methodology are as follows in Table IV.E-1:

  Table IV.E-1--SO2 and Annual NOX State Emissions Budgets for Electric Generating Units Before Accounting for
                                                 Variability 74
                                                     [Tons]
----------------------------------------------------------------------------------------------------------------
                                                                   SO2, 2012 and   SO2, 2014 and    NOX annual,
                              State                                    2013            later         all years
----------------------------------------------------------------------------------------------------------------
Alabama.........................................................         161,871         161,871          69,169
Connecticut.....................................................           3,059           3,059           2,775
Delaware........................................................           7,784           7,784           6,206
District of Columbia............................................             337             337             170
Florida.........................................................         161,739         161,739         120,001
Georgia.........................................................         233,260          85,717          73,801
Illinois........................................................         208,957         151,530          56,040
Indiana.........................................................         400,378         201,412         115,687
Iowa............................................................          94,052          86,088          46,068
Kansas..........................................................          57,275          57,275          51,321
Kentucky........................................................         219,549         113,844          74,117
Louisiana.......................................................          90,477          90,477          43,946
Maryland........................................................          39,665          39,665          17,044
Massachusetts...................................................           7,902           7,902           5,960
Michigan........................................................         251,337         155,675          64,932
Minnesota.......................................................          47,101          47,101          41,322
Missouri........................................................         203,689         158,764          57,681
Nebraska........................................................          71,598          71,598          43,228
New Jersey......................................................          11,291          11,291          11,826
New York........................................................          66,542          42,041          23,341
North Carolina..................................................         111,485          81,859          51,800
Ohio............................................................         464,964         178,307          97,313
Pennsylvania....................................................         388,612         141,693         113,903
South Carolina..................................................         116,483         116,483          33,882
Tennessee.......................................................         100,007         100,007          28,362
Virginia........................................................          72,595          40,785          29,581
West Virginia...................................................         205,422         119,016          51,990
Wisconsin.......................................................          96,439          66,683          44,846
                                                                 -----------------------------------------------
    Total.......................................................       3,893,870       2,500,003       1,376,312
----------------------------------------------------------------------------------------------------------------

    For more detail on how the budgets were developed, see the TSD:
``State Budgets, Unit Allocations, and Unit Emissions Rates''.
---------------------------------------------------------------------------

    \74\ The impact of variability on the budgets is discussed in
section IV.F, later.
---------------------------------------------------------------------------

2. Defining Ozone Season NOX State Emissions Budgets for
EGUs
    Ozone season NOX budgets were developed the same way as
the annual NOX budgets were developed (explained in IV.E.1,
previously).

   Table IV.E-2--Ozone-season NOX State Emissions Budgets for Electric
           Generating Units Before Accounting for Variability
                                 [Tons]
------------------------------------------------------------------------
                                                              NOX ozone
                           State                             season, all
                                                                years
------------------------------------------------------------------------
Alabama....................................................       29,738
Arkansas...................................................       16,660
Connecticut................................................        1,315
Delaware...................................................        2,450
District of Columbia.......................................          105
Florida....................................................       56,939
Georgia....................................................       32,144
Illinois...................................................       23,570
Indiana....................................................       49,987
Kansas.....................................................       21,433
Kentucky...................................................       30,908
Louisiana..................................................       21,220
Maryland...................................................        7,232
Michigan...................................................       28,253
Mississippi................................................       16,530
New Jersey.................................................        5,269
New York...................................................       11,090
North Carolina.............................................       23,539
Ohio.......................................................       40,661
Oklahoma...................................................       37,087
Pennsylvania...............................................       48,271
South Carolina.............................................       15,222
Tennessee..................................................       11,575
Texas......................................................       75,574
Virginia...................................................       12,608
West Virginia..............................................       22,234
                                                            ------------
    Total..................................................      641,614
------------------------------------------------------------------------

    These budgets are based on a 5 month ozone season (May 1 through
September 30). Consistent with the approach taken by the OTAG, the
NOX SIP Call, and the CAIR, we propose to define the ozone
season, for purposes of emissions

reductions requirements in this rule, as May through September. We
recognize that this ozone season for regulatory requirements will have
differences from the official state-specific ozone monitoring season.
EPA requests comment on whether the budgets for the final rule should
be based on a longer ozone season, such as March through October.

F. Emission Reduction Requirements Including Variability

    In this section, EPA discusses the inherent variability in electric
power system operation and presents proposed variability limits for
each state. As explained below, EPA proposes to calculate variability
limits for each state and to use those variability limits in
conjunction with the budgets (which are based on expected average
conditions) to provide limited flexibility (within the limits allowed
by the variability provisions) to address years in which more fossil
generation occurs than projected in the average base case year. This
section also presents projected emission reduction results.
1. Variability
a. Introduction to Power Sector Variability
    Historically, power sector emissions have varied over time.
Factors, such as fuel switching and installing new emissions controls,
which can lead to significant decreases in emissions, primarily affect
emissions rates rather than generation and change largely as a result
of pollution regulation.
    Even when emissions rates do not change from year to year, overall
emissions can change because of factors including power demand, timing
of maintenance activities, and unexpected shutdowns of units. Extreme
weather conditions, sudden economic shocks, and other unpredictable
events can also significantly impact power generation from fossil
units. These factors relate directly to heat input, generation, and the
routine operation of power plants to supply our electricity, and thus
affect total emissions.
    As discussed previously, EPA has identified a specific amount of
emissions that must be prohibited by each state to satisfy the
requirements of CAA section 110(a)(2)(D)(i)(I). EPA has also developed
state budgets based on its projections of state emissions in an average
year after the elimination of such emissions. However, because of the
unavoidable variability in baseline emissions--resulting from the
inherent variability in power plant operations--state-level emissions
may vary somewhat after all significant contribution and interference
with maintenance that EPA has identified in this proposal are
eliminated. This occurs even when the emissions rates of the units
within the state do not change. For this reason, EPA has determined
that it is appropriate to develop variability limits for each state
budget. These limits are used to identify the range of emissions that
EPA believes may occur in each state following the elimination of all
significant contribution and interference with maintenance.
    For the proposed rule, EPA proposes to factor this variability
explicitly in its consideration of how to control emissions. The Agency
believes that because baseline emissions are variable, emissions after
the elimination of all significant contribution are also variable and
thus it is appropriate to take this variability into account.
    As discussed in detail in section V, EPA proposes and considers
specific regulatory remedies that are designed to meet the emissions
budget in an average year. Because base case emissions may vary from
projections, EPA believes these same remedies may incorporate
provisions that account for variability. This variability, however,
must be limited to provide downwind states with assurance that
necessary reductions will be made in upwind states. This section
describes how EPA calculated variability limits for each state to
achieve this goal.
    Remedies (i.e., regulatory approaches for achieving emissions
reductions) can range from emissions rate-based ``direct control''
options to options which allow for interstate trading. EPA believes
that inherent variability in power system operations affects each
state's baseline emissions and thus also affects a state's emissions
after elimination of all significant contribution and interference with
maintenance. Thus, emissions may vary somewhat after implementation of
the remedies under consideration. Under an emissions rate-based
approach, emissions rate limits could be developed that would meet the
budget assuming a given pattern of operation for the affected units. If
some of the units with higher emissions rates actually operated more
than projected, the state's actual emissions would be higher. In an
interstate trading program, budgets could be developed that each state
would be projected to meet in an average year. In some years, however,
generation from units in one state may increase (with a corresponding
increase in emissions), but because variability in a larger region is
less significant than within a single state, the increase in one state
would be expected to be offset by decreases in other states. Finally,
even in an intrastate-only trading program, the ability to bank
allowances could mean that in one year, emissions would be below the
budget, while in another year they would be above.
    In all these cases, variability limits can be used to retain the
flexibilities that the various remedies provide to deal with real-world
variability in the operating system, while still providing downwind
states reasonable certainty about the level of upwind emissions.
    EPA also notes that explicit consideration of variability in the
emissions resulting from a remedy is consistent with removing a state's
``significant contribution.'' As noted previously, even if the
emissions result is variable from year to year, there is still a
similar increment of emissions reductions. For example, because
increased emissions in the control case would also correspond to
increased emissions in the base case, the increment of emissions
representing significant contribution and interference with maintenance
would still be removed. Finally, as is explained more below in IV.F.b,
the variability limits (as applied, for instance, in the State Budgets/
Limited Trading remedy in section V.D.4) are relatively low and thus
the total amount of variability allowed is very small compared to total
EGU emissions and even smaller when considering all of the emissions
within a state. It is also worth noting that in the proposed State
Budgets/Limited Trading remedy, variability is taken into account in
such a way that does not allow an overall increase in emissions. Under
this remedy, an individual state could emit up to its budget plus
variability limit. However, the requirement that all sources hold
allowances to cover emissions, and the fact that those allowances are
allocated based on state-specific budgets absent variability, would
ensure that total emissions do not increase. This remedy, therefore,
ensures not only that total emissions do not increase above state
budgets, but also that reductions occur in each and every state.
b. How EPA Accounted for Inherent Power Sector Variability
    EPA determined 1-year variability limits and 3-year rolling average
variability limits for each state. First, EPA determined 1-year
variability limits based on historical variability in heat input.
Second, EPA determined 3-year rolling average variability limits using
statistical methods to convert the 1-year variability into 3-year
variability. The approaches EPA used to determine the

1-year and 3-year limits are summarized later and described in more
detail in the Power Sector Variability TSD.
    Expected variability over a single year. EPA performed analyses
using historical data to demonstrate that there is year-to-year
variability in baseline emissions (even when emissions rates for all
units are held constant) and to quantify the magnitude of this
variability. This year-to-year variability in emissions is reflected,
in combination with other factors, in year-to-year variability in air
quality.
    The focus of the analysis is on quantifying the magnitude of the
inherent variability in the baseline emissions (on both a 1-year and a
3-year basis). The goals of this analysis, therefore, are to determine
the typical variability in emissions that is due to changes in
generation, and not due to changes in emission limits, and to set
emissions criteria limits that can be used as part of a remedy to
ensure that states are eliminating their significant contribution and
interference with maintenance to protect air quality.
    EPA used statewide average emissions rates projected using IPM to
convert historical heat input variability into corresponding emissions
variability limits. The approach assessed the variability in state-
level heat input over a 7-year time period (2002 through 2008) using
the standard deviation and then determined the difference in emissions
from the 95th percent two-tailed confidence level and the mean.\75\ The
approach resulted in a maximum allowable variability, in tons, for each
state. These values were then divided by the mean emissions values over
the 7-year time period to yield a percentage variability value for each
state. See the Power Sector Variability TSD for details.
---------------------------------------------------------------------------

    \75\ The two-tailed 95th percent confidence level is the
equivalent of the 97.5th upper (single-tailed) confidence level.
---------------------------------------------------------------------------

