In summary, the appropriate cost thresholds for each state were identified through the multi-factor assessment.  This assessment included both cost and air quality considerations.  As explained above, the ozone-season NOX threshold was determined to be $500/ton for all states required to reduce ozone-season NOX, with residual nonattainment and maintenance concerns to be addressed in a future rulemaking addressing a broader set of source categories for additional cost-effective reductions.  For PM2.5, the appropriate cost threshold for each state was determined to be either the level at which nonattainment and maintenance issues were completely resolved in downwind states to which the state is linked, the level where remaining nonattainment and maintenance issues are primarily local, or where we found greatly diminished improvements in air quality occurring if EPA moved further up the cost curve.  This assessment yielded a cost threshold of $2,300/ton on SO2 for Group 1 states starting in 2014 ($500/ton in 2012), a cost threshold of $500/ton on SO2 for Group 2 states, and a cost threshold of $500/ton on annual NOX for all states required to reduce emissions for purposes of the annual or 24-hour PM2.5 NAAQS in this rule.
      As explained above, none of these specific cost thresholds establish any precedent for the cost per ton stringency of reductions EPA may require in future transport-related rulemakings; these specific cost thresholds are based on current analyses of air quality and cost of emission reductions with respect to the NAAQS considered in this rulemaking and thus would not be relevant to future rulemakings (which would consider updated information) or rulemakings with respect to different NAAQS.  In particular, EPA acknowledges that additional action EPA will require in a subsequent rulemaking to address significant contribution to nonattainment and interference with maintenance of the 2008 ozone NAAQS (once reconsideration is finalized) is very likely to require a higher cost per ton stringency of ozone-season NOX control applied to a broader set of source categories from upwind states than found to be appropriate for this rulemaking.
2. State Emission Budgets (Step 4)
a. Budget Methodology
      EPA used the multi-factor assessment to identify, for each state, the cost threshold that should be used to quantify that state's significant contribution.  As described above, in the context of this rulemaking EPA identified a cost threshold of $500/ton for ozone-season NOX control for all states required to reduce ozone-season NOX emissions for purposes of the 1997 ozone NAAQS in this rule.  EPA also identified a cost threshold of $500/ton for annual NOX control for all states required to reduce annual NOX emissions for purposes of the annual or 24-hour PM2.5 NAAQS in this rule.  Finally, EPA identified a cost threshold of $500/ton of SO2 starting in 2012 for all states required to reduce SO2 emissions for purposes of the annual or 24-hour PM2.5 NAAQS in this rule, and $2,300/ton for the Group 1 states starting in 2014.
      EPA used these cost thresholds from the multi-factor analysis to quantify each state's emissions that significantly contribute to or interfere with maintenance downwind.  For example, for a Group 1 state, EPA modeling of the cost threshold conveys emission reductions available in each covered state from operation of existing pollution controls as well as all emission reductions available at cost thresholds of $500/ton for annual NOX in 2012 and 2014, $500/ton for SO2 in 2012, and $2,300/ton for SO2 in 2014.  The total SO2 and NOX projected at these cost levels in that state in those years represents that state's emissions once significant contribution to nonattainment or interference with maintenance downwind for the relevant PM2.5 NAAQS has been eliminated.

      Table VI.D-2  Example of Emission Reductions and Budget Formation in Michigan for Annual SO2 and NOX[a]

                             Final Cost Threshold
                        Base Case Emissions (1000 tons)
              Remaining Emissions at Cost Thresholds (1000 tons)
                       Emissions Eliminated (1000 tons)
                                       A
                                       B
                                       C
                                       D
                                       E
                                       F
                                     2012
                                      SO2
                                     $500
                                     252.4
                                     194.5
                                     57.9

                                      NOX
                                     $500
                                     60.6
                                     60.2
                                      0.4
                                     2014
                                      SO2
                                    $2,300
                                     265.6
                                      144
                                     121.6

                                      NOX
                                     $500
                                     64.3
                                     57.8
                                      6.5
[a] Note:  In this table, emissions are shown for fossil-fuel-fired EGUs > 25 MW (i.e., those units likely covered by the Transport Rule). Table VI.D.2 illustrates how budgets are derived from the elimination of significant contribution for the state of Michigan.  Column C illustrates the cost thresholds applied in the costing run that was ultimately identified as the final cost threshold in the multi-factor analysis.  Column D shows the base case emissions for the identified pollutant in the identified time period.  Column E shows the emission levels that result when the cost thresholds identified in column C are applied.  Because this is the cost threshold identified through the multi-factor analysis and the point where all significant contribution to nonattainment and interference with maintenance has been addressed for the PM2.5 NAAQS - state budgets are based on these emission levels.  The final column illustrates the emission reductions for the state in an average year (before accounting for variability) when the cost thresholds are applied - this is equal to the emission levels identified at the cost threshold subtracted from the base case emission levels.

      EPA's modeling of a state's SO2 and annual NOX emission levels (from fossil-fired EGUs >25 MW) at the relevant cost thresholds in each state reflect that state's emissions from covered sources after the removal of significant contribution to nonattainment and interference with maintenance of the PM2.5 NAAQS considered in this rulemaking.  As these state emission levels reflect the removal of significant contribution and interference with maintenance, they are reasonable levels on which to determine state budgets.  Consequently, EPA set state budget levels equal to the state level emissions that remained at the cost threshold. Each state's budget corresponds to its emission levels following the elimination of significant contribution to nonattainment and interference with maintenance in an average year (before taking year-to-year variability into account, as discussed in section VI.E below).  Therefore, the implementation and realization of these budgeted emissions levels leads to the elimination of significant contribution to nonattainment and interference with maintenance and EPA meets the statutory mandate of section 110(a)(2)(D)(i)(I) with respect to the 1997 annual PM2.5 -  NAAQS and the 2006 24-hour PM2.5 NAAQS.
      EPA's establishment of state budgets for ozone-season NOX control follow the same methodology as described above for SO2 and annual NOX.  Implementation of these ozone-season NOX budgets reflects the elimination of significant contribution to nonattainment and interference with maintenance of the 1997 ozone NAAQS for 15 states, whereas 11 other states' ozone-season NOX budgets reflect meaningful progress toward (but may not reflect full completion of) this elimination under the mandate of section 110(a)(2)(D)(i)(I). See section III for lists of states.
      This approach to basing budgets on projected state level emission used in the multi-factor analysis is identical to the approach used in the proposal for determining 2014 SO2 budgets for Group 1 states.  EPA is extending this approach more broadly in the final Transport Rule to create state budgets for ozone-season NOX, annual NOX, and SO2 in all relevant states in both 2012 and 2014.  In the proposal EPA used a more complex approach based on a comparison of historic and projected unit-level emissions (further adjusted for operation of existing controls) in each state to create 2012 state budgets for ozone-season NOX, annual NOX, and Group 2 SO2.  At the time of proposal, EPA believed that historic 2009 emissions data were in some cases more representative of expected emissions in 2012 than pure modeling projections made at the time (75 FR 45290).
      However, following the proposal EPA has made significant updates to the IPM model for projecting EGU emissions, including specifically the adoption of 2009 historic data into its modeling parameters directly.  EPA also received substantial public input following the proposal on the model's assumptions and representation of individual units, which allowed EPA to improve its 2012 and 2014 emission projections for states under the cost thresholds considered.  These modeling updates diminish the concerns EPA expressed at proposal that 2009 historic data may have offered for some states a better proxy for 2012 emissions than model projections, particularly now that EPA is incorporating 2009 data directly in its updated modeling projections.  Given these updates to the model in response to public comment, EPA believes it is more appropriate for the final rule to use a consistent approach based on projected state level emissions for all state budgets, as was done for Group 1 SO2 budgets in 2014 at proposal.  EPA received significant comment supporting the use of the model to project state-level emissions for creating budgets in this manner.  EPA also received comments that criticized the proposal's methodology for 2012 budgets for lack of transparency, unnecessary complexity, and inconsistency with the state-level emission projections used in the air quality modeling.  EPA's decision for the final Transport Rule to consistently apply across all pollutants the budget methodology originally used for Group 1 SO2 budgets in 2014 addresses those concerns.
      This budget methodology for the final rule uses projected state-level emissions in 2012 and 2014 to set emissions budgets for those years on relevant pollutants for that state to control under the Transport Rule.  EPA's modeling projects that some states have 2014 emissions that are lower than their 2012 projected emissions even as the same cost threshold (e.g., $500/ton) is applied in both years.  This occurs in the annual NOX, ozone-season NOX, and Group 2 SO2 program. As such, EPA's application of this budgeting methodology results in a tightening of budgets in states whose projected emissions of that budgeted pollutant decline from 2012 to 2014 as the cost threshold is held constant.
      There are two primary variables that explain the decrease in emissions for some states between 2012 and 2014 as the cost threshold remains constant over both time periods.  First, even though the cost threshold is constant between 2012 and 2014 for the programs noted above, the cost threshold for SO2 Group 1 increases in 2014.  This higher cost threshold for Group 1 SO2 results in obvious reductions in SO2 emissions in the Group 1 states, but also may lower the cost of certain related NOX reductions in those states as well such that they become newly available within the $500/ton threshold.  For example, if a state increases natural gas generation in response to the higher SO2 cost threshold, such action also yields additional annual and ozone-season NOX emission reductions that are cost-effective at the $500/ton NOX threshold.  Where the cost curve modeling shows such additional cost-effective NOX reductions in tandem with SO2 control, EPA is therefore reducing those states' 2014 annual NOX and ozone-season NOX budgets accordingly, so that those budgets accurately reflect remaining emissions from covered sources in those states after the elimination of all emissions that can be reduced up to the relevant cost thresholds (e.g., $500/ton).
      Second, some of these additional reductions are driven by non-Transport Rule variables.  These are reductions that occur due to state rules, consent decrees, and other planned changes in generation patterns that occur after 2012, but during or prior to 2014.  For example, EPA modeling reflects emission reduction requirements under provisions of a Georgia state rule that go into effect after 2012 but before 2014.  These requirements involve the installation and operation of specific advanced pollution controls.  These source-specific requirements under a legal authority unrelated to the Transport Rule result in sharp reductions in Georgia's baseline emission projections between 2012 and 2014.  Even though the cost threshold for NOX and for SO2 in Georgia is $500/ton in both 2012 and 2014, EPA believes it is important to establish separate NOX and SO2 budgets that accurately reflect the emissions remaining in Georgia (and other states experiencing similar reductions) after the elimination of emissions that can be reduced up to the Transport Rule remedy's cost thresholds (e.g., $500/ton) (See Table VI.D.3).  It illustrates a notable decrease between the 2012 and 2014 state budgets for NOX and SO2 in Georgia that is largely driven by state rule requirements).  If EPA did not adjust 2014 budgets to account for other emission reductions that would occur even in the baseline, other sources within the state would be allowed to increase their emissions under the unadjusted Transport Rule budgets to offset the emission reductions planned under other requirements such as state rules.  Therefore, to prevent the Transport Rule from allowing such offsetting of emission reductions already expected to occur between 2012 and 2014, EPA is establishing separate budgets for 2012 and 2014 in the final Transport Rule to capture emission reductions in each state that would occur for non-Transport Rule-related reasons (i.e., in the base case) during that time.
      EPA's modeling also projects that other states would slightly increase emissions from 2012 to 2014 even at the same cost threshold, such as $500/ton.  There are two primary variables that explain the increase in emissions for these states between 2012 and 2014.  These increases are generally small in magnitude.  For annual and ozone season NOX, they occur as a byproduct of small changes in dispatch related to changes in non-Transport Rule factors (e.g., higher demand in 2014).  For SO2, they primarily occur in Group 2 states and, in addition to the reasons given above, are influenced by some generation shifting from Group 1 to Group 2 states as the Group 1 states begin to face a higher cost threshold in 2014.  EPA believes that allowing for such emissions growth in covered states beyond 2012 would be inconsistent with the Transport Rule's identification and elimination of significant contribution to nonattainment and interference with maintenance beginning in 2012.  Therefore, for any covered state whose emissions of a relevant pollutant are projected to increase from 2012 to 2014 under the relevant cost thresholds selected in the multi-factor analysis described above, EPA is finalizing that state's 2014 emissions budget to maintain the same level of the 2012 emissions budget, thereby disallowing such an emissions increase that is inconsistent with the 110(a)(2)(D)(i)(I) mandate.  Tables VI.D-3 and VI.D-4 below list state emissions budgets.  [PLACEHOLDER FOR CAVEAT REGARDING REMEDY ANALYSIS AND REVISED VARIABILITY LIMITS]
Table VI.D-3 - SO2 and Annual NOX State Emission Budgets for Electric Generating Units before Accounting for Variability* (tons)

