Opt-in units. EPA proposes to include, in the trading programs
under the proposed FIP, provisions allowing non-electric generating
(non-covered) units to opt into one or more of the proposed trading
programs. EPA is proposing opt-in provisions since they could encourage
emission reductions by sources that could make lower cost emissions
reductions than electric generating units. These lower cost reductions
could replace higher cost reductions that would otherwise be required
by some electric generating units and could reduce overall program
costs.
    Specifically, the proposed opt-in provisions would allow a non-
covered unit to enter a proposed trading program voluntarily and obtain
an allocation of

allowances reflecting the unit's emissions before opting in. Once in
the program, the unit could make emissions reductions at a lower cost
than other units in the program and then sell, to covered sources for
use in compliance, allocated allowances that are in excess of the
unit's reduced emissions. The allowances created for and allocated to
the opt-in unit would be in addition to the allowances issued from the
state budget and would be usable in compliance by any covered unit (or
opt-in unit) just like the allowances allocated from the state budget
to covered sources. Replacing higher cost reductions by covered units
by lower cost reductions by opt-in units could reduce the overall cost
of controlling emissions. EPA requests comment on the benefits and
concerns of including opt-in provisions.
    The proposed opt-in provisions would establish the following
procedures, which are similar to those set forth in the CAIR FIPs. A
unit would be eligible to opt into one of the proposed trading programs
if the unit: (1) Is an operating boiler, combustion turbine, or other
stationary combustion device; (2) is in a facility that is located in a
state subject to that proposed trading program; (3) vents all its
emissions through a stack or duct; and (4) would be able to meet the
monitoring, reporting, and recordkeeping requirements for covered units
under the proposed trading program. The owners and operators, through a
designated representative, of a source with a unit seeking to opt in
would submit to EPA an opt-in application, which must include an
emissions monitoring plan for the unit. If EPA approved the monitoring
plan, the unit would operate, monitor, and report emissions in
accordance with the monitoring plan and monitoring and reporting
requirements under Part 75, for at least one or for up to 3 full
calendar years (or full ozone seasons, in the case of an opt-in unit in
the proposed NOX ozone season trading program). The unit's
monitored heat input and emissions rate for that period would be the
baseline heat input and baseline emissions rate used in calculating any
future opt-in allowance allocations.
    After the monitoring period, EPA would review the opt-in
application and either approve the application (including an allowance
allocation for the first year of approved opt-in status), effective
January 1 (May 1 for the NOX ozone season program) of the
year of the approval, or disapprove the application. By December 1
(September 1 for the NOX ozone season program) of the first
year and each subsequent year, EPA would calculate and record the opt-
in unit's allowance allocation for the year. The allowance allocation
for the year involved would be the product of: The lesser of the
baseline heat input and the opt-in unit's actual heat input during the
control period in the immediately preceding year; and the lesser of the
baseline emissions rate multiplied by 70 percent and the most stringent
state or federal emissions limitation applicable to the unit (or
emissions levels resulting from the imposition of Clean Air Act
requirements) any time during the control period in the year involved.
    After the opt-in unit was in the program for at least four years,
the owners and operators could request to withdraw the opt-in unit at
the end of a control period if the unit met the requirement to hold
allowances covering emissions for that control period and if any
allowances already allocated for a subsequent control period were
surrendered. However, the owners and operators could not submit a new
opt-in application for the withdrawn unit until at least 4 years after
the last control period before the withdrawal. An opt-in unit that had
a change in regulatory status during a control period and would then
meet the general applicability requirements for covered units would
immediately lose its status as an opt-in unit. Having lost its opt-in
unit status, the unit would have to surrender to EPA the allocated opt-
in allowances attributable to the portion of any control period during
which the unit no longer qualified as an opt-in unit.
    In addition to a general request for comment on all aspects of this
opt-in requirement, EPA requests comment on three specific aspects of
the proposed opt-in provisions. First, EPA requests commenters to
explain how much interest they believe owners and operators of
noncovered sources would have in using these proposed provisions to opt
into one or more of the proposed trading programs and what types of
sources would be most likely to opt in. Commenters on this aspect of
the proposed provisions should consider what effect (if any) future
emission reduction requirements under upcoming, new regulations (e.g.,
regulations concerning maximum available control technology (MACT)
standards for sources such as industrial boilers and cement kilns, best
available retrofit technology (BART) requirements for certain
stationary source categories, and reasonably available control
technology (RACT)) might have on the pool of sources that might be
interested in opting into the program. EPA notes that, in the Acid Rain
Program, opt-in provisions were established in section 410 of the Act,
were implemented in the Acid Rain Program regulations starting in 1995,
and, to date, have been used by 4 facilities (plus 2 more facilities
that temporarily opted in to obtain allowances for use in the CAIR
SO2 trading program). In the NOX Budget Trading
Program, EPA promulgated opt-in provisions that states could include in
their SIPs and that were used by 3 facilities.
    Second, EPA requests comment on whether it is necessary to take
steps to identify in this application process whether emissions
reductions identified by these facilities are reductions units would
not have made for other reasons unrelated to the opt in. Comments on
this issue would be especially useful if they discussed how the
proposed opt-in provisions could be revised in order to ensure that
opt-in units would not be credited for emissions reductions that the
units would make even if they did not opt in. For example, a unit that,
for business or other reasons, was already planning to take actions
that would have the effect of reducing emissions (e.g., fuel switching)
may be able to opt in under this proposed approach and obtain allowance
allocations that could be sold to covered units. In that case,
emissions reductions that would have occurred anyway would be offset by
the allocation of new, opt-in allowances that would be in addition to
the state budget. The net result, in that case, would be an increase in
total emissions--considering the emissions of both the covered units
and the opt-in unit--over what total emissions would have been if the
unit had not opted in. EPA requests comment on whether, in that
circumstance the total emissions reduction still may be sufficient to
satisfy the interstate transport issue if such reductions were not
anticipated in state budgets. In other words, even if emissions
reductions would have happened in the absence of the program, they may
still be reductions that alleviate attainment or maintenance issues in
downwind states. Third, EPA requests comment on whether the baseline
emission rate used to determine the allocations for each opt-in unit
should be multiplied by 70 percent before EPA compares that rate to the
unit's most stringent applicable emissions limitation in order to
determine which is lower. The lower emission rate would then be used in
calculating the opt-in unit's allocation. EPA also requests comment on
whether the allocation for an opt-in unit during Phase II of the
proposed SO2 Group 1

trading program should be reduced by 45 percent, reflecting the average
percent reduction in state SO2 Group 1 budgets from Phase I
to Phase II. The 70 percent reduction of the baseline emission rate for
all opt-in units, and the further 45 percent reduction in Phase II
allocations for SO2 Group 1 opt-in units, would be meant to
ensure that opt-in facilities install controls in a similar manner as
covered units; however, all things equal, this may serve to lower the
number of facilities that would opt into the program. EPA therefore
specifically solicits comment on whether the proposed 70 percent
reduction (or some other percentage reduction or no reduction) should
applied to the baseline emission rate for all opt-in units and on
whether any additional percentage reduction or 45 percent or some other
additional percentage reduction should be applied to SO2
Group 1 opt-in units on Phase II in order to strike a reasonable
balance between achieving additional reductions per opt-in facility and
having more facilities opt in.
    Sources equal to or less than 25 MWe and Non-EGUs. Certain smaller
EGUs and non-EGU sources that were included in the NOX
Budget Trading Program were brought into the CAIR NOX ozone
season trading program. For treatment of such sources in the proposed
FIPs, see section V.F in this preamble.
    In the Northeast, a large number of EGUs serving generators with a
nameplate capacity equal to or less than 25 MWe contribute
NOX emissions to ozone problems on high electric demand
days. There is regional interest in lowering the 25 MWe applicability
threshold in the ozone season to deal with this issue and in
potentially requiring these units to operate with greater controls than
a trading program would necessitate. EPA requests comment on lowering
the greater-than-25 MWe applicability threshold for EGUs during the
ozone season, and whether a trading program offers the right approach
for addressing NOX emissions from these smaller EGUs.
(2) Allocation of Emissions Allowances
    EPA proposes to distribute, to sources in each state, a number of
emissions allowances equal to the SO2, annual
NOX, and ozone-season emissions budgets for that state
identified in section IV.E (the state budgets listed in IV.E are the
budgets without accounting for variability). As discussed later, EPA
proposes to set aside 3 percent of each state's emissions budgets for
new units. Tables IV.E.-1 and IV.E.-2 in section IV.E, referenced
previously, show the permanent SO2, NOX, and
ozone season NOX budgets for each covered state (without
accounting for variability). EPA would distribute four discrete types
of emissions allowances for four separate cap and trade programs:
SO2 group 1 allowances, SO2 group 2 allowances,
NOX annual allowances, and NOX ozone season
allowances.
    In the SO2 group 1 and SO2 group 2 programs,
each SO2 allowance would authorize the emission of one ton
of SO2 annually. In the NOX annual program, each
NOX annual allowance would authorize the emission of one ton
of NOX annually. In the NOX ozone season program,
each NOX ozone season allowance would authorize the emission
of one ton of NOX during the regulatory ozone season (May
through September for this proposed rule). Note that, as explained in
section IV.E, EPA is taking comment on extending the ozone season for
this rule.
    In each of the four trading programs, a covered source would be
required to hold sufficient allowances to cover the emissions from all
covered units at the source during the control period. EPA proposes to
assess compliance with these allowance-holding requirements at the
source (i.e., facility) level.
    This section explains how EPA proposes to allocate to two sets of
units in a state, existing units and new units. This section also
describes the new unit set asides in each state, allocations to units
that are not operating, and the recording of allowance allocations in
facility accounts.
    EPA proposes to base allocations to existing units on projected
emissions from these units after elimination of some or all significant
contribution and interference with maintenance (i.e., projected
emissions after implementation of the proposed FIPs), and after
deductions for the new unit set asides. Section IV.E describes how EPA
developed the overall state budgets.
    EPA requests comment on all aspects of the allocation method, such
as the overall state budgets, the need to have existing unit and new
unit allowance allocations, the proposed allocation methodology for
existing units, and the proposed allocation methodology for new units.
EPA believes the proposed approach is consistent at the state budget
and unit level with the Court's direction and also addresses the new
unit issue. The proposed methodology for allocating allowances does not
consider heat input or fuel adjustment factors. Note that in light of
the Court decision, EPA also is not proposing any allocation
methodologies that rely on Title IV existing allowances.
    EPA requests comment on whether there are alternative allocation
methods EPA should consider that are consistent with the Court
decision. EPA asks that commenters present any such approaches in
detail to enable thorough evaluation and that they provide a legal
analysis demonstrating how the approach is consistent with the Court's
opinions and the statutory mandate of section 110(a)(2)(D).
    Allocations to existing units. Existing units are units, as
described in the Applicability section, previously (see 4.b), that
commenced commercial operation, or are planned \85\ to commence
commercial operation, prior to January 1, 2012. EPA proposes that, for
2012, each existing unit in a given state receives allowances
commensurate with the unit's emissions reflected in whichever total
emissions amount is lower for the state, 2009 emissions or 2012 base
case emissions projections. In either case, the allocation is adjusted
downward, if the unit has additional pollution controls projected to be
online by 2012. EPA proposes to use this same method to allocate
allowances for each of the four trading programs (SO2 group
1, SO2 group 2, NOX annual, and NOX
ozone season). This proposed allocation method is different from the
allocation method used in the CAIR.
---------------------------------------------------------------------------

    \85\ Planned units, as identified in the EGU inventory and
included in IPM modeling projections, comprise units that had broken
ground or secured financing and were expected to be online by the
end of 2011.
---------------------------------------------------------------------------