    From the state-by-state tonnage and percentage emission variability
values, EPA identified a single set of variability levels (that is, a
tonnage and a percentage) based on the historic variability. EPA made
the decision to adopt a single, uniform tonnage and percentage level
pairing to apply to all states in order to make the application of the
variability limits straightforward rather than developing state-by-
state percentage variability values. The effect of the pairing is to
ensure that each state is allowed adequate variability while minimizing
the total amount of emissions allowed. Using, for all states, only a
constant percentage (reflecting emissions variability in smaller states
with a greater range of emissions in percentage terms) would result in
large states being allowed greater variability than needed. Conversely,
using only a constant tonnage (reflecting emissions variability in
larger states with a greater range of emissions in tonnage terms) would
result in small states being allowed greater variability than needed.
To ensure adequate variability limits--even in states with small
numbers of units where expected variability would be more pronounced in
percentage terms, and in large states where expected variability would
be more pronounced in absolute tonnage terms--EPA derived variability
limits both as a percentage and in terms of absolute emissions (tons)
that serve to minimize the total amount of emissions allowed under this
combination variability limit approach.
    For the tonnage and percentage limit criteria, EPA looked at a wide
range of percentage and tonnage combinations, and chose for further
investigation combinations that provided states sufficient variability
limits (based on historic variability) and fit the requirement of
minimizing the allowed emissions. Power plants in states that were
close to the variability limits were evaluated more closely to ensure
the modeling reflected all controls known to operate. EPA believes that
the chosen limits would not be tighter than these states could be
expected to meet.
    This approach (identifying both a tonnage and a percentage)
addresses the difficulty that smaller states with fewer units could
face if only percentages were used to set the limits. For instance, in
a small state with a budget of 5,000 tons of SO2, an
infrequently used unit that on average emitted 500 tons when it
operated 10 percent of the time could increase its emissions to 1,500
tons by operating 30 percent of the time in a year when there is
unusually high demand for that unit. That would result in a 20 percent
increase in statewide emissions. In a much larger state, with a budget
of 50,000 tons, such a change in operation would only lead to a 1
percent change in statewide emissions.
    For both annual NOX and SO2, the percentage
variability limits are 10 percent of a state's budget and the
corresponding tonnage variability limits are 5,000 and 1,700 tons for
NOX and SO2, respectively. These are the values
that result from the approach described previously, i.e., these
variability levels allow the necessary variability for every state
based on its historic variability, while minimizing the amount of
emissions allowed.
    EPA assigned each state one of these values--either the tonnage
limit or the percent limit, whichever was greater for that state. For
instance, 10 percent of Connecticut's SO2 budget is less
than 1,700 tons, so Connecticut received a 1-year 1,700 ton variability
limit for its EGU SO2 emissions. EGU sources in Connecticut
could emit up to the state's SO2 budget plus the variability
limit of an additional 1,700 tons of SO2 in a year, and
still eliminate the state's significant contribution and interference
with maintenance. Proposed 1-year variability limits for each covered
state are shown in the tables in section IV.F.2, later. See the Power
Sector Variability TSD for more details on EPA's variability approach.
    Expected variability over a 3-year time period. Because air quality
is assessed under the Act annually on a rolling 3-year time period, EPA
believes that it is appropriate to also evaluate the inherent
variability in emissions over similar time periods, and to establish
state budgets with variability limits that ensure that the significant
contribution and interference with maintenance that EPA has identified
in this notice be eliminated.
    While the year-to-year variability in emissions could lead to
variability in 3-year rolling averages, inherent variability is lower
over a 3-year time period than over a 1-year period and thus a state's
3-year variability limit will be lower than the state's 1-year
variability limit. Establishing such 3-year limits thus provides an
opportunity to ensure that the variability limits do not allow greater
fluctuation in emissions than justified based on historic variability.
EPA estimated the variability in a state's emissions over a 3-year time
period based on the expected variability in emissions for a single
year.
    As summarized later and described in the Power Sector Variability
TSD, the Agency used statistical methods to estimate the 3-year
variability based on 1-year variability. The average variability of a
multi-year sample is the average variability of a single year divided
by the square root of the number of years in the multi-year sample.\76\
Thus, the variability of a 3-year average is equal to the annual
variability divided by the square root of three. EPA used this approach
to determine 3-year variability limits based on the 1-year limits. For
example, the Agency calculated the 3-year variability that corresponds
to a 1-year variability of 5,000 tons as 5,000 divided by the

square root of three, or 2,887 tons. Similarly, EPA calculated the 3-
year variability that corresponds to a 1-year variability of 1,700 tons
as 1,700 divided by the square root of three, or 981 tons. EPA decided
to use three years instead of some other interval in order to be
consistent with 3-year averaging used to assess attainment with the
NAAQS, as explained earlier in this section.
---------------------------------------------------------------------------

    \76\ Moore, David S. and George P. McCabe. Introduction to the
Practice of Statistics. 2nd ed. New York: W.H. Freeman and Company,
1993. p. 395.
---------------------------------------------------------------------------

    Proposed 3-year variability limits for each covered state are shown
in the tables in section IV.F.2, later. See the Power Sector
Variability TSD for more details on EPA's variability approach.
2. State Budgets With Variability Limits
    As explained previously, EPA determined variability limits for each
state. EPA then applied these variability limits on a state-by-state
basis to calculate state-specific emissions budgets with variability
limits. EPA calculated state budgets with both 1-year and 3-year
variability limits.
    Table IV.F-1 shows proposed variability limits by state on
SO2 emissions for 2014 and later. Table IV.F-2 shows
proposed variability limits by state on NOX annual emissions
for 2014 and later. EPA requests comment on the proposed variability
limits.
    EPA also requests comment on an alternative calculation method for
variability. The alternative method would use the results of the
proposed method but add a ceiling based on the maximum percentage of
variability among covered states as observed in the historic heat input
data described previously. For both NOX annual and
SO2, the percentage limits calculated using this alternative
methodology are 21 and 28 percent of a state's budget, respectively.
Under this alternative calculation method, a state's variability limit
would be no lower than 10 percent of its budget and no higher than 21
or 28 percent, for NOX and SO2, respectively.
Because no state varied more than these percentages, EPA believes they
could serve as reasonable caps on variability limits. These limits
would address the issue of small states receiving very large
variability limits as a fraction of their budgets.
    For instance, although Connecticut's proposed 1-year variability
limit of 1,700 tons is greater than 10 percent of its SO2
budget of 3,059 tons (306 tons), it is also greater than 28 percent of
the budget (857 tons). Therefore, under this alternative calculation
method, Connecticut's 1-year SO2 variability limit would be
857 tons (28 percent of the state's SO2 budget). Similarly,
for annual NOX, while Connecticut's proposed 1-year
variability limit of 5,000 tons is greater than 10 percent of its
NOX annual budget of 2,775 (278 tons), it is greater than 21
percent of the budget (583 tons). Therefore, under this alternative
approach, Connecticut's 1-year annual NOX variability limit
would be 583 tons. Tables IV.F-1 through IV.F-3 show the variability
limits under the proposed and alternative calculation methods. See the
Power Sector Variability TSD in the docket for this rule for more
details.

    Table IV.F-1--Variability Limits on SO2 Annual Emissions for 2014 and Later for Electric Generating Units
                                                     [Tons]
----------------------------------------------------------------------------------------------------------------
                                                                      Proposed                 Alternative
                                                  SO2 annual ---------------------------------------------------
                     State                        emissions                   3-year                    3-year
                                                    budget       1-year      average       1-year      average
                                                                 limit        limit        limit        limit
----------------------------------------------------------------------------------------------------------------
Alabama........................................      161,871       16,187        9,346       16,187        9,346
Connecticut....................................        3,059        1,700          981          857          495
Delaware.......................................        7,784        1,700          981        1,700          981
District of Columbia...........................          337        1,700          981           94           54
Florida........................................      161,739       16,174        9,338       16,174        9,338
Georgia........................................       85,717        8,572        4,949        8,572        4,949
Illinois.......................................      151,530       15,153        8,749       15,153        8,749
Indiana........................................      201,412       20,141       11,629       20,141       11,629
Iowa...........................................       86,088        8,609        4,970        8,609        4,970
Kansas.........................................       57,275        5,728        3,307        5,728        3,307
Kentucky.......................................      113,844       11,384        6,573       11,384        6,573
Louisiana......................................       90,477        9,048        5,224        9,048        5,224
Maryland.......................................       39,665        3,967        2,290        3,967        2,290
Massachusetts..................................        7,902        1,700          981        1,700          981
Michigan.......................................      155,675       15,568        8,988       15,568        8,988
Minnesota......................................       47,101        4,710        2,719        4,710        2,719
Missouri.......................................      158,764       15,876        9,166       15,876        9,166
Nebraska.......................................       71,598        7,160        4,134        7,160        4,134
New Jersey.....................................       11,291        1,700          981        1,700          981
New York.......................................       42,041        4,204        2,427        4,204        2,427
North Carolina.................................       81,859        8,186        4,726        8,186        4,726
Ohio...........................................      178,307       17,831       10,295       17,831       10,295
Pennsylvania...................................      141,693       14,169        8,181       14,169        8,181
South Carolina.................................      116,483       11,648        6,725       11,648        6,725
Tennessee......................................      100,007       10,001        5,774       10,001        5,774
Virginia.......................................       40,785        4,079        2,355        4,079        2,355
West Virginia..................................      119,016       11,902        6,871       11,902        6,871
Wisconsin......................................       66,683        6,668        3,850        6,668        3,850
                                                --------------
    Total......................................    2,500,003
----------------------------------------------------------------------------------------------------------------
Proposed 1-year variability limits are the larger of (1) 1,700 tons or (2) 10 percent of the state's budget. 3-
  year limits are the 1-year limits divided by the square root of three.
The alternative 1-year variability limit is 1,700 tons as long as that amount is between 10 and 28 percent of
  the state's budget. If 1,700 tons is greater than 28 percent of the state's budget, the state's limit is set
  at 28 percent of its budget. If 1,700 tons is less than 10 percent of the state's budget, the state's limit is
  set at 10 percent of its budget.

    Table IV.F-2--Variability Limits on NOX Annual Emissions for 2014 and Later for Electric Generating Units
                                                     [Tons]
----------------------------------------------------------------------------------------------------------------
                                                                      Proposed                 Alternative
                                                             ---------------------------------------------------
                     State                        NOX annual                  3-year                    3-year
                                                                 1-year      average       1-year      average
                                                                 limit        limit        limit        limit
----------------------------------------------------------------------------------------------------------------
Alabama........................................       69,169        6,917        3,993        6,917        3,993
Connecticut....................................        2,775        5,000        2,887          583          336
Delaware.......................................        6,206        5,000        2,887        1,303          752
District of Columbia...........................          170        5,000        2,887           36           21
Florida........................................      120,001       12,000        6,928       12,000        6,928
Georgia........................................       73,801        7,380        4,261        7,380        4,261
Illinois.......................................       56,040        5,604        3,235        5,604        3,235
Indiana........................................      115,687       11,569        6,679       11,569        6,679
Iowa...........................................       46,068        5,000        2,887        5,000        2,887
Kansas.........................................       51,321        5,132        2,963        5,132        2,963
Kentucky.......................................       74,117        7,412        4,279        7,412        4,279
Louisiana......................................       43,946        5,000        2,887        5,000        2,887
Maryland.......................................       17,044        5,000        2,887        3,579        2,066
Massachusetts..................................        5,960        5,000        2,887        1,252          723
Michigan.......................................       64,932        6,493        3,749        6,493        3,749
Minnesota......................................       41,322        5,000        2,887        5,000        2,887
Missouri.......................................       57,681        5,768        3,330        5,768        3,330
Nebraska.......................................       43,228        5,000        2,887        5,000        2,887
New Jersey.....................................       11,826        5,000        2,887        2,483        1,434
New York.......................................       23,341        5,000        2,887        4,902        2,830
North Carolina.................................       51,800        5,180        2,991        5,180        2,991
Ohio...........................................       97,313        9,731        5,618        9,731        5,618
Pennsylvania...................................      113,903       11,390        6,576       11,390        6,576
South Carolina.................................       33,882        5,000        2,887        5,000        2,887
Tennessee......................................       28,362        5,000        2,887        5,000        2,887
Virginia.......................................       29,581        5,000        2,887        5,000        2,887
West Virginia..................................       51,990        5,199        3,002        5,199        3,002
Wisconsin......................................       44,846        5,000        2,887        5,000        2,887
                                                -------------
    Total......................................    1,376,312
----------------------------------------------------------------------------------------------------------------
Proposed 1-year variability limits are the larger of (1) 5,000 tons or (2) 10 percent of the state's budget. 3-
  year limits are the 1-year limits divided by the square root of three.
The alternative 1-year variability limit is 5,000 tons as long as that amount is between 10 and 21 percent of
  the state's budget. If 5,000 tons is greater than 21 percent of the state's budget, the state's limit is set
  at 21 percent of its budget. If 5,000 tons is less than 10 percent of the state's budget, the state's limit is
  set at 10 percent of its budget.