                                      SO2
                                      NOX

                                     Group
                                   2012-2013
                                2014 and beyond
                                   2012-2013
                                2014 and beyond
Alabama
                                       2
                                                                        216,033
                                                                        213,258
                                                                        72,691
                                                                        71,962
Georgia
                                       2
                                                                        158,527
                                                                         95,231
                                                                        62,010
                                                                        40,540
Illinois
                                       1
                                                                        234,889
                                                                        124,123
                                                                        47,872
                                                                        47,872
Indiana
                                       1
                                                                        285,424
                                                                        161,111
                                                                       109,726
                                                                       108,424
Iowa
                                       1
                                                                        107,085
                                                                         75,184
                                                                        38,335
                                                                        37,498
Kansas
                                       2
                                                                         41,528
                                                                         41,528
                                                                        30,714
                                                                        25,560
Kentucky
                                       1
                                                                        232,662
                                                                        106,284
                                                                        85,086
                                                                        77,238
Maryland
                                       1
                                                                         30,120
                                                                         28,203
                                                                        16,633
                                                                        16,574
Michigan
                                       1
                                                                        229,303
                                                                        143,995
                                                                        60,193
                                                                        57,812
Minnesota
                                       2
                                                                         41,981
                                                                         41,981
                                                                        29,572
                                                                        29,572
Missouri
                                       1
                                                                        207,466
                                                                        165,941
                                                                        52,374
                                                                        48,717
Nebraska
                                       2
                                                                         65,052
                                                                         65,052
                                                                        26,440
                                                                        26,440
New Jersey
                                       1
                                                                          5,574
                                                                          5,574
                                                                         7,266
                                                                         7,266
New York
                                       1
                                                                         27,325
                                                                         18,585
                                                                        17,543
                                                                        17,543
North Carolina
                                       1
                                                                        136,881
                                                                         57,620
                                                                        50,587
                                                                        41,553
Ohio
                                       1
                                                                        310,230
                                                                        137,077
                                                                        92,703
                                                                        87,493
Pennsylvania
                                       1
                                                                        278,651
                                                                        112,021
                                                                       119,986
                                                                       119,194
South Carolina
                                       2
                                                                         88,620
                                                                         88,620
                                                                        32,498
                                                                        32,498
Tennessee
                                       1
                                                                        148,150
                                                                         58,833
                                                                        35,703
                                                                        19,337
Texas
                                       2
                                                                        243,954
                                                                        243,954
                                                                       133,595
                                                                       133,595
Virginia
                                       1
                                                                         70,820
                                                                         35,057
                                                                        33,242
                                                                        33,242
West Virginia
                                       1
                                                                        146,174
                                                                         75,668
                                                                        59,472
                                                                        54,582
Wisconsin
                                       1
                                                                         79,480
                                                                         40,126
                                                                        31,628
                                                                        30,398
Grand Total

                                                                      3,385,929
                                                                      2,135,026
                                                                      1,245,869
                                                                      1,164,910
Group 1 Total

                                                                      2,530,234
                                                                      1,345,402
                                                                             NA
                                                                             NA
Group 2 Total

                                                                       855,695
                                                                       789,624
                                                                             NA
                                                                             NA
Note - These state emissions budgets apply to emissions from electric generating units covered by the Transport Rule Program.  Group 1/Group 2 designations are only relevant for SO2 emissions budgets.

*The impact of variability on budgets in discussed in section VI.E

      The District of Columbia is not covered by the final Transport Rule.  As discussed in section V.D of this preamble and as done for the Transport Rule proposal, EPA combined contributions projected in the air quality modeling from Maryland and the District of Columbia to determine whether those jurisdictions collectively contribute to any downwind nonattainment or maintenance receptor in amounts equal to or greater than the 1 percent thresholds.  This modeling confirmed that the combined contributions exceed the air quality threshold at downwind receptors for the ozone, annual PM2.5, and 24-hour PM2.5 NAAQS considered.  Both Maryland and the District of Columbia are therefore linked to these receptors.  However, the District of Columbia is not included in the Transport Rule because, in the second step of EPA's significant contribution analysis, we concluded that there are no emission reductions available from EGUs in the District of Columbia at the cost thresholds deemed sufficient to eliminate significant contribution to nonattainment and interference with maintenance of the NAAQS considered at the linked receptors.  At the time of this rulemaking, EPA finds only one facility with units meeting the Transport Rule applicability requirements in the District of Columbia. EPA's projections do not show any generation from this facility to be economic under any scenario analyzed (including the base case), and the facility's owners have also announced plans to retire its units in early 2012.  Therefore, this unit is projected to have zero emissions in 2012.  As such, the total SO2 and NOX emissions in the District of Columbia for EGUs that meet the Transport Rule applicability requirements is also projected to be zero.  It follows therefore, that EPA did not identify any emission reductions available at any of the cost thresholds considered in the final rule's multifactor analysis to identify significant contribution to nonattainment and interference with maintenance.  For this reason, EPA concludes that no additional limits or reductions are necessary, at this time, in the District of Columbia to satisfy the requirements of section 110(a)(2)(D)(i)(I) with respect to the 1997 ozone, the 1997 PM2.5 and the 2006 PM2.5 NAAQS.  EPA is therefore neither establishing budgets nor finalizing any FIPs for the District of Columbia in this rule.
Table VI.D-4 - Ozone Season NOX State Emissions Budgets for Electric Generating Units Before Accounting for Variability* (tons)

                                   2012-2013
                                2014 and Beyond
Alabama
                                    31,746
                                    31,499
Arkansas
                                    15,037
                                    15,037
Florida
                                    27,825
                                    27,825
Georgia
                                    27,944
                                    18,279
Illinois
                                    21,208
                                    21,208
Indiana
                                    46,876
                                    46,175
Kentucky
                                    36,167
                                    32,674
Louisiana
                                    13,432
                                    13,432
Maryland
                                    7,179
                                    7,179
Mississippi
                                    10,160
                                    10,160
New Jersey
                                    3,382
                                    3,382
New York
                                    8,331
                                    8,331
North Carolina
                                    22,168
                                    18,455
Ohio
                                    40,063
                                    37,792
Pennsylvania
                                    52,201
                                    51,912
South Carolina
                                    13,909
                                    13,909
Tennessee
                                    14,908
                                    8,016
Texas
                                    63,043
                                    63,043
Virginia
                                    14,452
                                    14,452
West Virginia
                                    25,283
                                    23,291
Total
                                   495,314
                                   466,051
Note - These state emission budgets apply to emissions from electric generating units greater than 25 MW and covered by the Transport Rule Program.  Group 1/Group 2 designations are only relevant for SO2 emissions budgets.