    For states with lower SO2 budgets in 2014
(SO2 group 1 states), each unit's allocation for 2014 and
later is determined in proportion to its share of the 2014 state
budget, as projected by IPM. This approach is also different from the
allocation method in CAIR. Further details on the proposed allocation
method for existing units can be found in the ``State Budgets, Unit
Allocations, and Unit Emissions Rates'' TSD in the docket for this
rule.
    The proposed FIPs are designed to remove emissions from each upwind
state that significantly contributes to nonattainment or interferes
with maintenance downwind. The allocation method is consistent with the
proposed approach for determining each upwind state's significant
contribution and interference with maintenance (described in section
IV) because the allocations would be based on the projected remaining
emissions from each covered source in each upwind state after removal
of the state's significant contribution and interference with
maintenance.
    EPA proposes to allocate to existing units one time, before the
Transport

Rule cap and trade programs commence (see discussion of schedule,
later). The allocations generally would be permanent (with the
exception of non-operating units, discussed later) as base amounts and
would not be updated. (Note that any unused new source set aside
allowances would be distributed proportionally to existing units in
addition to the base amount.) By not updating the allocations, EPA can
allocate for several years at once, which supports the development of
allowance trading markets.
    The proposed unit-level allocations for existing EGUs for Phases I
and II are set forth in the ``State Budgets, Unit Allocations, and Unit
Emissions Rates'' TSD in the docket for this rule, but EPA proposes to
include them in the final rule in an Appendix A to each set of trading
program regulations (i.e., the SO2 group 1, SO2
group 2, NOX annual, and NOX ozone season trading
programs). Because the TSD shows the proposed allocations, Appendices A
in the proposed trading program regulations do not repeat the
allocations and are simply reserved. The only circumstances under which
allocations would not be permanent as base amounts would be if the unit
in the Appendix A table turned out not to be a covered unit, or turned
out not to be required to hold allowances to cover emissions, as of the
first day of the control period in 2012,\86\ or if the unit stops
operating for three consecutive years.
---------------------------------------------------------------------------

    \86\ If a unit was allocated allowances but turned out not to be
a covered unit or turned out not to be required to hold allowances
as of January 1, 2012, then the treatment of the allocation depends
on when the Administrator determines the unit is not subject to the
trading program or to the allowance-holding requirement. For
instance, if the allocation has not been recorded, the Administrator
would not record it, and, if the allocation has been recorded and
the Administrator has not completed the compliance determination
process for the unit, allowances equal to the allocation would be
deducted from the unit's compliance account.
---------------------------------------------------------------------------

    Allocations to new units. EPA proposes to allocate emissions
allowances to new units from new unit set-asides in each state. EPA
proposes, for each of the four trading programs, to define a new unit
as: Any covered EGU not listed in the table in Appendix A of the
trading rule applicable to that program; any unit listed in Appendix A
whose allocation is subject to the requirement that the Administrator
not record the allocation or that the Administrator deduct the amount
of the allocation (see previous discussion in footnote), or any unit
listed in Appendix A that stopped operating for three consecutive
years, is no longer allocated allowances as an existing unit, but
resumes operation.
    EPA believes it is important to have a small new unit set-aside in
each state to cover new units within the budget that was set aside to
address the state's significant contribution and interference with
maintenance. To create new unit set-asides, EPA would distribute to
existing EGUs a quantity of allowances less than the entire state
emissions budgets. EPA would hold back, for the new unit set-aside for
a state, 3 percent of the state budget. Three percent was established
based on the total amount of new unit emissions projected for all the
covered states (See ``State Budgets, Unit Allocations, and Unit
Emissions Rates'' TSD). In this way, new units could be allocated some
allowances for their emissions, which are part of the the state's
contribution to downwind nonattainment or interference with
maintenance.
    For every control period after the control period in which a new
unit commences commercial operation or, in the case of an existing unit
that did not operate for three consecutive years, resumes operation,
EPA would allocate to the unit from the new unit set-asides based on
the unit's reported emissions from the previous control period. EPA
would not allocate to a new unit for the control period during which
the unit commences commercial operation because the unit would have no
actual emissions data on which to base such an allocation.
    EPA proposes that, for the first control period for which the new
unit wants an allowance allocation from the new unit set aside (after
the first year of operation), the designated representative of the
source that includes the new unit would submit to EPA a request for a
new unit allocation.
    For each control period, any allowances remaining in a state's new
unit set-aside (after allocations are made to new units that requested
allowances) would be distributed to the existing units in that state in
proportion to the existing unit's original allocations. This ensures
that total allocations to units in the state would equal the state
budget.
    For each control period, if the size of the new unit set-aside were
insufficient to provide allocations for all new units requesting
allowances, then allocations to all new units would be proportionally
reduced.
    EPA requests comment on the proposed allocation approach for new
units. EPA also requests comment on alternative allocation approaches
that would provide allowances to new units for the control period
during which the unit commences commercial operation.
    Size of new unit set asides. EPA proposes new unit set-asides that
are 3 percent of the state emissions budgets. The size of the new unit
set-aside would be 3 percent for the SO2 group 1,
SO2 group 2, NOX annual, and NOX ozone
season trading programs, as appropriate, for each state. EPA based the
size of the proposed new unit set-asides on a comparison of projected
emissions from new units to projected emissions from existing units for
all covered states under the proposed State Budgets/Limited Trading
remedy. As noted previously, EPA proposes that after a unit is not
operating for three 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.
This approach would allow the size of the new unit set-asides to grow
over time. Note that in EPA's analysis to determine the size of the new
unit set-asides, EPA assumed that allocations for non-operating units
would be allocated to the new unit set-asides after a unit had ceased
operating for 3 consecutive years (see ``State Budgets, Unit
Allocations, and Unit Emissions Rates'' TSD). EPA requests comment on
the size of the new unit set-asides.
    Non-operating units. EPA proposes that, once an EGU does not
operate (i.e., does not combust any fuel) for 3 consecutive years, the
Agency would no longer allocate allowances to the unit, starting in the
seventh year after the first year of non-operation. All allowances that
would otherwise have been allocated to the unit for that seventh year
and every year thereafter would be allocated to the new unit set-aside
for the state in which the non-operating unit is located. This would
provide additional allowances for new units that may need them (e.g.,
for new units that replace non-operating units), and reflects the fact
that new unit emissions are included in the state's budget that
eliminates the portion of significant contribution and interference
with maintenance that EPA has identified in today's proposed action (in
an average year).
    EPA proposes to continue allocating allowances to non-operating
units during the 3 consecutive years of non-operation plus an
additional 3-year period to reduce the incentive for owners to keep
units operating simply to avoid losing the allowance allocations for
those units. Other options that EPA considered include continuing to
allocate allowances for an unlimited period of time, or

immediately discontinuing allocations to such units upon the unit
ceasing operation.
    Continuing allocations to non-operating units has the benefit of
reducing the incentive to keep units in operation that should otherwise
be, for instance, permanently retired due to age and inefficiency. EPA
believes there will be less incentive to continue running old,
inefficient EGUs if at least some allowances would still be received
after retirement. On the other hand, stopping allocations for non-
operating units realigns allowance allocations with the sources that
actually need such allowances. Non-operating units obviously are no
longer emitting and so do not need allowances. Moreover, additional
allowances may be needed for the new unit set-aside to accommodate new
units coming on line in the future. Allocating allowances for a
specified, but limited, period after the unit ceases operating for 3
consecutive years, as EPA proposes to do, would be a middle ground
approach to this issue.
    EPA requests comment on the proposed approach for allocating
allowances to non-operating units. EPA requests comment on simplifying
allocations by not allocating at all to non-operating units. EPA also
requests comment on maintaining perpetual allocations to non-operating
units, similar to the treatment of non-operating units in the title IV
Acid Rain Program.
    Schedule for determining and recording allowances. As discussed
previously, proposed allocations for existing units are shown in the
``State Budgets, Unit Allocations, and Unit Emissions Rates'' TSD. EPA
proposes to include final allocations for existing units in the
Appendix A for each proposed trading program in the final Transport
Rule.
    EPA proposes to record initial allowances for existing units in
facility accounts by September 1, 2011, for the control periods in
2012, 2013, and 2014. EPA proposes to record allowances for existing
units by July 1, 2012 and July 1 of each year thereafter, for the
control periods in the third year after the year the allowances are
recorded. For example, EPA would record existing unit allowances by
July 1, 2012 for control periods in 2015. Recording allowances several
years in advance supports the development of the allowance trading
markets and provides time for covered sources to plan for compliance.
    As discussed previously, EPA proposes to determine allocations to a
new unit based on the unit's reported emissions the prior year.
Although the last quarter of emissions data for a year must be
submitted to EPA in the fourth quarterly emissions report by January 30
of the next year, the emissions data in that report may be revised
based on EPA's review and may not be finalized until May or June after
receipt of that report. Consequently, EPA proposes to determine new
unit allocations by July 1 of the year for which the allocation is
determined. (Because, for an ozone season ending September 30,
emissions data may not be finalized until the following February or
March, EPA proposes to determine new unit allocations by April 1.) For
example, EPA would determine a new unit's allocations for control
periods in 2012 by July 1, 2012. EPA proposes to make the new unit
allocation determinations available to the public through a notice of
data availability. Under the proposal, objections to the notice could
be submitted, and EPA would issue a second notice of data availability
referencing any necessary adjustments of the new unit allocations.
    EPA proposes to record allowances for new units by September 1,
2012 and September 1 of each year thereafter, for the control periods
in the year that the allowances are recorded. (For the units in the
NOX ozone season program, the comparable deadline for
recordation of new units'' allowances is June 1.) For example, EPA
would record new unit allocations by September 1, 2012 for control
periods in 2012.
    EPA requests comment on the proposed schedule for determining and
recording emissions allowances, especially administratively-practical
ways to record allowances as soon as possible, so facilities have
information useful in compliance planning.
    Alternative allocation methods. The proposed allocation method,
described previously, would determine each unit's allocation consistent
with the proposed approach to determine each state's significant
contribution and interference with maintenance. EPA considered other
alternative allocation methods. One is discussed here, but EPA
recognizes that there are many ways that allowances could be allocated.
EPA is requesting comment on whether the alternative described here or
any other approach should be used instead of the proposed allocation
method.
    As discussed in section IV, the state emissions budgets are
determined based on EPA's analysis of significant contribution and
interference with maintenance in each upwind state. EPA believes that
it is appropriate to develop individual unit allowances consistent with
this approach. In the proposed approach, EPA does this by allocating
down to the individual unit level using all of the same assumptions
used in developing the proposed budgets. Under this approach all units
are allocated allowances consistent with their projected emissions;
this means that a unit that installs control equipment receives fewer
allowances than a similar unit that did not install control equipment.
    EPA is taking comment on an alternative methodology that still
links unit allowances directly to the way state budgets were developed
(and thus, significant contribution was defined). In the alternative,
all units within a state would be treated as a single group. The
allocation method would distribute allowances equal to a state's
emissions budget without variability to each covered source in the
state (in effect, distributing the responsibility for eliminating
significant contribution and interference with maintenance) based on
each source's proportional share of total state heat input. The state
heat input would be as projected for the initial year of the program.
In other words, this alternative method for distributing allowances
would have the effect of distributing the responsibility for
eliminating all or part of a state's overall significant contribution
and interference with maintenance to individual units based on each
unit's share of projected heat input.
    There are other approaches to allocation. For example, EPA could
identify groups of units in each state that are capable of having
similar emissions characteristics (e.g., grouped by size, fuel type, or
age). EPA would distribute a state's emissions budget without
variability to each group of units in the state (in effect,
distributing the responsibility for eliminating all or part of
significant contribution) perhaps based on each group's proportional
share of the state budget as projected in the initial year of the
program. After apportioning a state's budget to the groups of units,
under such an approach EPA could distribute allocations to individual
sources within each group based on each source's proportional share of
projected heat input. Like the first alternative allocation method
described previously, this approach distributes each state's
significant contribution and interference with maintenance to
individual sources in the state. By determining groups and then
distributing allocations within the groups based on proportional
shares, this approach would treat units within the categories equally
(i.e., it would not treat a source that had acted early to control
differently from one that had yet to take control action).