    The NOX ozone season variability limits have been
calculated based on five months of data corresponding to the May
through September ozone season. EPA is proposing to use the same
approach to calculate ozone season limits that the Agency used to
calculate the proposed SO2 and NOX annual
variability limits described earlier in this section, but adjusted to
reflect the ozone season data.
    Using that approach, the resulting ozone season 1-year variability
limits are 2,100 tons and 10 percent of a state's budget. EPA assigned
each state one of these values-either the tonnage limit or the
percentage limit, whichever was greater for that state--using the same
approach as for the SO2 and NOX annual limits
described previously. EPA determined the 3-year variability limits as
the 1-year limits divided by the square root of three, the same
approach used for the SO2 and NOX annual limits.
The NOX ozone season limits resulting from this approach are
shown in Table IV.F-3.
    EPA did not explicitly model ozone season variability limits
because it was assumed that the NOX annual limits would also
serve to limit variability in the ozone season and that additional
constraints were unnecessary. However, a comparison of the data
revealed that these variability limits would be lower than the ozone
season emissions shown in EPA's modeling for this proposed rule in
seven states, with the difference ranging from less than 100 tons to
about 900 tons. Adding these ozone season variability limits would,
presumably, change the NOX emissions projections in the IPM
modeling, but the differences are expected not to make a noticeable
impact in the overall air quality results.
    As with the SO2 and NOX annual variability
limits, EPA also calculated NOX ozone season limits using
the alternative calculation method described previously; the
alternative method adds a ceiling based on the maximum percentage of
variability among covered states as observed in the historic heat input
data. For NOX ozone season, the percentage limit ceiling
would be 27 percent of a state's budget. The NOX ozone
season limits resulting from this approach are also shown in Table
IV.F-3.
    EPA requests comments on the NOX ozone season limits
shown in Table IV.F-3.

    Table IV.F-3--Variability Limits on NOX Ozone Emissions for 2014 and Later for Electric Generating Units
                                                     [Tons]
----------------------------------------------------------------------------------------------------------------
                                                                      Proposed                 Alternative
                                                  NOX ozone  ---------------------------------------------------
                     State                          season                    3-year                    3-year
                                                  emissions      1-year      average       1-year      average
                                                    budget       limit        limit        limit        limit
----------------------------------------------------------------------------------------------------------------
Alabama........................................       29,738        2,974        1,717        2,974        1,717
Arkansas.......................................       16,660        2,100        1,212        2,100        1,212
Connecticut....................................        1,315        2,100        1,212          355          205
Delaware.......................................        2,450        2,100        1,212          662          382
District of Columbia...........................          105        2,100        1,212           28           16
Florida........................................       56,939        5,694        3,287        5,694        3,287
Georgia........................................       32,144        3,214        1,856        3,214        1,856
Illinois.......................................       23,570        2,357        1,361        2,357        1,361
Indiana........................................       49,987        4,999        2,886        4,999        2,886
Kansas.........................................       21,433        2,143        1,237        2,143        1,237
Kentucky.......................................       30,908        3,091        1,784        3,091        1,784
Louisiana......................................       21,220        2,122        1,225        2,122        1,225
Maryland.......................................        7,232        2,100        1,212        1,953        1,127
Michigan.......................................       28,253        2,825        1,631        2,825        1,631
Mississippi....................................       16,530        2,100        1,212        2,100        1,212
New Jersey.....................................        5,269        2,100        1,212        1,423          821
New York.......................................       11,090        2,100        1,212        2,100        1,212
North Carolina.................................       23,539        2,354        1,359        2,354        1,359
Ohio...........................................       40,661        4,066        2,348        4,066        2,348
Oklahoma.......................................       37,087        3,709        2,141        3,709        2,141
Pennsylvania...................................       48,271        4,827        2,787        4,827        2,787
South Carolina.................................       15,222        2,100        1,212        2,100        1,212
Tennessee......................................       11,575        2,100        1,212        2,100        1,212
Texas..........................................       75,574        7,557        4,363        7,557        4,363
Virginia.......................................       12,608        2,100        1,212        2,100        1,212
West Virginia..................................       22,234        2,223        1,284        2,223        1,284
                                                --------------
    Total......................................      641,614
----------------------------------------------------------------------------------------------------------------
Proposed 1-year variability limits are the larger of (1) 2,100 tons or (2) 10 percent of the state's budget. 3-
  year limits are the 1-year limits divided by the square root of three.
The alternative 1-year variability limit is 2,100 tons as long as that amount is between 10 and 27 percent of
  the state's budget. If 2,100 tons is greater than 27 percent of the state's budget, the state's limit is set
  at 27 percent of its budget. If 2,100 tons is less than 10 percent of the state's budget, the state's limit is
  set at 10 percent of its budget.

    As discussed in section V.D, the proposed FIPs would apply the 1-
year variability limits commencing in 2014 and the 3-year variability
limits commencing in 2016, noting that application of the 3-year
average limits in 2016 would serve to limit each state's emissions in
2014 and 2015. The Agency also requests comment on whether the remedy
in the proposed FIPs should be modified so that the limits would apply
starting in 2012 instead of 2014. In addition, the direct control
remedy option on which EPA requests comments includes assurance
provisions based on these variability limits that would apply starting
in 2012. Thus, EPA also explains later what variability limits would
apply in 2012 and 2013. The 1-year variability limits for 2012 and 2013
would be the same as the variability limits for 2014 and later in
Tables IV.F-1, IV.F-2, and IV.F-3 for all state budgets except for the
SO2 budgets for the 15 states comprising the stringent
SO2 tier (``group 1''), which have different SO2
budgets in 2012 and 2013 than in 2014 and beyond.
    If EPA finalizes a remedy that uses the 2012 and 2013 variability
limits, EPA would also start applying the 3-year variability limits in
2014 (for all state budgets except group 1 SO2 budgets)
which would serve to limit each state's emissions in 2012 and 2013, in
the same way that starting the 3-year limits in 2016 would serve to
limit emissions in 2014 and 2015 under the proposed approach. The 3-
year variability limits would be the same as the 3-year limits for 2014
and later in Tables IV.F-1, IV.F-2, and IV.F-3.
    In this alternative approach, the 15 SO2 group 1 states,
which have different SO2 budgets in 2012 and 2013 than in
2014 and beyond, would be subject to different 1-year variability
limits in 2012 and 2013 than in later years. All of the group 1 states
have sufficiently large SO2 budgets in 2012 and 2013 that
the tonnage limit of 1,700 tons would not apply and the 1-year limits
would be 10 percent of the state SO2 budgets. The 2012 and
2013 1-year limits on SO2 emissions for these 15 states
under this alternative approach are shown later in Table IV.F-4.
    Additionally, commencing in 2013, EPA would apply in these 15
states a distinct 2-year average variability limit on SO2
emissions for the years 2012 and 2013. Analogous to the 3-year average
in subsequent years, this 2-year average limit would restrict average
variability in 2012 and 2013 more than the 1-year average alone. Table
IV.F-4 shows, for this alternative approach, 2-year variability limits
on SO2 emissions for 2012 and 2013 for the 15 group 1
states. For these states, the 3-year variability limits for later years
would be as shown in Tables IV.F-1, IV.F-2, and IV.F-3.
    For an alternative approach where variability limits start in 2012
instead of 2014, EPA considered--instead of two-year average limits on
SO2 emissions in the 15 group 1 states in 2012 and 2013--
applying 3-year average limits in these states starting in 2014. This
would be the same method as for all other state budgets under the
alternative where variability limits start in 2012. However, because
the 15 group 1 states have different SO2 budgets in 2012 and
2013 than in 2014 and beyond, calculation of the 3-year average limits
to apply in

years spanning the two budget levels is less straightforward. EPA
analyzed this alternative method for the 15 SO2 group 1
states and compared results to the results using the 2-year average
limits in 2012 and 2013 for these states, and determined that the 2-
year average approach is reasonable. See the Power Sector Variability
TSD for more information.
    Table IV.F-4 includes 1-year and 2-year variability limits
calculated according to the proposed methodology. The 2-year limits are
the 1-year limits divided by the square root of two. The table does not
include separate columns with variability limits calculated according
to the alternative calculation method (i.e., the method that adds a
ceiling based on the maximum percentage of variability in historic
data, described previously) because for the SO2 budgets in
Table IV.F-4 the alternative calculation method would yield identical
results to the proposed method. The Power Sector Variability TSD
contains more details on the variability limits.

   Table IV.F-4--2012-2013 One- and Two-Year Variability Limits on SO2
       Emissions for Group 1 States for Electric Generating Units
                                 [Tons]
------------------------------------------------------------------------
                                    SO2 annual                 Two-year
              State                 emissions      1-year      average
                                      budget       limit        limit
------------------------------------------------------------------------
Georgia..........................      233,260       23,326       16,494
Illinois.........................      208,957       20,896       14,775
Indiana..........................      400,378       40,038       28,311
Iowa.............................       94,052        9,405        6,650
Kentucky.........................      219,549       21,955       15,524
Michigan.........................      251,337       25,134       17,772
Missouri.........................      203,689       20,369       14,403
New York.........................       66,542        6,654        4,705
North Carolina...................      111,485       11,149        7,883
Ohio.............................      464,964       46,496       32,878
Pennsylvania.....................      388,612       38,861       27,479
Tennessee........................      100,007       10,001        7,072
Virginia.........................       72,595        7,260        5,133
West Virginia....................      205,422       20,542       14,526
Wisconsin........................       96,439        9,644        6,819
------------------------------------------------------------------------
1-year variability limits calculated by the proposed method are the
  larger of (1) 1,700 tons or (2) 10 percent of the state's budget. Two-
  year limits are the 1-year limits divided by the square root of two.
The alternative 1-year variability limit is 1,700 tons as long as that
  amount is between 10 and 28 percent of the state's budget. If 1,700
  tons is greater than 28 percent of the state's budget, the state's
  limit is set at 28 percent of its budget. If 1,700 tons is less than
  10 percent of the state's budget, the state's limit is set at 10
  percent of its budget. The alternative calculation method would yield
  identical limits to the limits determined using the proposed method
  for the budgets in Table IV.F-4, because for each of these budgets,
  1,700 tons is less than 10 percent of the budget.

3. Summary of Emissions Reductions Across All Covered States
    Table IV.F-5 presents projected power sector emissions in the base
case (i.e., without the proposed Transport Rule or CAIR) compared to
projected emissions with the proposed Transport Rule in 2012 and 2014
for all covered states. Table IV.F-6 presents 2005 historical power
sector emissions compared to projected emissions with the Transport
Rule in 2012 and 2014.

  Table IV.F-5--Projected SO2 and NOX Electric Generating Unit Emissions Reductions in Covered States With the
                       Transport Rule Compared to Base Case Without Transport Rule or CAIR
                                                 [Million tons]
----------------------------------------------------------------------------------------------------------------
                                                     2012                                   2014
                                     2012 base    transport       2012      2014 base    transport       2014
                                        case         rule      emissions       case         rule      emissions
                                     emissions    emissions    reductions   emissions    emissions    reductions
----------------------------------------------------------------------------------------------------------------
SO2...............................          8.4          3.4          5.0          7.2          2.6          4.6
Annual NOX........................          2.0          1.3          0.7          2.0          1.3          0.7
Ozone Season NOX..................          0.7          0.6          0.1          0.7          0.6         0.1
----------------------------------------------------------------------------------------------------------------
Note: Emissions differ from emissions budgets due to banking.

  Table IV.F-6--Projected SO2 and NOX Electric Generating Unit Emissions Reductions in Covered States With the
                                Transport Rule Compared to 2005 Actual Emissions
                                                 [Million tons]
----------------------------------------------------------------------------------------------------------------
                                                                  2012         2012         2014         2014
                                                 2005 actual   transport    emissions    transport    emissions
                                                  emissions       rule      reductions      rule      reductions
                                                               emissions    from 2005    emissions    from 2005
----------------------------------------------------------------------------------------------------------------
SO2............................................          8.9          3.4          5.5          2.6          6.3

Annual NOX.....................................          2.7          1.3          1.4          1.3          1.4
Ozone Season NOX...............................          0.9          0.6          0.3          0.6         0.3
----------------------------------------------------------------------------------------------------------------
Note: Emissions differ from emissions budgets due to banking.