*The impact of variability on budgets in discussed in section VI.E

      EPA notes that the NOX budgets for five states linked to downwind ozone receptors in the final Transport Rule are equal to their projected 2012 base case emissions.  The five states are Arkansas, Indiana, Louisiana, Maryland, and Mississippi.  These states are among those found to meet or exceed the 1 percent contribution threshold for the 1997 ozone NAAQS at downwind receptors and are thus "linked" to downwind receptors.  EPA therefore evaluates, in the second step of its significant contribution analysis, what emission limits are necessary to ensure that all emissions that constitute the state's significant contribution to nonattainment and interference with maintenance are prohibited.  As explained above, EPA decided to require from all such states all reductions available at the $500/ton cost threshold.  The five states identified above do not appear to show EGU ozone season NOX reductions at the $500/ton cost threshold relative to the 2012 base case projections (which do not take into account reductions to be made in other states as a result of this rule).  Therefore, EPA conducted further analysis to evaluate whether such reductions were available in these states and whether emission limits are necessary to prohibit these states from significantly contributing to downwind nonattainment or interfering with maintenance of the 1997 ozone NAAQS in other states.
      Specifically, EPA projected those states' ozone-season NOX emissions if all other linked states (but not these five states) were to make all available reductions at the $500/ton threshold.  That analysis revealed that if emission limits were not established for these five states, ozone-season NOX emissions in each of the states would increase (beyond the 2012 base case emission projections), due to interstate shifts in electricity generation that cause "emissions leakage" in uncovered states.  These increases would result in each state's emissions being above the level associated with the prohibition of all emissions that can be eliminated at the $500/ton threshold.  EPA thus determined that it is necessary to establish emission limits for these states at the $500/ton level.  These limits, although equal to the state's 2012 projected base case emissions, are necessary to prohibit all emissions that can be controlled at the $500/ton cost threshold.  In other words, the significant contribution to nonattainment and interference with maintenance addressed by the ozone FIPs for these states is the difference between these states' projected emissions if they were not covered under the Transport Rule (but other states were), and their emissions after all emissions that can be eliminated at $500/ton are prohibited.
      In addition, EPA notes that four of these five states (Arkansas, Indiana, Louisiana, and Mississippi) are linked to receptors in either the Houston or Baton Rouge areas, which are projected to continue facing nonattainment or maintenance concerns with the 1997 ozone NAAQS, respectively.  To allow these states to increase emissions above base case projections would erode the measurable progress toward eliminating significant contribution to nonattainment and interference with maintenance secured by achieving ozone-season NOX reductions in the other states linked to these receptors.  Furthermore, as discussed in section III,  EPA may require additional reductions in these states to fully address significant contribution to nonattainment and interference with maintenance with respect to the 1997 ozone NAAQS in a future rulemaking to be proposed after finalizing reconsideration of the 2008 ozone NAAQS.
b. Relationship of Group 1 and Group 2 States for SO2 Control
      In the Proposal, EPA chose not to allow sources in Group 1 states to use Group 2 SO2 allowances for compliance, and likewise not to allow sources in Group 2 states to use Group 1 SO2 allowances for compliance at any time. The preamble clearly states, "With regard to interstate trading, the two SO2 stringency tiers would lead to two exclusive SO2 trading groups. That is, states in SO2 Group 1 could not trade with states in SO2 Group 2."  No such distinction or limitation exists for NOX allowance trading.
      EPA received significant public comment both in support and opposition to the two distinct SO2 trading programs.  Those in opposition noted that the variability limits imposed at the state level made the compliance restrictions between the two groups unnecessary.  Commenters also noted that it may unfairly penalize sources that are part of the same airshed, but are on opposite sides of a state boundary.  Those in favor of the separate SO2 compliance programs noted that it would reduce the probability of a state exceeding its variability limit.  Allowing the use of Group 1 or Group 2 allowances for compliance between the two SO2 programs would potentially encourage Group 1 states to purchase allowances instead of making reductions necessary to eliminate significant contribution.  Group 1 states are states that need continued reductions (beyond the $500/ton threshold) to eliminate their significant contribution to nonattainment and interference with maintenance.  Group 2 states have already eliminated their significant contribution to nonattainment and interference with maintenance at the $500/threshold.  So to allow Group 1 or Group 2 allowances to be used interchangeably for compliance between the two SO2 groups would be to allow the shifting of reductions from areas where they are needed to eliminate significant contribution to nonattainment and interference with maintenance to areas where they are not needed to eliminate the prohibited emissions.  EPA also agrees that allowing for trading between the two groups in the remedy finalized in this action would increase risk of a state exceeding its variability limit.  For these reasons, EPA is finalizing this rulemaking with the same prohibition on SO2 trading between Group 1 and Group 2 states that was defined in the proposal.  Further, EPA clarifies that while trading of allowances (i.e., buying, selling, and banking) is allowed without restriction, it is specifically the surrender of SO2 allowances for compliance that is limited.  As mentioned earlier, a source in a Group 1 state can only use SO2 allowances allocated to Group 1 states for compliance with the SO2 trading program.  Likewise, a source in a Group 2 state can only use SO2 allowances allocated to Group 2 states for compliance with the SO2 trading program.
c. Ozone Season Budgets
      EPA established the ozone-season NOX budgets in a similar manner to the annual NOX and SO2 budgets by using the state level emissions from the cost threshold that reflected the removal of significant contribution to nonattainment and interference with maintenance.  Ozone-season budgets were set equal to the state level emissions from fossil-fuel-fired units greater than 25 MW observed at this cost threshold.  As described in section VI.B, all cost thresholds examined reflected the final Transport Rule geography and the marginal costs were applied accordingly.  Therefore, for an ozone-only state like Florida, the state level emissions would only reflect an ozone-season cost threshold of $500/ton in the final cost curves for 2012 and 2014.  For a state subject to both annual and ozone-season programs, the marginal cost curves would reflect a $500/ton NOX cost year round, a $500/ton SO2 cost in 2012 and the $2,300/ton SO2 cost starting in 2014 if a Group 1 state.
(1) Length of ozone season
      (a) Proposed Rule. For purposes of determining ozone-season budgets in the proposed rule, EPA defined the ozone season based on a 5 month period (May 1 through September 30).   This 5 month ozone season was consistent with the approach taken by the OTAG, the NOX SIP Call, and CAIR.   EPA requested comment on whether EPA should base final rule budgets on a longer season, such as March through October.
      (b) Public Comments.  Several commenters supported continuing with the May through September time period.  One commenter supported continuing with this time period, but argued that EPA should consider lengthening the ozone season for future efforts.  One commenter questioned the concept of ozone season budgets and recommended EPA focus on sources with greater emissions on high ozone days.
      (c) Final rule.   For the final rule, EPA has retained the approach in the proposed rule, as commenters broadly supported the proposal's ozone-season duration and ozone-season NOX limitations.  Notably, many Transport Rule states covered for PM2.5 reductions will have sources with annual NOX controls that are likely to keep operating year round to address PM2.5 and ozone.  EPA believes that experience from ozone-season NOX trading has consistently shown that the emission measures taken to comply with ozone-season budgets provide emission reductions throughout the ozone-season, including the highest ozone days. (See NOX Budget Trading Program and CAIR Program progress reports in the docket to this rulemaking or at http://www.epa.gov/airmarkets/progress/nbp08.html and http://www.epa.gov/airmarkets/progress/CAIR_09/CAIR09.html.)  However, EPA believes that there is merit in future Agency actions addressing ozone transport in considering strategies to target high ozone days more specifically.
d. Summary of Cost Thresholds and Final Budgets for PM2.5 and Ozone
 	Summary of methodology.  In summary, EPA determined that SO2 emissions that could be reduced for $2,300/ton in 2014 should be considered a state's significant contribution to nonattainment and interference with maintenance, unless EPA determined that a lesser reduction would fully resolve the nonattainment and/or maintenance problem for all the downwind receptors to which a particular state might be linked.  For these Group 2 states EPA is determining that a lesser reduction of SO2, based on the amount of SO2 reductions that can be reasonably achieved by 2012 is appropriate.  This level is defined by the reductions observed in the $500/ton cost threshold.  EPA also determined that all states linked to downwind PM2.5 nonattainment and maintenance problems should be required to achieve those emission reductions that can be reasonably achieved by 2012.  Finally, EPA determined that all states linked to downwind PM2.5 nonattainment and maintenance problems should, by 2012, remove all NOX emissions that can be reduced for $500/ton and run all existing controls in 2012.
      For ozone season NOX, EPA determined that all states linked to downwind ozone and nonattainment and maintenance problems should be required to achieve those ozone season emission reductions associated with a cost threshold of $500 per ton.  Additionally, EPA examined final 2012 and 2014 budgets based on state level emissions at $500 cost threshold.
      The budget formation methodology finalized in this action responds to concerns about state budgets expressed by commenters on the Transport Rule proposal.  EPA requested comment on the four step approach used to determine significant contribution and determine budgets in the proposal.  Some commenters noted that the state level emissions from the cost thresholds used to determine significant contribution to nonattainment and interference with maintenance did not match the state level emissions allowed by the final budgets.  The concern was that the state level emissions that reflected the elimination of significant contribution in the AQAT analysis, in particular for NOX, were less than the emissions allowed by the final budgets.  The result would be an implementation that did not quite fully eliminate the significant contribution to nonattainment and interference with maintenance defined in the rule.  The proposed budgets not matching the levels reflected in the proposed costing runs were an artifact of the budget formation process that relied on a combination of historic and projected data.  While EPA noted this process resulted in state budgets that "reflected" EGU emissions at $500/ton, it was not always consistent with the EGU emissions at $500/ton in the costing runs as the commenters noted.  By using the cost curves to determine both significant contribution to nonattainment and interference with maintenance -- and state budgets -- in the final rule, EPA addresses the commenter's concerns about any inconsistency between the two in the proposal.  [PLACEHOLDER FOR CAVEAT REGARDING REMEDY ANALYSIS AND REVISED VARIABILITY LIMITS]
	Some commenters expressed concern that the Transport Rule would result in state budgets that were in some cases higher than those established in CAIR.  Commenters suggested that this would be inconsistent with requirements or the spirit of certain CAA provisions aimed at preventing backsliding, i.e., sections 110(l), 172(e), and 193.   However, the D.C. Court of Appeals rejected the state budgets in CAIR as arbitrary and capricious and not consistent with CAA section 110(a)(2)D)(i)(I)  ( North Carolina, 531 F.3d  918 and 921) and remanded CAIR to EPA to promulgate a new rule replacing CAIR and consistent with the Court's decision (North Carolina, 550 F.3d 1178).  As discussed elsewhere in this section, on remand EPA developed new, final state budgets that address the Court's concerns and meet section 110(a)(2)(D)(i)(I) requirements.
