM2.5 and Ozone of the Final SO2 and NOX Strategy

    The air quality modeling platform described in section V was used
by EPA to model the impacts of the final rule SO2 and
NOX emission reductions on annual average PM2.5,
24-hour PM2.5, and 8-hour ozone concentrations. In brief, we
ran the CAMx model for the meteorological conditions in the year of
2005 for the eastern U.S. modeling domain.\91\ Modeling was performed
for the 2014 base case and the 2014 air quality-assured trading (i.e.,
remedy) scenario to assess the expected effects of the final rule on
projected PM2.5 and ozone design value concentrations and
nonattainment and maintenance. The procedures used to project future
design values and nonattainment and maintenance are described in
section V.
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    \91\ As described in the Air Quality Modeling Final Rule TSD,
the eastern U.S. was modeled at a horizontal resolution of 12 x 12
km. The remainder of the U.S. was modeled at a resolution of 36 x 36
km.
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    The projected 2014 concentrations of annual PM2.5, 24-
hour PM2.5, and ozone at each monitoring site in the East
for which projections were made are provided in the Air Quality
Modeling Final Rule TSD. The number of nonattainment and/or maintenance
sites in the East for the 2012 base case, 2014 base case, and 2014
remedy for annual PM2.5, 24-hour PM2.5, and ozone
are provided in Table VIII.B-1.\92\ The average and peak reductions in
annual PM2.5, 24-hour PM2.5, and ozone predicted
at 2012 nonattainment and/or maintenance sites due the emission
reductions between 2012 and the 2014 remedy are provided in Table
VIII.B-2.
---------------------------------------------------------------------------

    \92\ To provide a point of reference, Table VIII.B-1 also
includes the number of nonattainment and/maintenance sites based on
ambient design values for the period 2003 through 2007.

                Table VIII.B-1--Projected Reduction in Nonattainment and/or Maintenance Problems for PM2.5 and Ozone in the Eastern U.S.
--------------------------------------------------------------------------------------------------------------------------------------------------------
                                                                                Percent
                                                                                reduction:
                                           Ambient (2003-                                                  2012 base case   Percent reduction: 2014 base
                                                2007)      2012 Base case  2014 Base case    2014 remedy      vs. 2014          case vs. 2014 remedy
                                                                                remedy
                                                                                (percent)
--------------------------------------------------------------------------------------------------------------------------------------------------------
Annual PM2.5 Nonattainment Sites \93\....             103              12               7               0             100  100 percent.
Annual PM2.5 Maintenance-Only Sites......              22               4               3               0             100  100 percent.
24-hour PM2.5 Nonattainment Sites........             151              20              10               1              95  90 percent.
24-hour PM2.5 Maintenance-Only Sites.....              48              21              12               4              81  67 percent.
Ozone Nonattainment Sites................             104               7               4               4              43  No Change.
Ozone Maintenance-Only Sites.............              65               9               6               6              33  No Change.
--------------------------------------------------------------------------------------------------------------------------------------------------------

     Table VIII.B-2--Average and Peak Reduction in Annual PM2.5, 24-Hour PM2.5, and Ozone for Sites That Are
                Projected to Have Nonattainment and/or Maintenance Problems in the 2012 Base Case
----------------------------------------------------------------------------------------------------------------
                                          Average reduction: 2012 base Case    Peak reduction: 2012 base case to
                                                    to 2014 remedy                        2014 remedy
----------------------------------------------------------------------------------------------------------------
Annual PM2.5 Nonattainment Sites.......  2.73 [mu]g/m\3\....................  3.32 [mu]g/m\3\.
Annual PM2.5 Maintenance-Only Sites....  2.99 [mu]g/m\3\....................  3.26 [mu]g/m\3\.
24-hour PM2.5 Nonattainment Sites......  6.8 [mu]g/m\3\.....................  11.7 [mu]g/m\3\.
24-hour PM2.5 Maintenance-Only Sites...  6.5 [mu]g/m\3\.....................  11.0 [mu]g/m\3\.
Ozone Nonattainment Sites..............  1.9 ppb............................  2.3 ppb.
Ozone Maintenance-Only Sites...........  1.8 ppb............................  2.1 ppb.
----------------------------------------------------------------------------------------------------------------