G. How the Proposed Approach Is Consistent With Judicial Opinions
Interpreting Section 110(a)(2)(D)(i)(I) of the Clean Air Act

    The methodology described previously quantifies states' significant
contribution and interference with maintenance in a manner that is
consistent with the decisions of the DC Circuit. As discussed in
section III previously, the DC Circuit has issued two significant
decisions addressing the requirements of 110(a)(2)(D)(i)(I). The first
opinion largely upheld the NOX SIP Call, Michigan v. EPA,
213 F.3d 663 (DC Cir. 2000), and the second found significant flaws in
the CAIR, North Carolina v. EPA, 531 F.3d. 896 (DC Cir. 2008). In both
cases, the Court considered aspects of the methodology used by EPA to
identify emissions that, pursuant to section 110(a)(2)(D)(i)(I), must
be eliminated due to their impact on air quality in downwind states.
EPA believes that the methodology used in this proposed Transport Rule
is consistent with both opinions and rectifies the flaws the North
Carolina Court identified with the methodology used in CAIR. The
methodology used for this proposed rule relies on state-specific data
to analyze each individual state's significant contribution, uses air
quality considerations in addition to cost considerations to identify
each state's significant contribution, and gives independent meaning to
the ``interference with maintenance'' prong. This methodology is then
applied in a reasonable manner consistent with the relevant judicial
opinions.
    In North Carolina, the Court held that EPA's approach to evaluating
significant contribution was inadequate because, by evaluating only
whether emissions reductions were highly cost effective ``at the
regional level assuming a trading program'', it failed to conduct the
required state-specific analysis of significant contribution. See id.
at 907. EPA, the Court concluded, ``never measured the `significant
contribution' from sources within an individual state to downwind
nonattainment areas.'' Id. The Court did not, however, disturb the air-
quality-based methodology used by EPA to identify the states with
contributions large enough to warrant further consideration.
    For this proposed transport rule, EPA uses a first step similar to
that used in the CAIR to identify the states with relatively large
contributions. However, in contrast to the CAIR, it then uses a state-
specific analysis. Instead of identifying a single emissions level that
could be achieved by the application of highly cost effective controls
in the region, EPA determines, on a state-by-state basis what
reductions could effectively be achieved by sources in that state.
EPA's new approach does not, as the CAIR methodology did, establish a
regional cap on emissions that is then divided into state budgets that
set the emission reduction requirements for each state. Instead, EPA
develops, for each covered state, emissions budgets based on the
reductions achievable at a particular cost per ton in that particular
state, taking into account the need to ensure reliability of the
electric generating system. The selected cost/ton levels reflect
consideration of both cost factors and air quality factors including
the estimated impact of upwind states' emissions on each downwind
receptor.
    In addition, in developing this approach, EPA was guided by the
Court's holdings regarding the use of cost to identify significant
contribution. Specifically, the Court held in Michigan that EPA could
``in selecting the `significant' level of `contribution' under section
110(a)(2)(D)(i)(I), choose a level corresponding to a certain reduction
in cost.'' North Carolina, 531 F.3d at 917 (citing Michigan, 213 F.3d
at 676-77). This holding also supported the Court's conclusion in
Michigan that it was acceptable for EPA to apply a uniform cost-
criterion across states. See Michigan, 213 F.3d at 679. In the CAIR
case, the Court rejected EPA's analysis, not because it relied on cost
considerations to identify significant contribution, but because it
found that EPA had failed to draw the significant contribution line at
all. See North Carolina, 531 F.3d at 918 (``* * * here EPA did not draw
the [significant contribution] line at all. It simply verified sources
could meet the SO2 caps with controls EPA dubbed `highly
cost-effective.' ''). The holdings in Michigan regarding the use of
cost and a uniform cost-criterion across states were left undisturbed.
See, e.g., North Carolina, 531 F.3d at 917 (explaining that in Michigan
the Court held that ``EPA may `after [a state's] reduction of all [it]
could * * * cost-effectively eliminate[ ],' consider `any remaining
contribution insignificant' ''). In fact, the Court acknowledged that,
based on the Michigan holdings, the measurement of a state's
significant contribution need not ``directly correlate with each
state's individualized air quality impact on downwind nonattainment
relative to other upwind states.'' North Carolina, 531 F.3d at 908.
    For these reasons, EPA determined that it was appropriate in this
rulemaking to consider the cost of controls to determine what portion
of a state's contribution is its ``significant contribution.'' However,
EPA also heeded the North Carolina Court's warning that ``EPA can't
just pick a cost for a region, and deem `significant' any emissions
that sources can eliminate more cheaply.'' North Carolina, 531 F.3d at
918. Thus, in this rulemaking, EPA departs from the practice used in
the NOX SIP Call and in CAIR of evaluating, based solely on
the cost of control required in other regulatory environments, what
controls would be considered ``highly-cost-effective.'' Instead, as
part of its determination of a reasonable cost per ton for upwind state
control, EPA evaluates the air quality impact of reductions at various
cost levels and considers the reasonableness of possible cost
thresholds as part of a multi-factor analysis.
    In addition, the methodology used in this rulemaking gives
independent meaning to the interfere with maintenance prong of section
110(a)(2)(D)(i)(I). In North Carolina, the Court concluded that CAIR
improperly

``gave no independent significance to the `interfere with maintenance'
prong of section 110(a)(2)(D)(i)(I) to separately identify upwind
sources interfering with downwind maintenance.'' North Carolina, 531
F.3d at 910. EPA rectified this flaw in this rulemaking by separately
identifying downwind ``nonattainment sites'' and downwind ``maintenance
sites.'' EPA decided to consider upwind states' contributions not only
to sites that EPA projected would be in nonattainment, but also to
sites that, based on the historic variability of their emissions, EPA
determined may have difficulty maintaining the relevant standards. The
specific mechanism EPA used to implement this approach is described in
detail in section IV.C. previously. For annual PM2.5, this
approach identified 16 maintenance sites in addition to the 32
nonattainment sites identified in the analysis of nonattainment
receptors. For 24-hour PM2.5 this approach identified 38
maintenance sites in addition to the 92 nonattainment sites identified
in the analysis of nonattainment receptors. For ozone it identified 16
maintenance sites in addition to the 11 ozone nonattainment sites
identified.
    EPA applied this methodology using available information and data
to measure the emissions from states in the eastern United States that
significantly contribute to nonattainment or interfere with maintenance
in downwind areas with regard to the 1997 and 2006 PM2.5
NAAQS and the 1997 ozone NAAQS. Although EPA has not completely
quantified the total significant contribution of these states with
regard to all existing standards, EPA has determined, on a state-
specific basis, that the emissions prohibited in the proposed FIPs are
either part of or constitute the state's significant contribution and
interference with maintenance. Thus, elimination of these emissions
will, at a minimum, make measurable progress towards satisfying the
110(a)(2)(D)(i)(I) prohibition on significant contribution and
interference with maintenance.

H. Alternative Approaches Evaluated But Not Proposed

    EPA evaluated a number of alternative approaches to defining
significant contribution and interference with maintenance in addition
to the approach proposed in this rule. Stakeholders suggested a variety
of ideas. EPA considered all suggested approaches.
    EPA evaluated approaches including those based solely on air
quality, based solely on cost with a uniform cost in all states, based
on cost per air quality impact (e.g., $ per [mu]g/m\3\), and binning of
states based on air quality impact. Detailed descriptions of the
alternative approaches that EPA evaluated are in a TSD in the docket
titled ``Alternative Significant Contribution Approaches Evaluated.''
    EPA is not proposing any of the alternative approaches listed here.
However, the proposed approach (described in section IV.D) incorporates
some elements from these approaches.

V. Proposed Emissions Control Requirements

    This section describes the proposed emissions control requirements
in detail. The section starts with V.A which discusses the pollutants
included in the proposal, followed by V.B which discusses the source
categories covered. Section V.C discusses the timing of the proposed
emissions control requirements. Section V.D describes the proposed
approach to implement the emission reduction requirements, starting
with a description of the NOX SIP Call and CAIR approaches
to implementing reductions and the judicial opinions on those
approaches, then describing in detail the proposed ``remedy'' (State
Budgets/Limited Trading) for FIPs that would implement the emissions
reductions, and explaining the structure and key elements of the
proposed Transport Rule trading program rules for State Budgets/Limited
Trading. Section V.D also describes two alternative remedies on which
EPA requests comment. Section V.E presents projected costs and
emissions for each remedy option. Section V.F discusses the transition
from the CAIR cap and trade programs to the proposed Transport Rule
programs. Section V.G discusses interactions of the proposed programs
with the existing Title IV and NOX SIP Call programs.

A. Pollutants Included in This Proposal

    In this action, EPA is proposing FIPs to directly regulate upwind
emissions of SO2 and NOX because of their impact
on downwind states' ability to attain and maintain the PM2.5
NAAQS. EPA is also proposing to regulate upwind emissions of
NOX because of their impact on 8-hour ozone attainment and
maintenance in downwind states. Our rationale for regulating these
precursor pollutants is discussed in section IV.B. In this section, we
also explain the regulatory mechanism we are proposing to use to
regulate these pollutants and take comment on two alternative options.

B. Source Categories

    EPA is proposing to require emissions reductions from the power
sector. This section discusses EPA's rationale for proposing to control
power sector emissions, and our rationale for not proposing to control
emissions from other source categories at this time.
1. Propose To Control Power Sector Emissions
    The proposed Transport Rule FIPs would require EGUs with capacity
greater than 25 MWe in the covered states to reduce emissions of
SO2, NOX, and ozone season NOX. See
section V.D.4., later, for a detailed description of the proposed
applicability requirements.\77\
---------------------------------------------------------------------------

    \77\ Certain non-EGUs and smaller EGUs were included in the CAIR
NOX ozone season program in some CAIR states. EPA
proposes that such units would not be covered by the Transport Rule
requirements; see section V.F in this preamble for further
discussion of these units.
---------------------------------------------------------------------------

    Electric generating units are important sources of SO2
and NOX emissions. In 2012, considering other controls that
will be in place, EPA projects that if a Transport Rule is not
implemented, EGUs would emit more than 70 percent of the total man-made
SO2 emissions and about 20 percent of the total man-made
NOX emissions in the group of 32 states that would be
affected by this rule (see Table III.A-1 in section III for lists of
states).\78\
---------------------------------------------------------------------------

    \78\ Emissions estimates are based on the 2012 baseline
projections described in section IV in this preamble.
---------------------------------------------------------------------------

    EPA has previously conducted extensive analyses of the cost and
emissions impacts of SO2 and NOX reduction
policies on the power sector using the Integrated Planning Model (IPM).
Examples include EPA's IPM analyses of a number of multi-pollutant
bills, including the Clean Air Planning Act (S. 843 in 108th Congress),
the Clean Power Act (S. 150 in 109th Congress), the Clear Skies Act of
2005 (S. 131 in 109th Congress), the Clear Skies Act of 2003 (S. 485 in
108th Congress), and the Clear Skies Manager's Mark (of S. 131). EPA
also analyzed several power sector multi-pollutant scenarios in July
2009 at the request of Senator Tom Carper. These analyses are on EPA's
Web site at: (http://www.epagov/airmarkets/progsregs/cair/multi.html).
EPA's IPM analysis for CAIR is another example: (http://www.epagov/
airmarkets/progsregs/epa-ipm/cair/index.html).
    Based on these analyses, EPA believes that there exist reasonable
means for EGUs to make substantial reductions in emissions of
SO2 and NOX. EPA also believes that, at this
time, EGUs can

reduce SO2 and NOX emissions more cost-
effectively than other source categories (see section IV.D for
discussion of control costs for non-EGU source categories). For these
reasons, EPA has decided to require reductions in SO2 and
NOX emissions from EGUs in the FIPs in this proposed rule.
EPA requests comments on these proposed FIPs and its proposal to
require reductions from EGUs.
2. Other Source Categories Are Not Included
    In these proposed FIPs, EPA is not proposing to include emission
reduction requirements for sources other than EGUs.\79\
---------------------------------------------------------------------------