      Although some state budgets under the final rule are higher than those under CAIR, this does not violate either the letter or the spirit of CAA provisions aimed at backsliding.  In particular, CAA section 110(l) provides that the Administrator may not approve a plan revision that would "interfere with any...applicable requirement" of the CAA.  42 U.S.C. 7410(l).  Because the Court reversed and remanded CAIR with instructions to "remedy" the rule's "fundamental flaws" (including specifically the state budgets found to be unlawful (North Carolina, 550 F.3d 1178), it is difficult to see how new state budgets replacing unlawful budgets and meeting section 110(a)(2)(D)(i)(I) requirements could be viewed as interfering with requirements of the CAA.  Indeed, the commenters' approach would severely limit EPA's ability to meet the Court's mandate to develop a new rule consistent with section 110(a)(2)(D)(i)(I).  See North Carolina, 531 F.3d 921 (explaining that EPA may not require "some states to exceed the mark" of eliminating their significant contribution).  Further, the other CAA sections cited by the commenters (section 172(e), addressing circumstances where the Administrator relaxes a NAAQS, and section 193, addressing the treatment of requirements promulgated before the November 15, 1990, enactment date for the 1990 Amendments to the Clean Air Act) are not applicable here.
      Additionally, while the CAIR budgets may have been tighter than Transport Rule state budgets for a couple of states, the sum of state budgets that were subject to both CAIR and the Transport Rule is lower under the Transport Rule for the annual programs.  Moreover, the carryover of the large Title IV allowance bank in CAIR allowed for a great deal more emissions within any given state than is permitted under the Transport Rule.
E. Approach to Power Sector Emission Variability
1. Introduction to Power Sector Variability
      Variability is an inherent aspect of the production and delivery of electricity.  In particular, emission variability is built into the design of power systems, which use a wide mix of power generation sources with varying use and emissions patterns.  Electricity is dispatched to meet loads while minimizing costs, with less expensive sources, such as coal-fired boilers, generally used before more expensive sources, such as natural-gas-fired combustion turbines.  Since cheaper sources may have very different emission rates  - - often, as in the case of coal units compared to natural gas units, much higher emission rates -- variations in the level of loads can have a significant impact on the level of emissions.
      Loads on a power system vary over every time interval, changing not only in the short term and seasonally, but also annually.  Load patterns and levels are determined by a number of factors, including economic activity and weather, which vary over time.  In particular, weather obviously varies not just from season to season but also from year to year, and even small changes in annual weather patterns can affect how the power system operates during a year.  For example, load, and the resulting use of generation sources on an interconnected grid to meet load, depend not only on how hot a summer day is, but also on how long a heat wave lasts.  Similarly, a relatively cold winter that drives up winter load may also change what generation sources are used.  Thus, the pattern of generation may shift geographically as a weather pattern moves across the country.  Because weather and other factors affecting loads, and the patterns of generation used to meet loads, vary over time and from state to state, the resulting level of emissions also varies over time and from state to state.
      In the final Transport Rule, like the proposed rule, EPA explicitly takes account of power sector emission variability.
As discussed previously, EPA identified a specific amount of emissions that must be prohibited by each state to meet the requirements of CAA section 110(a)(2)(D)(i)(I).  EPA also developed state baseline emissions based on projections of state emissions in an average year before the elimination of prohibited emissions, and state budgets based on projections of state emissions in an average year after the elimination of such emissions.  However, because of the inherent variability in state-level baseline emissions  - - resulting from the inherent variability in loads and power system operations -- state-level emissions are likely to vary even after all significant contribution to nonattainment and interference with maintenance that EPA identified in this final rule are eliminated.  EPA believes that, because baseline emissions are variable and emissions after the elimination of all significant contribution to nonattainment and interference with maintenance are therefore also variable, it is appropriate to take this variability into account in developing the remedy for meeting the requirements of CAA section 110(a)(2)(D)(i)(I).  For this reason, EPA is finalizing variability limits for each state budget to identify the range of emissions that EPA believes is likely to occur in each state following the elimination of all the state's significant contribution to nonattainment and interference with maintenance.
      As discussed in detail in section VII, the air quality-assured trading remedy's state-specific budgets represent each state's emissions in an average year after elimination of significant contribution to nonattainment and interference with maintenance.  Because actual base case emissions are likely to vary from projected base case emissions, this remedy incorporates provisions that account for such variability.  EPA believes that the remedy uses variability limits in a way that both provides the flexibility of interstate trading for dealing with real-world variability in the operation of the power system and for reducing costs of compliance with emission reduction requirements, as well as providing assurance for downwind states that significant contribution to nonattainment and interference with maintenance by upwind states will be eliminated.
      Moreover, EPA believes that the variability limits are used in a way that also does not allow an overall increase in emissions.  Under the remedy, an individual state can have emissions up to its budget plus the variability limit.  However, the requirement that all sources hold allowances covering emissions, and the fact that those allowances are allocated based on state-specific budgets without variability, ensure that the total emissions from the states do not exceed the sum of the state budgets.  The remedy, therefore, ensures both that total emissions do not exceed the total of the state budgets and that the required emission reductions occur in each state.
This section describes how EPA calculated variability limits for each state to achieve this goal.
2. Transport Rule Variability Limits
      EPA performed analyses using historical data to demonstrate that there is year-to-year variability in base case emissions (even when emission rates for all units are held constant) and to quantify the magnitude of this variability.
      The focus of the analysis is on quantifying the magnitude of the inherent year-to-year variability in state-level EGU emissions independent of measures taken to control those emissions (and thus due only to changes in electricity generation within each state).  EPA used this analysis to set variability limits as part of the remedy to ensure that states are eliminating their significant contribution to nonattainment and interference with maintenance to protect air quality.
      As discussed in detail below, EPA is finalizing the Transport Rule with one-year variability limits calculated using a modified approach from the one described in the proposal.  EPA is not including the proposal's three-year variability limits in the final Transport Rule.  EPA received comments that the three-year variability limits increased program costs and diminished compliance flexibility without delivering any additional air quality benefits.  EGU owners and operators expressed concern that three-year variability limits would be impracticable to implement and that the one-year variability limits themselves would be adequately stringent to ensure elimination of significant contribution to nonattainment and interference with maintenance in each state.
      After further consideration, EPA has concluded that three-year variability limits would be unnecessary, would be difficult to anticipate, and would not have a measurable impact on air quality benefits. EPA has determined that annual limits are sufficient to eliminate significant contribution to nonattainment and interference with maintenance in all upwind states while accommodating the historically observed year-to-year fluctuation in state-level EGU emissions even at the same rate of emissions control in a given state.
      In the proposal, EPA used statistical methods to derive the three-year variability limit directly from the one-year variability limit, meaning that the two are statistically equivalent in the long run under certain statistical assumptions.  Primarily, these assumptions were that the variation in electric demand around the budget is random from year to year and that, when the annual emissions are averaged over a multi-year time-period, the average emissions per year will equal the state's budget.  The first assumption was also made in the assessment of the historical year-to-year variation in heat input in developing the one-year limit (see section 2 of the "Power Sector Variability Final Rule TSD" for more details).  Regarding the second assumption, since the state-by-state emission budgets are based on the availability of emission reductions at an equal marginal cost level, EPA expects the sources in each of the upwind states to make these cost-effective reductions and to meet the emission budgets each year, on average.
      Since the three-year variability limit was based on average year-to-year variability over a longer time horizon, EPA notes that a random ordering of those years could yield two above-average years in a row.  If, by chance, a third above-average year were to follow, the state could face violation of the three-year limit, even if over a time period longer than three years, that state would never have exceeded the statistically-equivalent one-year variability limit and its annual emissions would have averaged to the level of its budget.  Effectively, this means that imposing a multi-year variability limit would erode the one-year variability limit's ability to accommodate historically observed year-to-year variability in state-level EGU emissions (due only to generation changes), and it would do so without providing any additional air quality benefits or protection for downwind areas (since the average emissions over the long time horizon equal the level of the budget).
      For more details about the relationship between the one- and three-year limits, see the discussions in section 3 of the "Power Sector Variability" TSD from the proposed Transport Rule, which describes the derivation of the three-year limit from the one-year variability and section 3 of the "Power Sector Variability Final Rule TSD", which describes the results of a numerical simulation showing that the one- and three-year limits result in similar numbers of exceedances.
      While EPA expects the yearly emissions in each state, on average, to equal the level of the budgets, EPA also estimated the air quality impacts of 5, 10, 15, and 20 percent emission variability using the air quality assessment tool (see section 4 of the "Power Sector Variability Final Rule TSD" for more details).  This analysis shows that year-to-year fluctuations of up to 20 percent in SO2 emissions from upwind states linked to a given downwind receptor do not undermine the ability of the Transport Rule programs to resolve nonattainment or maintenance concerns at that receptor.  This analysis was designed to examine the sensitivity of downwind air quality to upwind EGU emission levels.  The share of total SO2 emitted by EGUs is significantly larger than the share of total NOX emitted by EGUs.  For example, in the states for which EPA modeled base case contributions of these pollutants, EGUs accounted for 74 percent of total SO2, 14 percent of total annual NOX, and 15 percent of total ozone-season NOX emissions.  Therefore, when varying EGU emissions only, downwind air quality would be most sensitive to upwind variations in SO2, because relative variations in EGU SO2 emissions have a greater impact on total SO2 emissions than the same relative variation in EGU NOX emissions would have on total NOX emissions affecting downwind air quality.
      Furthermore, because the state budgets are based directly on IPM modeling of electric generation when cost-effective emission reductions have been achieved, sources within each state should have the same incentive to meet that budget, on average, in any given year.  Additional EPA analysis supports the claim that states would be no more likely to exceed one-year variability limits without the three-year limits than with the three-year limits.  See the "Power Sector Variability Final Rule TSD" for more details on this statistical analysis.  Finally, because the state budgets (and thus the total amount of allowances available) are fixed and every covered source must hold allowances covering its emissions, it is not feasible for all, or even many, states to repeatedly exceed their budgets.
      The approach calculated the standard deviation in state-level heat input from units expected to be covered by the final Transport Rule over an 11-year time period (2000 through 2010), from which the 95th percent confidence level was calculated.  EPA divided this value by the mean to get the percentage variation in heat input.  The two-tailed 95th percent confidence level is the equivalent of the 97.5 percent upper (single-tailed) confidence level.  This approach yielded an average year-to-year heat input variability for each state, as a proxy for historic year-to-year variability in state-level EGU emissions while holding emission rates constant.  The result, expressed as a percentage, conveys the maximum degree to which EGU emissions at the state level may be expected with 95th percent confidence to vary around a given target (i.e., budget) from year to year, on average, based on the statistical analysis of historic heat input over the 2000 through 2010 time period.