    EPA requests comment on the proposed allocation approach, the
alternative approach, and on any other approaches that are consistent
with the Court decision. EPA asks that commenters present any such
approaches in detail to enable thorough evaluation and that they
provide a legal analysis demonstrating how the approach is consistent
with the Court's opinions and the statutory mandate of section
110(a)(2)(D).
(3) Allowance Management System
    EPA proposes that the State Budgets/Limited Trading remedy include
an allowance management system (AMS) operated essentially the same as
the existing allowance management systems that are currently in use for
CAIR and the Acid Rain Program under Title IV. Under the proposed State
Budgets/Limited Trading remedy, the SO2 programs and the
NOX programs would remain separate trading programs
maintained in EPA's existing AMS. AMS would be 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. Specifically, AMS would track the allocation of all
SO2 and NOX allowances, holdings of
SO2 and NOX allowances in compliance accounts
(i.e., accounts for individual covered sources) and general accounts
(i.e., accounts for other entities such as companies and brokers),
deduction of SO2 and NOX allowances for
compliance purposes, and transfers of allowances between accounts. 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 rate limitations and other
emissions-related provisions of the cap and trade programs. AMS also
allows the public to see whether sources are complying. In addition,
AMS provides data to the allowance market, including a record of
ownership of allowances, dates of allowance transfers, buyer and seller
information, and the serial numbers of allowances transferred.
(4) Monitoring and Reporting
    EPA proposes to require that Transport Rule-covered sources monitor
and report SO2 and NOX emissions in accordance
with 40 CFR part 75. Most sources that would be covered by the proposed
Transport Rule are already measuring and reporting SO2 mass
emissions year round under CAIR and/or the Title IV Acid Rain Program.
Similarly, most sources that would be covered are already measuring and
reporting NOX mass emissions year round under CAIR. CAIR and
the Acid Rain Program both require Part 75 monitoring.
    Consistent, complete, and accurate measurement of emissions, as
Part 75 requires, ensures that, for a given pollutant, one ton of
reported emissions from one source is equivalent to one ton of reported
emissions from another source. Thus, each allowance represents one ton
of emissions, regardless of the source for which the emissions are
measured and reported. This establishes the integrity of each
allowance, which instills confidence in the underlying market
mechanisms that are central to providing sources with flexibility in
achieving compliance.
    EPA proposes to require monitoring of SO2 and
NOX emissions by all existing covered sources by January 1,
2012 for states covered for the daily and/or annual PM2.5
NAAQS, and monitoring of NOX emissions by May 1, 2012 for
sources covered for the 8-hour ozone NAAQS, using Part 75 certified
monitoring methodologies. New sources would have separate deadlines
based upon the date of commencement of commercial operation, consistent
with CAIR and the Acid Rain Program.
    Specifically, a new unit must install and certify its monitoring
system within 180 days of the commencement of commercial operation.
While, under the Acid Rain Program and CAIR, the deadline was the
earlier of 90 operating days or 180 calendar days after commencement of
commercial operation, EPA intends to propose that part 75 be revised to
use only the 180-day deadline. EPA believes that using only the 180-day
deadline would ensure that new units have sufficient time to complete
installation and certification of monitoring systems without having to
request extensions of time and would facilitate compliance by making
the monitoring deadline clearer for owners and operators and easier for
EPA to apply. See a discussion on units transitioning from CAIR and
units previously not covered by Part 75 requirements in section V.F,
later.
    EPA also proposes to require designated representatives to submit
quarterly reports that would include emissions and related data and
proposes to establish a procedure for resubmission of quarterly reports
where appropriate. Specifically, the proposed reporting provisions
would include the same requirement to submit quarterly reports as the
requirement in Part 75. In addition, the proposed provisions would
include language that would make explicit a process that is implicit
under, and has been in continuous use in, the Acid Rain, NOX
Budget, and CAIR trading programs. The resubmission process would be as
follows. The Administrator could review and audit any quarterly report
to determine whether the report met the monitoring, reporting, and
recordkeeping requirements in the proposed rule and Part 75. The
Administrator would provide notification to the designated
representative stating whether any of these requirements was not met
and specifying any corrections that the Administrator believed were
necessary to make through resubmission of the report and a reasonable
deadline for a response. The Administrator could provide reasonable
extensions of such deadline. The designated representative would be
required, within the deadline (including any extensions), to resubmit
the report with the identified corrections, except to the extent the
designated representative would submit information showing that a
correction was not necessary because the report already met the
monitoring, reporting, and recordkeeping requirements relevant to the
correction. Any resubmission of a quarterly report would have to meet
the requirements for quarterly report submission, except for the
deadline for initial submission of quarterly reports.
(5) Assurance Provisions
    To ensure that the proposed FIPs require the elimination of all
emissions that EPA has identified that significantly contribute to
nonattainment or interfere with maintenance within each individual
state, we are proposing to establish assurance provisions, as described
later, 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 budget
with the variability limit for state budgets, discussed in section IV.
As described therein, 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 is
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.
    Starting in 2014, EPA is proposing as part of the FIPs to establish
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 addition, the 3-year
rolling average of the state's emissions must not exceed the state
budget with the variability limit allowed on average for any
consecutive 3 years for that state (i.e., the state's 3-year
variability limit). Note that in 2014 and 2015, EPA would apply only
the 1-year variability limit, and not the 3-year variability limit.
Because emissions would be evaluated against the 3-year variability
limit on a 3-year rolling average basis, the application of the 3-year
variability limit in 2016 would serve to limit emissions in 2014 and
2015.
    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 one year, and the state's
annual average emissions for any 3-year period can not exceed, on
average, the state budget with the state's 3-year variability limit.
The fact of the 3-year variability limit would further assure that
emissions are constrained during the two preceding years.
    For example, a hypothetical state has a budget of 100,000 tons, a
1-year variability limit of 10,000 tons, and a 3-year variability limit
of 5,800 tons.
     In the first year, collective emissions from covered EGUs
in the state are 120,000 tons, 10,000 tons over the budget with 1-year
variability limit of 110,000 tons, triggering the assurance provisions
in that year.
     In the second year, collective emissions from covered EGUs
in the state are 97,500 tons, below the state budget with 1-year
variability limit of 110,000 tons. Assurance provisions are not
triggered.
     In the third year, collective emissions from covered EGUs
in the state are 109,000 tons, below the state budget with 1-year
variability limit of 110,000 tons. Assurance provisions are not
triggered for the 1-year variability limit. But after three years, the
state emissions are computed against the 3-year variability limit. The
3-year rolling average (adding the last 3 years of emissions and
dividing that by three) computes to 108,833 and determines that the 3-
year variability limit of 105,800 tons is exceeded, even though in any
one year, the 1-year variability limit may not have been exceeded.
     In the fourth year, collective emissions from covered EGUs
in the state are 99,000 tons, below the state budget with 1-year
variability limit of 110,000 tons. Assurance provisions are not
triggered for the 1-year variability limit. The 3-year rolling average
of the last 3 years is 101,833, which is less than the 3-year
variability limit of 105,800. Assurance provisions are not triggered
for the 3-year variability limit.
    The variability limits for each state are shown in Tables IV.F-1
through IV.F-3 in section IV. The basis for the variability limits is
also described in section IV.F. Additional details may be found in the
``Power Sector Variability'' TSD in the docket to this rule.
    To implement this requirement, EPA would first evaluate whether any
state's total EGU emissions in a control period exceeded the state's
budget with 1-year variability limit. Next, EPA would evaluate whether
any state's total EGU emissions in a control period exceeded the
state's budget with the 3-year variability limit (once the program is
in effect for 3 years, and each year thereafter). If any state's EGU
emissions in a control period exceeded either of these limits, then EPA
would apply additional criteria to determine which source owners in the
state would be subject to an allowance surrender requirement. The
proposed allowance surrender requirement that owners surrender
allowances under the assurance provisions would be triggered only for
owners of units in a state where the total state EGU emissions for a
control period exceed the applicable state budget with the variability
limit. Moreover, only an owner whose units'' emissions exceed the
owner's share of the state budget with the variability limit would be
subject to the allowance surrender requirement.
    In applying the additional criteria, EPA would evaluate which
source owners in the state had emissions exceeding the respective
owner's share of the state budget with the variability limit
(regardless of whether the source had enough allowances to cover its
emissions). An owner's share would equal the sum of the allocations of
its EGUs in the state, plus its proportional share of the amount of the
variability limit that, when included with the state budget, was
exceeded by the state's EGU emissions during the year involved. If the
state emissions exceeded both the state budget with the 1-year and with
the 3-year variability limit, then the 3-year variability limit would
be used in determining the owner's share of the state budget.
    On the other hand, if the state's total EGU emissions for a control
period in a given year did not exceed the state budget with the state's
1-year variability limit and did not exceed, on a 3-year rolling
average basis, the state budget with the state's 3-year variability
limit, then the additional criteria concerning the emissions of each
owner's sources in the state would not apply. For more details see
subsection V.D.4.i, later, and the rule text at the end of this
preamble (Sec. Sec.  97.425, 97.525, 97.625, and 97.725--Compliance
with assurance provisions).
    As discussed previously, EPA would not allocate emissions
allowances to a new unit for the control period during which the unit
commences commercial operation. In the case where assurance provisions
for a state are triggered in the year that a new unit first operates,
the owner's share--if calculated as the sum of the allocations of its
EGUs plus its proportional share of the variability limit--would
necessarily be zero because the new unit would have no allocation for
that year. Instead, EPA would use a specific surrogate emissions number
to calculate the maximum amount the unit could emit in that year before
being required to surrender allowances under the assurance provisions.
The surrogate emissions number would apply only if the state's
assurance provisions were triggered and only in the first year of the
new unit's operation.
    The surrogate emissions number would be calculated by multiplying
the unit's allowable emissions rate (in lbs/MWe) by the unit's maximum
hourly load (in MWe/hr) and a default capacity factor specific to the
unit type. The default capacity factors would be: 84 percent for coal-
fired units, 66 percent for gas-fired combined cycle units, and 15
percent for combustion turbines in the NOX annual and
SO2 trading programs; and 89 percent for coal-fired units,
72 percent for gas-fired combined cycle units, and 22 percent for
combustion turbines in the NOX ozone season trading program.
These percentages are based on the 95th percentile capacity factors for
these unit types in quarterly data that have been reported to EPA for
coal-fired units commencing operation since 2000 and combustion
turbines since 2004. EPA believes that this approach would cover a
range of operating conditions for new units and thus avoid attributing
to each new unit a share of the state budget with variability
reflecting the maximum amount of emissions possible for the unit in its
first operating year, in the case where the state's assurance
provisions were triggered. (See ``Capacity Factors Analysis for New
Units'' TSD in the docket for further information on the proposed
default capacity factors for new units).