    \79\ See section IV.D.3 for discussion of non-EGUs that were
included in the CAIR NOX ozone season trading program.
---------------------------------------------------------------------------

a. Why EPA Does Not Require Reductions From Other Source Categories To
Address Transport Requirements for PM2.5
    In the proposed FIPs to address the section 110(a)(2)(D)(i)(I)
requirements with respect to the 1997 and 2006 PM2.5
standards, EPA proposes to regulate only emissions from EGUs. As
discussed previously in section IV.D, EPA's review of the costs of EGU
and non-EGU controls resulted in a conclusion that substantial
SO2 and NOX reductions from EGUs are available at
a cost per ton that is lower than the cost per ton of non-EGU controls.
Other analyses discussed in section IV.D demonstrated that these EGU
reductions are sufficient to eliminate the quantity of emissions
identified by EPA as significantly contributing to or interfering with
maintenance of the 1997 PM2.5 NAAQS in downwind areas. This
same section explains that EGU reductions substantially address
eliminating the quantity of emissions identified by EPA as
significantly contributing to or interfering with maintenance of the
2006 PM2.5 NAAQS, and this same section explains the need
for EPA to further analyze remaining winter PM2.5
exceedances. This conclusion does not, in any way, address whether a
FIP promulgated by EPA or SIPs promulgated by the states should include
reductions from non-EGU sources in order to eliminate significant
contribution and interference with maintenance for any other NAAQS,
including the 1997 ozone NAAQS and future NAAQS for PM2.5.
b. Why EPA Does Not Propose To Require Reductions From Other Source
Categories To Address Transport Requirements for Ozone
    In the FIPs for this proposed rule, EPA is only proposing to
require reductions from EGUs to address emissions from those source
categories that significantly contribute to or interfere with
maintenance of the 1997 ozone NAAQS. As discussed previously in section
IV.D, EPA's review of the costs of EGU and non-EGU controls resulted in
a conclusion that significant NOX emissions reductions from
EGU are available at a cost per ton that is lower than the cost per ton
of non-EGU NOX controls. The same section also explains the
need for EPA to further analyze whether fully addressing upwind state
responsibilities to reduce NOX emissions that contribute to
downwind nonattainment and maintenance problems requires additional
reductions at higher cost per ton, which again would involve analysis
of potential EGU and non-EGU reductions and costs. EPA will be moving
forward to complete its assessment of pollution transport for the 1997
ozone NAAQS as soon as possible.
    For future ozone and PM2.5 NAAQS, EPA intends to
quantify the emissions reductions needed to satisfy the requirements of
110(a)(2)(D)(i)(I) with respect to those NAAQS. EPA has not made any
determinations or assessments regarding whether reductions from source
categories other than EGUs will be needed to achieve the necessary
reductions in each state.

C. Timing of Proposed Emissions Reduction Requirements

    EPA is proposing an initial phase of reductions in 2012 followed by
a second phase in 2014. Sources will be required to comply with the
annual SO2 and NOX requirements by January 1,
2012 and January 1, 2014 for the first and second phases, respectively.
Similarly, sources will be required to comply with the ozone season
NOX requirements by May 1, 2012, and by May 1, 2014. EPA
chose these dates to coordinate with the NAAQS attainment deadlines and
to assure that reductions are made as expeditiously as practicable, as
described later in this section. This section also discusses how the
compliance deadlines address the Court's concern about timing.
Additionally, this section explains that EPA will consider additional
reductions to address the NAAQS in the future.
1. Date for Prohibiting Emissions That Significantly Contribute or
Interfere With Maintenance of the PM2.5 NAAQS
    For all areas designated as nonattainment with respect to the 1997
PM2.5 NAAQS, the SIP deadline for attaining that standard
must be as expeditious as practicable but no later than April 2010,
with a possible extension to no later than April 2015. Many areas have
already come into attainment by the April 2010 deadline due in part to
reductions achieved under CAIR. Because the 2010 deadline will have
passed before the Transport Rule is finalized, we decided to coordinate
the deadline for eliminating significant contribution under this rule
with respect to the 1997 PM2.5 NAAQS with the April 2015
deadline that applies to areas that will need an extension of the April
2010 deadline. For all areas designated as nonattainment with respect
to the 2006 24-hour PM2.5 NAAQS, the attainment deadline
must be as expeditious as practicable but no later than December 2014
with a possible extension to as late as December 2019.\80\
---------------------------------------------------------------------------

    \80\ Section 172(a)(2) of the Clean Air Act provides that ``the
attainment date for an area designated nonattainment with respect to
a national primary ambient air quality standard shall be the date by
which attainment can be achieved as expeditiously as practicable,
but no later than 5 years from the date such area was designated
nonattainment under section 7407(d) of this title, except that the
Administrator may extend the attainment date to the extent the
Administrator determines appropriate, for a period no greater than
10 years from the date of designation as nonattainment, considering
the severity of nonattainment and the availability and feasibility
of pollution control measures.'' Designations for the 2006 24-hour
PM2.5 NAAQS became effective on December 14, 2009.
---------------------------------------------------------------------------

    Upwind emissions reductions achieved by the 2014 emissions year
will help areas that failed to meet the April 2010 deadline, to meet
the April 2015 deadline for the 1997 PM2.5 NAAQS. These
reductions will also help areas meet the December 2014 attainment
deadline with respect to the 2006 PM2.5 NAAQS. Any areas not
meeting that deadline can request a 5-year extension to December 2019.
    Further, a deadline of January 1, 2014 also provides adequate and
reasonable time for sources to plan for compliance with the Transport
Rule and install any necessary controls. EPA believes that this
deadline is as expeditious as practicable for the installation of the
controls needed for compliance (see further discussion in section
IV.D).

2. Date for Prohibiting Emissions That Significantly Contribute or
Interfere With Maintenance of the 1997 Ozone NAAQS
    Ozone nonattainment areas must attain permissible levels of ozone
``as expeditiously as practicable,'' but no later than the date
assigned by EPA in the ozone implementation rule (40 CFR part 51). The
areas designated nonattainment in 2004 with respect to the 1997 8-hour
ozone NAAQS in the eastern United States were assigned maximum
attainment dates corresponding to the end of the 2006, 2009, and 2012
ozone seasons. Many areas have already attained due in part to CAIR,
federal mobile source standards, and other local, state, and federal
measures. Those that have not yet attained the standard have maximum
attainment dates ranging from 2010 (these are the 2009 areas that have
been granted a 1-year extension due to clean data in 2009) to 2018.
Areas designated ``serious'' nonattainment areas have a June 2013
maximum attainment deadline. The proposed Transport Rule's first phase
of reductions in 2012 will help the remaining areas with June 2013
maximum attainment deadlines attain the 1997 8-hour ozone NAAQS by
their deadline. The reductions will also improve air quality in areas
with later deadlines.
3. Reductions Required by 2012 To Ensure That Significant Contribution
and Interference With Maintenance Are Eliminated as Expeditiously as
Practicable
    EPA is requiring an initial phase of reductions by 2012. These
reductions are necessary to ensure that significant contribution and
interference with maintenance are eliminated as expeditiously as
practicable. This will in turn assist downwind states to achieve
attainment as expeditiously as practicable as required by the CAA.
    Because the proposed rule, if finalized, will replace the CAIR, EPA
cannot assume that after this rule is finalized, EGUs would continue to
emit at the reduced emissions levels achieved by CAIR. Instead, it is
the emissions reductions requirements in the proposed FIPs that will
determine the level of EGU emissions in the eastern United States. For
these reasons, EPA is proposing to require an initial phase of
reductions by 2012 which would ensure that existing and planned
SO2 and NOX controls operate as anticipated.
4. How Compliance Deadlines Address the Court's Concern About Timing
    As directed by the Court in North Carolina v. EPA, 531 F.3d 896 (DC
Cir. 2008), and described previously, EPA has established the
compliance deadlines in the proposed rule based on the respective NAAQS
attainment requirements and deadlines applicable to the downwind
nonattainment and maintenance sites.
    The 2012 deadline for compliance with the limits on ozone-season
NOX emissions is coordinated with the June 2013 maximum
attainment deadline for serious ozone nonattainment areas (taking into
account the need for reductions by 2012 to demonstrate attainment by
that date). This deadline is also consistent with the requirement that
states attain the NAAQS as expeditiously as practicable.
    The 2014 deadline for compliance with the limits on annual
NOX and annual SO2 emissions is coordinated with
the April 2015 maximum attainment deadline for areas that received the
maximum 5-year extension of the 5-year attainment deadline for the 1997
PM2.5 NAAQS (taking into account the need for reductions by
2014 to demonstrate attainment by April 2015). This 2014 compliance
deadline is also consistent with December 2014 attainment deadline (5
years from designation, in the absence of an extension) for areas
designated nonattainment for the 2006 PM2.5 NAAQS. Areas
unable to meet this 2014 deadline may seek a maximum 5-year extension
to 2019.
    In addition, the 2012 compliance deadline for the first-phase of
annual NOX and annual SO2 emissions reductions
will assure the reductions are achieved as expeditiously as
practicable. EPA established the interim 2012 compliance deadline for
annual NOX and annual SO2 reductions because a
significant number of reductions can be achieved by 2012. However,
given the time needed to design and construct scrubbers at a large
number of facilities, EPA believes the 2014 compliance date is as
expeditious as practicable for the full quantity of SO2
reductions necessary to fully address the significant contribution and
interference with maintenance. Requiring reductions in transported
pollution as expeditiously as practicable, as well as within maximum
deadlines, helps to promote attainment as expeditiously as practicable.
This is consistent with statutory provisions that require states to
adopt SIPs that provide for attainment as expeditiously as practicable
and within the applicable maximum deadlines.
5. EPA Will Consider Additional Reductions in Pollution Transport To
Assist in Meeting Any Revised or New NAAQS
a. Ozone
    As noted, in a January 19, 2010, notice of proposed rulemaking, EPA
proposed to strengthen the NAAQS for ozone. In that notice, EPA
proposed levels for the ozone standard to a level within the range of
0.060 to 0.070 parts per million. EPA also proposed in this same notice
to establish a distinct cumulative, seasonal ``secondary'' standard,
designed to protect sensitive vegetation and ecosystems, including
forests, parks, wildlife refuges and wilderness areas.\81\
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    \81\ This proposed cumulative, seasonal standard is expressed as
an annual index of the sum of weighted hourly concentrations,
cumulated over 12 hours per day (8 a.m. to 8 p.m.) during the
consecutive 3-month period within the O3 season with the
maximum index value, set at a level within the range of 7 to 15 ppm-
hours.
---------------------------------------------------------------------------

    EPA expects to finalize the revised NAAQS for ozone in August 2010.
After the NAAQS are finalized, EPA will be able to identify areas that
are expected to have difficulty attaining and maintaining those
standards and will evaluate and analyze the impact of upwind state
emissions in those areas with regard to those standards. EPA has
already begun the technical background work necessary to allow it to
move quickly, once the revised ozone standards are promulgated, with a
proposal to address upwind emissions that significantly contribute to
nonattainment of or interfere with maintenance of those standards.
Because that analysis will take some time, and because EPA recognizes
the urgency of responding to the concerns raised by the Court in North
Carolina v. EPA, EPA intends to address the requirements of
110(a)(2)(D)(i)(I) with respect to the revised ozone standards in a
subsequent proposal. Addressing the 110(a)(2)(D)(i)(I) requirements for
the new NAAQS shortly after promulgation of those NAAQS would help
clarify the requirements related to transported emissions before
downwind state nonattainment SIPs are due. In doing so, the transport
rule would aid downwind states in developing plans for attaining and
maintaining the new NAAQS.
b. Fine Particles
    EPA is also on a schedule to review and, if necessary update the
PM2.5 NAAQS. This review is scheduled for completion in
October 2011. EPA plans

to conduct background technical analyses so that EPA will be prepared
to move quickly, if necessary, with a transport rule related to any
revised PM2.5 NAAQS.