      From the state-by-state variability calculations, EPA identified a single variability level (percentage) for each of the annual and ozone-season programs based on the historic variability measured at units in covered states on an annual basis and an ozone-season basis, respectively.  In the proposal, EPA "identified a single set of variability levels . . . 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" (75 FR 45293).  In the final rule, EPA is also identifying a single set of variability levels to apply to all states in favor of straightforward application but also because EPA has determined that it is appropriate to afford all states under the Transport Rule programs the extent of measured historic variability experienced by any Transport Rule state.  In the variability analysis for the final rule, EPA identified Tennessee as having the highest measured historic variability of annual heat input of 18 percent, and EPA identified Virginia as having the highest measured historic variability of ozone-season heat input of 21 percent.  Because EGU fleets in these states are reasonably representative of EGU fleets in the region as a whole, EPA believes it is appropriate to apply an 18 percent annual variability limit to all states covered by the annual SO2 and NOX programs and a 21 percent ozone-season variability limit to all states covered by the ozone-season NOX program.
      EPA is determining the final rule's variability limits for all states on the basis of the maximum measured historic variability at the state level among the states subject to the final Transport Rule.  EPA's analysis of historic heat input variability in multiple states over the 2000 to 2010 baseline yields a range of potential year-to-year variability values for state-level EGU emissions.  Any one state's measured variability from 2000 to 2010 is due at least in part to factors that are not unique to that particular state and may thus drive variability in year-to-year EGU emissions in other states in the future.  For example, a prolonged outage of a baseload nuclear plant in any state could require substantial increases in fossil fuel-fired baseload generators from that state or, indeed, from a neighboring state connected by the power grid.  Data from the Energy Information Administration reporting Tennessee electric generation from 2000 to 2010 show considerable variability from year to year between fossil and non-fossil generation sources.  This data reveals instances where fossil generation has increased in years when nuclear generation has declined, potentially due to times during which not all of the state's nuclear power plants were fully operating.  There are substantial amounts of nuclear and fossil generation capacity scattered throughout the states in the region covered by the Transport Rule in a similar pattern as those categories occupy in Tennessee.
      Such a disruption at a large baseload unit in a given state could yield substantial swings in heat input at units subject to the Transport Rule in that state or possibly in other states to make up for the disrupted generation.  EPA believes that it is reasonable, therefore, to determine that the maximum measured variability at the state level should represent the minimally necessary variability that any covered state may need in future years, considering that multiple states may have in common at least some of the factors driving historic variability in the state featuring the highest variability during the measured baseline period (2000 to 2010).
      EPA also believes that it is appropriate to accommodate this potential future variability at the state level if and only if it can be accommodated without undermining the programs' beneficial impacts on downwind air quality that eliminate significant contribution to nonattainment or interference with maintenance of the NAAQS assessed in this rulemaking (see the "Power Sector Variability Final Rule TSD" for more information on this analysis).  The Transport Rule identifies and quantifies, on a state-by-state basis, the emissions in each state that significantly contribute to nonattainment or interfere with maintenance in another state.  This is done by analyzing specific air pollution linkages between each upwind state and each downwind maintenance or nonattainment receptor.    Nonetheless, it is clear from the air quality analyses that the air quality outcome at a given downwind receptor is a function of the cumulative emissions from all upwind states and the receptor's home state.  Once the Transport Rule emission reduction requirements are implemented in all states subject to the programs, EPA's analysis shows that the impact on a downwind receptor of any single upwind state's year-to-year fluctuation of up to 20 percent in SO2 emissions would be so limited as to not disturb that receptor's ability to maintain or attain the NAAQS analyzed in this rulemaking.  Therefore, to the extent that such variability has been measured in historic data in any state subject to the Transport Rule programs, it is reasonable to provide for potential future variability in Transport Rule states within the scope of what EPA's analysis shows to preserve downwind air quality gains achieved by the Transport Rule programs.
      The approach to establishing variability limits in the final rule modifies the approach from the proposed rule in two ways.  First, EPA is applying only a percentage variability limit to each budget in the final rule, whereas the proposed rule applied the greater of a percentage or an absolute tonnage variability limit to each budget.  EPA explained in the proposal that it was necessary to impose both a percentage and a tonnage limit due to the inclusion of "states with small numbers of units where expected variability would be more pronounced in percentage terms" (75 FR 45293).  However, the states with the smallest numbers of units included at proposal (such as Connecticut and the District of Columbia) are not covered by any of the final Transport Rule's programs.  In the final rule's variability analysis, Tennessee has the highest measured annual variability percentage and Virginia has the highest measured ozone-season variability percentage.  Both of these states have a sufficient number of units for the percentage variability findings to be representative of variability in all of the Transport Rule states; therefore, it is not necessary to impose a tonnage limitation in the final rule.
      Second, EPA has expanded the historic baseline of the variability analysis to consider heat input data from 2000 through 2010, as compared to 2002 through 2008 at proposal, and EPA has also expanded the dataset to include all units expected to be covered by the final Transport Rule's programs.  EPA received a number of comments that the proposal's variability limits were too stringent in part because they relied on too short a historical baseline that failed to capture the full extent of long-run year-to-year variability.  EPA agrees with these comments and believes that the historic baseline modification described above supports variability limits in the final rule that are a better approximation of future potential year-to-year variability in state-level EGU emissions around the budgets as a function of inherent variability in baseline state-level EGU operations.  EPA believes the 2000 through 2010 historic baseline supports a more accurate approximation of year-to-year variability in state-level EGU operations than previously measured on a 2002 through 2008 baseline.
      Some commenters expressed the view that allowing variability limits in addition to state budgets undermines the requirements of CAA section 110(a)(2)(D)(i)(I) to eliminate significant contribution to nonattainment and interference with maintenance of the NAAQS in downwind states.  EPA disagrees with these comments.  As explained above, EPA finds that year-to-year variability is an inherent characteristic of power sector emissions whether or not such emissions are controlled by state budgets; the future year-to-year variability is a component of the sector's emissions baseline before emission reductions are required.  As done for proposal, EPA has analyzed the impact of allowing emissions from upwind states in a given year to rise above the budgets but within the variability limits allowed in the final rule.  This analysis shows that emission fluctuations around the budgets but within the variability limits will not undermine the downwind air quality gains achieved by the implementation of the Transport Rule budgets, and therefore the variability limits cannot be said to undermine the elimination of significant contribution to nonattainment or interference with maintenance achieved under the Transport Rule programs.  Based on historical data and projected air quality impacts, the Agency believes that states will have sufficient flexibility and room to operate within the final rule's variability limits while addressing all emissions identified as significantly contributing to nonattainment or interfering with maintenance in other states.
F. Variability Limits and State Emission Budgets: State Assurance Levels
      As explained above, EPA applied the variability levels on a state-by-state basis to calculate specific emission budgets with variability limits.  The state budget plus the variability limit is also called the "state assurance level."  Table VI.F-1 shows final state budgets, variability limits, and assurance levels by state for SO2 emissions.  Table VI.F-2 shows final state budgets, variability limits, and assurance levels by state for annual NOX emissions.  Table VI.F-3 shows final state budgets, variability limits, and assurance levels by state for ozone-season NOX emissions.

Table VI.F-1  -  State Budgets, Variability Limits, and Assurance Levels for SO2 Emissions

                            Emission Budget (tons)
                       Emission Variability Limit (tons)
                    State Emissions Assurance Level  (tons)

2012- 2013
2014 and beyond
2012- 2013
2014 and beyond
2012- 2013
2014 and beyond
Alabama
216,033
213,258
                                    38,886
                                    38,386
                                    254,919
                                    251,644
Georgia
158,527
95,231
                                    28,535
                                    17,142
                                    187,062
                                    112,373
Illinois
234,889
124,123
                                    42,280
                                    22,342
                                    277,169
                                    146,465
Indiana
285,424
161,111
                                    51,376
                                    29,000
                                    336,800
                                    190,111
Iowa
107,085
75,184
                                    19,275
                                    13,533
                                    126,360
                                    88,717
Kansas
41,528
41,528
                                     7,475
                                     7,475
                                    49,003
                                    49,003
Kentucky
232,662
106,284
                                    41,879
                                    19,131
                                    274,541
                                    125,415
Maryland
30,120
28,203
                                     5,422
                                     5,077
                                    35,542
                                    33,280
Michigan
229,303
143,995
                                    41,275
                                    25,919
                                    270,578
                                    169,914
Minnesota
41,981
41,981
                                     7,557
                                     7,557
                                    49,538
                                    49,538
Missouri
207,466
165,941
                                    37,344
                                    29,869
                                    244,810
                                    195,810
Nebraska
65,052
65,052
                                    11,709
                                    11,709
                                    76,761
                                    76,761
New Jersey
5,574
5,574
                                     1,003
                                     1,003
                                     6,577
                                     6,577
New York
27,325
18,585
                                     4,919
                                     3,345
                                    32,244
                                    21,930
North Carolina
136,881
57,620
                                    24,639
                                    10,372
                                    161,520
                                    67,992
Ohio
310,230
137,077
                                    55,841
                                    24,674
                                    366,071
                                    161,751
Pennsylvania
278,651
112,021
                                    50,157
                                    20,164
                                    328,808
                                    132,185
South Carolina
88,620
88,620
                                    15,952
                                    15,952
                                    104,572
                                    104,572
Tennessee
148,150
58,833
                                    26,667
                                    10,590
                                    174,817
                                    69,423
Texas
243,954
243,954
                                    43,912
                                    43,912
                                    287,866
                                    287,866
Virginia
70,820
35,057
                                    12,748
                                     6,310
                                    83,568
                                    41,367
West Virginia
146,174
75,668
                                    26,311
                                    13,620
                                    172,485
                                    89,288
Wisconsin
79,480
40,126
                                    14,306
                                     7,223
                                    93,786
                                    47,349

Note: Budgets, limits, and assurance levels apply to each state's emissions from covered sources, as defined by this final rule, only.