    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 later.
    EPA believes the likelihood of triggering assurance provisions is
low. The State Budgets/Limited Trading programs have a regional cap
that limits overall emissions; state-specific budgets that are the
basis for allocating emissions allowances in each state; assurance
provisions that each state eliminates the excess emissions leading to
significant contribution and interference with maintenance that EPA has
identified in this proposed action; and additional allowance surrender
requirements for not meeting emissions reductions requirements. As
discussed in section e, later, the underlying mechanism of cap and
trade, even without assurance provisions, has succeeded in reducing
emissions below allowance levels. The accumulated data, history, and
experience from these programs underscore that emissions reductions
requirements and environmental and public health goals of the programs
were met. However, unlike earlier cap and trade programs (e.g., the
Acid Rain, CAIR, and NOX Budget Trading Programs), where
allocations were made based on the same average emissions rates for
classes of units, in this proposed rule EPA specifically designed
budgets that were intended to match up with reductions at certain cost
levels used to determine the respective state's significant
contribution and interference with maintenance. This means more units
are likely to have allocations close to their emissions when the state
is eliminating its significant contribution and interference with
maintenance and there is likely to be less need for trading in order
for sources to comply with the requirement to hold allowances covering
emissions. Additionally, EPA has now added assurance provisions to
ensure that emissions within a state do not exceed the state budget
with the variability limitation.
    The existence of these assurance provisions will limit incentives
to trade and ensure that state emissions will stay below the level of
the budget with the variability limit. An example of a circumstance
that might result in emissions approaching the variability limit is an
extended nuclear unit outage that causes a company to run its fossil
units harder to meet demand. Increased emissions under such a scenario
would not result from the ability to trade across state boundaries, or
because the fossil units were not controlled, but because the units
were operated more. In this type of scenario, emissions would also be
higher in a rate-based program that did not allow interstate trading.
    EPA is setting two criteria to determine if a state has exceeded
its budget using the state budget with the 1-year variability limit on
an annual basis, and the state budget with the 3-year variability limit
on a 3-year rolling average basis. EPA proposes that emissions from an
owner's EGUs in excess of the owner's share of the state budget with
the variability limit would not be a violation of the regulation or the
CAA. But the owner would be required to make an allowance surrender of
one allowance for each ton emitted over the owner's proportional share
of the amount by which state emissions exceed the state budget with the
variability limit.
    This allowance surrender requirement is significant, and EPA
believes sufficient, to ensure that the state emissions will not exceed
the budgets plus the variability limit. The allowance surrender
requirement, however, is less severe than the penalties (discussed
later) that apply if a source fails to comply with the requirement to
hold an allowance for each ton emitted by EGUs at the source. However,
failing to hold sufficient allowances to meet the allowance surrender
requirement would be a violation of the regulations and the CAA.
    EPA requests comment on whether the allowance surrender requirement
should be different (either more or less) than one allowance per ton
emitted over the owner's proportional share of the state budget with
the variability limit. In addition, EPA requests comment on whether the
exceedance of total emissions by an owner's sources over the owner's
share of the state budget with the variability limit should be a
violation of the CAA and thus subject to discretionary penalties.
Finally, EPA requests comment on all aspects of the proposed assurance
provisions in the proposed FIPs.
(6) Penalties
    All covered sources must hold an allowance for each ton of
SO2 or NOX emitted and are subject to penalties
if they fail to comply with this allowance-holding requirement.
    Each source must hold in its compliance account in the AMS enough
allowances issued for the respective annual trading program
(SO2 group 1, SO2 group 2, or NOX
annual programs) to cover the annual emissions of the relevant
pollutant from all the EGUs at the source. The source owner must
provide, for deduction by the Administrator, one allowance as an offset
and one allowance as an excess emissions penalty for each ton of excess
emissions. These are automatic penalties-they are required, 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., a calendar year), is a violation of the CAA, for which
the maximum discretionary penalty is $25,000 (inflation-adjusted to
$37,500 for 2009) per violation under CAA Section 113.
    For the ozone season control program, the same provisions apply as
for an annual program, except that the control period (and averaging
period) is the ozone season, not a calendar year. Consequently, the
relevant allowances and emissions are for an ozone season.
    EPA requests comment on the amount of allowances required for the
automatic penalties.
c. 2012 and 2013 Transition Period
    For the 2012-2013 transition period, EPA is proposing the State
Budgets/Limited Trading remedy without the previously-described
assurance provisions (penalty provisions would remain in effect), but
taking comment on whether the assurance provisions should be in force
during that period.
    New state-specific control budgets (developed as described in
section IV) and new allowances would be allocated to sources in the
Transport Rule region. These state budgets would reflect the operation
of all existing and planned emission control devices. Under EPA's
proposed approach, for 2012 and 2013, intrastate and interstate
trading, without the assurance provisions, would be allowed.
    The locations of existing and planned air pollution control
retrofits on EGUs are known, and this knowledge provides greater
certainty of where reductions will occur and how these reductions
should impact air quality in downwind areas. There would not be
sufficient time to complete construction of additional control
retrofits or entirely new, controlled EGUs before 2014.\87\
---------------------------------------------------------------------------

    \87\ U.S. Environmental Protection Agency (U.S. EPA). 2002.
Engineering and Economic Factors Affecting the Installation of
Control Technologies for Multipollutant Strategies. Washington, DC.
---------------------------------------------------------------------------

    Consequently, EPA believes that there is a high level of certainty
that emissions reductions projected for

2012-2013 with interstate trading would be achieved within the states
where they are projected to occur, making imposition of the assurance
provisions during 2012-2013 unnecessary. In addition, EPA believes that
the two alternative options discussed later present greater
implementation challenges than this proposed interim remedy for 2012-
2013. See sections V.D.5 and V.D.6. Except for the absence of the
assurance provisions, the remedy for 2012-2013 would be the same as the
State Budgets/Limited Trading option, including compliance and penalty
provisions described previously.
    The 2012-2013 transition period would provide time for sources to
migrate to the new rule requirements in 2014, such as preparing for the
imposition of the assurance provisions and, for some states, tighter
SO2 budgets. EPA is requesting comment on the proposed
approach of locking in emissions reductions for 2012 and 2013 by
allocating new state-specific budgets based on significant contribution
and interference with maintenance and ensuring that pollution control
devices operate, while allowing for interstate trading in 2012 and 2013
without the assurance provisions. Assurance provisions would provide
sources less flexibility and therefore likely increase compliance
costs, but would be required starting in 2014. EPA requests comment on
the pros and cons of including assurance provisions or other
limitations on trading during the 2012-2013 period. Section IV.F
presents variability limits for the alternative where assurance
provisions would apply during 2012 and 2013 (see Tables IV.F-1 through
IV.F-4).
d. Electric Reliability
    The State Budgets/Limited Trading remedy is not a risk to electric
reliability. The option for sources to trade across state borders and
to emit up to the specified state budget with variability limit gives
ISOs (Independent System Operators) the flexibility to manage regional
electricity generation so that reliability is maintained. For example,
the operations of the electricity generation sector under the State
Budgets/Limited Trading remedy, as compared to the option allowing only
intrastate trading, would be less constrained by state borders and have
greater flexibility to handle unexpected events such as extreme weather
or the loss of generating capacity for extended periods of time.
e. How Emissions Cap and Trade Programs Have Worked Under Title IV, the
NOX SIP Call, and CAIR
    Even absent assurance provisions, cap and trade programs have
resulted in broad-based emissions reductions distributed across the
entire covered area, with the reductions coming where emissions were
highest and most cost effective. The national SO2 emissions
cap and trade program that EPA implemented under Title IV of the CAA
Amendments (the Acid Rain Program) and the regional SO2 and
NOX programs established under CAA section 110(a)(2)(D)(i),
in the form of the NOX Budget Trading Program and the three
CAIR trading programs, all have several key components in common:
     Phases and reductions.
    [cir] An emissions cap is established and the programs are phased
in, with increasing stringency to lower emissions.
     Allowance allocation.
    [cir] Authorizations to emit, i.e., allowances, are allocated to
affected sources and are limited by each state's trading budget.
     Allowance trading.
    [cir] Markets enable sources to trade allowances.
     Flexible compliance.
    [cir] Sources have the flexibility to choose the most efficient way
to comply including adding emission control technologies, updating
control technologies, optimizing existing controls, switching fuels,
and buying allowances.
     Annual reconciliation.
    [cir] At the end of every compliance period, each source must
surrender sufficient allowances to cover its emissions. Excess
allowances may be sold or banked for future use.
     Penalties and enforcement.
    [cir] There are automatic penalties and potentially discretionary
civil penalties for program noncompliance.
     Stringent monitoring and reporting.
    [cir] Sources must use approved monitoring methods under EPA's
stringent monitoring requirements (40 CFR part 75) to monitor and
report emissions.
     Data transparency.
    [cir] The data on key program elements, such as emissions,
allocations, and allowance trades, are publicly available on EPA's web
site and in annual progress reports.
    About 50 government staff operate these cap and trade programs.
They have been successful in achieving the emissions reductions goals
at reasonable costs with virtually 100 percent program compliance. In
the following paragraphs, specific results from the programs are
described. These results are documented in program progress reports
that are available on EPA's Web site (http://www.epagov/airmarkets/
progress/progress-reports.html) and in the docket to this rule, as
referenced at the end of each program section later.

Title IV Acid Rain Program--Emissions Reductions

    Since program implementation in 1995, the ARP has reduced
SO2 and NOX emissions from the power sector
across the nation. In 2008, the ARP SO2 program covered
3,572 electric generating units (including 1,055 coal-fired units,
which account for almost 99 percent of total ARP unit SO2
emissions). Verified data submitted to EPA from 2008 show that:
     SO2 emissions from power sector sources were
7.6 million tons, which is 52 percent less than 1990 levels and already
below the statutory annual emission cap of 8.95 million tons set for
compliance in 2010.
     NOX emissions from power sector sources were
3.0 million tons, which is 51 percent less than 1995 levels and more
than double the Title IV NOX program emission reduction
objective, but also reflects reductions achieved under the
NOX Budget and CAIR NOX trading programs.
    The largest reductions have occurred in the states with the highest
power plant emissions. These high emitting areas were upwind of major
populations centers and areas of environmental and ecological concern.
Emissions reductions have led to improvements in air quality with
significant benefits to sensitive ecosystems and human health.
     Between the 1989 to 1991 and 2006 to 2008 observation
periods, decreases in wet sulfate deposition averaged more than 30
percent for the eastern U.S.
     Acid Neutralizing Capacity (ANC), the ability of water
bodies to neutralize acid deposition, increased significantly from 1990
to 2008 in lake and stream long-term monitoring sites in New England,
the Adirondacks, and the Northern Appalachian Plateau.
     Recently updated assessments of U.S. PM2.5 and
ozone health-related benefits estimate that PM2.5 benefits
due to ARP implementation in 2010 are valued at $170-$410 billion
annually and ground-level ozone benefits from ARP implementation in
2010 are valued at $4.1-$17 billion (estimates are in 2008 dollars).
The benefits are primarily from reduced premature mortality.
    See EPA's docket for this rule and http://www.epagov/airmarkets/
progress/ARP_4.html.