D. Implementing Emissions Reductions Requirements

    In this rule, EPA is proposing FIPs to eliminate the significant
contribution and interference with maintenance EPA has identified in
this action. We are proposing one ``remedy'' option to implement the
necessary emissions reductions and taking comment on two other options.
Before presenting these options we briefly summarize the approaches
used in the NOX SIP Call and CAIR.
1. Approaches Taken in NOX SIP Call and CAIR
    In the NOX SIP Call and CAIR, EPA developed emissions
trading programs as possible remedies to 110(a)(2)(D)(i)(I) SIP
deficiencies. States covered by the rules were given the option of
joining the trading programs and EPA determined that, by doing so, they
would satisfy the requirements of 110(a)(2)(D)(i)(I) with respect to
specific NAAQS. The NOX SIP Call provided an ozone-season
NOX trading program and addressed the requirements of the
ozone NAAQS only. The CAIR provided SO2, annual
NOX, and ozone-season NOX trading programs, and
addressed both the 1997 ozone and the 1997 PM2.5 NAAQS.
    NOX SIP Call approach. The NOX SIP Call proposed a
regional cap and trade program as a way to make cost-effective
NOX reductions. Created after years of scientific research
and air quality data analyses showed that upwind NOX
emissions can contribute significantly to ozone nonattainment in
downwind states, the NOX Budget Trading Program (NBP)
followed several other major efforts to reduce NOX from
large, stationary sources. These initiatives included the Acid Rain
Program, OTC NOX Budget Program, New Source Review, New
Source Performance Standards, application of Reasonably Available
Control Technology to existing sources, and other state efforts.
    By notice dated October 27, 1998 (63 FR 57356), EPA took final
action to require states to prohibit specified amounts of emissions of
one of the main precursors of ground-level ozone, NOX, in
order to reduce ozone transport across state boundaries in the eastern
half of the United States. EPA found that sources in 23 states emit
NOX in amounts that significantly contribute to
nonattainment of the 1-hour ozone NAAQS in downwind states. EPA set
forth requirements for each of the affected upwind states to submit SIP
revisions prohibiting those amounts of NOX emissions that
significantly contribute to downwind air quality problems. EPA
established statewide NOX emissions budgets for the affected
states. States had the flexibility to adopt the appropriate mix of
controls for their state to meet the NOX emissions
reductions requirements of the SIP call.
    In the final regulation, EPA offered to administer a multi-state
NOX Budget Trading Program for states affected by the
NOX SIP Call. The NOX Budget Trading Program was
an ozone season (May 1 to September 30) cap and trade program for EGUs
and large industrial combustion sources, primarily boilers and
turbines. The program used a regionwide cap for ozone season
NOX emissions. The cap was the sum of the state emissions
budgets established by EPA under the NOX SIP Call regulation
to help states meet their SIP obligations. Authorizations to emit,
known as allowances, were allocated to affected sources based on state
trading budgets. The NOX allowance market enabled sources to
trade (buy and sell) allowances throughout the year. Sources could
reduce NOX emissions in any manner. Options included adding
emissions control technologies, replacing existing controls with more
advanced technologies, optimizing existing controls, or switching
fuels. At the end of every ozone season, each source surrendered
sufficient allowances to cover its ozone season NOX
emissions (each allowance represents one ton of NOX
emissions). This process is called annual reconciliation. If a source
did not have enough allowances to cover its emissions, EPA
automatically deducted allowances from the following year's allocation
at a 3:1 ratio. If a source had excess allowances because it reduced
emissions beyond required levels, it could sell the unused allowances
or bank (save) them for use in a future ozone season. To accurately
monitor and report emissions, sources use continuous emission
monitoring systems (CEMS) or other approved monitoring methods under
EPA's stringent monitoring requirements (Title 40 of the Code of
Federal Regulations [CFR], Part 75).
    The NOX SIP Call cap and trade program was a way to make
cost-effective NOX reductions. Under the NOX SIP
Call, states had the flexibility to determine the mix of controls to
meet their emissions reductions requirements. However, the rule
provides that if the SIP controls EGUs, then the SIP must establish a
budget, or cap, for EGUs. The EPA recommended that each state authorize
a trading program for NOX emissions from EGUs. Each of the
states required to submit a NOX SIP under the NOX
SIP Call chose to adopt the cap and trade program regulating large
boilers and turbines. Each state based its cap and trade program on a
model rule developed by EPA. Some states essentially adopted the full
model rule as is, while other states adopted the model rule with
changes to the sections that EPA specifically identified as areas in
which states may have some flexibility. The NOX SIP Call cap
and trade program, modeled closely after the OTC NOX Budget
Program, was phased in starting in 2003 for the OTC states, with the
majority of affected states participating as of 2004.
    CAIR Approach. In May 2005, EPA promulgated CAIR to address
emissions in 28 states and the District of Columbia that it found
contribute significantly to nonattainment of the 1997 PM2.5
and 8-hour ozone NAAQS in downwind states. The EPA required these
upwind states to revise their SIPs to include control measures to
reduce emissions of SO2 and/or NOX. Reducing
upwind precursor emissions helps the downwind PM2.5 and 8-
hour ozone nonattainment areas achieve the NAAQS. Moreover, reducing
upwind emissions makes it possible for attainment to be achieved in a
more equitable, cost-effective manner than if each nonattainment area
attempted to achieve the NAAQS by implementing local emissions
reductions alone.
    In CAIR, EPA offered states optional regionwide cap and trade
programs, which were similar to the SO2 trading program in
Title IV of the CAA and the NOX Budget Trading Program in
the NOX SIP Call. CAIR required implementation of emissions
reductions requirements for SO2 and NOX in two
phases. The first phase of NOX reductions started in 2009
(covering 2009-2014) and the first phase of SO2 reductions
began in 2010 (covering 2010-2014); the second phase of reductions for
both NOX and SO2 would start in 2015 (covering
2015 and thereafter). The required emissions reductions requirements
are based on controls that are known to be highly cost effective for
EGUs. CAIR also included model rules for multi-state cap and trade
programs for annual SO2 and NOX emissions for
PM2.5, and seasonal NOX emissions for ozone, that
states could choose to adopt to meet the required emissions reductions
in a flexible and cost-effective manner. The CAIR provided for the
NOX SIP Call cap and trade program to be replaced by the

CAIR ozone season NOX trading program.
    The U.S. Court of Appeals granted several petitions for review of
the CAIR and remanded the rule to EPA. Because the Court decided to
remand the rule without vacatur, however, CAIR remains in effect. This
proposed rule would replace the CAIR upon final promulgation.
2. Judicial Opinions
    Challenges to both the NOX SIP Call and the CAIR were
brought before the U.S. Court of Appeals for the DC Circuit. In
Michigan v. EPA, 213 F.3d 663, the Court largely upheld the
NOX SIP Call. The portion of this opinion most directly
related to the remedy selected by EPA, discusses EPA's decision to
utilize a uniform control strategy. The Court rejected two specific
challenges to the requirement that ``all covered jurisdictions,
regardless of amount of contribution, reduce their NOX by an
amount achievable with ``highly cost-effective controls.'' Id. at 679.
EPA's approach, Petitioners first alleged, was irrational because it
did not take into account differences in individual states'' respective
contributions to downwind nonattainment. Both small and large
contributors were required to make reductions achievable by the
application of highly cost effective controls. The court rejected this
challenge finding that this result ``flows ineluctably from EPA's
decision to draw the `significant contribution' line on the basis of
cost differentials.'' Id.
    Petitioners' second objection to the use of uniform controls was
that it failed to take into account the fact that the location of
emissions reductions may affect the impact of those reductions on
downwind nonattainment areas. Petitioners argued that because
reductions closer to the nonattainment area have a greater benefit,
EPA's use of a highly-cost-effective standard and region-wide emissions
trading did not guarantee that it would have secured the rule's health
benefits at the lowest cost. See id. The Court rejected this challenge
also, giving deference to EPA's judgment that non-uniform regional
approaches would not `` `provide either a significant improvement in
air quality or a substantial reduction in cost.' '' Id. (quoting 63 FR
57423).
    Petitioners challenging the CAIR also raised issues related to
EPA's use of an interstate trading program to satisfy the requirements
of section 110(a)(2)(D)(i)(I). Petitioners challenged both the trading
program itself and the state budgets. These budgets were used to
determine the number of emission allowances allocated to sources in
each state or, if the state chose not to participate in the trading
programs, the specific emission reduction requirements for that state.
    The Court concluded, in North Carolina v. EPA, 531 F.3d 896, that
EPA had not demonstrated that the 110(a)(2)(D)(i)(I) remedy promulgated
in CAIR would effectuate the statutory mandate of section
110(a)(2)(D)(i)(I) and promote the goal of prohibiting contributing
sources within one state from contributing to nonattainment in another
state. In reaching this conclusion, the Court emphasized that EPA had
not adequately measured each individual state's significant
contribution. See id. at 908. (``It is unclear how EPA can assure that
the trading programs it has designed in CAIR will achieve section
110(a)(2)(D)(i)(I)'s goals if we do not know what each upwind state's
``significant contribution'' is to another state.'')
    The Court also emphasized that section 110(a)(2)(D)(i)(I)
``prohibits sources `within the State' from `contribut[ing]
significantly to nonattainment in * * * any other State * * *' '' Id.
at 907. (quoting section 110(a)(2)(D)(i)(I) and adding emphasis). While
recognizing that it was ``possible that CAIR would achieve section
110(a)(2)(D)(i)(I)'s goals'' it concluded that ``CAIR assures only that
the entire region's significant contribution will be eliminated,'' and
that ``EPA is not exercising its section 110(a)(2)(D)(i)(I) duty unless
it is promulgating a rule that achieves something measurable toward the
goal of prohibiting sources ``within the State'' from contributing to
nonattainment or interfering with maintenance ``in any other State.''
Id. at 907. Furthermore, since CAIR was designed as a ``complete remedy
to section 110(a)(2)(D)(i)(I) problems'' the Court emphasized that ``it
must actually require elimination of emissions from sources that
contribute significantly and interfere with maintenance.'' Id. at 908.
In doing so, however, the Court also acknowledged that it had accepted
in Michigan v. EPA, 213 F.3d 663 (D.C. Cir. 2000) EPA's decision to
apply uniform emissions controls and its consideration of cost in the
definition of significant contribution. See North Carolina, 531 F.3d at
908.
    In developing options to eliminate the emissions identified as
constituting all or part of a state's significant contribution and
interference with maintenance, EPA has been mindful of the direction
provided by the Court. As discussed in greater detail later, EPA
believes that each of the remedy options presented is consistent with
the Court's opinions interpreting the requirements of section
110(a)(2)(D)(i)(I).
3. Remedy Options Overview
    EPA is proposing one ``remedy'' option to implement the emissions
reductions requirements and taking comment on two alternatives. This
section provides a brief overview of the proposed remedy and the two
alternatives. Sections V.D.4, V.D.5, and V.D.6, later, describe the
proposed remedy and the alternatives in detail.
    EPA considered a full range of remedy options in developing this
proposal. Among other things, EPA considered variations of direct
control options, intrastate cap and trade, interstate cap and trade,
hybrids of these approaches, and simple state emissions caps.
Stakeholders have suggested a variety of remedy options for EPA's
consideration. A TSD in the docket entitled ``Other Remedy Options
Evaluated'' describes other options that EPA evaluated.
    Based on its consideration of a range of options, EPA is proposing
one remedy option and requesting comment on two alternatives. The
proposed remedy option, discussed later, is a hybrid approach that
combines limited interstate trading with other requirements. The
alternative remedies on which EPA requests comment include an
intrastate trading option and a direct control option. The proposed and
alternative remedy options would regulate SO2 and
NOX emissions from EGUs through FIPs in the covered states
to eliminate or address the states'' significant contribution to
nonattainment in, or interference with maintenance by, downwind areas
with respect to the daily and annual PM2.5 NAAQS and the 8-
hour ozone NAAQS.
    The remedy option EPA is proposing would use state-specific control
budgets and allow for intrastate and limited interstate trading of
emissions allowances allocated to EGUs. This approach would assure
environmental results while providing some limited flexibility to
covered sources consistent with the Court decision as described later.
The approach would also help ease the transition for implementing
agencies and covered sources from CAIR to the Transport Rule. Based on
consideration of a range of options, EPA believes that the proposed
option is the best approach, for the reasons discussed in section
V.D.4.
    The Agency is also presenting other alternative remedies for
comment. The first alternative for which EPA requests comment would use
state-specific control budgets and allow intrastate trading of
emissions allowances allocated to EGUs, but no interstate