Table VI.F-2  -  State Budgets, Variability Limits, and Assurance Levels for Annual NOX Emissions

                            Emission Budget (tons)
                       Emission Variability Limit (tons)
                    State Emissions Assurance Level  (tons)

2012- 2013
2014 and beyond
2012- 2013
2014 and beyond
2012- 2013
2014 and beyond
Alabama
                                                                        216,033
                                                                        213,258
                                    38,886
                                    38,386
                                    254,919
                                    251,644
Georgia
                                                                        158,527
                                                                         95,231
                                    28,535
                                    17,142
                                    187,062
                                    112,373
Illinois
                                                                        234,889
                                                                        124,123
                                    42,280
                                    22,342
                                    277,169
                                    146,465
Indiana
                                                                        285,424
                                                                        161,111
                                    51,376
                                    29,000
                                    336,800
                                    190,111
Iowa
                                                                        107,085
                                                                         75,184
                                    19,275
                                    13,533
                                    126,360
                                    88,717
Kansas
                                                                         41,528
                                                                         41,528
                                     7,475
                                     7,475
                                    49,003
                                    49,003
Kentucky
                                                                        232,662
                                                                        106,284
                                    41,879
                                    19,131
                                    274,541
                                    125,415
Maryland
                                                                         30,120
                                                                         28,203
                                     5,422
                                     5,077
                                    35,542
                                    33,280
Michigan
                                                                        229,303
                                                                        143,995
                                    41,275
                                    25,919
                                    270,578
                                    169,914
Minnesota
                                                                         41,981
                                                                         41,981
                                     7,557
                                     7,557
                                    49,538
                                    49,538
Missouri
                                                                        207,466
                                                                        165,941
                                    37,344
                                    29,869
                                    244,810
                                    195,810
Nebraska
                                                                         65,052
                                                                         65,052
                                    11,709
                                    11,709
                                    76,761
                                    76,761
New Jersey
                                                                          5,574
                                                                          5,574
                                     1,003
                                     1,003
                                     6,577
                                     6,577
New York
                                                                         27,325
                                                                         18,585
                                     4,919
                                     3,345
                                    32,244
                                    21,930
North Carolina
                                                                        136,881
                                                                         57,620
                                    24,639
                                    10,372
                                    161,520
                                    67,992
Ohio
                                                                        310,230
                                                                        137,077
                                    55,841
                                    24,674
                                    366,071
                                    161,751
Pennsylvania
                                                                        278,651
                                                                        112,021
                                    50,157
                                    20,164
                                    328,808
                                    132,185
South Carolina
                                                                         88,620
                                                                         88,620
                                    15,952
                                    15,952
                                    104,572
                                    104,572
Tennessee
                                                                        148,150
                                                                         58,833
                                    26,667
                                    10,590
                                    174,817
                                    69,423
Texas
                                                                        243,954
                                                                        243,954
                                    43,912
                                    43,912
                                    287,866
                                    287,866
Virginia
                                                                         70,820
                                                                         35,057
                                    12,748
                                     6,310
                                    83,568
                                    41,367
West Virginia
                                                                        146,174
                                                                         75,668
                                    26,311
                                    13,620
                                    172,485
                                    89,288
Wisconsin
                                                                         79,480
                                                                         40,126
                                    14,306
                                     7,223
                                    93,786
                                    47,349

Note: Budgets, limits, and assurance levels apply to each state's emissions from covered sources, as defined by this final rule, only.

Table VI.F-3  -  State Budgets, Variability Limits, and Assurance Levels for Ozone-Season NOX Emissions

                            Emissions Budget (tons)
                      Emissions Variability Limit (tons)
                    State Emissions Assurance Level  (tons)

2012- 2013
2014 and beyond
2012- 2013
2014 and beyond
2012- 2013
2014 and beyond
Alabama
                                    31,746
                                    31,499
                                     6,667
                                     6,615
                                    38,413

                                    38,114
Arkansas
                                    15,037
                                    15,037
                                     3,158
                                     3,158
                                    18,195
                                    18,195
Florida
                                    27,825
                                    27,825
                                     5,843
                                     5,843
                                    33,668
                                    33,668
Georgia
                                    27,944
                                    18,279
                                     5,868
                                     3,839
                                    33,812
                                    22,118
Illinois
                                    21,208
                                    21,208
                                     4,454
                                     4,454
                                    25,662
                                    25,662
Indiana
                                    46,876
                                    46,175
                                     9,844
                                     9,697
                                    56,720
                                    55,872
Kentucky
                                    36,167
                                    32,674
                                     7,595
                                     6,862
                                    43,762
                                    39,536
Louisiana
                                    13,432
                                    13,432
                                     2,821
                                     2,821
                                    16,253
                                    16,253
Maryland
                                     7,179
                                     7,179
                                     1,508
                                     1,508
                                     8,687
                                     8,687
Mississippi
                                    10,160
                                    10,160
                                     2,134
                                     2,134
                                    12,294
                                    12,294
New Jersey
                                     3,382
                                     3,382
                                      710
                                      710
                                     4,092
                                     4,092
New York
                                     8,331
                                     8,331
                                     1,750
                                     1,750
                                    10,081
                                    10,081
North Carolina
                                    22,168
                                    18,455
                                     4,655
                                     3,876
                                    26,823
                                    22,331
Ohio
                                    40,063
                                    37,792
                                     8,413
                                     7,936
                                    48,476
                                    45,728
Pennsylvania
                                    52,201
                                    51,912
                                    10,962
                                    10,902
                                    63,163
                                    62,814
South Carolina
                                    13,909
                                    13,909
                                     2,921
                                     2,921
                                    16,830
                                    16,830
Tennessee
                                    14,908
                                     8,016
                                     3,131
                                     1,683
                                    18,039
                                     9,699
Texas
                                    63,043
                                    63,043
                                    13,239
                                    13,239
                                    76,282
                                    76,282
Virginia
                                    14,452
                                    14,452
                                     3,035
                                     3,035
                                    17,487
                                    17,487
West Virginia
                                    25,283
                                    23,291
                                     5,309
                                     4,891
                                    30,592
                                    28,182

Note: Budgets, limits, and assurance levels apply to each state's emissions from covered sources, as defined by this final rule, only.