    NOX SIP Call NOX Budget Trading Program--Emissions Reductions. From
2003-2008, the NBP reduced ozone season NOX emissions
throughout the NOX SIP Call region each year. Results of the
program include:
     In 2008, NBP ozone season NOX emissions totaled
481,420 tons, which is 62 percent below 2000 levels and 9 percent below
the 2008 NOX emissions cap. Emissions were also below the
caps in 2006 and 2007.
     The average NOX emissions rate for the 10
highest electric demand days (as measured by megawatt hours of
generation) consistently fell every year of the NBP.
     The largest NOX emissions reductions and 8-hour
ozone concentrations reductions took place along the Ohio River Valley,
as was projected by EPA air quality models of the NOX SIP
Call.
     Noticeable improvements in ambient concentrations of ozone
have been measured across the region.
     Of the 104 areas in the eastern United States designated
to be in nonattainment for the 1997 8-hour ozone NAAQS in 2004, 88
areas (85 percent) had ozone air quality better than the level of the
1997 standard in 2008. 8-hour ozone concentrations were 10 percent
lower in 2008 than in 2001. This decline is largely due to reductions
in NOX emissions required by the NOX SIP Call
rule.\88\
---------------------------------------------------------------------------

    \88\ U.S. EPA, Our Nation's Air Status and Trends through 2008,
Office of Air Quality Planning and Standards, EPA-454/R-09-002,
Research Triangle Park, NC, pp. 1, 17.
---------------------------------------------------------------------------

    Over the past several years a series of studies \89\ \90\ \91\ have
evaluated the NOX SIP Call and the link between decreasing
NOX emissions and decreasing ozone concentrations. These
studies demonstrate that the NOX SIP Call has been effective
in improving ozone air quality in the eastern U.S.
---------------------------------------------------------------------------

    \89\ G[eacute]go, E., P.S. Porter, A. Gilliland, and S.T. Rao,
2007: Observation-Based Assessment of the Impact of Nitrogen Oxides
Emissions Reductions on Ozone Air Quality over the Eastern United
States. J. Appl. Meteor. Climatol., 46, 994-1008.
    \90\ Godowitch, J.M., Hogfrefe, C., & Rao, S.T. 2008. Diagnostic
analyses of a regional air quality model: Changes in modeled
processes affecting ozone and chemical-transport indicators from
NOX point source emission reductions. Journal of
Geophysical Research, 113, D19303, doi:10.1029/2007JD009537.
    \91\ Godowitch, J.M., Gilliland, A.B., Draxler, R.R., and Rao,
S.T. 2008. Modeling assessment of point source NOX
emission reductions on ozone air quality in the eastern United
States. Atmospheric Environment, 42 (1), 87-100.
---------------------------------------------------------------------------

    EPA stopped administering the NBP at the conclusion of 2008 control
period. States still have the emissions reductions requirements under
the NOX SIP Call and can use the CAIR NOX ozone
season trading program to meet these.
    See EPA's docket for this rule for more details on the results of
the NOX Budget Trading Program, or see http://www.epagov/
airmarkets/progress/NBP_4.html.
    CAIR--Emissions Reductions. Anticipation of the CAIR regional
program in 2008 resulted in an additional 2.8 million tons of
SO2 reductions from 2005 levels in the eastern United
States, bringing emissions well under the 2010 Title IV cap. The
NOX annual and ozone season programs began on January 1 and
May 1, 2009, respectively. The SO2 program began on January
1, 2010. The CAIR cap and trade programs remain in effect, consistent
with the Court's remand, in order to benefit public health and the
environment, until EPA replaces the rule.
    Allowance trading. Because of the ease with which allowances can be
banked, bought and sold, and transferred in the trading programs,
robust allowance trading markets have developed over the past fifteen
years, along with considerable banking of allowances.
    Allowance prices and trading activity under the trading programs
were reduced in 2008 in response to the Court's July 2008 decision in
North Carolina v. EPA granting petitions for review of CAIR. However,
the allowance markets remained active. For a recent assessment on
allowance markets, see http://www.epagov/airmarkets/resource/docs/
marketassessmnt.pdf.
    Transaction Costs. The cap and trade program results described
previously are real, measurable, and very significant. These results
demonstrate that cap and trade is a policy tool that can achieve cost-
effective, broad reductions quickly to improve human health and the
environment and help states meet their obligations to attain the NAAQS.
While some have suggested that transaction costs associated with cap
and trade programs were high or problematic, EPA has found no
indication that this is the case. Transaction costs are important
because they can diminish the incentive to trade or the amount traded.
    In fact, few empirical studies on transaction costs have been done.
EPA has searched the literature and compiled a list of anecdotal
discussions on transaction costs, including a study of the ARP's
SO2 cap and trade program by Ellerman \92\ of MIT, published
in 2004. Ellerman suggests that, while no comprehensive study has been
conducted on the subject, ``* * * the creation of a standard unit of
account in allowances and the lack of any review requirement for
trading has avoided the very large transactions costs that limited * *
* earlier experiments with emissions trading.'' Other studies (see
Schennach, 2000 \93\) suggest transaction costs are about one percent
of the allowance price. An industry expert, Gary Hart,\94\ suggested
that a typical fee charged by a brokerage firm is $0.50 for each
SO2 allowance.
---------------------------------------------------------------------------

    \92\ Ellerman, A. Denny. 2004. ``The U.S. SO2 Cap-
and-Trade Programme,'' Tradeable Permits: Policy Evaluation, Design
and Reform, chapter 3, pp. 71-97, OECD.
    \93\ Schennach, S.M. 2000. The Economics of Pollution Permit
Banking in the Context of Title IV of the 1990 Clean Air Act
Amendments. Journal of Environmental Economics and Management 40(3):
189-210.
    \94\ Personal communication with Gary Hart, ICAP-United, June
25, 2007 as quoted in Napolitano, S., J. Schreifels, G. Stevens, M.
Witt, M. LaCount, R. Forte, & K. Smith. 2007. ``The U.S. Acid Rain
Program: Key Insights from the Design, Operation, and Assessment of
a Cap-and-Trade Program.'' Electricity Journal. Aug/Sept. 2007, Vol.
20, Issue 7. doi:10.1016/j.tej.2007.07.001.
---------------------------------------------------------------------------

    Tietenberg, in his book, Emissions Trading Principles and
Practice,\95\ explains the role of transaction costs and their impact
on trading. Note that Tietenberg and many economists use the word,
``permits,'' in the same way EPA uses the word, ``allowances.''
---------------------------------------------------------------------------

    \95\ Tietenberg, T.H. 2006. Emissions Trading Principles and
Practice. Washington, DC. Published by Resources for the Future.
---------------------------------------------------------------------------

    Tietenberg defines transactions costs as ``the costs, other than
price, incurred in the process of exchanging goods and services. These
include the costs of researching the market, finding buyers or sellers,
negotiating and enforcing contracts for permit transfers, completing
all the regulatory paperwork, and making and collecting payments.''
\96\ He also describes how to lower transaction costs, as follows:
``Transaction costs can be lowered by making permit transactions
transparent, by the availability of exchanges and knowledgeable
brokers, and by the sharing of information on the availability of cost-
effective abatement technologies, while administrative costs can be
lowered by continuous emissions monitoring and by software that
streamlines monitoring and reporting.'' \97\ He goes on to say, ``Price
transparency (making prices public) can reduce the uncertainty
associated with trading and facilitate negotiations about price and
quantity. One good example is [the] public auctions held each spring
for the Sulfur Allowance Program [ARP].'' \98\
---------------------------------------------------------------------------

    \96\ Ibid., p. 41.
    \97\ Ibid., p. 73.
    \98\ Ibid., pp. 70-71.
---------------------------------------------------------------------------

    Tietenberg contrasts EPA's earlier credit-based trading programs in
the

1970s and 1980s (U.S. Emissions Trading Program (ETP)) with cap and
trade programs, such as the Acid Rain Program for SO2. He
says that while credit-based programs ``typically involved a
considerable amount of regulatory oversight at each step of the process
(e.g., certification of credits and approval of each trade),'' cap and
trade programs use instead a system ``that compares actual and
authorized emissions at the end of the year, which can lower
transactions costs'' compared to a credit program.
    All the features Tietenberg highlights comprise fundamental aspects
of EPA's cap and trade program design. Program design remains one of
the principle ways to ensure lower transaction costs. Over the last 15
years, EPA's state-of-the-art information management system has evolved
in parallel with the advancement of technology in order to offer
platforms for reporting and receiving data and for public access. EPA
provides dedicated assistance for sources, states, and regions around
the country on program operations and monitoring and reporting,
specifically. With limited oversight of transactions, EPA focuses on
recording data and information accurately, including allowance
transfers, as well as ``true-up'', where actual emissions are
reconciled with allowances held in accounts for compliance.
    These features of EPA's program management lead to low transaction
costs. EPA is attuned to trying to keep requirements as simple and
straightforward as possible, and offers substantial and routine
training to ensure successful program implementation and regulatory
compliance. While some have equated the length of EPA's trading program
rules with higher transaction costs, in fact, the detailed regulatory
sections, such as for allocations and the stringent monitoring
requirements, form the basis of what actually allows the programs to
function with limited oversight, virtually 100 percent compliance,
public transparency, and nominal transaction costs.
    For the ARP, NOX Budget Trading Program, and CAIR
trading programs, EPA records all allowance allocations in accounts in
an electronic allowance tracking system (currently called the AMS). In
addition, EPA records in the AMS all allowance transfers that are
submitted by parties for official recordation. These allowance accounts
are searchable and visible to the public. The trading program
regulations that directly govern allowance trading, i.e., the
regulations governing the establishment of allowance accounts and the
submission of allowance transfers, are relatively simple and establish
requirements that are easy to meet. See, e.g., 40 CFR 96.151(a)
(requiring establishment of source compliance accounts). Allowances may
be held in an allowance account (i.e., banked) for use or trading in
any future year in which the trading program involved is in effect.
See, e.g., 40 CFR 96.155 (allowing banking). Further, allowances may be
transferred from one account to another with no restrictions except the
requirements that the authorized account representative of the
transferor account submit to EPA a simple (generally electronic)
allowance transfer form identifying the allowances to be transferred
and the account to receive them, and that the allowances must be
currently recorded in the transferor account. See, e.g., 40 CFR 96.160
(requiring submission of specified allowance transfer form) and
96.161(a)(2) (requiring that allowance be in transferor account). This
transparency of data and availability of information allows the
allowance market to function smoothly.
    EPA research found no indications that transaction costs have been
a problem. From discussions with a leading industry consultant we
learned that there is enough competition among the approximately
fifteen brokerage houses that any attempt at charging fees in excess of
market standards will be bid down through competition.\99\ In many
instances, clients can negotiate fees even lower than market averages.
Financial exchanges, such as the Chicago Climate Exchange and New York
Mercantile Exchange, added SO2 and NOX allowances
to their list of commodities. Prior to the vacatur of CAIR, transaction
costs (broker fee as a percent of allowance price) were estimated at
less than 0.2 percent for SO2, less than 1.8 percent for
seasonal NOX, and less than 0.5 percent for annual
NOX.\100\ These transaction costs are low and not expected
to affect program outcome.
---------------------------------------------------------------------------

    \99\ Memo from ICF International to EPA Clean air Markets
Division, September 17, 2008. Transaction Costs in Allowance Trading
Markets.
    \100\ Ibid.
---------------------------------------------------------------------------