trading. The second alternative for which EPA requests comment is a
direct control program in combination with state-specific control
budgets.
    EPA recognizes there could be cost savings from an approach that
uses aless restrictiveinterstate trading option. EPA also recognizes
that unrestricted trading programs including the NOX SIP
Call Trading Program have been very successful in addressing regional
pollution problems.
    In this action, EPA is not proposing such an unrestricted trading
program, because EPA does not believe that such an option could provide
assurance that each state achieves emissions reductions within the
state, as required by the North Carolina decision. As the D.C. Circuit
emphasized in its opinion, the statutory requirement in section
110(a)(2)(D)(i)(I) aims to prohibit ``sources ``within the State'' from
contributing to nonattainment or interfering with maintenance in ``any
other State.'' North Carolina, 531 F.3d at 908. The location of
emission reductions is relevant because it can influence where air
quality improvements occur and whether a particular state meets its
statutory obligations. See North Carolina, 531 F.3d at 907.
    In addition to considering unrestricted trading, EPA also
considered whether there were other ways that a trading program could
be structured to address the Court's concerns. In particular, EPA
reviewed a methodology that had been investigated during the
development of the NOX SIP Call regulation that used trading
ratios (``Development and Evaluation of a Targeted Emission Reduction
Scenario for NOX Point Sources in the Eastern United States:
An Application of the Regional Economic Model for Air Quality
(REMAQ)'', Prepared by Stratus Consulting inc. November 24, 1999) (at
http://www.epagov/airtransport). This approach would allow interstate
trading, but use trading ratios to take into account differences in the
cumulative downwind impact of emissions from different states. Trading
ratios would be developed for each pair of states using air quality
modeling such that, given the meteorological assumptions underlying the
air quality modeling, the ratios would represent the ratio of the
benefit to downwind air quality within a region from controlling
emissions in different upwind areas. For instance, in its simplest
form, if emission reductions from State A were twice as effective at
reducing cumulative downwind air quality impact on a set of downwind
receptors as emission reductions from State B, the trading ratio
between States A and B would be 2 to 1.\82\ In other words, if the
States chose to trade, State A would have to purchase 2 allocations
from State B to cover 1 ton of State A's emissions, since State A's
emissions have twice the impact on downwind air quality. Such an
approach offers the very valuable potential to address the transport
problem in an effective (and potentially less costly) manner, as it
incentivizes reductions from the places where they have the greatest
value in reducing downwind air quality problems. While it offers such
opportunities, there are challenges in developing such a system that is
consistent with the requirement under section 110(a)(2)(D) that
emission reductions occur in particular geographic locations. The
trading ratio approach would be designed to assure a cumulative
downwind air quality result, not to assure specific upwind reductions.
Although it would reduce the incentive for sources from upwind states
with larger cumulative impacts to comply by purchasing allowances
(since they would need to purchase a greater number of allowances per
ton emitted than sources in states with less of an impact), as
currently contemplated it would not be possible under this approach to
include enforceable legal requirements to ensure that a specific
state's emissions remain below a specified level or to ensure that a
specific amount of reductions occur within a particular state. EPA
specifically requests comment on whether a ratios trading program could
be designed to provide such a legal assurance. We also seek comment on
whether such an assurance would be needed if, for example, in practice
modeling results predicted with confidence that sufficient state-by-
state reductions would be achieved under such an approach.
---------------------------------------------------------------------------

    \82\ Note that the report evaluating this alternative was a
theoretical economic and air quality analysis of the concept. It did
not explore how trading ratios would be incorporated into a workable
trading program. It did however indicates that the ``approach also
provides for the possibility that the emission weights developed by
this analysis could be incorporated into an emission trading program
in which emission weights act like exchange rates between different
subregions and species. However this adds a significant increase in
the complexity of the market and in practical terms is worth
considering only when the potential cost savings are large enough to
offset the additional complexity in market structure.'' P. 1-7,
Stratus Consulting Inc. November 24, 1999.
---------------------------------------------------------------------------

    In the SIP Call, EPA did not ultimately propose this methodology
for several reasons. First, the Stratus Consulting study (``Development
and Evaluation of a Targeted Emission Reduction Scenario for
NOX Point Sources in the Eastern United States: An
Application of the Regional Economic Model for Air Quality (REMAQ)'')
estimated that the most significant cost savings occurred from moving
from a uniform direct control approach to a conventional cap-and-trade
approach (the study suggested that this would lead to cost savings of
approximately 25 percent). Adding trading ratios added significant
complexity while only very slightly lowering costs (1 percent to 5
percent compared to conventional cap and trade, where the cost savings
decreased as the problem being addressed became more widespread (e.g.
cost savings for the more stringent 1997 8 hour ozone NAAQS standard
would be less than cost savings for the less stringent early 1 hour
standard)) (Stratus, page s-2). However, because the transport rule is
a larger program covering multiple pollutants with a different set of
non-attainment areas and a broader geographic scope, there is the
potential for greater cost savings. Second, the trading ratios are
dependent upon the meteorological assumptions used to develop them; to
the extent that future year meteorology or costs turn out to be
different, the trading ratios could in fact lead to less than predicted
downwind air quality benefits. Notably in reality, the ratios would
have to consider that the upwind states that impact a downwind receptor
vary from receptor to receptor; conversely each upwind state
contributes to different sets of downwind receptors. It would be very
challenging to develop trading ratios that account for this myriad of
different relationships. EPA believes these concerns are also valid in
the context of this Transport Rule.
    In addition, in considering this approach in the original SIP Call,
it took close to a year to perform the underlying analysis to develop
ratios for 1 pollutant (NOX) and one downwind air quality
problem (ozone). In this context, there are 3 pollutants (annual
NOX, annual SO2 and ozone season NOX)
and two downwind air quality problems (ozone and PM2.5) to
consider.
    EPA requests comment on the trading ratios approach, including
whether: The trading ratio approach described above would be consistent
with the Court opinion in North Carolina v. EPA and satisfy the section
110(a)(2)(D) requirement that reductions occur ``within the state'';
there are ways the approach could be modified to be consistent with the
Court opinion and the statutory requirement; there are ways that such
an approach could administratively be put in place by 2012 and be
modified and adopted if further reductions are required to address

future NAAQS; and on whether there are ways that such a system could be
designed to be transparent and relatively simple for sources to
understand and comply with.
    Analysis from the SIP Call suggests that the trading ratios
approach might have the potential to slightly reduce costs. However,
the approach, as envisioned, appears to be in tension with EPA's
mandate under section 110(a)(2)(D)(i)(I) to assure that significant
contribution is fully addressed in each upwind state. While such an
approach would ensure reductions on a region-wide basis, EPA has not
been able to identify a way that the trading ratio approach could be
modified to assure a specific set of downwind emissions reductions from
all states. Under such an approach, there is the potential that some
upwind states might make reductions that are larger than their
significant contribution, while other states might make reductions that
are less than their significant contribution. Because the state budgets
have been designed to achieve all reductions available at a given cost,
trading ratios other than one to one, although providing equivalent
improvements in downwind air quality would lead to emissions reductions
that were inconsistent with the initial budgets.\83\
---------------------------------------------------------------------------

    \83\ EPA, however, has proposed variability limits to these
budgets, and it is possible a ratios approach may imply emissions
would fall within the variability limits if the ratios ultimately
turned out to be close to one-to-one.
---------------------------------------------------------------------------

    Because EPA recognizes the potential cost savings and potential
improvements in program effectiveness associated with less restricted
trading options, EPA is also requesting comment on the appropriateness
of the assurance provisions that have been proposed, including whether
they are adequate to assure that significant contribution and
interference with maintenance are addressed in each state, whether they
are overly restrictive, and whether there are less restrictive options
that would provide adequate assurance that the statutory mandate is
satisfied while providing more flexibility. Alternative approaches
could potentially include: Using the basic methodology proposed with a
higher or lower variability limitation or using an alternative to the
approach to assure that state emissions budgets are met (e.g., trading
ratios designed to assure that certain upwind emission reduction
targets are met, rather than trading ratios designed to assure that
downwind air quality goals are met). With regards to the variability
limits that EPA has proposed, EPA takes comment on alternative
approaches to calculating those limits, such as considering confidence
intervals different than a 95 percent confidence interval such as a 99
percent confidence interval (For more information see TSD, ``Power
Sector Variability''.)
    EPA specifically requests that any commenter suggesting a less
restrictive approach address how the commenter's preferred approach
would satisfy the statutory mandate in section 110(a)(2)(D)(i)(I) of
the Clean Air Act and be consistent with the decision of the DC Circuit
in North Carolina v. EPA, 531 F.3d 8906 (2008) (e.g., if commenters
suggest a higher variability limitation, what would be the rationale
for allowing that amount of variability; if commenters suggest an
alternative framework, how would that framework assure that reductions
occur ``within the state'') as well as how EPA could develop the
approach in a way that would be workable for sources, states, and EPA
in time to achieve emission reductions in 2012 (e.g., would an approach
with trading ratios impact transaction costs or be overly complex for
less sophisticated trading entities, can the analysis needed to develop
the approach be completed in a timely way).
    As discussed in section IV.E, EPA is proposing new state budgets
developed on a different basis from the CAIR budgets. The intrastate
and interstate trading remedy options would use new allowance
allocations, also developed on a different basis from the CAIR FIP
allowance allocations. See section IV for the proposed state budget
approach and section V.D.4 for proposed allowance allocation
approaches.
    As discussed in section IV.F, EPA believes that inherent
variability in power system operations affects each state's baseline
emissions and thus also affects a state's emissions after elimination
of all significant contribution and interference with maintenance.
Thus, emissions may vary somewhat after implementation of the remedies
under consideration. This includes the proposed remedy option (State
Budgets/Limited Trading), the intrastate trading alternative, and the
direct control alternative. Sections V.D.4, V.D.5, and V.D.6 describe
variability approaches for the proposed remedy and each of the
alternative remedies.
    EPA also considered only establishing state emissions caps. Such an
approach would define what must be done to eliminate all (or in some
cases part) of each state's significant contribution and interference
with maintenance, but it would not implement specific requirements to
eliminate those emissions. As described in section III.C in this
preamble, EPA decided to implement the emission reduction requirements
through FIPs. To do so, EPA recognized that it needed to do more than
establish simple state emissions caps. For this reason, EPA rejected
the simple state emission cap option.
    As with any FIP that EPA issues, a covered state may submit, for
review and approval, a state implementation plan (SIP) that replaces
the Federal requirements with state requirements that would achieve the
required reductions. A state's SIP submission to replace the Transport
Rule FIP might propose to use any remedy of the state's choosing that
actually eliminates the emissions that significantly contribute to
nonattainment or interfere with maintenance downwind. Section VII in
this preamble further discusses SIP submissions.
4. State Budgets/Limited Trading Proposed Remedy
    In this action, EPA is proposing FIPs that would establish state-
specific emission control requirements using state budgets starting in
2012 in 32 states.\84\ This remedy option would allow unlimited
intrastate trading and limited interstate trading to account for
variability in the electricity sector, but also includes assurance
provisions to ensure that the necessary emissions reductions occur
within each covered state. The assurance provisions, described later in
this section, would restrict EGU emissions within each state to the
state's budget with the variability limit and would ensure that every
state is making reductions to eliminate the portion of significant
contribution and interference with maintenance that EPA has identified
in today's action. EPA is proposing to impose these assurance
provisions starting in 2014. State-specific emissions budgets with
variability limits would be established as described in section IV in
this preamble. These budgets without the variability limits would be
used to determine the number of emissions allowances allocated to
sources in each state: An EGU source would be required to hold one
allowance for every ton of