      See Section VII.E for the discussion of how variability limits and state assurance levels are used in the implementation of assurance provisions for the air quality-assured trading programs.  [PLACEHOLDER FOR CAVEAT REGARDING REMEDY ANALYSIS AND REVISED VARIABILITY LIMITS]
G. How the State Emission Reduction Requirements are Consistent with Judicial Opinions Interpreting the Clean Air Act
      The methodology described in this notice quantifies states' significant contribution to nonattainment and interference with maintenance in a manner that is consistent with the decisions of the D.C. Circuit.  As discussed previously, the D.C. 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, 213 F.3d 663, and the second found significant flaws in CAIR, North Carolina, 531 F.3d. 896.  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 final 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 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 emission 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 rule, EPA uses a first step similar to that used in CAIR to identify the states with relatively large contributions.  However, in contrast to 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 each 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, emission 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 V.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 FIPs are either part of or constitute the state's significant contribution to nonattainment and interference with maintenance.  Thus, elimination of these emissions will, at a minimum, make measurable progress towards satisfying the section 110(a)(2)(D)(i)(I) prohibition on significant contribution to nonattainment and interference with maintenance.
VII. FIP Program Structure to Achieve Reductions
A. Overview of Air Quality-Assured Trading Programs
      EPA is finalizing an air quality-assured trading remedy that is substantially similar to the preferred trading remedy presented in the proposal.  Key differences from the preferred trading remedy in the proposal include:
   * Recalculated state budgets and variability limits (i.e., state assurance levels) based on updated modeling;
   * Simplified variability limits for one-year application only;
   * Revised allocation methodology for existing and new units and revised new unit set-asides for new units in Transport Rule states and new units potentially locating in Indian country;
   * Changed start of assurance provisions to 2012 and increased assurance provision penalties; and
   * Removed opt-in provisions.
      In the final rule, as in the proposed rule, EPA is promulgating FIPS to require SO2 and NOX reductions from power plants in jurisdictions that contribute significantly to nonattainment in, or interfere with maintenance by, a downwind area with respect to the 1997 ozone NAAQS, the 1997 annual PM2.5 NAAQS, and/or the 2006 24-hour PM2.5 NAAQS.  These FIPs establish state-specific emission control requirements using state budgets starting in 2012, with a second phase of SO2 reductions in some states in 2014.  Section IV explains EPA's authority to issue FIPs.
      The air quality-assured trading remedy in the final rule allows interstate trading to account for variability in the electricity sector, but also includes assurance provisions to ensure that the necessary emission reductions occur within each covered state.  The assurance provisions restrict EGU emissions within each state to the state's budget plus the variability limit and ensure that every state is making reductions to eliminate the significant contribution to nonattainment and interference with maintenance that EPA has identified.  While EPA proposed to impose these assurance provisions starting in 2014, the final rule implements these provisions starting in 2012 (see section VII.E of this preamble).  Additionally, the final FIPs include penalty provisions adequate to ensure that the state budget with the variability limit will not be exceeded.
      In the final rule, as in the preferred trading remedy discussed in the proposed rule, state-specific emission budgets without the variability limits are used to determine the number of emission allowances allocated to sources in each state.  An EGU source is required to hold one SO2 or one NOX allowance, respectively, for every ton of SO2 or NOX emitted during the control period.  Banking of allowances for use or trading in future years is allowed.
      The final rule establishes four interstate trading programs, each 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 SO2 Group 1) that need to make larger reductions to eliminate their significant contribution, while the second is for sources in states (referred to as SO2 Group 2) that need to make smaller reductions.  A source in a Group 1 state can only use SO2 allowances allocated to Group 1 states for compliance with the SO2 trading program.  A source in a Group 2 state can only use SO2 allowances allocated to Group 2 states for compliance with the SO2 trading program.  For compliance in the annual NOX and ozone-season trading programs respectively, sources may use annual NOX and ozone-season allowances allocated for any state, even if that state is in a different group for SO2 than the source's state.  Four sets of new emission allowances based on the new state-specific budgets without variability are allocated to sources, one set for each of the four trading programs.  Each state has the option of replacing these FIPs with state rules.  EPA believes that this remedy meets the concerns raised by the Court in the 2008 North Carolina decisions which remanded CAIR to EPA.
      In the proposed rule, EPA took comment on all aspects of the preferred trading remedy and on two alternative regulatory options: (1) intrastate trading; and (2) direct control.  EPA also took comment on a trading ratios approach.
      Comments on the Preferred Trading Remedy:  The great majority of public comments supported the preferred trading remedy.  Most of these commenters voiced their support for the broadest possible trading mechanism because it allows for the most cost-effective implementation of any emission controls.  Commenters noted that flexibility is always needed in the early years of new programs.  Further, commenters favoring the preferred remedy agreed with EPA that, by using state-specific control budgets and allowing for interstate trading, the preferred remedy provided electricity generators the flexibility to undertake the most cost-effective reductions while assuring that the resulting reductions occur within the individual states.
      Some commenters that supported the preferred remedy felt that, while not ideal, the interstate trading remedy was preferable to the alternative options of intrastate trading or direct control.  Many commenters that supported the preferred remedy felt that the intrastate trading remedy and direct control remedy options offer minimal flexibility from a compliance perspective.  They stated that this lack of flexibility would unnecessarily increase the cost of emission reductions.
      Other commenters who generally support the preferred remedy cited concerns about the level of complexity in the assurance provisions.  One commenter surmised that the preferred option creates significant risk where a company could unexpectedly find itself in a noncompliance situation due to the after-the-fact variability analysis.  Another said that the rule's features needlessly reduce the system's efficiency and increase complexity.  These commenters generally preferred unlimited trading, noting that EPA has proven success with Title IV, the NOX SIP Call, and CAIR unlimited interstate trading programs and that allowing unrestricted interstate trading would increase flexibility to meet reduction goals and minimize increases in power costs.
      EPA is finalizing the preferred trading remedy for the following reasons.  EPA believes this approach is the most cost-effective and practical way to comply with the Court decision in North Carolina to ensure that all emissions in a given state that EPA has identified as significantly contributing to downwind nonattainment or interfering with maintenance are eliminated.  The vast majority of public commenters agree.  In addition, this approach provides the most flexibility for sources while meeting the Clean Air Act requirements and protecting public health.  As a result, potential innovations and resulting cost savings are more likely to be found and implemented.  Based on historical experience (see the Transport Rule proposal, p. 45315), EPA has shown that the results offered by a flexible trading approach (e.g., flexible compliance choices, incentives to reduce emissions early and in the highest emitting areas, 100 percent compliance with requirements) are substantial.  A large number of commenters have corroborated this assessment.  As summarized in the proposal, EPA believes that the preferred trading remedy will allow source owners to choose among several compliance options to achieve required emission reductions in the most cost-effective manner, such as installing controls, changing fuels, reducing utilization, buying allowances, or any combination of these actions.  Interstate trading with assurance provisions will also allow the electricity sector to continue to operate as an integrated, interstate system able to provide electric reliability.
      Comments on Intrastate Trading:  A few commenters favored the first alternative, intrastate trading.  One commenter who favored intrastate trading stated that many power plants have avoided investment in pollution controls by buying allowances from other plants, affecting local air quality improvement.  EPA notes that this Transport Rule aims to address emissions from one state that significantly contribute to nonattainment or interfere with maintenance of certain NAAQS in other states.  Local air quality issues are directly addressed by other provisions in the Clean Air Act.
      Several commenters raised concerns about the intrastate trading approach.  Some stated, as EPA noted in the proposal, that the intrastate trading option would be more resource intensive, more complex, less flexible, and potentially more susceptible to market manipulation than the other options.  In addition, some commenters felt that this alternative would provide less flexibility to ensure electric reliability than the preferred approach, resulting in greater private costs to the power sector and greater social costs for consumers.
      EPA is not finalizing the intrastate trading option for the following reasons.  As EPA expressed in the proposal and as commenters have agreed, the intrastate trading option would be more resource intensive (both for EPA and for sources), more complex, less flexible, and potentially more susceptible to market manipulation than the preferred trading approach that EPA is finalizing.  The intrastate trading option would be more costly and less transparent due to the large number of trading programs that would be operated simultaneously and the large number of annual auctions that would be held every year to address the issues of market power within states.  This option would also result in a greater burden for participants operating EGUs in multiple states.
      Comments on Direct Control Option:  Several commenters favored the second alternative, direct control.  One commenter stated that direct control -- allowing no trading -- was the option best aligned with the 2008 Court decisions.  EPA disagrees with this comment for the reasons given below and because, as explained in this rule, EPA believes the air quality-assured trading remedy finalized today is consistent with the decisions of the D.C. Circuit in North Carolina.
      Some commenters, who support direct control, voiced concerns that the other emission trading approaches would disadvantage poor and minority communities or allow increased emission impacts in neighborhoods near power plants.  EPA notes that a direct control approach would not require controls on all plants in a state, but only on a sufficient number to address the transport requirements under section 110(a)(2)(d)(i)(I) that this rule addresses, and therefore would not necessarily mandate controls on each neighborhood power plant.
      In addition, EPA has conducted an analysis of the effects of the Transport Rule on environmental justice and other vulnerable communities.  We concluded that, similar to our experience with the Acid Rain Program, many environmental justice communities are expected to see large health benefits, and none are expected to experience any disbenefits, from implementing an air quality-assured trading program.  The results of this analysis are presented in section XII of this preamble and Chapter 5 of the RIA for this rule.  In addition, the Clean Air Act provides flexibility for state and local authorities to impose stricter limits on sources to address specific local air quality concerns.  Such limits are independent of the requirements in this rule, and compliance with Transport Rule requirements in no way excuses a source from complying with other Clean Air Act or state law requirements.
      Several commenters raised concerns with the direct control approach.  One commenter felt that issues with electricity market reliability could occur during high electricity demand periods if sources ceased operations due to approaching their emission rate limitations under a direct control remedy.  Another commenter was concerned that applying emission rates under a direct control remedy to small municipal units would cause disproportionate impacts on power plants where pollution control is more expensive.  Other commenters cited concerns that EPA's proposed within-state company-wide averaging provision in the direct control proposed alternative (designed to allow some flexibility for sources) would place companies with fewer units at a disadvantage compared to companies with more units.  EPA generally agrees with the commenters concerns and has decided not to finalize the direct control remedy for the following reasons.  EPA modeling projects that the direct control alternative would result in fewer emission reductions and higher costs compared to the air quality-assured trading remedy.  EPA analysis indicates that it is not necessary to implement a direct control approach in order to protect vulnerable and sensitive populations or environmental justice communities.   Also, the direct control approach would result in fewer compliance options because a direct control approach would directly regulate individual sources by setting unit-level emission rate limits.  This lack of flexibility could lead to potential increases in reliability risks in the electric power system and fewer opportunities for potential technological innovations that reduce emissions further and/or lower costs.  For these reasons, EPA believes that this approach is inferior to the air quality-assured trading remedy.
       Other Comments:  A handful of commenters mentioned the trading ratios approach, though none favored it as a viable alternative.  One commenter said the trading ratios approach was not consistent with CAA section 110(a)(2)(D) requirements that reductions in emissions occur in particular geographic locations.  Other commenters agreed that it was administratively unworkable and would be difficult to implement due to the complexity and variety of meteorological conditions.  EPA generally concurs with the commenters.  In the proposal, EPA noted that it would not be possible under this approach, as contemplated, 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 requested comment on whether a ratios trading program could be designed to provide such legal assurances.  Of the few comments received, none offered such a solution.  For these reasons, EPA is not finalizing this approach.