    In summary, EPA believes its cap and trade programs functioned
efficiently and did not result in high transaction costs for several
reasons. First, in developing the regulations for the trading programs,
EPA strove to make the programs as transparent as possible in order to
ensure that relevant data were available to the market, to minimize
regulatory oversight of trading activity, and to let the market work
unhampered. Strong markets exist that have seen upwards of 273 million
SO2 allowances transferred to date. Educational and
professional associations that hold regular conferences for members,
regulated entities, government agents, and the public have existed to
increase transparency of information and exchange ideas on cap and
trade programs for more than a decade.
    Further, EPA is not aware of any source participating in the
trading programs over the past 15 years that expressed concern about
the costs of making allowance transfers. For example, EPA has received
no comment in the rulemaking proceedings for the trading programs
raising concern about the level of transactions costs for allowance
transfers under these programs, and no party challenged the allowance
transfer provisions on appeal of any of the trading program rules.
    In addition, all available information indicates that actual
transactions costs are very low. For a list of some articles written by
scholars and economists over the past 15 years on transaction costs,
see the docket for this rule.
f. How the Remedy in the Proposed FIPs Is Consistent With the Court's
Opinions
    The proposed remedy discussed in this section effectuates the
statutory goal of prohibiting sources within the state from
contributing to nonattainment or interfering with maintenance in any
other state. See North Carolina, 531 F.3d at 908. The proposed FIPs
eliminate all or the emissions that EPA has identified as significantly
contributing to downwind nonattainment or interference with maintenance
in today's proposed action by requiring sources to participate in
emissions trading programs that allow intrastate trading and limited
interstate trading, and that also 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 emissions allowances sufficient to cover their emissions,
effectuate the requirement that emissions reductions occur ``within the
State.''
    A state's ``significant contribution'' is the portion of emissions
that must be eliminated.\101\ State budgets represent EPA's estimate of
the remaining emissions after elimination of significant contribution,
but in actuality

the amount of remaining emissions may vary. As explained in greater
detail previously, both the budgets and the assurance provisions
recognize the inherent variability in state EGU emissions. 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
states' baseline emissions are variable, their remaining emissions
after all significant contribution is eliminated are 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, could in fact exceed the state budget without
variability. For this reason, the assurance provisions limit a state's
emissions to the state's budget with variability limit.
---------------------------------------------------------------------------

    \101\ Note that in cases where EPA has not fully identified the
quantity of emissions that represent significant contribution or
interference with maintenance, state budgets define the emissions
that remain after the part that has been identified is eliminated.
---------------------------------------------------------------------------

    In addition, the requirement that all sources hold emissions
allowances (and the fact that the total number of emissions 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) 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 emissions levels, are more likely to vary significantly within the
region so that resulting emissions 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 proposed use of state budgets
with the variability limit may allow limited shifting of emissions
between states is not inconsistent with the Court's holding that
emissions reductions must occur ``within the state.'' North Carolina,
531 F.3d at 907. Under the proposed 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. It is
thus consistent with the statutory mandate of section
110(a)(2)(D)(i)(I) as interpreted by the Court.
g. Why EPA Is Proposing the State Budgets/Limited Trading Option
    The FIPs that EPA is proposing use the State Budgets/Limited
Trading remedy to eliminate all of the significant contribution and
interference with maintenance that EPA has identified. This remedy--
which would use state budgets (see section IV) and allow full trading
within each state and limited trading outside of each state--would be a
cost-effective method for eliminating all or part of each state's
emissions that constitute a significant contribution and interfere with
maintenance, would be consistent with the Court's decision in North
Carolina v. EPA, and would address the issues raised by the Court.
    In the first phase (2012 and 2013), the proposed remedy would
provide a new interstate trading program that would ensure existing and
planned pollution controls operate. Units would be required to run
their existing, or already planned, pollution control devices when the
units are operating. The State Budgets/Limited Trading remedy would use
the new state budgets described in section IV and allocate allowances
to individual sources using a methodology directly related to the
methodology used to identify emissions that significantly contribute to
nonattainment or interfere with maintenance in downwind areas. EPA
believes that because the location of existing and already planned
pollution controls for 2012 and 2013 is known, the use of these
budgets, even without the added assurance provisions, would assure that
the necessary emissions reductions would occur in each state under the
trading programs during those years. The impact of the resulting
emissions reductions on atmospheric concentrations of particulate
matter and other pollution, and subsequent benefits for the environment
and human health, would be significant and are described in sections
III.B and IX. The proposed remedy would offer the most expeditious
approach practicable for compliance in 2012-2013, given the short time
available for sources, states, and EPA to implement a transition from
CAIR. While there is some uncertainty about how quickly units
potentially capable of switching fuels would actually be able to
implement such fuel switching, the banking provisions of the State
Budgets/Limited Trading approach would provide incentives to reduce
emissions as quickly and early as possible. The trading provisions
would provide flexibility for sources to purchase allowances in the
meantime, without the risks of unexpected high costs, non-compliance,
or the inability to operate if unable to switch fuels. The remedy would
be relatively easy for sources and states to understand and follow as
they transition from prior trading programs to a new regime, beginning
in 2014, that would include limits on interstate trading.
    The second phase would begin in 2014 with tighter state-specific
SO2 caps for states in the more stringent group 1 tier to
address significant contribution and interference with maintenance. In
addition, assurance provisions limiting interstate trading would become
effective in each state. This approach in the proposed remedy, which is
modeled in several ways after the approaches of the ARP and NBP
programs, is likely to lead to virtually 100 percent compliance. The
approach ensures that, as we see economic growth, future air quality is
not compromised and states can depend on emissions reductions in
meeting local air quality goals.
    The limited interstate trading permitted in this proposed remedy
would address some of the problematic issues identified in the
alternative options discussed later, such as, under the intrastate
trading option, concerns about the administrative burden and needed
resources associated with administering 82 new trading programs (with
82 new sets of allowances),

conducting 82 annual auctions, concentrated allowance market power
within individual states, and regional electricity reliability. In
particular, the interstate trading component with assurance provisions
would mean that allowances issued for one state for a trading program
could be used in any of the states included in the respective trading
program. This feature of the proposed remedy would create a regionwide
allowance market, rather than single-state allowance markets where
individual owners of sources would be much more likely to have market
power (see discussion later in section V.D.5). Further, the interstate
trading component with assurance provisions would provide source owners
with much more flexibility to ensure electric reliability in the event
of future variability in electricity demand (e.g., due to weather or
economic changes) or in the availability of specific individual
electricity generation facilities.
    In addition, the proposed State Budgets/Limited Trading remedy
provides reductions at a lower cost than the direct control option
described later and is flexible enough to accommodate unit-specific
circumstances. In contrast, the direct control option described later
would involve a complex process of determining unit-by-unit emissions
limits that might need to take account of unit-specific circumstances.
Moreover, this option would be roughly $600 million (2006$) more
expensive than the proposed remedy in 2012. See section V.E for more
details on projected costs and emissions.
    In summary, EPA believes that interstate trading, although limited
by the assurance provisions, would allow source owners to choose among
several compliance options to achieve required emissions reductions in
the most cost-effective manner, such as installing controls, changing
fuels, reducing utilization, buying allowances, or any combination of
these actions. Interstate trading with assurance provisions would also
allow the electricity sector to continue to operate as an integrated,
interstate system able to provide electric reliability. Compared to the
alternative options, EPA believes the State Budgets/Limited Trading
remedy would provide the greatest flexibility to companies complying
with the rules and is the approach most likely to achieve the goals and
principles outlined in section III.C.
    The proposed remedy provides intrastate and interstate trading
components that simplify implementation for EPA (and, where applicable,
states) and sources and results in cost-effective achievement of
required emissions reductions. Resource needs for EPA and sources to
implement the proposed remedy are expected to be comparable to the
resources necessary to implement CAIR.
    EPA believes the State Budgets/Limited Trading proposed remedy
provides more assurance that the emissions levels necessary to address
NAAQS nonattainment are not exceeded than most previous regulatory
programs such as rate-based direct control programs and even
nonattainment plans, none of which places an absolute cap on emissions.
EPA has pointed out, in contrast, that the results from cap and trade
programs such as the Acid Rain and NOX Budget Trading
programs demonstrate how substantial emissions reductions have been
delivered throughout the respective covered region with high levels of
compliance, at low costs, and with significant health and ecological
benefits. The proposed State Budgets/Limited Trading remedy provides
added assurance that emissions reductions now will occur on a state-by-
state basis, not just overall at a regional level. These assurance
provisions would prohibit states from exceeding their state-level
budgets with variability limits and impose stringent and costly
allowance surrender requirements that are known upfront to deter
exceedances. EPA is confident that the proposed program is both
reasonable to implement and stronger than the alternative options.
    Additionally, this remedy approach and the method EPA proposes for
determining significant contribution together provide a workable
regulatory structure for not only dealing with the transport problem
for the existing NAAQS, but also would be usable in the years ahead
when EPA considers further revisions of the NAAQS, notably for ozone
and fine particles. EPA requests comment on the State Budgets/Limited
Trading proposed remedy. EPA is also requesting comment on the two
options described later in sections V.D.5 and V.D.6.
h. Other Limited Interstate Trading Options Evaluated
    EPA considered a range of ways to create an interstate-trading-
with-limitations option consistent with the direction provided by the
Court. One option considered was to put in place simultaneously
intrastate trading with direct control requirements and interstate
trading with direct control requirements. The challenges associated
with developing direct control requirements are discussed in section
V.D.6 later.
    EPA also considered interstate trading with backstop provisions,
which were rejected as not workable. EPA considered a backstop
provision that prohibited the units in a state from future
participation in the interstate trading program if the state's
emissions in a control period in any year exceeded the state's budget
with variability. In that event, the units would be limited to
intrastate trading only in the control period of the next year. This is
not EPA's proposed option because data on annual emissions are not
final until several months into the next year, making it hard for the
units in a state to know early enough whether they would be in the
interstate trading program or an intrastate trading program for that
next year. This would make compliance planning and implementation of
compliance plans extremely difficult and adversely affect allowance
markets.
    In summary, EPA rejected these alternatives as more complicated and
perhaps problematic to implement. Instead, EPA is proposing the State
Budgets/Limited Trading remedy, which is similar in many ways to the
approaches implemented in the past that have succeeded in reducing
emissions. However, in order to address the Court's concerns about
trading, the proposed remedy includes assurance provisions to ensure
that the remedy removes each upwind state's significant contribution
and interference with maintenance. The ``Other Remedy Options
Evaluated'' TSD in the docket contains greater detail on the
deliberations undertaken to evaluate other options for this rulemaking.
i. Structure and Key Elements of Proposed Transport Rule Trading
Program Rules for State Budgets/Limited Trading
    This preamble section describes the structure and key elements of
the proposed Transport Rule trading program rules for the State
Budgets/Limited Trading remedy in the proposed FIPs. Proposed
regulatory text that would be added to the Code of Federal Regulations
if this option is finalized appears at the end of this notice. EPA
requests comment on the structure and key elements of the program as
well as on the proposed regulatory text.
    In order to make the proposed FIP trading program rules as simple
and consistent as possible, EPA designed them so that the proposed
rules for each of the trading programs (i.e., the Transport Rule
NOX Annual trading program, Transport Rule NOX
Ozone Season trading program, Transport Rule