SO2 and/or NOX emitted during the compliance
period. Banking of allowances for use in future years would be allowed
under the proposed remedy. For the 2012-2013 transition period, EPA is
proposing the State Budgets/Limited Trading remedy without assurance
provisions. EPA is taking comment on all aspects of, as well as
alternatives to, this option that address the requirements of
110(a)(2)(D)(i)(I) for prohibiting emissions that significantly
contribute to or interfere with maintenance of the NAAQS in downwind
states.
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    \84\ The 32 states are: Alabama, Arkansas, Connecticut, District
of Columbia, Delaware, Florida, Georgia, Illinois, Indiana, Iowa,
Kansas, Kentucky, Louisiana, Maryland, Massachusetts, Michigan,
Minnesota, Mississippi, Missouri, Nebraska, New Jersey, New York,
North Carolina, Ohio, Oklahoma, Pennsylvania, South Carolina,
Tennessee, Texas, Virginia, West Virginia, and Wisconsin. As noted
in section III, for purposes of this rulemaking, when we discuss
``states'' we are also including the District of Columbia.
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a. Description of the Proposal
    The proposed FIPs would address the elimination of significant
contribution and interference with maintenance by 2014. A first phase
of reductions would be required by 2012 to assure that significant
contribution and interference with maintenance are eliminated as
expeditiously as practicable.
    To directly eliminate the portion of each state's significant
contribution and interference with maintenance that EPA has identified
in this action, the proposed remedy utilizes the state budgets with
variability limits described in section IV. The budgets without
variability limits are used to determine the number of allowances
issued to sources in each state. Each affected source must hold, and
surrender to EPA, allowances equal to its emissions during the
compliance period. In addition, assurance provisions under the proposed
remedy cap each state's EGU emissions at a state-specific budget with a
variability limit to ensure that every state actually reduces, within
the state, all emissions necessary to eliminate the portion of its
significant contribution and interference with maintenance that EPA has
identified in today's proposal.
    For the 2012-2013 transition period, EPA is taking comment on
whether the assurance provisions used to limit interstate trading are
needed, since the state-specific budgets are based on known air
pollution controls and thus a high level of certainty exists about
where reductions will occur. As described later, the proposed FIPs
include penalty provisions that are adequate to ensure that the budget
including a variability limit will not be exceeded so that each state
eliminates the portion of its significant contribution and interference
with maintenance that EPA has identified in today's proposed action.
    The proposed remedy establishes four interstate trading programs
starting in 2012: Two for annual SO2, one for annual
NOX, and one for ozone season NOX. One
SO2 trading program is for sources in states (referred to as
the SO2 group 1) that need to make more aggressive
reductions to eliminate the portion of their significant contribution
that EPA has identified in today's proposed action, while the second is
for sources in states (referred to as SO2 group 2) with less
stringent reduction requirements. States within SO2 group 1
can trade SO2 allowances only with other states in that
group. Similarly, states within SO2 group 2 can trade
SO2 allowances only with other states in that group. Note
that all states covered for annual NOX may trade with each
other, even if they are in different groups for SO2. Table
IV.D.5 in section IV, previously, summarizes the respective covered
states for the SO2 group 1, SO2 group 2, and
annual NOX trading programs; Table IV.E-2 lists the states
for the ozone season NOX program.
    New emissions allowances based on the new state budgets without
variability would be allocated to individual sources, as described
later. Four sets of allowances would be allocated, one for each of the
four trading programs (SO2 group 1, SO2 group 2,
NOX annual, and NOX ozone season). This
allocation methodology neither uses heat input adjusted by fuel
factors, nor relies on the allocation of allowances under Title IV of
the Act.
    Sources would be allowed to trade allowances. However, the
assurance provisions would limit total emissions from each state,
restricting the variability of emissions from any particular state to
the variability associated with its baseline emissions prior to the
elimination of all or part of the state's significant contribution or
interference with maintenance.
    Allowance banking is permitted. Banking (or saving) allowances for
future use in any given year allows sources flexibility in compliance
planning. Banking lowers costs and helps reduce market volatility.
Banking also acts as an incentive to reduce emissions early and
accumulate allowances that can be used for compliance in future
periods. Because the early reductions encouraged by the ability to bank
allowances would result in the reduction of emissions below allowable
levels earlier than required, the environmental and human health
benefits of the reductions would accrue sooner.
b. How the Proposal Would Be Implemented
(1) Applicability
    The requirements in the proposed FIPs would apply to large EGUs.
Specifically, a covered source would be any stationary, fossil-fuel-
fired boiler or stationary, fossil-fuel-fired combustion turbine
serving at any time, since the later of November 15, 1990 or the start-
up of the unit's combustion device, a generator with nameplate capacity
of more than 25 MWe producing electricity for sale. The term ``fossil
fuel'' is defined as including natural gas, petroleum, coal, or any
form of fuel derived from such material. This is the same definition
that was used in CAIR and would include all material derived from
natural gas, petroleum, or coal, regardless of the purpose for which
such material is derived. For example, with regard to consumer products
that are made of materials derived from natural gas, petroleum, or
coal, are used by consumers and then used as fuel, these materials in
the consumer products would qualify as fossil fuel.
    Certain cogeneration units or solid waste incinerators otherwise
covered by this general category of covered units would be exempt from
the FIP requirements. These proposed applicability requirements are
essentially the same as those in the CAIR model trading rules and CAIR
FIPs (reflecting the revised cogeneration unit definition promulgated
in October 2007 (72 FR 59195; October 19, 2007)), with some technical
corrections to the exemptions.
    Cogeneration unit exemption. In order to meet the proposed
definition of ``cogeneration unit,'' a unit (i.e., a boiler or
combustion turbine) must operate as part of a ``cogeneration system,''
which is defined as an integrated group of equipment at a source
(including a boiler or combustion turbine, and a steam turbine
generator) designed to produce useful thermal energy for industrial,
commercial, heating, or cooling purposes and electricity through the
sequential use of energy. In order to qualify as a cogeneration unit, a
unit also must meet, on an annual basis, specified efficiency and
operating standards, e.g., the useful power plus one-half of useful
thermal energy output of the unit must equal no less than a certain
percentage of the total energy input, useful thermal energy must be no
less than a certain percentage of total energy output, and useful power
must be no less than a certain percentage of total energy input. Total
energy input includes all energy input except from biomass.
    These proposed elements of the ``cogeneration unit'' definition are
very similar to the definition used in CAIR. However, there are two
technical differences. First, under the definition used in CAIR to
qualify as a ``cogeneration unit,'' a unit had to meet

the efficiency and operating standards every year starting with the
first 12-months during which the unit produced electricity. In
contrast, under the definition proposed here, a unit can qualify as a
``cogeneration unit'' if it meets the efficiency and operating
standards every year starting the later of November 15, 1990 or the
date on which the unit first produces electricity. EPA believes this
definition of ``cogeneration unit'' is preferable because it may be
problematic to obtain sufficiently detailed information about unit
efficiency and operations for some units (e.g., old units that may have
started producing electricity many years ago). This approach is also
more consistent with the approach taken in the general applicability
criteria. EPA requests comment on whether it may also be problematic to
obtain sufficiently detailed information about unit efficiency and
operation back to November 15, 1990 and whether the efficiency and
operating standards should be limited to even more recent years by
requiring that the standards be met every year starting the later of a
date (e.g., January 1) of a more recent year (e.g., 2000, 2005, or
2009) or the date on which the unit first produces electricity. Second,
in CAIR, each unit had to meet individually the efficiency standard
(i.e., the requirement that useful thermal or electrical output be at
least a specified percentage of energy input). In contrast, under the
``cogeneration unit'' definition proposed here, if the cogeneration
system of which a topping-cycle unit (where power is produced first and
then useful thermal energy is produced using the resulting waste
energy) is a part meets the efficiency standard on a system-wide basis,
then the unit is also deemed to meet that efficiency standard. EPA
believes this definition is preferable because it addresses cases where
one unit in a cogeneration system is operated at a lower efficiency
(e.g., as a ``swing'' unit whose use varies with demand) to allow the
rest of the units in the cogeneration system to operate with higher
efficiency. EPA requests comment on whether this approach should also
be applied to bottoming-cycle units (where useful thermal energy is
produced first and then useful power is produced using the resulting
waste energy).
    As discussed previously, the operating and efficiency standards in
the ``cogeneration'' definition must be met every year. However, EPA is
concerned whether these annual standards should be applied to a
calendar year when the unit involved did not operate at all. For such a
year, the unit would be unable to meet the operating and efficiency
standards but also would not have any emissions. EPA therefore requests
comment on whether it should exclude, from the requirement to meet the
operating and efficiency standards, calendar years (if any) during
which a unit does not operate at all.
    If a unit meets the definition of cogeneration unit (including the
efficiency and operating standards), then it may qualify for the
proposed cogeneration unit exemption depending on whether it meets
additional criteria concerning the amount of electricity sales from the
unit. In order to qualify for the exemption, a cogeneration unit would
need to supply in any calendar year--starting the later of November 15,
1990 or the start-up of the unit's combustion chamber--no more than
one-third of its potential electric output capacity or 219,000 MWh,
whichever is greater, to any utility power distribution system for
sale. EPA requests comment on whether it may be problematic to obtain
sufficiently detailed information about the disposition of a unit's
generation (e.g., how much was used on site or by an industrial host
and how much was supplied to a utility distribution system for sale)
back to November 15, 1990 and whether the electricity sales limit
should be restricted to more recent years by requiring that the limit
be met every year starting the later of a date (e.g., January 1) of a
more recent year (e.g., 2000, 2005, or 2009) or the start-up of a
unit's combustion chamber.
    Solid waste incineration unit exemption. The proposed FIPs also
include an exemption for solid waste incineration units commencing
operation before January 1, 1985, for which the average annual fuel
consumption of non-fossil fuels during 1985-1987 exceeded 80 percent
and, during any three consecutive calendar years after 1990, the
average annual fuel consumption of non-fossil fuels exceeds 80 percent,
on a Btu basis. With regard to a solid waste incineration unit
commencing operation on or after January 1, 1985, EPA proposes that the
unit would be exempt if its average annual fuel consumption of non-
fossil fuel for the first 3 calendar years of operation and for any 3
consecutive calendar years, thereafter, does not exceed 80 percent.
This is the same as the solid waste incineration unit exemption used in
CAIR. EPA requests comment on whether it may be problematic to obtain
sufficiently detailed information about unit operation potentially as
far back as 1985-1987 and 1990 and whether the fuel consumption
standard for each unit should be limited to more recent years by
requiring that the standard be met every year starting the later of a
date (e.g., January 1) of a more recent year (e.g., 2000, 2005, or
2009) or the date on which the unit first produces electricity.
    Further, analogous to the approach proposed for the cogeneration
unit exemption, the proposed solid waste incineration unit exemption
would apply to units that qualify as solid waste incineration units
every year starting the later of November 15, 1990 or the date the unit
first produces electricity. EPA requests comment on whether it may be
problematic to obtain sufficiently detailed information about whether a
unit qualified as a solid waste incineration unit back to November 15,
1990 and whether the qualification requirement should be restricted to
more recent years by imposing the qualification requirement every year
starting the later of a date (e.g., January 1) of a more recent year
(e.g., 2000, 2005, or 2009) or the date of unit first produces
electricity.
    EPA also proposes to make explicit in the FIPs an interpretation
that the Agency adopted in applying CAIR, namely that--solely for
purposes of applying the fossil-fuel use limitation in the solid waste
incineration unit exemption--the term ``fossil fuel'' is limited to
natural gas, petroleum, coal, or any form of fuel derived from such
material ``for the purpose of creating useful heat.'' For example, this
means that consumer products made from natural gas, petroleum, or coal
are not fossil fuel, for purposes of determining qualification under
the limitation on fossil-fuel use, because the products (e.g., tires)
were derived from natural gas, petroleum, or coal in order to meet
certain consumer needs (e.g., to meet transportation needs), not in
order to create fuel (i.e., material that would be combusted to produce
useful heat).