      Some commenters offered additional suggestions, such as:  unrestricted trading; using different authorities in the Clean Air Act to address interstate transport such as section 110(k)(5) and section 126; and an approach that would replace the assurance provisions by a system using both emission allowances usable (as well as bankable) in any state and assurance allowances usable (but not bankable) in only the state for which they would be issued.  While EPA appreciates the thoughtful and constructive comments, we did not find any of these suggestions improved our ability to address interstate transport under CAA section 110(a)(2)(D)(i)(I), in line with the Court decision, in an administratively practical way.
      Several commenters liked the idea of establishing unit-by-unit short-term and long-term performance standards/emission rates but suggested adding an overlaid cap and trade program.  EPA believes the air quality-assured trading remedy finalized today is consistent with the decisions of the Court in North Carolina and will ensure the reductions necessary to meet statutory requirements.
      For the 2012-2013 period, EPA took comment on whether the assurance provisions are needed, since the state-specific budgets would be based on known air pollution controls and the penalty provisions would be adequate to ensure that the budget, including a variability limit, would not be exceeded.  Further, EPA proposed to use two variability limits:  a 1-year limit, based on the year-to-year variability in emissions relative to the proposed budgets; and a 3-year limit based on the variability in a 3 year average relative to the proposed budget.
      Based on comments on the assurance provisions (see section VII.E of this preamble) and variability limits (see section VI.E.2 of this preamble), EPA is finalizing the Transport Rule with state budgets plus variability limits and assurance provisions starting in 2012 for all of the trading programs.  EPA sees an immediate need to ensure that emissions within a state do not exceed the state budget plus the variability limitation in order to comply with the Court's opinion.  Further, commenters stated that the 3-year variability limit increased costs and unnecessarily complicated the trading programs.  As explained in section VI.E.2, EPA is finalizing the 1-year variability limit starting in 2012, but not the 3-year limit.
B. Applicability
      The applicability provisions in the final rule are, except as discussed herein, essentially the same as in the proposed rules and for each of the Transport Rule trading programs.
      Under the general applicability provisions of the proposed rule, the Transport Rule trading programs would cover fossil-fuel-fired boilers and combustion turbines serving  - - on any day starting November 15, 1990 or later -- an electrical generator with a nameplate capacity exceeding 25 MWe and producing power for sale, with the exception of certain cogeneration units and solid waste incineration units.
      EPA requested comment on whether a more recent year should be used instead.  The proposed use of the November 15, 1990 date was consistent with the use of 1990 as the beginning of the historical period for which owners and operators would generally be required to have information about their units for purposes of determining whether the units were covered by the Transport Rule trading programs.  Because unit information is generally compiled and retained on a calendar year basis, EPA believes that, for the general applicability provisions, it is preferable to use January 1, rather than November 15.  In determining which year should be used as the reference year in the general applicability provisions, EPA considers several factors.
      First, in order for owners and operators, and EPA, to be able to determine which units are subject to the Transport Rule trading programs, EPA believes that the reference year should not be so far in the past that the unit information necessary to make applicability determinations is not readily available.  This particularly becomes an issue in cases of older units that have changed ownership over time.  EPA found, in making some applicability determinations under the CAIR trading programs, that some older units with ownership changes had difficulty obtaining information back as far as twenty or more years.  Using January 1, 1990 as the reference date in the general applicability provisions could effectively require some owners and operators to retain unit information going back as far as 20 years.  As a point of contrast, under the title V permitting rules, owners and operators are generally required to retain data for 5 years.  See 40 CFR 70.6(a)(3)(B).
      Second, EPA also believes that the reference year used in the applicability provisions should be far enough in the past that the unit information on which applicability determinations are based provides a full picture of the nature of the unit and its operations over time, such as the types of fuels combusted at the unit and whether the unit has produced electricity for sale.
      Third, EPA considers whether selecting a different reference year for the applicability provisions than the one in the proposed rule dramatically changes what units will be covered by the Transport Rule trading programs.  In this case, EPA believes, based on available information about the units potentially subject to the Transport Rule, that using a somewhat later year than the one in the proposed rule will likely have little effect on what units are covered.  Balancing these factors, EPA concludes that it is reasonable to use January 1, 2005, rather than November 15, 1990, in the general applicability provisions in the final rule.
      In the final rule, EPA is taking the same approach with regard to defining whether a boiler or combustion turbine is considered to be "fossil-fuel-fired" as the one used in the proposal.  Under the proposed rule, a unit was considered to be "fossil-fuel-fired" if it combusts any amount of fossil fuel at any time in 1990 or later.  For the same reasons that EPA decided to use January 1, 2005 in the general applicability provisions, and in order to have a consistent reference year in all applicability-related provisions, the final rule defines a "fossil-fuel-fired" unit as one that combusts any amount of fossil fuel in 2005 or later.
      EPA notes that the final Transport Rule allows a state to submit a SIP revision (an abbreviated or full SIP) under which the state may -- in addition to making certain types of changes concerning allowance allocations in the Transport Rule trading programs  - - expand the general applicability provisions of the Transport Rule NOX Ozone Season Trading Program to cover fossil-fuel-fired boilers and combustion turbines serving  - - at any time starting January 1, 2005 or later  -  a generator with a nameplate capacity as low as 15 MWe producing power for sale.  The exemptions, discussed below, for cogeneration units and solid waste incineration units still will continue to apply.
      Cogeneration unit exemption.  Under the final rule (as well as the proposed rule) certain cogeneration units or solid waste incinerators are exempt from the FIP requirements.  In particular, the final rule includes an exemption for a unit that qualifies as a cogeneration unit throughout the later of 2005 or the first 12 months during which the unit first produces electricity and continues to qualify through each calendar year ending after the later of 2005 or that 12-month period and that meets the limitation on electricity sales to the grid.  In order to meet the definition of "cogeneration unit" in the final rules, a unit (i.e., a fossil-fuel-fired boiler or combustion turbine) must be a topping-cycle or bottoming-cycle that operates as part of a "cogeneration system," which is defined as an integrated group of equipment at a source (including a boiler, or combustion turbine, and a steam turbine generator) designed to produce useful thermal energy for industrial, commercial, heating, or cooling purposes and electricity through the sequential use of energy.  A topping-cycle unit is a unit where the sequential use of energy results in production of useful power first and then, through use of reject heat from such production, in production of useful thermal energy.  A bottoming-cycle unit is a unit where the sequential use of energy results in production of useful thermal energy first and then, through use of reject heat from such production, in production of useful power.  In order to qualify as a cogeneration unit, a unit also must meet certain efficiency and operating standards.
      In the proposed rule, a unit would have to qualify as a cogeneration unit and meet the limitation on electricity sales starting the later of 1990 or the year when the unit begins operating.  EPA requested comment on whether a more recent year should be used.  For the reasons discussed above concerning the reference year used in the general applicability provisions and in order to have a consistent reference year in all applicability-related provisions, EPA concludes that it is reasonable to use 2005, rather than 1990, in the cogeneration unit exemption provisions in the final rule.  Consequently, the final rule provides that the requirements to qualify as a cogeneration unit and to meet the electricity sales limitation start no earlier than 2005.
      In the final rule, EPA also clarifies that the electricity sales limitation under the exemption is applied in the same way whether a unit serves only one generator or serves more than one generator.  In both cases, the total amount of electricity produced annually by a unit and sold to the grid cannot exceed the greater of one-third of the unit's potential electric output capacity or 219,000 MWhr.  This is consistent with the approach taken in the Acid Rain Program (40 CFR 72.7(b)(4)), where the cogeneration unit exemption originated.  EPA believes that this clarification is needed to ensure that a unit serving, for example, two generators would not have a limit on sales of electricity to the grid that would be different (i.e., twice as high) from the limit for a unit serving only one generator with the same total nameplate capacity as the first unit's two generators.
      EPA also took comment on whether efficiency standards should be applied on a system-wide basis to bottoming-cycle units (where useful thermal energy is produced before useful power is produced), as they are for topping-cycle units (where useful thermal energy is produced after useful power) and whether to exclude, from the requirement to meet the operating and efficiency standards, calendar years during which a cogeneration unit does not operate at all.  Several commenters argued EPA should apply efficiency standards to both types of units.  EPA agrees that applying efficiency standards on a system-wide basis to both bottoming-cycle and topping-cycle units is reasonable because EPA sees no technical reason to distinguish between the two types of units in this instance.  EPA further agrees with commenters that excluding calendar years in which the cogeneration unit does not operate at all, i.e., does not combust any fuel, from the requirements to meet operating and efficiency standards is also reasonable.  For such a year, the unit would not produce any useful thermal energy or useful power and therefore could not meet the minimum output requirements in the operating and efficiency standards, but the unit also would not have any emissions.  For these reasons, the final rule expressly provides that the operating and efficiency standards do not have to be met for a calendar year throughout which a unit did not operate at all.
      Solid waste incineration unit exemption.  The final rule also includes an exemption for a unit that qualifies as a solid waste incineration unit during the later of 2005 or the first 12 months during which the unit first produces electricity, that continues to qualify throughout each calendar year ending after the later of 2005 or that 12-month period each year thereafter, and that meets the limitation on fossil-fuel use.  In contrast, the exemption for solid waste incineration units in the proposed rule distinguished between units commencing operation before January 1, 1985 and those commencing operation on or after that date.  A unit commencing operation before January 1, 1985 would be exempt if it qualified as a solid waste incineration unit starting the later of 1990 or the year when it began producing electricity and its average annual fuel consumption of non-fossil fuels exceeded 80 percent of total heat input during 1985-1987 and during any three consecutive calendar years after 1990. A unit commencing operation on or after January 1, 1985 would be exempt if it qualified as a solid waste incineration unit starting the later of 1990 or the year when it began producing electricity and its average annual fuel consumption of non-fossil fuel exceeded 80 percent of total heat input for the first 3 calendar years of operation and for any 3 consecutive calendar years thereafter.
      In the proposal, EPA requested comment on whether it would be problematic to obtain sufficiently detailed information about unit operation potentially as far back as 1985-1987 and 1990, and whether the fuel consumption standard for each unit should be limited to more recent years.  For the reasons discussed above concerning the reference year used in the general applicability provisions and in order to have a consistent reference year for all applicability-related provisions, EPA concludes that it is reasonable to use 2005, rather than 1990, in the solid waste incineration unit exemption in the final rule.  In particular, EPA notes that the proposed provisions for units commencing operation before January 1, 1985 and for units commencing operation on or after January 1, 1985 could require some owners and operators to retain unit information going back more than 20 years before the promulgation of this final rule.  Further, EPA believes that removing the distinction between units commencing operation during these two periods, and referencing somewhat later years as the earliest years for which information on fossil-fuel consumption is required, will result in the exemption still being based on sufficient data to provide a full picture of the nature and operation of the units involved.  EPA also believes, based on available information about the units potentially subject to the Transport Rule, that this approach will not significantly change which units qualify for the exemption.  Consequently, the final rule removes the distinction based on whether a solid waste incineration unit commences operation before January 1, 1985 or on or after January 1, 1985.  In order to be exempt, the unit must qualify as a solid waste incineration unit during the later of 2005 or the first 12 months during which the unit first produces electricity, must continue to qualify throughout each calendar year ending after the later of 2005 or that 12-month period, and must meet the limitation on fossil-fuel use on a three-year average basis during the first 3 years of operation starting no earlier than 2005 and every 3 years of operation thereafter.