    The information in Table VIII.B-1 shows that there will be
significant reductions in the extent of nonattainment and maintenance
problems for annual PM2.5, 24-hour PM2.5, and
ozone between 2012 and 2014 as a result of the emission budgets in this
rule coupled with emission reductions during this time period from
other existing control programs. Specifically, the results of the air
quality modeling indicate that no sites are projected to be in
nonattainment or projected to have a maintenance problem for annual
PM2.5 in 2014 with the emission reductions expected from the
Transport Rule. As indicated in Table VIII.B-2, the average reduction
in annual PM2.5 across the twelve 2012 nonattainment sites
is 2.73 [mu]g/m\3\ and the peak reduction at an individual
nonattainment site is 3.32 [mu]g/m\3\. Large reductions are also
projected at annual PM2.5 maintenance-only sites.
---------------------------------------------------------------------------

    \93\ ``Nonattainment'' is used to denote sites that are
projected to have both nonattainment and maintenance problems.
---------------------------------------------------------------------------

    For 24-hour PM2.5, we project that the number of
nonattainment sites will be reduced by 95 percent and the number of
maintenance-only sites by 81 percent in 2014 compared to the 2012 base
case. The average reduction in 24-hour PM2.5 across the
twenty 2012 nonattainment sites is 6.8 [micro]g/m\3\ and the peak
reduction at an individual nonattainment site is 11.7 [micro]g/m\3\.
Similarly large reductions are projected at 24-hour PM2.5
maintenance-only sites, as indicated in Table VIII.B-2.
    The emission reductions in the Transport Rule will result in
considerable progress toward attainment and maintenance at the 5 sites
that remain as nonattainment and/or maintenance for the 24-hour
PM2.5 standard. On average for these 5 sites, the predicted
amount of PM2.5 reduction in 2014 is 64 percent of what is
needed for these sites to attain and/or maintain the 24-hour standard.
    Thus, the SO2 and NOX emission reductions
which will result from the Transport Rule will greatly reduce the
extent of PM2.5 nonattainment and maintenance problems by
2014 and beyond. As described previously, these emission reductions are
expected to substantially reduce the number of PM2.5
nonattainment and/or maintenance sites in the East and make attainment
easier for those counties that remain nonattainment by substantially
lowering PM2.5 concentrations in residual nonattainment
sites. The emission reductions will also help those locations that may
have maintenance problems.
    Based on the 2012 base air quality modeling for ozone, 16 sites in
the East are projected to be nonattainment or have problems maintaining
the 1997 ozone standard. The summer NOX reductions are
projected to lower 8-hour ozone concentration by 1.8 ppb, on average by
2014, at monitoring sites projected to be nonattainment and/or have
maintenance problems in the 2012 base case. We expect that the number
of nonattainment sites will be reduced by 43 percent and the number of
maintenance-only sites by 33 percent in 2014 compared to the 2012 base
case. Thus, our modeling indicates that by 2014 the summer
NOX emission reductions in this rule, coupled with other
existing control programs, will lower ozone concentrations in the East
and help bring areas closer to attainment for the 8-hour ozone NAAQS.
As discussed in section III of this preamble, EPA plans to finalize its
reconsideration of the 2008 revised ozone NAAQS soon, and these
reductions will help areas achieve those revised NAAQS.

C. Benefits

1. Human Health Benefit Analysis
    To estimate the human health benefits of the final Transport Rule,
EPA used the BenMAP model to quantify the changes in PM2.5
and ozone-related health impacts and monetized benefits based on
changes in air quality. For context, it is important to note that the
magnitude of the PM2.5 benefits is largely driven by the
concentration response function for premature mortality. Experts have
advised EPA to consider a variety of assumptions, including estimates
based both on empirical (epidemiological) studies and judgments
elicited from scientific experts, to characterize the uncertainty in
the relationship between PM2.5

concentrations and premature mortality. For this rule we cite two key
empirical studies, one based on the American Cancer Society cohort
study \94\ and the other based on the extended Six Cities cohort
study.\95\
---------------------------------------------------------------------------

    \94\ Pope et al., 2002. ``Lung Cancer, Cardiopulmonary
Mortality, and Long-term Exposure to Fine Particulate Air
Pollution.'' Journal of the American Medical Association. 287:1132-
1141.
    \95\ Laden et al., 2006. ``Reduction in Fine Particulate Air
Pollution and Mortality.'' American Journal of Respiratory and
Critical Care Medicine. 173:667-672.
---------------------------------------------------------------------------

    The estimated benefits of this rule are substantial, particularly
when viewed within the context of the total public health burden of
PM2.5 and ozone air pollution. A recent EPA analysis
estimated that 2005 levels of PM2.5 and ozone were
responsible for between 130,000 and 320,000 PM2.5-related
and 4,700 ozone-related premature deaths, or about 6.1 percent of total
deaths from all causes in the continental U.S. (using the lower end of
the range for premature deaths).\96\ In other words, 1 in 20 deaths in
the U.S. is attributable to PM2.5 and ozone exposure. This