SO2 Group 1 trading program, and Transport Rule
SO2 Group 2 trading program) would be parallel in structure
and contain the same basic elements. For example, the proposed rules
for the Transport Rule NOX Annual, NOX Ozone
Season, SO2 Group 1, and SO2 Group 2 trading
programs would be located, respectively, in subparts AAAAA, BBBBB,
CCCCC, and DDDDD of Part 97. Moreover, the order of the specific
provisions for each trading program would be same, and the provisions
would have parallel numbering. The key elements of the proposed
Transport Rule trading program rules are discussed later.
(1) General Provisions
(i) Sec. Sec.  97.402 and 97.403, 97.502 and 97.503, 97.602 and 97.603,
and 97.702 and 97.703--Definitions and Abbreviations
    The definitions and measurements, abbreviations, and acronyms would
be the same in all four proposed Transport Rule trading programs,
except where necessary to reflect the different pollutants
(NOX and SO2), control periods (for
NOX, annual and ozone season), and geographic coverage (for
SO2, Group 1 and Group 2) involved. Moreover, many of the
definitions would be essentially the same as those used in prior EPA-
administered trading programs, in some cases with modifications to
reflect the specific, proposed Transport Rule trading program involved.
For example, the definitions of ``unit'' and ``source'' would be the
same as in prior trading programs. As a further example, the
definitions of ``allowance transfer deadline,'' ``owner,'' and
``operator'' would be the same as in prior trading programs, except for
references to Transport Rule NOX Annual allowances,
Transport Rule NOX Ozone Season allowances, Transport Rule
SO2 Group 1 allowances, or Transport Rule SO2
Group 2 allowances or Transport Rule NOX Annual units and
sources, Transport Rule NOX Ozone Season units and sources,
Transport Rule SO2 Group 1 units and sources, or Transport
Rule SO2 Group 2 units and sources, as appropriate. As a
further example, the term ``Allowance Management System'' would be used
instead of the term ``Allowance Tracking System'' but would have
essentially the same definition, while referencing the type of
allowances appropriate for the proposed Transport Rule trading program
involved. As a further example, ``continuous emission monitoring
system'' is essentially the same as in prior trading programs, except
for references to the proposed Transport Rule trading program rules.
    Some definitions would be similar to those used in prior EPA-
administered trading programs but with some substantive differences.
For example, the definitions of ``cogeneration unit'' and ``fossil-
fuel-fired,'' used in the applicability provisions and discussed in
this section of the preamble, would be similar to those in prior
trading programs but with changes to minimize the need for data
concerning individual units or combustion devices for periods before
1990.
    A few new definitions would be included to reflect unique
provisions of the proposed Transport Rule trading programs. For
example, the terms, ``owner's assurance level'' and ``owner's share'',
would be used in the Transport Rule assurance provisions and defined in
the proposed Transport Rule trading program rules. The assurance
provisions are discussed previously in section V.D.4.b.
(ii) Sec. Sec.  97.404 and 97.405, 97.504 and 97.505, 97.604 and
97.605, and 97.704 and 97.705--Applicability and Retired Units
    The applicability provisions would be the same for each of the
proposed Transport Rule trading programs, except that the provisions
would reflect (through the definition of ``state'') differences in the
specific states whose EGUs are covered by the respective Transport Rule
trading programs (as discussed in section IV.D of this preamble). In
general, the proposed Transport Rule trading programs would cover
fossil fuel-fired boilers and combustion turbines serving an electrical
generator with a nameplate capacity exceeding 25 MWe and producing
power for sale, with the exception of certain cogeneration units and
solid waste incineration units. The applicability provisions are
discussed previously in section V.D.4.b.
    The provisions exempting permanently retired units from most of the
requirements of the Transport Rule trading programs would be the same
for each of the trading programs. The purpose of the retired units''
exemption would be to avoid requiring units that are permanently
retired to continue to operate and maintain emission monitoring
systems, to report quarterly emissions, and to hold allowances, as of
the allowance transfer deadline, sufficient to cover their emissions
determined in accordance with the monitoring and reporting
requirements. Consequently, the retired unit provisions would exempt
these units from the rule sections imposing the relevant monitoring,
recordkeeping, and reporting requirements and allowance-holding
requirements. However, an owner would include each of these permanently
retired units that it owns in determining whether and, if so, how many
allowances the owner would be required to surrender in compliance with
the assurance provisions. As discussed earlier in this section, while
these units would have zero emissions once they are permanently
retired, the units could continue to receive allowance allocations for
several years thereafter. Consequently, an owner would include these
units in determining whether the owner's share of total emissions of
covered units in a state exceeded its share (generally based on the
allowances allocated to its units) of the state budget with the
variability limit and thus whether the owner would have to surrender
allowances under the assurance provisions.
    The exemption for a retired unit would begin on the day the unit is
permanently retired. The unit's designated representative (i.e., the
person authorized by the owners and operators to make submissions and
handle other matters) would be required to submit notification to the
Administrator within 30 days of the unit's permanent retirement.
    The retired unit exemption provisions would not directly address
any permit-related matters concerning these units. This would be
consistent with the general approach under the Transport Rule trading
program rules of leaving permitting matters largely to be addressed by
the existing, applicable state and federal title V permit programs.
Permitting is discussed in section VIII of this preamble.
(iii) Sec. Sec.  97.406, 97.506, 97.606, and 97.706--Standard
Requirements
    The basic requirements applicable to owners and operators of units
and sources covered by the proposed Transport Rule trading programs and
presented as standard requirements would include: Designated
representative requirements; emissions monitoring, reporting, and
recordkeeping requirements; emissions requirements comprising emissions
limitations and assurance provisions; permit requirements; additional
recordkeeping and reporting requirements; liability provisions; and
provisions describing the effect of the Transport Rule trading program
requirements on other Act provisions. The paragraphs, in the standard
requirements section, that would address designated representative
requirements and emissions monitoring, reporting, and recordkeeping

requirements would reference the details of these requirements in other
sections of the proposed Transport Rule trading program rules.
    The paragraphs addressing emissions requirements would describe
these requirements in detail and reference other sections that would
set forth the procedures for determining compliance with the emissions
limitations and assurance provisions. These paragraphs would also
explain that: Transport Rule NOX Annual allowances,
Transport Rule NOX Ozone Season allowances, Transport Rule
SO2 Group 1 allowances, or Transport Rule SO2
Group 2 allowances would each authorize emission of one ton of
emissions under the applicable Transport Rule trading program; such
authorizations could be terminated or limited by the Administrator to
the extent necessary or appropriate to implement any provision of the
CAA; and such allowances would not constitute a property right. The
proposed Transport Rule SO2 trading programs use new
SO2 allowances and not CAA Title IV allowances, thus the
provisions allowing the Administrator to terminate or limit the
Transport Rule trading program allowances under this rule would not be
contrary to the Court's North Carolina decision, which addressed the
Administrator's authority to terminate or limit Title IV SO2
allowances through the CAIR.
    The remaining paragraphs in the standard requirements section
concern permitting, recordkeeping and reporting, liability provisions,
and the effect on other CAA provisions. As discussed in section VIII of
this preamble, the paragraphs concerning permitting requirements would
be limited to stating that no title V permit revisions would be
necessary to account for allowance allocation, holding, deduction, or
transfer and that the minor permit modification procedures could be
used to add or change general descriptions in the title V permits of
the monitoring and reporting approach used by the units covered by each
title V permit. The paragraphs on recordkeeping and reporting would
generally require owners and operators to keep on site for 5 years
copies (which could be electronic) of certificates of representation,
emissions monitoring information (including quarterly emissions data),
and submissions and records demonstrating compliance with the proposed
Transport Rule trading programs. The paragraphs on liability would
state that each covered source and covered unit would be required to
meet the Transport Rule trading program requirements, any provision
applicable to a source or designated representative would be applicable
to the source and unit owners and operators, and any provision
applicable to a unit or designated representative would be applicable
to the unit owners and operators. The paragraph on the effect on other
CAA provisions would state that the Transport Rule trading programs do
not exempt or exclude owners and operators from any other requirements
under the CAA, an approved SIP, or a federally enforceable permit.
(iv) Sec. Sec.  96.407, 97.507, 97.607, and 97.707--Computation of Time
    These sections would clarify how to determine the deadlines
referenced in the proposed Transport Rule trading program rules. For
example, deadlines falling on a weekend or holiday are extended to the
next business day. These are the same computation-of-time provisions
used in prior EPA-administered trading programs.
(v) Sec. Sec.  97.408, 97.508, 97.608, 97.708 and Part 78--
Administrative Appeal Procedures
    Final decisions of the Administrator under the proposed Transport
Rule trading program rules would be appealable to EPA's Environmental
Appeals Board under the regulations that are set forth in part 78 (40
CFR part 78) and are proposed to be revised to accommodate such
appeals. Specifically, the list in Sec.  78.1 of the types of final
decisions that could be appealed under Part 78 would be expanded to
include specific types of decisions under the proposed Transport Rule
trading program rules.
    Further, under the approach in the existing part 78, an
``interested person'' (in addition to the official representative of
owners and operators or an allowance account involved in a matter) may
petition for an administrative appeal of a final decision of the
Administrator. In order to expand the ``interested person'' definition
(which is currently in part 72 of the ARP regulations) and make the
definition more readily accessible to readers of part 78, the
definition would be removed from Sec.  72.2, added in Sec.  78.2, and
expanded in a way that would cover the proposed trading program rules.
Provisions concerning public availability of information, and
provisions concerning computation of time (revised to be consistent
with the requirements for computation of time used by the Environmental
Appeals Board in other types of administrative proceedings), would also
be moved to Sec.  78.2. In particular, the revised ``interested
person'' definition would include, with regard to a decision appealable
under Part 78, any person who--in connection with the Administrator's
process of making that decision--submitted comments, testified at a
public hearing, submitted objections, or submitted their name to be
included by the Administrator in an interested persons list.
    In addition, Sec.  78.3 would be revised to allow for petitions for
administrative appeal of decisions of the Administrator under the
proposed Transport Rule trading programs. Further, Sec.  78.4 would be
expanded to state that filings on behalf of owners and operators of a
covered source or unit under the proposed Transport Rule trading
programs would have to be signed by the designated representative of
the source or unit. Filings on behalf of persons with an interest in
allowances in an account in the proposed programs would have to be
signed by the authorized account representative of the account.
(2) Allowance Allocations
    Sections 97.410 through 97.412, 97.510 through 97.512, 97.610
through 97.612, and 97.710 through 97.712 would set forth: Certain
information related to allowance allocation and for implementation of
the assurance provisions; the timing for allocation of allowances to
existing and new units; and the procedures for new unit allocations. In
particular, these sections would include tables providing, for each
state covered by the particular proposed Transport Rule trading program
and for each year, the state trading budget (without the variability
limit), new unit set-aside, and one-year and three-year variability
limits. With regard to existing units, these sections would also state
that existing units would be allocated the allowances set forth in
appendix A of the relevant Transport Rule trading program rules. These
allocations would be permanent (taking into account the reductions in
allocations, for the Transport Rule SO2 Group 1 trading
program, from Phase I to Phase II) with one exception. A unit that does
not operate (i.e., has no heat input) for three consecutive years
starting in 2012 would continue to receive its Appendix A allocation
for those years plus only three more years. Starting in the seventh
year, the Administrator would stop recording the allocations for the
unit and would instead add to the new unit set-aside the allowances
that would otherwise have been recorded for the non-operating unit.
Because the proposed unit-by-unit allocations are set forth in the
``State Budgets, Unit Allocations, and Unit Emissions Rates'' TSD cited
previously,

the proposed Transport Rule trading program rules do not repeat these
allocations in Appendix A to each rule. Instead, each Appendix A is
reserved, and EPA proposes to include the unit-by-unit allocations, for
each Transport Rule trading program, in Appendix A to the respective
final Transport Rule trading program rules.
    With regard to new units (as well as units whose allocations are
subject to the requirement that the Administrator not record them or
that the Administrator deduct the amount of the allocation and units
that lost their allocations after not operating and that subsequently
began operating again), the owner and operator of such units could
request, by a specified deadline each year, an allocation from the new
unit set-aside for that year and each year thereafter. The allocation
would equal that unit's emissions--as determined in accordance with
part 75 (40 CFR part 75)--for the control period (annual or ozone
season, depending on the Transport Rule trading program involved) in
the preceding year. The Administrator would determine whether the total
number of properly requested allowance allocations for all units in a
state for a control period would exceed the amount in the new unit set-
aside for the state for the control period. If not, the Administrator
would allocate consistent with all proper requests. If the total number
would exceed the new unit set-aside, the Administrator would allocate
to each properly requesting unit its proportionate share of the new
unit set-aside. The Administrator would provide notice of these
determinations (which would reflect these calculations rather than any
exercise of discretion on the part of the Administrator) through
issuance of a notice of data availability to which parties could submit
objections and a second notice addressing any objections. Any
unallocated allowances in the new unit set-aside would be allocated to
existing units in proportion to their current allocations.
    If a unit that was not really a covered unit or a unit that was not
subject to the allowance-holding requirement were allocated allowances,
the proposed provisions set forth a process under which the allocation
would not be recorded or the amount of the recorded allocation would be
deducted, with one exception. The exception would be if the process of
determining compliance with the emission limitation for the source that
includes the unit were already completed, in which case no action would
be taken to account for the erroneous allocation for the control period
involved.
(3) Designated Representatives and Alternate Designated Representatives
    Sections 97.413 through 97.418, 97.513 through 97.518, 97.613
through 97.618, and 97.713 through 97.718 would establish the
procedures for certifying and authorizing the designated
representative, and alternate designated representative, of the owners
and operators of a source and the units at the source and for changing
the designated representative and alternate designated representative.
These sections would also describe the designated representative's and
alternate designated representative's responsibilities and the process
through which he or she could delegate to an agent the authority to
make electronic submissions to the Administrator. These provisions
would be patterned after the provisions concerning designated
representatives and alternates in prior EPA-administered trading
programs.
    The designated representative would be the individual authorized to
represent the owners and operators of each covered source and covered
unit at the source in matters pertaining to all Transport Rule trading
programs to which the source and units were subject. This approach
would ensure that one individual was required to be knowledgeable about
the requirements of, and responsible for compliance with, all Transport
Rule trading programs. One alternate designated representative could be
selected to act on behalf of, and legally bind, the designated
representative and thus the owners and operators. Because the actions
of the designated representative and alternate would legally bind the
owners and operators, the designated representative and alternate would
have to submit a certificate of representation certifying that each was
selected by an agreement binding on all such owners and operators and
was authorized to act on their behalf.
    The designated representative and alternate would be authorized
upon receipt by the Administrator of the certificate of representation.
This document, in a format prescribed by the Administrator, would
include: Specified identifying information for the covered source and
covered units at the source and for the designated representative and
alternate; the name of every owner and operator of the source and
units; and certification language and signatures of the designated
representative and alternate. All submissions (e.g., monitoring plans,
monitoring system certifications, and allowance transfers) for a
covered source or covered unit would have to be submitted, signed, and
certified by the designated representative or alternate. Further, upon
receipt of a complete certificate of representation, the Administrator
would establish a compliance account in the Allowance Management System
for the source involved.
    In order to change the designated representative or alternate, a
new certificate of representation would have to be received by the
Administrator. A new certificate of representation would also have to
be submitted to reflect changes in the owners and operators of the
source and units involved. However, new owners and operators would be
bound by the existing certificate of representation even in the absence
of such a submission.
    In addition to the flexibility provided by allowing an alternate to
act for the designated representative (e.g., in circumstances where the
designated representative might be unavailable), additional flexibility
would be provided by allowing the designated representative or
alternate to delegate authority to make electronic submissions on his
or her behalf. The designated representative or alternate could
designate agents to submit electronically certain specified documents.
The previously-described requirements for designated representatives
and alternates would provide regulated entities with flexibility in
assigning responsibilities under the Transport Rule trading programs,
while ensuring accountability by owners and operators and simplifying
the administration of the proposed Transport Rule trading programs.
(4) Allowance Management System
    The Transport Rule trading program rules listed later would
establish the procedures and requirements for using and operating the
Allowance Management System (which is the electronic data system
through which the Administrator would handle allowance allocation,
holding, transfer, and deduction), and for determining compliance with
the emissions limitations and assurance provisions, in an efficient and
transparent manner. The Allowance Management System would also provide
the allowance markets with a record of ownership of allowances, dates
of allowance transfers, buyer and seller information, and the serial
numbers of allowances transferred. Consistent with the approach in
prior EPA-administered trading program, allowance price

information would not be included in the Allowance Management System.
EPA's experience is that private parties (e.g., brokers) are in a
better position to obtain and disseminate timely, accurate allowance
price information than is EPA. For example, because not all allowance
transfers are immediately reported to the Administrator for
recordation, the Administrator would not be able to ensure that any
reported price information associated with the transfers would reflect
current market prices.
(vi) Sec. Sec.  97.420, 97.520, 97.620, and 97.720--Compliance and
General Accounts
    The Allowance Management System would contain two types of
accounts: compliance accounts, one of which the Administrator would
establish for each covered source upon receipt of the certificate of
representation for the source; and general accounts, which could be
established by any entity upon receipt by the Administrator of an
application for a general account. A compliance account would be the
account in which any allowances used by the covered source for
compliance with the emissions limitations and assurance provisions
would have to be held. The designated representative and alternate for
the source would also be the authorized account representative and
alternate for the compliance account. Using source-level, rather than
unit-level accounts, would provide owners and operators more
flexibility in managing their allowances for compliance, without
jeopardizing the environmental goals of the Transport Rule trading
programs, because the source-level approach would avoid situations
where a unit would hold insufficient allowances and would be in
violation of allowance-holding requirements even though units at the
same source had more than enough allowances to meet these requirements
for the entire source.
    General accounts could be used by any person or group for holding
or trading allowances. However, allowances could not be used for
compliance with emissions limitations or assurance provisions so long
as the allowances were held in, and not properly and timely transferred
out of, a general account. To open a general account, a person or group
would have to submit an application for a general account, which would
be similar in many ways to a certificate of representation. The
application would include, in a format prescribed by the Administrator:
The name and identifying information of the individual who would be the
authorized account representative and of any individual who would be
the alternate authorized account representative; an identifying name
for the account; the names of all persons with an ownership interest
with the respect to allowances held in the account; and certification
language and signatures of the authorized account representative and
alternate. The authorized account representative and alternate would be
authorized upon receipt of the application by the Administrator. The
provisions for changing the authorized account representative and
alternate, for changing the application to take account of changes in
the persons having an ownership interest with respect to allowances,
and for delegating authority to make electronic submissions would be
analogous to those applicable to comparable matters for designated
representatives and alternates.
(vii) Sec. Sec.  97.421 Through 97.423, 97.521 Through 97.523, 97.621
Through 97.623, and 97.721 Through 97.723--Recordation of Allowance
Allocations and Transfers
    By September 1, 2011, the Administrator would record allowance
allocations for existing units, based on Appendix A to each proposed
Transport Rule trading program rule, for 2012 through 2014. By June 1,
2012 and June 1 of each year thereafter, the Administrator would record
such allowance allocations for each proposed Transport Rule trading
program for the third year after the year of the recordation deadline,
e.g., for 2015 in 2012. Recording these allowance allocations about 3
years in advance of the first year for which they could be used for
compliance would facilitate compliance planning by owners and operators
and promote robust allowance markets, including futures markets for
allowances. By September 1 (for the Transport Rule NOX and
SO2 annual trading programs and June 1, for the Transport
Rule NOX Ozone Season program) of each year starting with
2012, the Administrator would record allowance allocations for that
year from the new unit set-aside. Because this would occur before the
allowance transfer deadline for each proposed Transport Rule trading
program involved, this would still allow for trading and thereby
promote robust allowance markets.
    The process for transferring allowances from one account to another
would be quite simple. A transfer would be submitted providing, in a
format prescribed by the Administrator, the account numbers of the
accounts involved, the serial numbers of the allowances involved, and
the name and signature of the transferring authorized account
representative or alternate. If the transfer form containing all the
required information were submitted to the Administrator and, when the
Administrator attempted to record the transfer, the transferor account
included the allowances identified in the form, the Administrator would
record the transfer by moving the allowances from the transferor
account to the transferee account within 5 business days of the receipt
of the transfer form.
(viii) Sec. Sec.  97.424, 97.524, 97.624, and 97.724--Compliance With
Emissions Limitations
    Once a control period has ended (i.e., December 31 for the
Transport Rule NOX and SO2 annual trading
programs and September 30 for the NOX ozone season trading
program), covered sources would have a window of opportunity (i.e.,
until the allowance transfer deadline of midnight on March 1 or
December 1 following the control period for the annual and ozone season
trading programs respectively) to evaluate their reported emissions and
obtain any allowances that they might need to cover their emissions
during the control period. Each allowance issued in each proposed
Transport Rule trading program would authorize emission of one ton of
the pollutant, and so would be usable for compliance, for a control
period in the year for which the allowance was allocated or a later
year. Consequently, each source would need--as of the allowance
transfer deadline--to have in its compliance account, or have a
properly submitted transfer that would move into its compliance
account, enough allowances usable for compliance to authorize the
source's total emissions for the control period. The authorized account
representative could identify specific allowances to be deducted, but,
in the absence of such identification or in the case of a partial
identification, the Administrator would deduct on a first-in, first-out
basis.
    If a source were to fail to hold sufficient allowances for
compliance, then the owners and operators would have to provide, for
deduction by the Administrator, 2 allowances allocated for the control
period in the next year for every allowance that the owners and
operators failed to hold as required to cover emissions. In addition,
the owners and operators would be subject to discretionary civil
penalties for each violation, with each ton of unauthorized emissions
and each day of the control

period involved constituting a violation of the Clean Air Act.
    EPA believes that it is important to include a requirement for an
automatic deduction of allowances. The deduction of one allowance per
allowance that the owners and operators failed to hold would offset
this failure. The deduction of another allowance per allowance that the
owners and operators failed to hold would provide an automatic penalty
that could not be avoided, regardless of any explanation provided by
the owners and operators for their failure, and would therefore provide
a strong incentive for compliance with the allowance-holding
requirement by ensuring that non-compliance would be a significantly
more expensive option than compliance.
(ix) Sec. Sec.  97.425, 97.525, 97.625, and 97.725--Compliance With
Assurance Provisions
    EPA proposes to include assurance provisions in the Transport Rule
trading programs in order to ensure that each state would eliminate
that part of its significant contribution and interference with
maintenance that EPA has identified in today's proposed action (see
section V.D.4.b previously). As previously discussed, a requirement
that owners surrender allowances under the assurance provisions would
be triggered only for owners of units in a state where the total state
EGU emissions for a control period would exceed the applicable state
budget with the variability limit. Moreover, only an owner whose units'
emissions would exceed the owner's share of the state budget with the
variability limit would be subject to the allowance surrender.
    The process of determining, for a given control period, which
states would have total EGU emissions sufficient to trigger the
allowance surrender requirement, which owners would be subject to the
allowance surrender, and whether those owners were in compliance would
be implemented in a series of steps. (The dates summarized later apply
to the proposed annual programs; the dates for the proposed ozone
season program would be earlier.)
    First, the Administrator would perform the calculations necessary
to determine whether any states had total state EGU emissions for a
control period greater than the state budget with the variability
limit, applying both the 1-year and the 3-year variability limits
discussed earlier. By June 1 (starting in 2015), the Administrator
would promulgate a notice of availability of the results of these
calculations and provide an opportunity for submission of objections.
By August 1, the Administrator would promulgate a second notice of
availability of any necessary adjustments to the calculations and the
reasons for accepting or rejecting any properly submitted objections.
    Second, by August 15, the designated representative of every
Transport Rule source in a state identified in the August 1 notice as
having control period emissions in excess of the budget with the
variability limit would make a submission to the Administrator that
would identify: Each person having (as of the last day of the control
period) a legal, equitable, leasehold, or contractual reservation or
entitlement in the Transport Rule units at the source; and the
percentage of each such person's reservation or entitlement.
    Third, by September 15, the Administrator would calculate, for each
state identified in the August 1 notice and for each owner of covered
units in the state, the owner's share of emissions, the owner's share
of the state budget with the variability limit, and the amount (if any)
that the owner would be required to hold for surrender under the
assurance provisions (i.e., the owner's proportionate share of the
excess of state emissions over the state budget with the variability
limit). The Administrator would promulgate a notice of availability of
the results of these calculations, provide an opportunity for